Phillips 66
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Phillips 66
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Welcome to the Fourth 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 the Phillips 66 fourth quarter earnings conference call. Participants on today's call will include Greg Garland, Chairman and CEO; and Kevin Mitchell, Executive Vice President and CFO.
The presentation material we will be using during the call can be found on the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information. Slide 2 contains our Safe Harbor statement. It's a reminder that we will be making forward-looking statements during the presentation and our Q&A. Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here, as well as in our SEC filings.
In order to allow everyone the opportunity to ask a question, we ask that you limit yourself to one question and one follow-up. If you have additional questions, we ask that you rejoin the queue.
With that, I'll turn the call over to Greg Garland for opening remarks.
Thanks, Jeff. Good morning, everyone, and thank you for joining us today. Phillips 66 delivered another quarter of strong operating performance and record setting financial results for 2018.
Adjusted earnings for the fourth quarter were a record $2.3 billion or $4.87 per share, and we generated $4.1 billion of operating cash flow. We reordered our shareholders with strongest revisions during the quarter returning $864 million through dividends and share purchases. Refining operated 99% capacity utilization and we towards [ph] heavy Canadian crude and other bandage [ph] crudes throughout our refining system to capture strong margins.
In midstream, we benefited from increased pipeline and terminal throughput across our integrated network. For the year, adjusted earnings were $5.6 billion or $11.71 per share. We generated $7.6 billion of operating cash flow. The record financial performance in 2018 demonstrates our refining portfolios ability to run well and capture market opportunities. Marketing provided pull-through of our refined products to keep record adjusted earnings, also contributing to our strong results for the midstream and chemicals growth projects which were placed in the service during the past two years. In 2018 we increased the quarterly dividend 14%, and repurchased 10% of the shares outstanding resulting in $6.1 billion of capital being returned to our $2.5 billion to shareholders through dividends, share repurchases and exchanges reducing our initial shares outstanding by 30%.
Disciplined capital allocation is a priority, and we're committed to a secure competitive and growing dividend. As we look to 2019, we expect to deliver another double-digit dividend increase. Through our ongoing share repurchase program we continue to buy shares when they trade below intrinsic value as demonstrated by our fourth quarter pace of repurchases.
Phillips 66 Partners achieved it's 5-year 30% CAGR target. It also delivered industry-leading distribution growth since it's IPO in 2013. With it's scale, financial strength and project opportunities PSXP is well positioned to fund and sustain organic program to continue to drive EBITDA growth. We're investing in a robust portfolio projects across our businesses with attractive returns to create shareholder value. The Grey Oak pipeline will provide 900,000 barrels a day of crude oil transportation from the Permian and the Eagle Ford to Texas Gulf Coast destinations, including our Sweeney refinery. The project is supported by shipper commitments, and is on-schedule to be in service by the end of this year. Phillips 66 Partners is the operator and the largest owner.
Grey Oak will connect with multiple terminals in Corpus Christi, including the South Texas Gateway Terminal in which PSXP has a 25% ownership. The Marine Terminal will have two deepwater docks, planned storage capacity of 6.5 million to 7 million barrels, and is expected to start-up at mid-2020. At the Sweeny hub, we're building two 150,000 barrel per day NGL fractionators, and adding 6 million barrels of storage at Philip 66 Partners Clements Caverns. The hub will have 400,000 barrels per day of fractionation capacity and 15 million barrels of storage when the expansion is completed in late 2020. We continue to have strong interest from customers in additional fractionation expansion projects.
The growth in domestic crude production is expected to result in an increased need for Gulf Coast exports; we're making investments at our Beaumont Terminal to capitalize on this opportunity. During the fourth quarter, we placed 1.3 million barrels of fully contracted new crude oil storage into service; this brings the terminals total capacity to 14.6 million barrels. Construction is underway to further increase crude storage by 2.2 million barrels with completion anticipated in early 2020. DCP Midstream has a 25% interest in the Gulf Coast Express pipeline project that will transport approximately 2 billion cubic feet per day of natural gas from the Permian to Gulf Coast markets. Completion is expected in the fourth quarter of 2019. In the high growth DJ Basin, DCPs O'Connor 2 plant is expected to begin operations in the second quarter of 2019.
