菲利普斯66 (PSX) 2018 Q1 法說會逐字稿

Welcome to the First Quarter 2018 Phillips 66 Earnings Conference Call. My name is Sharon, and I will be your operator for today's call. (Operator Instructions) 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 First 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 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 our opening remarks.

Thanks, Jeff. Good morning, everyone, and thank you for joining us today. Adjusted earnings for the first quarter were $512 million or $1.04 per share. We generated $1.3 billion in operating cash flow, excluding working capital.

Our solid earnings reflect the benefit of our diversified portfolio, and we have seen positive impacts from U.S. tax reform. Our strategy is designed to generate long-term value for our shareholders, and our employees are executing the strategy well.

We've achieved significant growth milestones and completed return-enhancing projects. We're developing new projects with attractive returns that complement our strategy. And by doing all of this well, we can continue to reward our shareholders with solid distributions.

During the quarter, we bought back 35 million of our shares in a single transaction and continued with our share repurchase program. All in, we returned $3.8 billion to shareholders. Since our company's formation in 2012, we've returned over $20 billion through dividends, share repurchases and share exchanges. To put this in perspective, our market cap at inception was $20 billion. Today, our market cap is over $50 billion. We've repurchased -- exchanged close to 30% of our shares outstanding at the time of the spin.

CPChem started up its new cracker at Cedar Bayou, which is one of the largest and most energy-efficient crackers in the world. This milestone caps the completion of its U.S. Gulf Coast Petrochemicals Project. The cracker reached full design rates in April. CPChem also operated well during the quarter and has fully recovered from the hurricane downtime at Cedar Bayou. With major capital spending now complete and contributions from the new petrochemicals project, we expect increased distributions from our Chemicals joint venture.

In Midstream, Phillips 66 Partners recently announced that it will proceed with the construction of the Gray Oak Pipeline system. The pipeline will provide crude oil transportation from the Permian Basin to Gulf Coast destinations, including our Sweeny refinery. An extension to open season is underway and will determine the ultimate scope and capacity of the pipeline, which could be up to 700,000 barrels per day or more. Assuming the pipeline is fully subscribed, the capacity could be expanded to about 1 million barrels per day. The pipeline is backed by long-term take-or-pay commitments with primarily investment-grade customers and is expected to be complete by the end of 2019. Phillips 66 Partners will be the largest equity owner in this joint venture project.

Construction continues on the Bayou Bridge Pipeline extension from Lake Charles to St. James, Louisiana. Commercial operations are expected to begin in the fourth quarter of 2018. The existing segment of the line from our Beaumont Terminal to Lake Charles is operating well and is providing crude optionality to our Lake Charles refinery. PSXP has a 40% ownership in Bayou Bridge.

Phillips 66 continues to expand the Beaumont Terminal, where we are adding 3.5 million barrels of fully contracted crude oil storage. This project will bring our total crude and product storage capacity at Beaumont to 14.6 million barrels by year-end.

The Sand Hills pipeline capacity was close to 400,000 barrels per day at the end of the first quarter. Further capacity expansion to over 450,000 barrels a day is anticipated in the second half of 2018. The pipeline transports natural gas liquids from the Permian Basin to the Gulf Coast of Texas and is owned 2/3 by DCP and 1/3 by Phillips 66 Partners.

DCP continues to progress construction of 2 200 million cubic feet per day gas processing plants in the high-growth DJ Basin. The Mewbourn 3 plant is expected to start up in the third quarter of 2018, and the O'Connor 2 plant is scheduled for completion in mid-2019.

DCP is also participating in the Gulf Coast Express Pipeline project, in which it holds a 25% interest. The pipeline will provide an outlet for natural gas production in the Permian Basin to markets along the Texas Gulf Coast. The pipeline has a total design capacity of approximately 2 billion cubic feet per day and is nearly fully subscribed. The pipeline is expected to be completed in the fourth quarter of 2019.

In Refining, we recently completed FCC unit modernization projects at the Bayway and Wood River refineries. At both facilities, we replaced the FCC reactor system with state-of-the-art technology. The projects were completed on time and on budget. Units have been operating as planned, and early operating data is showing an increased yield of high-value clean products as premised.

