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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
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 2 contains our Safe Harbor statement. It is a reminder that we will be making forward-looking statements during the presentation and our Q&A session. Actual results may differ materially from today’s comments. Factors that could cause actual results to differ are included here, as well as in our SEC filings.
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 the – 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 on 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 commitment to 700,000 barrels per day and the reservation of walk-up capacity for shippers.
Gray Oak is expandable to approximately 1 million barrels per day and 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 barrels 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 the 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 terminals 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 its 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 has strong operations from its new Gulf Coast petrochemicals assets, which contributed solid earnings growth during the quarter. Ethane cracker has demonstrated 3.5 billion pounds 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-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.
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, second quarter earnings were $1.3 billion. We have 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 5 compares second quarter and first quarter adjusted earnings by segment. Quarter-over-quarter adjusted earnings increased over $800 million, mainly driven by Refining.
Slide 6 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 Bakken 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 average 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 and $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 7. 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 cost 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 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 global 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 second quarter was $14.86 per barrel, compared to $13.12 per barrel in the first quarter. Our 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 of 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 rent 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 reimaged over 250 domestic marketing sites during the quarter, bringing the total to over 1,700 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. 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. [Operator Instructions]. Neil Mehta from Goldman Sachs, please go ahead. Your line is open.
Hey, thanks.
Good morning.
Good morning, Jeff. Good morning, Greg and Kevin. I appreciate the comments there 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 hey, 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’re modeling the crude capture versus the product capture, if that makes sense, just to have a tendency to have more of the crude discounts drop to the pre-tax margin. But just that, 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% 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 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.
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.
No, that – that’s helpful color. I want to build on that WCS point, because we’ve seen the differentials really widened 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 it – now that project is starting to come back on. We expect additional volumes in August and September. Fort Hills is continuing with its impressive Brent towards 200,000 barrels a day potentially higher.
As we look at maintenance activity, pad two 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 a 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 of 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, Greg.
Roger Read from Wells Fargo. Please go ahead. Your line is open.
Yes. Thank you. Good morning and really great quarter here, I think, we have to say. I would 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 has 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 first quarter. We came up. 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 this 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 just open back up in many cases.
IMOs going to be a nice tailwind, I think, for the industries as we start moving into 2019, particularly the back-half of 2019. And 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 in 2019, we’re pretty constructive on that. I don’t know, Jeff, you want to add anything 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 at coking capacity, which we’re an industry leader there. And so I think, they’ll continue to be focused 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 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, and so you just have to simply work your way within the system as it is?
Well, just a couple of points. I think that even in our second quarter, 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 they ran well above the 100% level coming into it.
The other thing I would say, we’ve come through two heavy turnaround here in 2018 and 2017 for us. And so we’re really, I think, from a portfolio standpoint, turnaround standpoint, well positioned for 2019 and 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 effect 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 stretch – stressed a lot of Latin American refineries fall in that category. We’ll have to see how the product flows just that 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. First question just on the Chemicals. Could you just elaborate a little bit about what kind of contribution you think you saw from the cracker in the second quarter? What kind of start-up costs may have still been incurring? And just kind of try 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 second quarter, 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 a very healthy utilization rates.
I don’t think some of that expenses were anything to really move the needle in the quarter. There may be – 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 into 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, so that was up, we’re up, now ExxonMobil’s coming up. And so near-term, you could have some compression of margins as these volumes are starting to get absorbed in the marketplace.
Offsetting that though – I mean, 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 three to four 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 three to four-year window.
And, Greg, if I were to think about how that seasoned your timing of a potential second cracker and what are your latest thoughts there?
Well, I think, you kind of start with the fundamentals. You still have 500,00, 600,000 barrels a day of ethane rejection, there’s more come in at. So there’s going to 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 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. And we could 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 first quarter. Obviously, you got the – some of the working capital reversal and the cash balances built up nicely. So how do you think about the cash balances now and where you want to prioritize for the rest of the year?
Yes. So $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, so getting cash back to 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 of 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 the debt paydown.
We’ll do some more buybacks, too, Phil. It’s okay.
That’s right there as well as a possibility, and then we 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 four or five years or so, we’ve had been running cash that’s been $2 billion to $3 billion certainly for a chunk of that time. So wouldn’t surprise me if you 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 heavy or the start is not yet right for you guys and would be difficult to repeat it?
Well, I think that we’re set up to run well. And in terms of utilization that we don’t have a lot of big turnaround in front of us coming into the third quarter from that standpoint. I think that the – definitely the marketplace this brings of our portfolio. I think our commercial and supply folks did a really nice job getting the right crews to front, the refineries and then guys in refineries did a great job of running those crews and creating value.
But as I look out into third quarter, fourth quarter, I’m still constructive on refining kind of going forward. So whether we can repeat $1.3 billion quarter or not, I can’t forecast that for you today. But I do think that that Refining is going to do well coming into the third quarter.
