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 Dietert, Vice President, Investor Relations. Jeff, you may begin.
Good morning, and welcome to Phillips 66 second quarter earnings conference call. Participants on today's call will include Greg Garland, Chairman and CEO, and Kevin Mitchell, Executive Vice President and CFO. The presentation 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 two contains our safe harbor statement. It is a reminder that we will be making forward-looking statements during the presentation and our Q&A session. Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here as well as in our SEC filings. 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 business has operated well and delivered strong earnings and cash flows. Adjusted earnings were $1.3 billion, 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 $2.4 billion of cash from operations during the quarter, which is the highest since 2012. We rewarded our shareholders by returning $602 million through dividends and share repurchases, which brings our total distributions for the year to $4.4 billion. A secure, competitive, and growing dividend is fundamental to our strategy. During the second quarter, 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 two major growth projects: construction of the Gray Oak pipeline and expansion of the Sweeny Hub. Phillips 66 Partners recently completed the expansion open season for the Gray Oak pipeline. Gray Oak will provide crude oil transportation from the Permian in 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 million 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 billion. Phillips 66 Partners will be the largest equity owner in this joint venture project.
At Sweeny, we're building two 150,000 barrel per day NGL fractionators and adding 6 million barrels of storage at Phillips 66 Partners' Clemens Caverns. We have agreements in place with multiple parties, including DCP Midstream, to supply the new fractionators. The hub will have 400,000 barrels a day of fractionation capacity and access to 15 million 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 and 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 1.3 million barrels of fully contracted crude storage into service, bringing the terminal's total crude and product storage capacity to 12.4 million barrels. Additional crude oil tanks are under construction that will increase the terminal's capacity to 14.6 million 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 second quarter, DCP increased the pipeline's capacity to 425,000 barrels per day, with further growth to 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 two-thirds by DCP and one-third by Phillips 66 Partners. Also in the Permian Basin, DCP Midstream has a 25% interest in the Gulf Coast Express Pipeline project, which will transport 2 billion cubic feet per day of natural gas to Gulf Coast markets. Completion of the pipeline is anticipated in the fourth quarter of 2019. In the high-growth DJ Basin, DCP's Mewbourn 3 gas processing plant is expected to start up in the third quarter of 2018, and the O'Connor 2 plant in the second quarter of 2019. In chemicals, CPChem had strong operations from its new Gulf Coast Petrochemicals assets, which contributed to solid earnings growth during the quarter. Ethane crackers demonstrated 3.5 billion pounds per year of capacity, which is 6% above 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-2020. 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. 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 four, second quarter earnings were $1.3 billion. We had special items that netted to a gain of $17 million. After excluding special items, adjusted earnings were $1.3 billion, or $2.80 per share. The second quarter adjusted effective tax rate was 22%. Operating cash flow was $2.4 billion. This included distributions from equity affiliates of $610 million and positive working capital impacts. Capital spending for the quarter was $538 million, with $348 million spent on growth projects. Second quarter distributions to shareholders consisted of $372 million in dividends and $230 million in share repurchases. We ended the quarter with 464 million shares outstanding. Slide five compares second quarter and first quarter adjusted earnings by segment. Quarter-over-quarter adjusted earnings increased over $800 million, mainly driven by refining. Slide six shows our midstream results.
Transportation adjusted net income for the quarter was $137 million, in line with the previous quarter. Increased volumes following the completion of first 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 million, down $23 million, reflecting positive inventory impacts in the first quarter of about $20 million. 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 million in the second quarter, a $9 million decrease from the previous quarter. The first quarter included a $9 million 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 seven. Second quarter adjusted net income for the segment was $262 million, $30 million higher than the first quarter. In Olefins and Polyolefins, adjusted net income increased $23 million from the ramp-up of the new ethane cracker and polyethylene units. Global O&P utilization was 95% in the second quarter. Adjusted net income for SA&S increased $14 million from the completion of first quarter 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 eight, we'll cover refining. Crude utilization was 100% compared with 89% in the first quarter. Our second quarter clean product yield was 84%. Pre-tax turnaround costs were $60 million, a decrease of $185 million from the previous quarter.