At the Lake Charles refinery, we completed crude unit modifications to run more domestic crudes, which improves our supply optionality. Additional improvements are planned to be completed in the fourth quarter.

Finally, we're very honored that 4 of our refineries were recently recognized by the AFPM for excellent safety performance in 2017. Our Bayway Refinery received the Distinguished Safety Award, which is the highest annual safety award given by our industry. The Sweeny, Alliance and Wood River refineries were also recognized for their top-tier safety excellence.

I'm very proud of the people at Phillips 66 and their strong commitment to our safety culture. So with that, I'll turn the call over to Kevin to review the financials.

Thank you, Greg. Hello, everyone. Starting with an overview on Slide 4. First quarter earnings were $524 million. We had special items that netted to a gain of $12 million. After excluding special items, adjusted earnings were $512 million or $1.04 per share. Operating cash flow, excluding working capital, was $1.3 billion. Capital spending for the quarter was $328 million, with $171 million spent on growth projects. First quarter distributions to shareholders consisted of $3.5 billion in share repurchases and $327 million in dividends.

Slide 5 compares first quarter and fourth quarter adjusted earnings by segment. Quarter-over-quarter adjusted earnings decreased by $36 million, driven by lower Refining results, mostly offset by improvements in Chemicals, Midstream and marketing, highlighting the benefit from our diversified portfolio.

Slide 6 shows our Midstream results. Transportation adjusted net income for the quarter was $136 million, up $28 million from the prior quarter. The increase was primarily due to lower taxes and operating costs. Volumes were lower in the first quarter due to the impact of turnarounds at certain of our refineries. NGL and Other adjusted net income was $73 million compared with $20 million in the fourth quarter. Our first quarter earnings reflect improved realized margins and positive inventory impacts. We continue to run well at our Sweeny Hub this quarter, averaging about 9 cargoes a month at the export facility and 95% utilization at the fractionator. However, U.S. Gulf Coast to Asia margins remain challenged.

DCP Midstream had adjusted net income of $24 million in the first quarter. The $10 million increase from the previous quarter was due to the timing of incentive distributions, hedging gains and lower taxes. The increase was partially offset by lower volumes. DCP has steadily improved its financial condition. EBITDA is growing and it's generating positive cash flow and making distributions to our owners.

Turning to Chemicals on Slide 7. First quarter adjusted net income for the segment was $232 million, $111 million higher than the fourth quarter. In Olefins and Polyolefins, adjusted net income increased $129 million from higher margins and volumes, reflecting the Cedar Bayou facility's return to full operations. Global O&P utilization was 96%, up from 79% in the fourth quarter. Adjusted net income for SA&S decreased by $16 million due to turnarounds.

In Refining, crude utilization was 89% compared with 100% in the fourth quarter. Clean product yield was 83%, a decrease of 4 percentage points. Both our utilization and clean product yield were lower due to turnaround impacts. Pretax turnaround costs were $245 million, an increase of $146 million from the previous quarter. This excludes the turnaround costs for our joint venture, WRB. Realized margin was $9.29 per barrel, up from $8.98 per barrel last quarter. Although the market crack decreased 6%, our actual realized margins improved 3% from wider crude differentials, specifically, heavy Canadian.

The chart on Slide 8 provides a regional view of the change in adjusted net income. In total, Refining's first quarter adjusted net income was $89 million, down $269 million from last quarter due to lower volumes and higher costs associated with turnarounds. This decrease was partially offset by higher realized margins.

In the Atlantic Basin, the $193 million decrease in adjusted net income was mostly due to a major turnaround at the Bayway Refinery. The Gulf Coast adjusted net income decreased $71 million, mainly due to turnarounds at the Sweeny and Alliance refineries. Adjusted net income in the Central Corridor was $203 million, an increase of an -- of $11 million from higher realized margins driven by Canadian crude oil differentials.

The impact from the fourth quarter completion of the Ponca City Refinery turnaround was more than offset by first quarter turnarounds at the Wood River and Borger refineries. In the West Coast, adjusted net income decreased $16 million from the previous quarter, mainly due to lower volumes.