CPChem's new Gulf Coast petrochemical assets are running well and generating strong free cash flow. A second Gulf Coast project is expected to include both ethylene and derivative capacity is under development. CPChem is also evaluating additional capacity increases across multiple product lines through debottlenecked opportunities. At refining, we continue to focus on high return projects to improve margins. We have an FCC upgrade project underway at Sweeny refinery that will increase production of higher valued petrochemical products and higher octane gasoline; this project is planned -- during the fourth quarter, we completed crude unit modifications at our Lake Charles Refinery to run additional advantage domestic crudes. Also at Lake Charles Phillips 66 Partners is constructing a 25,000 barrel per day isomer [ph] unit to increase production of higher octane gasoline 1 components; this unit is expected to be completed in the third quarter of this year.
As we move into 2019 we remained focus on operating excellence and executing our strong portfolio growth projects. We're optimistic about the future opportunities across our businesses, and will investment in projects with attractive return back [ph].
So with that, I'll turn the call over to Kevin to view the financials.
Thank you, Greg, hello everyone. Starting with an overview on Slide 4, we summarize our financial results for the year. 2018 adjusted earnings were $5.6 billion or $11.71 per share. We generated $7.6 billion of operating $9 billion in distributions from equity affiliates, with approximately $1 billion each from CPChem and WRB. This is the highest annual earnings and operating cash flow we have delivered since our company's inception. At the end of the fourth quarter the net debt to capital ratio was 23%, our return on capital employed for the year was 17%.
Slide 5 shows the change in cash during the year. We began the year with $3.1 billion in cash on our balance sheet. Cash from operations excluding the impact of working capital was $7.9 billion. Working capital changes reduced cash flow by $300 million. During the year we funded $2.6 billion of capital expenditures and investments, paid dividends of $1.4 billion and repurchased $4.7 billion of our shares representing 10% of shares outstanding. Our ending cash balance was $3 billion.
Slide 6 summarizes our fourth quarter results. Adjusted earnings were $2.3 billion and adjusted earnings per share was $4.87. We generated operating cash flow of $4.1 billion, including distributions from equity affiliates of $840 million. Capital spending for the quarter was approximately $1 billion with $648 million spent on growth projects. We returned $864 million to shareholders through $367 million of dividends and $497 million of share repurchases. We ended the year with 456 million shares outstanding.
Moving to Slide 7. As I mentioned on last quarter's call, we have changed our segment reporting to a pretax basis. Income taxes are reflected at the consolidated company level, this change makes our segment reporting more comparable with our peers. This slide highlights the change in pretax income by segment from the third quarter to the fourth quarter. Quarter-over-quarter adjusted earnings increased $804 million driven by higher results in refining, marketing and midstream, partially offset by lower chemicals results. The fourth quarter adjusted effective tax rate was 21%.
Slide 8 shows our midstream results. Fourth quarter adjusted pretax full year adjusted pretax income was a record $1.2 billion, more than $600 million higher than the prior year. Transportation adjusted pretax income for the fourth quarter was two on [ph] both, our joint venture and wholly-owned assets. Our operated pipelines benefited from strong utilization at our refineries. In addition, fourth quarter throughput on the Bakken pipeline increased barrels per day. NGL and other adjusted pretax income was $122 million, an increase of $48 million primarily from inventory impacts. We continue to run well at the Sweeny hub, during the quarter the export facility averaged 10 cargos a month, and the fractionator averaged 116% utilization. Pretax income of $53 million in the fourth quarter is up $24 million from the previous quarter, primarily due to improved hedging results partially offset by higher operating costs.
During the fourth quarter, DCP completed the expansion of the Sand Hills pipeline capacity to 485,000 barrels per day. Sand Hills is owned two-thirds by DCP and one-third by Phillips 66 Partners.
Turning to Chemicals on Slide 9; fourth quarter adjusted pretax income for the segment was $152 million, $111 million lower than the third quarter. Olefins and polyolefins adjusted pretax income was $158 million, down $67 million from the previous quarter. The decrease reflects seasonally lower polyethylene sales volumes and higher turnaround and maintenance costs. Global O&P utilization was 95% in the fourth quarter, adjusted pretax income from CPChem's equity affiliates and higher domestic turnaround costs. The $9 million decrease and other reflects the fourth quarter increase of a contingent liability, and the gain on an asset sale in third quarter. During the fourth quarter we received $300 million of cash distributions from CPChem.
Crude utilization was 99% compared with 93% in the third quarter. The fourth quarter clean product yield was 86% and pretax turnaround costs were $130 million, moving [ph] $5 million from the previous quarter. The market crack declined 36% from the previous quarter, realized margin was $16.53 per barrel, 24% higher than the third quarter.