Refining second quarter adjusted net income was $911 million, up $822 million 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 first 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. A 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 nine covers market capture.
The 3-2-1 market crack for the second quarter was $14.86 per barrel compared to $13.12 per barrel in the first quarter. A realized margin for the second quarter was $12.28 per barrel, resulting in an overall market capture of 83%, up from 71% in the first quarter. Market capture was impacted in part by the configuration of our refineries. We made less gasoline and more distillate than premised in the 3-2-1 market crack. Losses from secondary products of $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 million, $21 million higher than the first 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 1,700 since the start of the program. We continued to see strong export demand during the quarter, with 200,000 barrels per day of refined product exports. Specialties adjusted net income increased $5 million from improved base oil margins.
On Slide 11, the corporate and other segment had adjusted net costs of $183 million this quarter, compared with $162 million in the prior quarter. The $21 million increase reflects higher interest expense and taxes. Slide 12 highlights the change in cash during the quarter. We entered the quarter with $842 million in cash on our balance sheet. Cash from operations excluding the impact of working capital was $1.7 billion. Working capital changes increased cash flow by $692 million, primarily from increased net payables as refining returned to normal operating levels following the first quarter turnarounds. During the quarter, we funded $538 million of capital expenditures and investments, returned $602 million to shareholders through dividends and the repurchase of shares, and repaid $250 million of debt. Our ending cash balance was $1.9 billion. This concludes my review of the financial and operational results.
Next, I'll cover a few outlook items for the third quarter. In chemicals, we expect the global O&P utilization rate to be in the mid-90s. This reflects the Cedar Bayou ethane cracker at the recently increased capacity of 3.5 billion pounds per year. In refining, we expect the worldwide crude utilization rate to be in the mid-90s and pre-tax turnaround expenses to be between $60 million and $80 million. We anticipate corporate and other costs to come in between $170 million and $190 million after tax. With that, we'll now open the line for questions.
Thank you. We will now begin the question and answer session. If you have a question, please press star then one on your touch-tone phone. If you wish to be removed from the queue, please press the pound key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touch-tone phone. Neil Mehta from Goldman Sachs, please go ahead. Your line is open.
Hey, thanks very much, guys.
Morning.
Good morning, Jeff. Good morning, Greg and Kevin. Appreciate the comments today. 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. Can you help us understand what drove the delta versus maybe what you guys were even modeling internally? 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 pre-tax margin. Just any of those deltas would be helpful in terms of framing the go forward.
I think refining performed exceptionally well in the quarter, averaging 100% utilization. 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. 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 wide WTI 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. I think finally, RINs costs were cut in half during the quarter. That helped capture rates as well.
No, that's helpful color. I want to build on that WCS point because we've seen the differentials really widen out here. You guys import more WCS than anybody else. Can you just 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's starting to come back on. We expect additional volumes in August and September. Fort Hills is continuing with its impressive ramp towards 200,000 barrels a day, potentially higher. As we look at maintenance activity, PADD 2 has well above average refinery maintenance planned for the fall, and some of that is going to reduce the demand for WCS as well. 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 Canadian 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 slightly higher than the average of 130,000 barrels a day last year. We're getting a little bit more rail, but not substantially more. We expect WCS discounts to be attractive for at least the next 18 months, and potentially longer.
Thanks, Jeff.
Roger Read from Wells Fargo, please go ahead. Your line is open.
Yeah, thank you. Good morning. Really great quarter there, I think we have to say. I'd like to come at it from the refining utilization side. 100% utilization. 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? 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 the first quarter. We came out, we ran really well. Given the market opportunities available to us, I encourage us to run. I suspect that we're in a period where dips may come in just a little bit. 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, particularly the back half of 2019. I think that we're pretty constructive on both the supply and demand side. We've got a strong economy going. 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. 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. I think there'll continue to be a focus on running well, certainly within our portfolio.