Slide 9 covers market capture. The 3:2:1 market crack for the first quarter was $13.12 per barrel compared to $13.98 in the fourth quarter. Our realized margin for the first quarter was $9.29 per barrel, resulting in an overall market capture of 71%, up from 64% in the fourth quarter.

Market capture is impacted in part by the configuration of our refineries. We made less gasoline and more distillate than premised in the 3:2:1 market crack. Losses from secondary products of $1.47 per barrel were lower than the previous quarter by $0.52 per barrel. Feedstock advantage improved realized margins by $1.63 per barrel, which was $0.81 per barrel better than the prior quarter from the widening WTI-WCS differential.

The other category mainly includes costs associated with RINs, outgoing freight, product differentials and inventory impacts. This category reduced realized margins by $2.08 per barrel compared with $2.39 per barrel in the prior quarter. The improvement was driven by lower RINs costs.

Let's move to Marketing and Specialties on Slide 10. Adjusted first quarter net income was $174 million, $50 million higher than the fourth quarter. In Marketing and Other, the $42 million increase in adjusted net income was due to improved realized margins and lower taxes and operating costs. This was partially offset by lower volumes. During the first quarter, we exported 190,000 barrels per day of refined products. We continue to see strong export demand during the quarter.

Specialties adjusted net income was $45 million, an increase of $8 million from the prior quarter, mainly due to lower taxes. During the first quarter, we completed a restructuring of our Excel Paralubes joint venture. Both partners contributed their base oil businesses to the venture to create an integrated manufacturing and marketing business. The JV restructuring provides Excel Paralubes with greater agility to provide quality base oil solutions to their customers.

On Slide 11, the Corporate and Other segment had adjusted net costs of $162 million this quarter compared with $140 million in the prior quarter. The $22 million increase reflects the ongoing impact of lower tax rates on our corporate costs.

Slide 12 highlights the change in cash during the quarter. We entered the year with $3.1 billion in cash on our balance sheet. Cash from operations, excluding the impacts from working capital, was $1.3 billion. Working capital changes reduced cash flow by about $800 million, largely due to normal seasonal inventory builds. We funded approximately $300 million of capital expenditures and investments. And we distributed $3.8 billion to shareholders through dividends and the repurchase of over 37 million shares, ending the quarter with 466 million shares outstanding. We also received $1.5 billion from the issuance of debt. Our ending cash balance was $842 million.

This concludes my review of the financial and operational results. Next, I'll cover a few outlook items.

In the second quarter, in Chemicals, we expect the global O&P utilization rate to be in the mid-90s. In Refining, we expect the worldwide crude utilization rate to be in the mid-90s and pretax turnaround expenses to be between $90 million and $120 million. We anticipate second quarter Corporate and Other costs to come in between $170 million and $190 million after-tax. The increased guidance reflects interest expense associated with our first quarter issuance of debt.

With that, we'll now open the line for questions.

(Operator Instructions) And you have a question from Doug Terreson with Evercore ISI.

And congratulations on having the financial strength to be able to repurchase 7% of your equity in 1 quarter. We don't see that, that often. That's pretty impressive. So my question is about IMO 2020 and specifically how you guys are thinking about the type of products that are likely to be provided to the market, as it seems that many of these fuels are still in the design phase, and there's still a lot of unknowns in that area. And when you think about marine fuel blends, how challenging the issues of compatibility and stability are likely to be and also availability along the marine fuel network as the market goes to the transition in coming years. So 2 questions on IMO 2020.

Yes. Thanks, Doug. While we know the sulfur content of bunker fuels, we don't have the detailed specifications yet. They're still evolving. We do expect a significant influx of diesel into the bunker category. We talked about it last quarter, kind of 2 million to 3 million barrels a day increased diesel demand. Secondly, we do expect low sulfur cat cracker feed to be an attractive blend stock for bunker fuels as well, which will support the gasoline markets also. We're expecting the turnover at tanks and blending infrastructure to start next year, perhaps sometime around midyear. And so it's a big shift, and we're preparing for that. I think one of the things that I would mention is just that our portfolio and our existing Refining assets are well positioned for this IPO -- IMO transition. We've got very high distillate yield, about 41% last year. A $1 a barrel distillate change margin is $300 million in EBITDA. In addition, we expect fuel oil to weigh on heavy crude prices. We have heavy crude of about 700,000 barrels a day or about 35% of our total portfolio. We have more coking capacity at 470,000 barrels a day than the peers. Every dollar per barrel change in heavy crude discount is about $250 million in EBITDA. So our portfolio is well positioned the way it stands today.