The chart on Slide 10 provides a reasonable view of the change in adjusted pretax income which increased $745 million, primarily from strong results in the central corridor and Gulf Coast regions. For the full year, refining generated adjusted pretax income of $4.6 billion. The Atlantic basin results increased as the Bayway Refinery return to normal operations following third quarter downtime. Gulf Coast adjusted pretax income of 468 [ph] product realizations improved heavy Canadian crude differentials, and increased volumes at the Alliance Refinery following third quarter downtime. The higher clean product realizations benefited from declining market prices.
Capacity utilization in the Gulf Coast region was 100%. Adjusted pretax income in the central corridor was $1.2 billion, an increase of $342 million reflecting expanded discounts on Canadian crudes. Capacity utilization in the central corridor with 106%. In the West Coast, the increase was mainly due to higher realized margins driven by widening crude differentials partially offset by higher turnaround costs.
Slide 11 covers market capture. The 3:2:1 market crack for the fourth quarter was $9.11 per barrel compared with $14.21 in the third quarter. The realized margin was $16.53 per barrel, and resulted in an overall market capture of 181%. Market capture was impacted by the configuration of our refineries. We made less gasoline and more distillate than premised in the 3:2:1 market crack. The gasoline crack spread declined by $8.75 per barrel during the quarter, while the distillate crack improved by $2.20 per barrel. Losses from secondary products of $0.29 per barrel were improved $1.33 per barrel from the previous quarter due to the decline in crude oil prices relative to NGL, fuel oil and coke.
Advantage feedstock improved realized margins by $3.79 per barrel, an improvement of $1.29 per barrel from the prior quarter, primarily due to widening Canadian crude differentials. The other category improved realized margins by $3.57 per barrel, primarily due to optimization across our NIST logistics network to capture market opportunities associated with widening crude differentials. Realize margins were further improved by Gulf Coast clean product price realizations.
Moving to Marketing & Specialties on Slide 12; adjusted fourth quarter pretax income was a record $592 million, $207 million higher than the third quarter. Marketing and other increased $205 million from improved margins associated with sharply falling spot prices. Refined product exports in the fourth quarter were a record 249,000 barrels per day. We reimaged 466 domestic branded sites during the fourth quarter bringing the total to approximately 2,600 since the start of our program. For 2019, an additional 1,800 sites are scheduled for reimaging. Specialties adjusted pretax income increased $2 million during the quarter, primarily due to higher lubricants margins.
On Slide 13, the corporate and other segment had adjusted pretax cost of $201 million, improved $22 million from the prior quarter. Lower net interest expense was due to interest income on a higher and corporate overhead cost decrease which is due to employee severance costs recognized in the third quarter. This concludes my review of the financial and operating results.
Next, I'll cover a few outlook items for the first right to be in the mid-80s and pretax expenses to be between $140 million and $170 million. We anticipate first quarter corporate and other costs to come in between $210 million and $240 million pretax. For 2019, we plan full year turnaround expenses to be between $550 million and $600 million pretax. We expect corporate and other costs to be in the range of $850 million to $900 million pretax for the year. We anticipate full year D&A of about $1.4 billion. And finally, we expect the effective income tax rate to be in the low 20's.
With that, we'll now open the line for questions.
[Operator Instructions] Phil Gresh from JPMorgan.
Hi, and congratulations on a solid quarter here. Greg, I guess the first question here would be if you look back at 2018, I mean this is the third straight quarter where you single-handedly beaten the consensus expectations, seems to be driven by different parts of the portfolio obviously refining's been strong but given other parts of the portfolio have been very strong as well; so how do you think about reforming this year? Do you see some kind of sustainable structural improvement going on at Phillips that's under-appreciated or is this just either keeping control of the sell side there?
You guys are doing a great job, Phil. So look I think that there's no question the market environment we find ourselves is playing to the strength of our portfolio and it's two things; it's just right in differentials, and so no question, the fourth quarter -- the WCS that differential drove a lot of the value creation. We improved our distillate yield, we're up another 1% in the fourth quarter, so 39% distillate yield. So versus our peers were at the high-end of the range on distillate, and given our coking capacity and our ability to run heavy, it's differential. The other thing I would just say is, we've got these chemicals assets that are up, they're running, they're performing well; that's going to continue to drive earnings improvement versus mid cycle for us. Then you think about our midstream business starting to kick in, we actually made more in midstream than we made in chemicals in 2018. So across the portfolio, the things we've been investing are starting to show up and deliver value.
And then finally, we continue to run really well. Operational excellence is key for us, we continue to emphasize that in the quarter where we needed to run well. We ran 106% utilization on the central quarter, we ran 100% on the Gulf Coast and it showed up as value. So Jeff, are you having comments on other structural changes?