Yeah, I appreciate that. I guess that's what I'm trying to get at is, if you ran at 100% this quarter, and 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, you just have to simply work your way within the system as is.
Well, just a couple of points. I think that even in our second quarter, we probably about 3.5% due to downtime due to unplanned downtime and turnaround activity during the quarter. We had assets that ran well above the 100% level coming into it. The other thing I would say, we've come through two heavy turnaround years, in 2018 and 2017 for us. We're really, I think from a portfolio standpoint, turnaround standpoint, well positioned for 2019 and 2020 to run well.
I appreciate that. 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'll 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.
Okay. I appreciate it. Thank you.
Phil Gresh from JPMorgan. Please go ahead. Your line is open.
Hey, good afternoon, good morning.
Good afternoon, Phil.
First question just on chemicals. Could you elaborate a little bit about what kind of contribution you think you saw from the cracker in the second quarter? What kind of startup costs you may have? 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.
Yeah. Phil, it's Kevin. I'd say as you look at the second quarter, you certainly have some ramp-up in terms of utilization. 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 startup expenses were anything to really move the needle in the quarter. There may have been a little bit, but it's just not material. I think as we step back and look at this, the mid-cycle guidance that we've talked to previously is still intact.
Still expect to generate that incremental EBITDA in the same range of numbers we've talked about in the past.
Yeah. I think, Phil, in the third quarter, we certainly would expect kind of run rate type levels of performance out of that asset. I think, you think about the near term, Dow was up. We're up now. ExxonMobil's coming up. Near term, you could have some compression of margins, as these volumes start to get absorbed in the marketplace. Offsetting that, though, the global economy is strong. You saw the GDP number for the U.S. today. We've got great demand on this. We're still pretty constructive, out over the next 3 to 4 years of good, solid demand growth. I think that our view is that there's probably more upside to the downside on the margins if you want to look out in kind of this 3- to 4-year window.
Greg, if I were to think about how that feeds into your timing of a potential second cracker, what are your latest thoughts there?
I think you kind of start with the fundamentals. You still have 500,000, 600,000 barrels a day of ethane and 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 is one 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. We frankly like that spacing in between this project and the next project.
Okay. 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 first quarter. Obviously, you got some of the working capital reversal, and the cash balances built up nicely. How are you thinking about the cash balances now and what you want to prioritize for the rest of the year?
Yeah. $1.9 billion at the end of the second quarter. Obviously, the first quarter, 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, 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'd probably do a bit more debt paydown. Debt's probably running a little bit higher than we'd like it to be. The balance sheet's still strong, still got great credit ratings. We'd like to do a little bit more on debt paydown.
We need some more buybacks too, though, Phil. It's okay.
That's out there as well as a possibility. We've talked about the growth projects and the capital program. 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 four or five years or so, we've been running cash that's been $2 billion to $3 billion, certainly, for a chunk of that time. 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.
Greg, just curious, 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 heavy or the stars aligned right for you guys and will be difficult to repeat it?
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 third quarter from that standpoint. I think that definitely the marketplace has strengths of our portfolio. I think our commercial and supply folks did a really nice job of getting the right crews to the front of the refineries, and the guys in the refineries did a great job of running those crews and creating value. As I look out into third quarter, fourth quarter, I'm still constructive on refining kind of going forward. Whether we can repeat a $1.3 billion quarter or not, I can't forecast that for you today.
Sure.
I do think that refining is going to do well coming into the third quarter.
Since the margin near-term bottom in late June, they are recovering in the last several days that I've 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 into the quarter relatively soft into Q. 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 five-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. The distillate inventories are at the low end or actually below the five-year range on an absolute and days of demand cover basis. Distillate looks really strong.
Yeah. Thank you. All those are great information. I'm just curious that, because typically those is not going to lead to all the sudden for the last several day, a sudden jump. 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 trigger such a-
Well-
-substantial move.
Yeah. There has been some unplanned downtime, some heat-related power issues, but nothing more specific than that.