It sounds like it, Jeff. And I just wanted to follow up on your point about diverting vacuum gas all around the cat cracker straight into the marine fuel pool. I mean, it seems that, that would surely enhance marine fuel supply, but it also seems like it would come at the expense of gasoline supply and that it might make it somewhat of a zero-sum game. And so would you disagree with that, number one? Number two, how commonly is that practice being employed in the industry, meaning, is this something that you guys have done frequently or have we seen this before?

This is something that we expect to be more of a new activity, which converting from max gasoline to max diesel during the summer months as well as [pulling] some of the cat cracker feed, I think, will support gasoline margins as well as supporting diesel cracks.

Next question comes from Neil Mehta with Goldman Sachs.

First question I had was just around capital spending. I know it's really early in the year, but CapEx was below certainly the annualized run rate that you've kind of guided to. Can you just speak to the guidance and whether there is a downward vector to it and just the timing of spend as well?

Neil, I think we're consistent with the guidance around the $2.3 billion. I think that we were a little light in the first quarter and we knew we were going to be when we put the plan in place. But $2.3 billion is still a good guidance for us this year.

Okay. Great. Second question, on the quarter, Midstream, a big part of the beat. NGL and Other was a driver of that. Another were some inventory benefits there. Can you just kind of speak to what some of those dynamics were and how we should think about the run rate going forward?

Yes, Neil, it's Kevin. As you look at that, so I think the NGL segment reported $73 million of income in the quarter. About $20 million of that is associated with inventory LIFO-related items. Nothing specifically unusual in what happened. It's just that the -- the magnitude and it's positive in the quarter. And these things will happen from time to time, and it can go in the opposite direction also. But as you look at that and try and think about our run rate going forward, you probably ought to back out somewhere in the order of $20 million from what we reported in the second -- in the first quarter.

That is helpful. And last question for me. On Permian differentials, you guys have a good perspective on this. And just over the next 2 years, there's absence of major pipelines till the back half of 2019. How do we get the crude to market from West Texas?

Yes, I think it's a good question. And there -- you're correct, the next major pipelines are scheduled for the back half of 2019. We saw about 750,000 barrels a day of new capacity that was added late last year and early this year. And it certainly appears that, that pipeline capacity is filling up more rapidly than anticipated. As we look at alternative options, trucking is one. That's kind of a $12 a barrel movement at this point, although that's not going to be a steady number. A typical truck can haul about 180 barrels of crude. It's roughly a 500-mile haul from the Permian to the Gulf Coast. It's a day -- a 2-day round trip. So you need 100 trucks to move 10,000 barrels a day. It's not really realistic to expect to move 100,000 barrels a day or 200,000 barrels a day. It's just not really practical. From a rail perspective, there's not a lot of rail facilities. Most of the rail facilities in the Permian Basin are now designed for frac sand and not crude movement. And so that's not a great option. So we are in need of a new pipeline capacity serving the Permian Basin. I think there's a lot of talk on the crude side. And when you look at the Midland differential to East Houston, it's out to $9 a barrel. When there was enough infrastructure, that was kind of a $3 a barrel differential. When you look at natural gas as well. Waha prices have declined about $1 in MMBtu relative to where they were last year. And that sets a lower price for natural gas and ethane rejection. So we may see some additional ethane production coming out of the Permian Basin as well.

Next question comes from Blake Fernandez with Scotia Howard Weil.

First one is just more housekeeping, probably for Kevin. The tax rate seemed really low in the quarter. I'm just trying to figure out if that's maybe some one-off issues driving that or if that's kind of sustainable.