Yes, I'm thinking about $1.5 billion of EBITDA and incremental projects added across kind of evenly distributed between chemicals midstream and refining that's improved our overall cash flow from operations and in a normalized environment.
Yes, I would quite say -- given the kind of normalized mid-cycle we used to say $4 billion to $5 billion, we're kind of $6 billion to $7 billion now of cash flow on a normalized basis.
I guess the second question just looking at the guidance for the first quarter, the mid-utilization or refining and the turnaround cost there. Would you say that the entire impact on utilization is the turnarounds or are you seeing an environment here for yourselves and for the industry that is warranting some run cuts here in the first quarter?
Most of that guidance is centered around turnaround activity. We've pulled a few things maybe from the back half of the year into the front half year where we could making sure that we can run in the back half but that's around the margins Phil, there wasn't a lot of work there. So it's mostly focused around our turnaround activity.
Last one, just for Kevin. How do you feel about the balance sheet levels here? Obviously, earlier in the year you issued some debt to buyback, some shares; finishing the year you're really strong on cash flow, clearly. So how do you feel about desires to pay down debt from here?
So, we feel pretty good about where we got to. In fact, we basically -- we replenished the cash from where we had been with the strong third and fourth quarter this year. So $3 billion of cash, debt to cap is at 29% on a fully consolidated basis, 23% net of cash, so we feel good on that. We have some that's available for pay down, but we'll look at that in the overall context of -- how the start of the year shakes out. We'll have a little bit of a turnaround on working capital that's typically a use of cash in the first quarter, and so we'd expect to see that happen as it typically does. But the nice thing is we'll have the flexibility to work through; so if we have weak margins for any kind of extended period, we have the flexibility to continue to work through that and fund all of our obligations.
Doug Terreson with Evercore ISI.
Good morning, everybody. Does your 17% return on capital employed and your 10% reduction in shares outstanding are the best in the U.S. energy industry. So kudos to the team on exceptional results, that's really good work there. My question is on your outlook for the key businesses. And starting with refining, with margins on variable cost for conversion capacity unusually low, do you think that utilization is going to decline for some of these processes or because weakness is often seasonal this time of the year, is throughput going to remain high. So the question is, how are you guys thinking about managing conversion utilization given these circumstances? And also, how do you think it plays out across the industry?
So, I'll take a stab and Jeff can correct me. How about that? Look, I think that everyone is concerned about the high gasoline inventories at this point in the cycle, there's no question the fourth quarter. The market environment was encouraging due to run, given the diesel cracks that we had and gasoline cracks weren't that great but we're heading into the spring turnaround season, there are some operational issues out there; so our assessment is we're probably a little above normal in terms of outages for this time of year. When you get to the top in butane and gasoline, it comes out to the gasoline pool; that's all directionally helpful for gasoline. We're still constructing overall demand; we think gasoline demand in North America is going to be flat for 2019. We'd see this will end up 1% to 1.3% in that range. When you add on IMO, and I know there is a debate about IMO and that but it's still going to be some level of tailwind; so as we look at 2019 for the year, we're still mid-cycle or better in terms of refining cracks, Doug.
Go ahead, Doug
Well, I was just going to ask a question about chemicals and specifically, you guys are at strength capacity in the last couple of years and same position for more spending in the area based on Greg's comments today. So I just want to get an update on your construct view on chemicals which is a little bit more constructive than some and so basis the increased investment that area; why are you guys optimistic for chemicals?
First of all, you think about growing global economy and albeit '19 is probably a lower growth year than what '18 is globally. But we're still constructive of demand, particularly for polyethylene which is mostly what CPChem makes. In our view, demand is going to grow faster than capacity in 2019, so it should be constructive for operating rates and margins in 2019. Then you look at all that advantage feedstock are still available in the U.S. again, so that really says you should build into that. If you have a great position which CPChem does, access to advantage feedstock, great technology, great return of business. And so it's a business that we should want to invest into.
Polyethylene grew by 6% last year, substantially above GDP growth. We did have some weakness in the fourth quarter. We experienced a typical seasonal softness in demand but it was a compounded by 35% decline in crude prices. As we started the year, margins were soft but the crude prices have rebounded and CPChem seeing signs of demand improvement. Healthy demand is expected to drive some polyethylene price increases in the first quarter.
Neil Mehta from Goldman Sachs.
Good morning team and I'll add my congratulations on a good quarter here. The kickoff question for me is on Western Canadian crude differentials which have obviously were big tailwind 4Q and ever first here in one 1Q. Our view is that ultimately will settle out towards transportation economics which is wider than here but just your latest thoughts on how this plays out in 2019 and then longer term is there still a lot of uncertainty around the pipe and how you're just adjusting your business to take advantage of that?