Can you tell us that how much is the heavy oil you run in the U.S. in the second quarter comparing to the first quarter or the second quarter last year as a %?
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. 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.
Yeah. As you know, we've just recently sanctioned two large midstream projects, at a consolidated level. Obviously, the Gray Oak Pipeline being done at the MLP, but that rolls up into the consolidated number. Year-to-date spend is running lower, just under $900 million year to date. The consolidated budget's $2.3 billion. We are seeing the spend rate pick up, and we would expect that to continue into the second half of the year. At this point, I'd say there's potential that we could go a little bit over the $2.3 billion budget in aggregate. I don't think it would be significantly above that. I would guess at this point would be somewhere between $2.3 billion-$2.5 billion 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 two and a half billion kind of range?
Yeah.
It's going to be higher?
Yeah, I would. I think in overall terms, the $2 billion-$3 billion a year of CapEx is good guidance to go with still.
Two final questions. Quick one. One, do you guys think that we will have sufficient crude export capability in the Gulf Coast if, say, over the next two or three years, we will continue to increase the volume that we need to export by half to 1 million barrel per day a year? Whether that is a business you guys also want to get into more. 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 a potential backlash if what we expect in terms of the rapid rise in the product prices come to materialize? Thank you.
All right. Yeah, 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, as we look at the majority of the large long-haul pipelines, they have got export options. We see export capability being added. We believe most of the incremental production is going to get exported, 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, bunker fuel is a small percentage of total transport demand, but it makes up the vast majority of SO2 emissions. I think there's 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, then taking it down to 0.1% sulfur in the following year. We've seen the IMO focus on inspections on both import and export facilities. We see this moving forward on 01/01/2020. 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. 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 pipeline project, 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 million a day number with pretty little incremental capital from the 800 a day starting point?
We put in 30-inch pipe, that kind of tells you that it's going to be a pretty easy lift to get to the 1 million barrels a day. I think that, look, a lot of interest still in the Permian and takeaway capacity. I think we're pleased at where we're at in terms of project execution. You've got the steel on order essentially, lined up the contractors, the project's really on track. We're pleased at where we're at.
Perfect. Appreciate that. Maybe following up on Phil's question on capital allocation, how should we think about M&A, if at all, in that process? Maybe especially with some of the midstream packages out there today.
I think, we, like everyone else, looks at everything that's out there. Things still 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&A space today. 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.
Great. Thanks, Greg. Appreciate it.
You bet.
Doug Leggate from Bank of America, Merrill Lynch. Please go ahead. Your line is open.
Thanks. Good morning, everybody. Kevin, maybe 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? Is there a level of cash that you want to get back to? I think you kind of suggested you obviously want to build a little bit more cash after the Berkshire buyback and so on. Is there a level of cash you want to get to? 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.
I'd say there's not a target level. There's not a number. Very comfortable with where we are today. I think of when we were $800 million at the end of the first quarter, that's a bit lower than we like to be. You're probably looking at something north of $1.5 billion plus. $1.5 billion-$3 billion is a very comfortable range to be in, not targeting any one particular number on that. In terms of CPChem cash distributions, there is no set schedule on distributions. We've guided to $600 million-$800 million this year. The significant increase from where we have been, 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.
Ideally, a quarterly distribution would be perfect, it doesn't necessarily play out like that. It's somewhat dependent on how the cash balances at CPChem move over month to month. As a board, we kind of work through what the appropriate distributions are going to be. Ratable would be nice, it probably will be not too far off of ratable, it can still be somewhat lumpy there. There was a third one-
Can I just come in on that just a little?
Yeah.
The board can decide what to do at CPChem, the basis of the foundation agreements are we really don't hold a lot of cash at CPChem. We tend to distribute the cash out. Obviously, we want to hold enough cash to do the capital programs or whatever's going on at CPChem. As 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. The principles around the dividend, secure, growing, competitive, and obviously you saw the 14% increase last quarter. 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 billion-$2 billion per year range in normal circumstances. Obviously, this year is a little bit unique with the large transaction we did last quarter. In overall terms, no change.