Since the margin near-term bottom in May, June, they have been 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 into the quarter relatively soft in 2Q. Since that time, we’ve seen utilization come down. Demands 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. And the distillate inventories are at the low-end or actually below the five-year range on an absolute and days of demand cover basis. So distillate looks totally strong.
Yes, thank you. I mean, all those are great information. I’m just curious that, because typically, those are not going to meet your [indiscernible] for the last several day a sudden jump. So wondering that marketing people have seen any news or anything out there saying that have all of the sudden happened in the last several days that may have triggered such a substantial move?
There has been some unplanned downtime, some heat related power issues, but nothing more broader – more specific than that.
And can you tell us that how much is the heavy oil you’ve run in the U.S. in the second quarter comparing to the first quarter or the second quarter 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 two large Midstream projects at a consolidated level. Obviously, Gray Oak Pipeline being done at the MLP, but that rolls up into the consolidated number. So year-to-date spend’s running lower, so we’re just under $900 million year-to-date, the consolidated budget is $2.3 billion. But we are seeing the spend rate to 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 $2.3 billion budget in aggregate. I don’t think it would be significantly above that. I mean, we – I would guess at this point, it 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 $2.5 billion type of range, or it’s going to be higher?
Yes, I would. I think, in overall terms, the $2 billion to $3 billion a year of CapEx is a good guidance to go with so.
Two final question, quick one. One, do you guys think that we have 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 0.5 million to 1 million barrel per day a year. And whether that 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 – we a high -risk that IMO 2020 end up being pushed out because of a potential 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 a 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 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 to 0.1% sulfur in the following year. We’ve seen the IMO focus on inspections on both the import and export facilities. And so we see this moving forward on 1/1/2020.
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, 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, I 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 million a day number with pretty little incremental capital from the 800 a day starting point?
Well, we’re putting in 30-inch pipes, so that kind of tells you that it’s going to be a pretty easy lift to get to the 1 million barrels a day. So, yes, I think that with lot of interest still in the Permian and takeaway capacity, I think, we’re pleased with where we’re at in terms of project execution. You’ve got the still on order essentially lined up the contractors. And, yes, so the project is really on track. So we’re pleased with where we’re at.
Perfect, I appreciate that. And then 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?
Well, I think, we like everyone else kind of 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. But we’ll continue to watch it if we create value by doing it. We’re certainly willing to do. We’ve got the balance sheet and the capability to do it, if the right opportunity happens to come our way.
Great. Thanks, Greg. I 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 I could, if I could go back to the cash question. You’ve got a nice distribution obviously from CPChem this quarter. I’m just curious those are 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 suggest that you want to 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 million at the end of the first quarter, that’s a bit lower than we’d like to be.
So you’re probably looking at something north of $1.5 billion-plus, $1.5 billion to $3 billion 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 million to $800 million this year. The increase – significant increase from where we have been and it’s driven by a function of higher operating cash flow within 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 a ratable, but it can still be somewhat lumpy there, and those are third one.
Can I just comment on that just a little bit?
Yes.
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. So whatever is 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’ll look at that on a intrinsic value. We’ll look at where the shares are trading relative to our view of intrinsic value. We’ve guided to $1 billion to $2 billion per year range in normal circumstances, obviously this year is a little bit unique with the large transaction we did last quarter, but in overall terms no change.
Greg, I wonder if I could just go to my macro question then, I’ve kind of got two parts if I may. On IMO there was obviously you’ve been, I think if I may phrase it this way, a little more measured than your expectations of how that may payout and where you’ve characterized it, but we’re starting to hear about a new refinery or dormant refineries coming back up. [indiscernible] has been mentioned,[indiscernible] has been mentioned, I think there is a German refineries away this want to be mentioned.
I’m just curious as to how you could frame your thoughts as to how, how much conviction you have on the scale to potential benefits? And my quick bolt-on is to one of the earlier questions on the export issue, it’s bit of a random one really, but are we comfortable if the FDX board capacity gets built, the bottle neck gets cleared once the pipelines move and assuming there is no trade wall ramifications from the potential outlets there, I’ll leave it there, thanks.
Yes, I think that, we’ll start and go backwards, that the S4 capacity is probably – is going to get built, I think the infrastructure to clear all the products or this crude NPLs or gas are going to get built, because it just looks like to us that the production is going to go faster than what we can consume at there in the U.S.
But I think that fundamental permits that we are going to be exporting all three products is a good one and we actually want to participate in that so you know we talked about Buckeye but we are also by the new year we are going to have Beaumont going from 600,000 to 900,000 barrels a day, you know you think about our – kind of our exports platforms off the U.S. gulf coast, we probably get 10% or 12% expansion capabilities late into those, over the next two years or so.
So I think we are 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 familiar with the German one you just mentioned, we shut it down.
Right. I was – well, you can probably speak to the speculation of this private equity was speculating no selling and then.