We've gone from an unsustainably wide discount for Canadian heavy to unsustainably narrow discount. We believe with the mandated cuts, there were substantially more volume that came off the market than what the $325 targeted amount was. We also had some economic run reductions -- production reductions and so we're running well below what the producing capacity is in Canada. We do expect similar to your comments to move to rail economics as this passes. I think a number of the Canadian producers have argued for moving away from the mandates and so we expect the differentials to go back to kind of rail economics WTI minus 20 something in that area.
That's helpful and then the follow up to something a little more specific. Slide 11 of your deck on refining margins. Kevin you walk through configuration of the stock that made a lot of sense. The other number felt bigger than normal $3.57 and that is a big part of the strength in the realized market to talk about what that is a little bit more detail and how should we think about that is that just a function of crude prices coming down precipitously or can we carry any of that forward?
So you're probably on to that Neil, it does cover there are a variety of things in that other category but the big drivers for why that's a positive of $3 plus per barrel, you know the overall declining market helped on the product price realizations. And then the other is just on the crude side, the crude differential side being able to optimize how we're moving barrels around our network to capture opportunities as they were available which in that kind of market environment we saw in the fourth quarter so it lends itself to us being able to do that. So you think about both of those are not really -- it was good to have in the fourth quarter, good that we could capture it but not something you would assume is rateable [ph].
Blake Fernandez with Piper Jaffray.
Good morning and congrats as well on the strong print there. I know you covered chemicals already but in the release, you talked a little bit about some potential de-bottlenecking and I was hoping you could maybe elaborate a little bit on that. I'm assuming that's totally separate from a potential second cracker. Just trying to get a sense of how significant that could be and maybe time -- timing around that?
Yes, Blake, its Kevin. In terms of the de-bottleneck opportunities, I -- those are not of anything like the scale of the next major expansion -- major project second cracker project. These are what I would consider to be in a portfolio like CPChem has. We're always able to identify opportunities for incremental investment to drive incremental production and usually very strong returns on those investments. So I don't think we look at any one of those as significantly large but they typically scream pretty high to the list of priorities for investment because by nature of them being incremental to the existing portfolio usually very attractive returns.
Gulf Coast Project was like 33% capacity increase I mean, the debottleneck is typically on the order of 5%, maybe 10%. Like and but it's not across all the products we have very specific places where we think we can get to more capacity out of the derivatives and actually some of the F1 units too. But there are certainly workers doing when you look at the returns.
Yes, got it. The second one really is just on the I guess is focused on moving toward light sweet given the compression and heavy differentials in the market so maybe if you could just give an update on where you are in your system as far as ability to flex back and forth between light sweet and then I guess while we're on it may be the same with the distillate gasoline you know if you're at max distillate mode at this point?
Yes, we have shifted given the economics in the marketplace, they've really driven a move towards maxing diesel, and so we're there, we've been there and so we're making about as much diesel as we can, given the current economics. Similar on the light products side, we're about 50% sweet and 50% sour, that's about a million barrels a day or so of sweet crude; there is a potential to go maybe another 100,000 barrels a day, it's obviously dependent on economics, we need the economic incentives to do that but that's what our upside potential is there.
Roger Read with Wells Fargo.
Thanks, good morning. I guess, maybe we could talk a little bit about the midstream segment, obviously, highlight Grey Oak and so forth, but as I think about the performance in the quarter looking in the '19 and '20 in an EMP industry that seems to be slowing it's spending a little bit, may be slowing production. How does that environment compare to the baseline that you've laid out in terms of your expectation for future pipeline investments? And I guess, NGL fractionation etcetera as you think about what may get the trigger pulled on it in '19 or '20? And I guess really at the heart of it I'm trying to understand what may be the growth prospects are for -- at least the transportation in NGL side of the midstream as we look over the next year too?
So let's start with -- we're just not going to build speculative capacity, Roger. I think the midstream projects we have in the queue are subscribed with P&D and long-term contracts, these are 7-year and 10-year contracts with good counterparts on the other side. So I think that's a starting point. I think you're right, the extent that the drill bit slows down to North America, some of these additional investments will slow down. Then we can get these things subscribed, we're not going to build them; it's probably the starting point on that. Grey Oak, fully subscribed; frac 2 and 3, fully subscribed; but it's interesting, we're still seeing good interest in additional frac capacity. We're out in open seasons and Red Oak and Liberty -- and I'd say interest levels good on those, we'll see -- well, I don't know exactly where we'll end up yet when people want to sign. We just completed successful open season on Dapple [ph], now going to 570.