Thanks. Greg, I wonder if I could just go to my macro question then. I've kind of got two parts to it, if I may. On IMO, there is obviously, you've been, I think if I may phrase it this way, a little more measured in your expectations of how that may play out and the way you've characterized it. We're starting to hear about new refinery or dormant refineries coming back up. Hovensa has been mentioned, St. Croix has been mentioned. I think there's a German refinery is the latest one to be mentioned. I'm just curious as to how you could frame your thoughts as to how much conviction you have on the scale, the potential benefit. My quick bolt-on is to one of the earlier questions on the export issue.
It's a bit of a random one really. Are we comfortable if the export capacity gets built, the bottleneck gets cleared once the pipelines move? I'm assuming there's no trade war ramifications from the potential outlets there. I'll leave it there. Thanks.
I think that we'll start go backwards with the export capacity 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's going to grow faster than what we can consume it here in the U.S. 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. We talked about the Buckeye, but we're also by the end of the year, we're going to have Beaumont going from 600 to 900,000 barrels a day. Think about our export platforms off the U.S. Gulf Coast, we probably got 10 or 12% expansion capabilities played into those over the next 2 years or so.
I think we're trying to position the portfolio to get ready to export more crude and products. On IMO, I suspect that we're familiar with the German one you just mentioned. We shut it down.
Yeah. Oh, right. Well, you can probably speak to the speculation. It was private equity that was speculating, you're not selling.
We're happy with our position there, Doug. Let's put it like that. I think IMO is 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 2 years, it's going to be a nice tailwind for the industry. We can argue about whether it's $5 or $10 on the crack spread or what it's going to be. I do think when you look out over a long enough timeframe, 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.
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 tend to get competed away over time. I just don't fundamentally have a different view on that today.
Just last bolt-on very quickly. All you guys, Joe was the same with Valero, and Gary had 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 in your thoughts?
I just saw that. Yeah.
Yeah.
That certainly is a nice tailwind.
All right.
Yeah, it could be a meaningful impact next year. An ongoing trend to the Venezuela refining utilization and Mexico refining utilization. As we think about IMO, it will likely take some time. There is not a substantial uptick in capital spending that is 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. I think it will be a challenge for the industry, but a challenge we are 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.
Hey, Brad.
Question on the cracker. 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 CapEx to debottleneck in that facility too, that I think that we'll be able to address better with you in the coming quarters. Certainly, the asset came up and ran better than our expectations. Probably, I think it's probably the smoothest startup we've seen in the last five of those big assets that we've started up.
Okay, great. On the new fracs, you guys obviously put out a cost estimate, but no EBITDA number. I would think that the fracs themselves are probably just getting sort of a normal tolling fee, if you will. I know you overbuilt the original one, so I'd imagine the whole system should work better together. Any thoughts on what the EBITDA uplift for across the whole hub is?
Well, on the new fracs themselves, you should expect kind of typical type midstream returns, so let's call it six to eight, and the fracs are probably to the higher end of that. The pipes are probably to the lower end of that. You can kind of back into it.
Okay. Is there any uplift for the existing assets from having the two new fracs installed?
Yeah. There's no question that a large part of the investment for Frac One was in infrastructure pipes to get to Mont Belvieu and back some of the early cavern work that we did. Today off of Frac One, 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. That delta between what we're making and what we're exporting, we're actually bringing from Mont Belvieu. We're buying those barrels in Mont Belvieu today, and we're paying a fee to move them on the pipes. There are going to be synergies and uplifts by making more of the propane at the Sweeney site to be exported.
Okay. Thank you.
You bet.
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 2009 and 2012 had some startup issues. One of your peers who achieved mechanical completion in one queue 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%-80% design rate. You're already hitting 106%. It's pretty impressive. I'm just trying to understand how you did it. What did you guys do so differently that others could not and buck the trend?