Yes, Blake. It is a little bit low and it's -- it really reflects the mix effect of certain items in the portfolio. So the international -- the higher proportion of international earnings than I would say normal, in part because of the amount of U.S. Refining turnaround activity we had, so relatively low U.S. Refining earnings contribution, some of that dynamic as you look in the Chemicals segment, the Middle East joint ventures that CPChem has, so that's in Qatar and Saudi Arabia, those are equity method accounting accounted at the CPChem level. And those equity earnings are after-tax. So the entities themselves pay tax, and that flows through after-tax. And so that has the impact of reducing the overall effective tax rate. And it's more pronounced than a period where the other pretax income is lower because of, for example, turnaround impacts. You also have the effect of noncontrolling interest in the effective tax rate calculation. We factor that into our overall guidance around effective tax rates. But again, when the rest of the portfolio is in a relatively low earnings quarter, it has a slightly bigger impact. So all in, as we look at where this -- where we expect this to be on an ongoing basis, we'd still come back to it should be low 20s from an effective tax rate standpoint.

Okay. Got it. Greg, I'll go out on a limb and assume that the buyback level of $3.8 billion in the first quarter is not sustainable. As we kind of get our bearings straight after that big slug, do you have any thoughts around the way we should think about that moving forward?

Yes, I think we'll stick with our guidance of $1 billion to $2 billion of share repurchases in 2018. We may skew towards the lower end of the range given what we've done in the first quarter, Blake. But yes, we'll still be buying shares. We're buying today.

Next question comes from Phil Gresh with JPMorgan.

First question is just on some of the cash flow items. I guess this is for Kevin. The ending cash balance, obviously given the repurchase in the quarter, how do you think about managing the cash balances and where you'd like to have them? And I guess a related question to that is should we be thinking of drop-downs to PSXP as a, I guess, a driver of some cash that would potentially make its way to the parent company this year? Or with the organic opportunities available at PSXP, is that not necessarily something that we would be thinking about?

Yes, Phil. So a couple of comments on that. Obviously, the drawdown in the cash was a function of the buyback. So we did a $3.3 billion buyback with Berkshire, and we issued $1.5 billion of debt. So we consumed a fair amount of cash in doing that. Part of the reason we were able to do that is you think back to tax reform and the ability to get access to cash that previously was -- it wasn't trapped internationally, but there was a greater cost to accessing that cash. And so we've taken advantage of that. And so what that means is on a go-forward basis, we have the ability to utilize more access to overall available cash balances. In terms of as you look out the year, we typically don't give -- well, we haven't given guidance on drop-down plans around that. But as we commented or sort of stated in the PSXP earnings release, we're not that far from our stated 2018 EBITDA guidance at the MLP level. So there's potential that with growth -- there were organic growth projects underway at the MLP. Drop-down needs would be pretty minimal from an MLP growth standpoint. And I wouldn't imagine we'd be in a situation where we were just forced to drop to provide funding back up to the parent. All those decisions are made from a sort of long-term MLP growth perspective.

Sure. Okay. No, that's very helpful. I guess the second question, a bit more of a strategic one for Greg. Just thinking about the current environment for chemical margins. Obviously, you have your cracker coming onstream. It sounds like it's going really well in terms of the start-up. If you look at the margin profile out there, ethylene margins are challenged, but the full-chain margins are obviously still holding in pretty strongly. So how do you think about the chemical environment and what it might mean for the timing of the second cracker?

Well, I mean, first of all, it was a great start-up. I think it's one of the better starts-ups we've had in the last few that we've executed. So kudos to the CPChem folks for doing a great job getting that cracker up and running at full rates. The derivatives were up in the fourth quarter last year. Dow's up, and so we've been up since, really, the fourth quarter. And the market -- so the market-facing element of those projects are out there in the markets. And you look at kind of the full-chain margin, which is what we really care about, what's that spread between ethane and say, polyethylene, and particularly, high-density polyethylene. And as you said, those margins are pretty similar. So we've been able to move the products into the markets without a really detrimental effect on the margins at this point in time, the chain margin. And I think that really speaks to the demand that we're seeing out there. We're seeing good fundamental demand growth in North America, Europe, Asia for petrochemicals, but specifically, for polyethylene. You got ExxonMobil coming up later this year. Then you have 2 crackers coming up in '19. And what's happened, we thought these crackers are all going to hit in 2017. That just didn't happen. And so they're getting spaced out, and the market's been able to absorb these volumes that are coming on, coupled with good demand growth globally. And so as we start thinking about that next cracker, we like what we see in terms of the NGL supply. Increase in NGL is coming, particularly out of the Permian, but from the U.S. Gulf Coast is a good place to build. The next cracker, we believe, we're still kind of 2019 probably for an FID on that facility.