So we're still seeing good interest level out there from the producers and investing in or having infrastructure to clear from the production centers to the market centers. Jeff, you want to comment?
Yes. There is still substantial resource available, and with new infrastructure coming the potential that activity resumes -- we're looking at NGL production growth that's been around 500,000 barrels a day year-on-year, we're not adding that type of capacity in '19. And so as production continues to grow the need for infrastructure will continue, the challenge is matching the timing with production growth and infrastructure structure growth; and so that's what getting projects fully contracted attempts to do.
And then shifting gears back to refining; Greg, you mentioned kind of a mid-cycle or better assumption on margins for refining in '19. Seems that on a macro front we get more concerns raised by investors that globally new capacity coming online will be faster than demand growth; not asking you to forecast demand growth as too tough for any of us. But as you think about the new capacity coming online, how much of that do you think is really aimed at the transportation market versus what is normally aimed at the petrochemical side in terms of feedstock?
Yes. So we have a couple in China, one in the Middle East coming on in 2019. The transparency into China is probably a little harder for us, our view is that those two refineries are probably more petrochemical feedstock oriented and less gasoline oriented. So, and we think that they're probably towards the back half of 2019; so yes, there is capacity that's going to come on this year but I'm not sure it's going to be as a bigger impact particularly through the first half of the year is what some people think.
Jeff, you want to comment?
Yes, I think on the Chinese side it's petrochemical focused as Greg mentioned but with the low diesel yields as well.
Paul Sankey from Mizuho.
Greg, you made some interesting comments recently to us about China demand keeping on with the general demand picture. Your sales I think has held up pretty well. Could you expand on what you were saying about the global market petrochemicals? So you also -- as you may know had Exxon saying that there is weakness because of the excess capacity which I think you've already referred to earlier on this call, all other shipped in new capacity. Could you just talk a little bit about how the market could be clearing, and particular the market so concerned about China, anything you could add on that would be interesting. Thanks.
Yes, absolutely. Thanks, Paul. First of all, we're still constructive of petrochemical demand coming into 2019, still driven by hundreds of millions/billions of people ultimately coming in the middle class over the next decade or so; so I think the fundamentals are set up well there. China, I mean interesting when you see crude prices fall as drastically as they did in the fourth quarter, they always slowdown because they know that petrochemical prices are going to follow those down in a way to try to time the bottom and start buying again. So we did probably see some slowdown activity in the fourth quarter around China but as we look into China through -- into the base demand in China, it's still pretty healthy. I'd say North American demand, European demand still relatively healthy in terms of growth, and so I think that's been the surprise to the upside in the chemicals environment.
So still constructive, I think I would say is that our fundamental view on 2019 for chemicals is that demand on chemicals is going to grow faster than capacity additions; and the other thing is, we may see some slippage on these other projects that are slated to come up in 2019.
And then the follow-up is pretty large drastic question but it's related to your cash return versus CapEx framework which is 60:40 as we now know at the moment. I was wondering of what timeframe and for reasons that might shift given the scale of the company, for example, is getting so large? Thanks.
If you think about 12 to 18 and consider our investments in equity affiliate, we're right on top of the 60:40; 60% reinvested back into our company and 40% back to shareholders to secure growing competitive dividend and share repurchases and exchanges. In 2018, we were 60:40, it was just the other way, we were 60% distributions and 40% investment banking and core business. But I think Paul, as I think kind of over a 3-year horizon, in the mid-term; most of our projects that we're investing in midstream refinery, we kind of have 2-year horizons on them. The chemicals projects tended to go into a 3 to 4-year horizon on them but if I want to think about a 3-year horizon, I still think 60:40 is about the right place for us to be.
Paul Cheng from Barclays.
Couple of quick questions. Greg, you talked about China; can you talk about Mexico that where do you see on the expanded market there? That with -- I mean, we have heard early in the year that some widespread fell salty; that's an issue of founder impact in your spot volume [ph]. And have you seen any change in the trend? That's the first question. The second question is on the crude difference [ph]; Exxon have said that in the fourth quarter versus the year before fourth quarter there, crude depends upon the fee -- it is about $1.2 billion, half the tax. And matter of fact, if you look at the chart, it looks like it's about $1.6 billion, I'm wondering that is a number that you can share?