We are happy with our position there Doug, let’s put it like that. But yes, I think people, I think IMO it’s kind of perceived as a big opportunity to guy 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 that it’s going to be a nice tailwind for the industry, I mean we can argue about whether it is $5 or $10 on the distillate crack of what it’s going to be, but 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. 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, it’s a 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 one, just a bold-on very quickly, I mean like all you guys have Joe was the same like Valero 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 in your thoughts?
Maybe I 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 Dennis utilization. You know as we think about IMO, there is – we’ll 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 are up for.
Thanks everybody, we appreciate your answers.
Brad Heffern with RBC Capital Markets. Please go ahead, your line is open.
Hey good morning everyone. A question on the crackers, so you guys have already demonstrated above nameplate on that, I’m sure that you are 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 asset we’ll get better as we get more and more experience running and you know 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 know 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 startup we’ve seen in the last five of those big assets that we 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 or across the whole hub is?
Well on the new fracs themselves, if you expect kind of typical type midstream returns and so let’s call it 6 to 8 and the facts 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 two new fracs installed?
Yes, yes there’s no, there is no question at all, a large part of the investment for frac one was in infrastructure pipes to get to Bellevue and back to some of the early cabin work that we did, today off of frac one we’re I don’t know 38,000 barrels a day of propane and you we’re running to export facility 200,000 barrels a day and so that delta between what were making and what we’re exporting, we’ll are actually brining it from Mt. Bellevue. And so we are buying those barrels in Bellevue today and we are paying a fee to move them on the pipe. And so there are going to be synergies and uplifts by making more of the propane assets at the swingy side to be exported.
Okay, thank you.
You bet.
Manav Gupta from Credit Suisse, Please go ahead, your line is open.
Hey guys so 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 1Q could not start the cracker for six months, and then run into multiple issues at the start up.
Your ethylene cracker has had one of the smoothest starts we have witnessed in the last decade. Most ethylene crackers achieved 70% to 80% design rate, you are already hitting on [indiscernible]. So it’s pretty impressive I’m just trying to understand how you didn’t, like what did you guys do so differently that others could not and bucked the trend?
Well hopefully we learn something over the five times and we are one of the parties that started up and had trouble in the Middle East, I think our last outing our Saudi Polymers project and it took eight 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, you know all the way to construction the startup of the facility.
I think that that, they’re really help, I think as we watch the construction and we were going to the fabrications 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 disappointing with that, the overall quality of this construction was very, very good.
That’s a great job guys. And the 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 Bayou Bridge adds to this positive momentum and the uplift you get once you get the second leg completed?
Well, no, sorry I think Bayou Bridge is an important asset for us and we are running you know 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 a $1 a barrel or something like that you know 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 the 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 Sweeny this quarter, some into Lake Charles. Obviously, Lake Charles benefited by the Maya, LLS also. And so just things work its – worked well for us in the Gulf Coast this quarter.
Great. And the 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’ve 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 prices 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 that they have in the Eagle Ford, in the Permian, on the Midcontinent, particularly in the DJ basin, so 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. And if we look out over the next five years or so, we definitely see a lot more cracker capacity coming online than derivative capacity. I’m 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. I – look, I – 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 stay in that full value chain.
Makes sense. And then on heavy Canadian, so Enbridge made some progress on their Line 3 replacement recently. I don’t think Phillips is much of a shipper on Enbridge. But regardless, we 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, if you’ve got the exact number…
Yes.
…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 a great quarter.
Thank you.
I understand nothing has really changed in terms of capital allocation and we, at least, want to pay back another $1 billion, maybe $1.25 billion the debt we took out for the share buyback in the first quarter. But it sounds like there’s a vision here of maybe a really nice, call it, two, maybe three-year kind of one-time-ish very strong cash flows on the low inventories, but leading into IMO 202. And, of course, the thinking that eventually that will get worked up by the market. But what do you do with a windfall? I mean, if you come up with an extra couple billion dollars and you don’t think it’s repeatable, how do you think about that?
Look, I – well, first of all, what a great problem to have. And – but I think, our fundamental capital allocation strategy, which has served as well for six years really isn’t going to change. We kind of 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. And then 40%, we’re going to give back to shareholders through a strong, secure growing dividend and share repurchases as long as long we’re trading below intrinsic value on the share purchase side.
So, we continue look three years out, sum of the parts, historical multiples. And if that value is higher than the price of the market, we’re buying. So we’re buying today in the market. So, I don’t think that fundamental change – that changes. Maybe would 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 work down 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 2020, do you think there’s the ability if the cash flows materially increase to take up to $3 billion to $4 billion in growth CapEx on an annual basis for a couple of years?
So I’ll just come back. I think the portfolio is going to generate $5 billion to $6 billion of cash. We’ve got $1 billion of sustaining capital. We want to fund kind of another $1 billion to $2 billion of growth, so call it, $2 billion to $3 billion of capital. So that takes care of that. We’ve got $1.5 billion dividend today and that leaves room for another $1 billion to $2 billion of share repurchases and that kind of all balanced within our means.
And so I think that you 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. So I think we’ve got a good run in front of us in terms of just the opportunities 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’s conference. You may now disconnect.