Well, hopefully, we learned something over the five 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. It took 8 months to get that cracker up and running from the time that we started up. We had multiple challenges and issues. 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 startup of the facility. I think that really helped. I think that as we watched the construction and we were going to the fabrication sites, we had better quality control this time. We just didn't see the equipment issues starting up this facility.
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 good.
That's it. Great job, guys. Second question is, on the Gulf Coast, it's good to see meaningful contribution for the refining earnings from the Gulf Coast. Can you talk about how Bayou Bridge adds to this positive momentum and the uplift you get once you get the second leg completed?
Well, no, certainly, I think Bayou Bridge 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. We're also looking at running pipe to St. James down to Alliance. Ultimately, we want to connect all of our Louisiana refineries with the Texas Gulf Coast. From a general interest perspective, we think that's good. 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. We got Canadian heavy into Sweeney this quarter, some into Lake Charles. Obviously, Lake Charles benefited by the Maya LLS also. Just things worked well for us in the Gulf Coast this quarter.
Great. Last question is that ethane prices have moved up to $0.35 per gallon. I was wondering if you could talk about how that impacts your entire NGL business. 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've moved up as much as people expected them to at this point in the cycle, given three cracker startups, each needing about 90,000 barrels a day of ethane. 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 positive towards DCP. It doesn't fundamentally change our view on DCP. We like DCP. We like the asset footprint that they have in the Eagle Ford, in the Permian, in the Mid-Continent, particularly in the DJ basin. Good assets for DCP.
Thank you so much, guys.
You bet.
Matthew Blair from Tudor, Pickering Holt, please go ahead. Your line is open.
Hey, good morning, everyone.
Good morning.
Greg, I was wondering, does CPChem have any interest in adding more ethylene derivative capacity? I know you run more of an integrated model here, but we're looking at pretty low ethylene spot prices. If we look out over the next five 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. What kind of interest, if any, would you have in, say, like, a standalone PE unit to take advantage of some of these trends?
Yeah. 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, 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. 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. We like to add integration and be able to participate in that full value chain.
Makes sense. On heavy Canadian, 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. 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.
Yeah
It's right in that range. We're kind of maxed out on Canadian heavy today.
Yeah, about 80% of that is heavy. 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. We at least want to pay back another $1 billion, maybe $ billion and a quarter on the debt we took out for the share buyback in the first quarter. It sounds like there's a vision here of maybe a really nice, call it a two, maybe three-year, kind of one-time-ish, very strong cashflows. The low inventories, but leading into IMO 2020. Of course, the thinking that eventually that'll get worked out by the market. What do you do with a windfall? If you come up with an extra couple billion dollars and you don't think it's repeatable, how do you think about that?
Well, first of all, what a great problem to have. Yeah, I think our fundamental capital allocation strategy, which has served us well for 6 years, really isn't going to change. We think about this 60/40, 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. 40%, we're going to give back to shareholders through a strong, secure, growing dividend and share repurchase, as long as we're trading below intrinsic value on the share purchase side. We continue to look 3 years out, some of the parts, historical multiples, and if that value's higher than the price of the market, we're buying. We're buying today, in the market. I don't think that changes.
Maybe we hold a little higher cash, maybe we pay down a little bit more debt along the way. 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 down some massive project portfolio. You announced Gray Oak and Sweeney Fracs expansions. How much after that do you think we have? As we look into the early 2020s, do you think there's the ability, if the cash flow is materially increased, to take it up to $3 billion-$4 billion in growth CapEx on an annual basis for a couple of years?
Yeah. I just come back. I think the portfolio's going to generate $5 billion-$6 billion of cash. We got $1 billion of sustaining capital. We want to fund another $1 billion-$2 billion of growth, so call it $2 billion-$3 billion of capital. That takes care of that. Got a $1.5 billion dividend today, that leaves room for another $1 billion-$2 billion of share repurchases, and that kind of all balance within our means. 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 4 out there. In the future, there may be more pipe opportunities, more export-oriented opportunities for us as we think about 2020 and beyond.
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 Rosy or me. Thank you.
Thank you, ladies and gentlemen. This concludes today.