The next question comes from Manav Gupta with Crédit Suisse.

I had a quick question. On the -- so the Midcon results, which are very strong, so I'm trying to understand how much of WCS were you running in the Midcon. And did you actually uptake the intake of WCS in your Midcon system, which got reflected in a very high capture?

We imported 550 million of Canadian imports on average for 2017...

1,000.

Or [550,000], sorry. Thank you. And some of that was for WRB. Our net, we were about 4 50, and 80% of that was Canadian-heavy. And so that's the range of what we'd expect to run kind of on an annual basis. We don't intend on updating that on a quarterly basis, but we continue to import as we could on the Canadian heavy front.

Jeff, my follow-up is on the question that Phil also asked, was I'm trying to understand where you actually short ethylene in 1Q '18 because what I'm trying to get to is the $232 million net income you reported. Would that have been like $250 million and $260 million had your ethylene cracker actually been running and you were not short ethylene in that period?

No, we weren't short ethylene. We had ethylene inventory, and there was plenty of ethylene available in the industry. And I think that's what you're seeing in terms of just the ethylene margin itself.

Next question comes from Roger Read with Wells Fargo.

I guess if we could maybe hit the Midstream segment one more time. I mean, that's just been, if you go back the last year, 1.5 years, a pretty tough sector until the fourth quarter and now the first quarter. So can you kind of walk us through how much of this is sort of market conditions changed, like oil prices recovered, and how much of it is the new projects coming online as well as just internal restructuring and so forth? And then maybe kind of help us understand the sustainability here going forward, ex an oil price continuing to increase or holding at these levels.

Well, I think I'll start. As you know, NGLs have certainly recovered versus, say, a year ago, in terms of pricing and that. First quarter volumes were seasonally -- they were lower than the fourth quarter or third quarter, but that's just seasonal, weather-related impacts, particularly around the NGL side for us. You have the Sweeny Hub that's performing, albeit not at the level that we would expect. If you take the first quarter hub and you kind of annualize those results, we get to, say, $130 million, $140 million of annualized EBITDA out of the hub. We've laid in the plan. As we've said previously, $150 million of EBITDA for the hub this year. And that's against an expectation of kind of $300 million or $400 million without the arb. So I think that, that asset still has room to go. And as we look at the NGLs that are coming at us out of the Permian this year, we do think that the fees across the dock are going to go up as we get in the back half of this year and certainly into next year. So we'll see continued improvement there. We certainly have the new pipes. DAPL is on. Bayou Bridge is on. So a lot of it is around the new assets that we've been bringing on, Roger, that have been driving this.

Roger, I might just highlight. I know you are aware. But in our supplemental reports on Page 6, we identified Midstream adjusted EBITDA. And if you look at PSXP and other Midstream, it generated about $363 million of EBITDA in the first quarter. If you were to annualize that, it's about $1.45 billion. We've also got about $300 million of Refining assets, and that's -- ties back with the $1.8 billion to $2 billion of EBITDA that we talked about in our presentation material. So that supplemental report will give you a scorecard to keep track on our progress.

Okay. Great. That's really helpful. And then maybe just a complete change of direction here. RINs, you mentioned in the presentation part, that lower RINs had helped out a little bit. Just curious what your expectation is, if anything, for, let's call it, potential RINs reform as we see '18 unfold.

So I'd answer the question this way, we're ever hopeful. So I hope we'll see some RINs reform. I'm just not sure we're going to get there. There's a lot of good work that's going on, AFPM, API. Management teams are in Washington talking to Congress about potential reform. Our view is that it's broke, the system's broke, we need to fix it. And so we'll see. But I don't hold a lot of hope for 2018. Now some of my friends in the business are a lot more optimistic than I am, that we'll get something done in 2018. I guess the other impact that you're seeing is these small refinery exemptions, and that has certainly had an impact on the RINs prices. And so we'll continue to follow it, we'll continue to work it and continuing to be hopeful we get to a resolution there.