I'll take the Mexico question. We are seeing some impact on exports to Mexico as their demand has gone down with the pipeline shutdowns. Mexico demand is about 800,000 barrels a day gasoline, and about 350,000 barrels a day of diesel. They import about 75% of that from the U.S., at least in 2018. As you know refining utilization averaged about 38% last year and we're expecting it to go down lower from this year. We have seen some impact on exports into Mexico and those volumes are down, we're seeing some signs of movement into some of the interior but some of that demand is going to be lost permanently, and as they're able to get product back into the central country, that will resume their imports but we are seeing that down somewhat.
Jeff, have you seen any sign -- the export to Mexico has start to recover or only increasing?
Yes, we have seen a little bit of relief recently but it's probably going to be an area we don't have a lot of transparency in as they try to recover from these pipeline outages.
And how about the crude differential?
On your first question, when you look at WCF-TI, kind of year-over-year '17 versus '18, it's about $13. And $1 is about $100 million, so on an EBITDA basis, it's $1.3 billion.
Doug Leggate from Bank of America Merrill Lynch.
This is Clay [ph] on for Doug, thanks for taking the question. So my first is on -- it's a follow-up to Phil's question about the use of cash. Just wondering whether balance is reloaded, does this affirm the high-end of your $1 billion to $2 billion buyback target for 2019?
I think it will guide to the range of $1 billion to $2 billion.
My second question is a follow-up to Neil's question. Just on the WCF differential, the Alberta cuts have worked but perhaps they work too well since the dip is now out of the money as it relates to rail. So my question is, do you see a sharp slowdown in rail? And do you think that this could be a catalyst for a sharp widening of the dips; maybe not to October levels but towards that direction?
Yes, we are seeing a reduced utilization of rail as we come into February. I believe some of the Canadian producers that ship by rail have acknowledged reduction. Those economics are closed, their arms closed, and the marketplace is starting to react.
It's interesting, it looks like to us that we've pulled inventories which was the whole idea of the government intervention, and we've overshot on the differential and it looks like to us inventories are starting to build again in Canada. So I think that we will get back to the point where we have a differential, at least clear by rail, and so -- you think about a fully loaded rail cost kind of $18 to $20 a barrel, you look at variable cost is probably $15 to $16. So I think we'll get to a variable cost and then we'll move to variable cost as the year goes on.
Prashant Rao with Citigroup.
My first sort of startles [ph] midstream and refining a bit. I'm thinking about storage capacity and needs, particularly in the Gulf Coast and through logistics needs and opportunities over the next couple of years. I sort of see at least two windows here; one being IMO. I'm thinking about a longer hydrocarbon chains here, in particular, medium to longer hydrocarbon chains. One is IMO, we were expecting storage needs for fuel oil, storage needs for different sorts of distillate, changes in crude trade wins and dynamics. And the second being the wave of barrels that we expect to hit the Gulf Coast for export as we get towards 2020-2021; I'm curious to know sort of your thoughts on how the existing infrastructure -- where it stands in terms of capacity to handle the demand that will be there along these various lanes? And so where is the opportunity for Phillips since you've invested in projects that are or through the value chain I have figured you might have a view into sort of where the best sort of incremental opportunities are; how things play off against each other?
Yes. So we do expect the growing production to largely be export as the pipelines are announced, most of the major pipelines have associated export terminals tied with them similar to our Grey Oak in South Texas Gateway Terminal. We've got export capacity out of Beaumont, and we're continuing to build out that facility. We've got LPG export capability out of Sweeny, and as more and more fractionation comes online, a lot of that LPG is going to be -- need to be exported. And so we do see those opportunities across many of our value chains.
Manav Gupta with Credit Suisse.
Can you talk about the benefits of Bayou Bridge on your Gulf Coast refining system and the actual startup date?
So Bayou Bridge, we have expectations for it to start up in March and provide service into St. James. Bayou Bridge also provides service from Beaumont into Lake Charles and our Lake Charles Refinery. At Lake Charles, we've had projects there to increase our ability to use discounted domestic crudes and so we're benefiting there from the Bayou Bridge access to crudes. And then the Bayou Bridge, Lake Charles, the St. James provides opportunity for East pipeline, which is in open season and that open season is continuing with strong interest and hopefully we'll have more to report on that in the near future.
And a quick follow-up; Jeff, two areas where you first feel a recession coming is polyethylene demand and distillate demand. Demand softness is one thing, but you're very close to both those end markets. Is there any sign in any of those two markets that we are probably approaching recession?
Yes, I think Greg covered the polyethylene side of the equation and perhaps more information there, but when we look at diesel, demand is very strong. Tonnage up 8% year-on-year, most recent information. Global airline revenue miles up 6% year-on-year. We're continuing to see strong diesel demand in the markets in which we participate. So we don't see any signs as of this point.