Next question comes from Justin Jenkins with Raymond James.

I guess maybe in Midstream with the Gray Oak project. I'm not sure how far I'll get here, but I have to try. Can we get a ballpark of maybe total capital costs or at least a range on that project? And then along that line, maybe the confidence you had to push the spend down directly to PSXP at the outset here.

Yes, so 2 parts. First part is really can't comment. We're in an extension of open season. And the actual volumes that we end up with will dictate the size of the pipe, the actual capital cost. You should expect that, I would say, 45 to 60 days, we'll get this wrapped. And then we'll come back and we'll tell you what the capital cost is going to be on the line. We started at kind of a 3 80 in the open season. I would just tell you, we obviously did -- got more interest than that, and that really kind of encouraged us to move on with the extension of the open season. So I think we're really optimistic on the line and where the ultimate capacity lands on that line. And then just as you think about the decision of where to place it, we've always said we want to execute as many of the organic projects as we can at PSXP. And given this pipeline, we have increased the budget of PSXP for this year, and Gray Oak's part of the reason we increased that. But you shouldn't look that, that increases the total cost of the pipeline, if you want to think about it that way. So anyway, I think that Gray Oak is a great opportunity for our company. It's certainly a great opportunity for Phillips 66 Partners. And we'll continue to make decisions about where do we place these projects, either at PSX or PSXP obviously. But we'll continue to put as much as we can to PSXP and execute as much organic growth as we can at the MLP. And that's very consistent with what we've been saying for the past couple of years.

Perfect. That's helpful, Greg. And I guess shifting gears maybe on cash returns. I understand you answered Phil's question earlier about the buyback. But how should we think about the, maybe the mix of returns going forward here? We've got a good problem to have with the dividend yield maybe as low as we can remember in a while. But the mix of the buyback versus dividend growth or maybe faster dividend growth going forward.

Yes, I still think that if you think we're kind of a $5 billion to $6 billion of cash at mid-cycle generation, we can report a, first, $1 billion sustaining capital. The dividend's $1.4 billion. That gives you a lot of room to grow the dividend, but also execute a $1 billion to $2 billion growth program and a $1 billion to $2 billion share repurchase program. And so that's how we continue to think about it at mid-cycle. Certainly, as these new projects come on and we're going to add another $1 billion to $1.5 billion of EBITDA, that increases our capability to fund or reinvest in the company. But we'll -- we're sticking with the 60-40 guidance. It's going to be really hard to hit that this year because we're already at 3 8 distributions against the $2.3 million capital budget. And we just don't see ourselves really materially changing the capital guidance at this point in time in the year. So we will be heavy on the distribution side in '18. But long term, we do like that 60-40 mix.

And just to add, Justin, on dividend, no change from what we've said in the past in terms of secure, competitive and growing. So we'll continue to grow the dividend. Just because we did the big share buyback this year, it doesn't preclude us from increasing the dividend as well this year.

Next question comes from Doug Leggate with Bank of America Merrill Lynch.

A couple of follow-ups actually on that last question, Greg, if I may. Obviously, your share price is substantially above when you set the original distribution policy, I guess. What about the mix between dividends and buybacks as part of that 60-40 split? Do you see yourselves skewing more to -- back to the dividend? Or is -- are you kind of agnostic to the share price as it relates to where you're buying back shares?

No, I wouldn't say we are -- well, first of all, on share repurchase, it's all intrinsic value. And as we've said, we're using historical multiples, in our view of EBITDA, essentially kind of 2 years out. And as long as shares are trading below that, we're going to be buying shares. When you think about the dividend, to Kevin's point, secure, growing, I think investors need to see that we have runway to continue to grow the dividend, and we want to grow the dividend every year. We think it needs to be competitive. So we look around at kind of what's S&P 200 yield, what's the yields of our competitors. And so we make sure we've got a very competitive dividend in the group. And so we'll always grow the dividend, but we'll grow it within those parameters. And to the extent that we're balancing between reinvestment and share repurchase, we'll buy the shares then.

Sorry to add an add-on to that, but it's really more of a -- is it dividends per share or dividends per se? In other words, when you buy back stock, is that counted as part of the dividend growth per share or not?