Chris Sighinolfi with Jefferies.
Thanks for taking my questions. I have two and they both relate to Marketing and Specialties. I guess, first, very strong results here in the fourth quarter. And if I look at how things performed versus our expectations and history, it appears international fuel margins were particularly bright spot. So I'm wondering with a near double -- it's almost a doubling of the foreign margin quarter-on-quarter, I believe it's the second consecutive record for you on fuel margins there. Just wanted to check kind of about any particular drivers of that? And if anything structural, is it for it that you've cautioned us to pay attention to?
I'd maybe start with -- in Europe, our markets are focused around Germany, Austria, Switzerland and the UK. In Germany, we had low water levels at the Rhine and that presented some logistical challenges and we were able to use our infrastructure and logistic systems to capture some of the opportunity in advantaged. As you know, we're kind of reimaging, rebuilding about 30 new JET sites a year in Europe and so we're seeing some increased uplift from that. So that's a piece, it's -- I don't know if it's structural or not, but it's certainly added [ph]. And then we're moving into UK doing some similar work in the UK around the JET brand in the UK. So combination of a logistical opportunity created in the fourth quarter and just some good nice growth opportunities.
And I would just add on that. The overall environment, the falling price environment had the benefit you would expect to see in those markets as well, like we saw in the US.
And I guess, secondly you've continued to execute that reimaging effort on the branded sites, here you noted in the release I think roughly 2% same-store sales growth figure for the reimaged sites last year. And I'm just curious, how that would compare to sites that have yet to be reimaged?
I think the 2% is a really good number and it's what we see inside outside in terms of the uplift. I mean, the sites are certainly more attractive. It's drawing people in and they're spending money and that's a whole reason we're doing the campaign.
Jason [ph] from Cowen & Company.
I was going to ask about the international margin, so thanks for addressing that. I guess, my other question is just going back to Refining margins. Wondering with oil prices falling as they did just in terms of the secondary product realizations, which geography do you see the highest uplift from those secondary products?
We do see uplift across all our regions. As you know, we have cokers at all our refineries, except for Ferndale and Bayway. And so there is some contribution, meaningful contribution from all of the different regions. We saw it benefit coke NGLs and fuel oil during the quarter, so it was really across all the products and there was meaningful contributions from each of the regions.
So you wouldn't say just in a more general way that one region tends to benefit more than others, it sounds like?
Yes, it's across the board.
And then just a quick follow-up; it looks like CapEx ran a little high. And 4Q obviously not a big concern, given the cash flow you generated in the quarter. But I was just wondering, what that was from? And if that resulting in maybe CapEx coming in a bit lower next year?
This is Kevin. You just look at the two large projects that we sanctioned last year and the timing of when the spend really started to ramp-up on those, so that was Gray Oak and the expansion of the Sweeny Hub with the additional fractionation capacity. And so you're just seeing the impact of the spend level ramping up on those projects. And that's already factored into our capital budget for 2019 that we communicated back in December.
Matthew Blair from Tudor, Pickering, Holt.
Good morning, everyone. It seems like your Gulf Coast Refining system really outperformed peers. You think that was the result of bringing down the WCS barrels or was there anything unusual or anything that stood out this quarter?
I think as we optimize across the integrated logistics network, we did -- are able to allocate the Canadian heavy volumes to the area that are most beneficial. We did consume a fair amount of Canadian heavy in the Gulf Coast. We also benefit from the wide Bakken differential with the Bakken pipeline feeding into the Gulf Coast and across Bayou Bridge into Lake Charles. So those were big contributions. Configuration is a meaningful impact on Gulf Coast because we produce less gasoline and more diesel than is in the 3:2:1. Product realizations from pricing lags in a declining oil price environment were positive. And I think finally the Alliance Refinery was down for maintenance during part of the third quarter and ran during the fourth quarter. So we had higher volumes and lower turnaround expense there.
100% utilization for the region for the quarter always helps to.
Sounds good. And what kind of impact, if any, are you expecting from this recent Keystone pipeline outage?
Yes, it's a little bit early to know what the impact is going to be. We are a shipper on the pipe, so there is the potential for some impact, but we will have to wait and see what the details of that situation are.
We got to work around, we actually talked about that this morning. I guess, Platte [ph] is down too. So we're -- I think we're prepared, but again as Jeff said, I think we need to see more details about how long the pipe is going to be down.
We have now reached the time limit available for questions. I would now turn the call back over to Jeff.
Thank you, Julie and thanks all of you for your interest in Phillips 66. If you have additional questions, please call Brent or me. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. You may now disconnect.