So we're looking at dividends per share in terms of gain. Yes.

All right. So my follow-up is more a micro question, Greg, and it kind of goes back to the dinner you hosted back in December. I think you talked about the IMO issues as being more -- I don't want to put words in your mouth -- but more kind of transitory when it happens and not something that you would expect to work through the system. I'm just wondering if your views have changed on that. I understand you're well positioned for it regardless of what happens. But do you see it as more enduring or still somewhat short-lived when it gets implemented in 2020?

Yes. I -- my own personal view, and Jeff can jump in on this, if he has a different one, is that this is -- I don't know if it's going to be short-lived. I think within a couple of years, you'll see that actually competed away.

Next question comes from Brad Heffern with RBC Capital Markets.

I was wondering on the crude export front, since you guys have Beaumont and so on, we're exporting over 2 million barrels a day now. Most people are expecting 1 million barrels a day of growth in the U.S. So is there the infrastructure in place to -- or will be in place to export 3-plus million barrels a day next year and then 4 million in 2020 and on down the line?

Yes. So you're right, we've seen a number of weeks over 2 million barrels a day of exports. We've expanded our capacity at Beaumont to go from 400,000 barrels a day to 600,000 barrels a day. You saw we're participating in the Buckeye facility in Corpus as well, associated with Gray Oak Pipeline. We are seeing the expansion of export capabilities. It's one of a -- part of the value chain that's going to have to grow in order to continue to export. And we think the majority of the incremental production is going to be exported. So we think maybe there's 3 million barrels a day capacity today, but that number is growing. We don't see an immediate issue there at this point.

Okay, Jeff. And then maybe for Kevin, you guys gave the mid-90s utilization guidance for CPChem. I assume that that's off of a new base. So if you could just clarify that, if that's the case and if that's for the whole quarter, and sort of what the new capacity number is that, that 95% is based on.

Yes, Brad. You're correct that with the cracker starting up, they declared commercial operations on it in April. And so that adds it into the denominator from a total capacity standpoint. So the polyethylene units, new polyethylene units were already reflected in the denominator. The new cracker is in [effective] second quarter. So that 96% includes our assumptions around what all the new units will be running.

Next question comes from Ryan Todd with Deutsche Bank.

Maybe I want to start off on product exports. I mean, can you talk about the dynamics that you're seeing right now in the -- in product exports? You had a sequential decrease, I think, quarter on quarter. But it seems like we've also seen reports that demand to ship [just a little] on Colonial has dropped to very low levels. I mean, what are you seeing in terms of sequential drivers, what are you seeing in terms of relative netbacks that you can see domestically versus export and your ability to kind of capitalize on that going forward?

Yes, you're right. Our product exports were down 190,000 barrels a day this quarter. About 90,000 barrels a day of that was gasoline, and 100,000 barrels a day was diesel. We had refinery maintenance at Alliance, in particular, that reduced the availability of product that we could put into the export market. We are continuing to see strong demand, continued struggles with Refining capacity in Latin America. And so we expect that to hold up longer term.

Okay. And then maybe a follow-up on, since you brought up your personal views, Greg, on the duration of the IMO benefits. How do you think that it gets -- how do you think that the arb gets competed away? I mean, it -- I don't disagree that it will be. But at this point, we've seen, for the most part, independent refiners holding a relatively good line in terms of incremental investment. You're not planning for any large-scale material investments to kind of compete away the arb. How does it get competed away? And who is that? Is it the majors and the global NOCs of the world and Asia that kind of competes away the arb? Or how do you think that plays out?

Yes, I think you'll see continued investment in Asia in Refining capacity. That's a big fuel market, obviously. Yes, I suspect there will be continued discipline. We don't plan to make big investments really to swing the portfolio. I think we've got plenty of capabilities as we sit today. There may be small things that we do along the way, but I just -- it's just this industry, we just have a long history of being able to compete away really good margins. And whether it's $5 to $15 on the distillate crack, yes, I don't know what that's going to be. I'll probably be on the low end of that one for a couple of years. But this -- I think you're in a time -- certainly, '19, '20, we're going to really like the Refining business and the margins and the cash that's coming off this business. But you get out another 3 or 4 years, it gets really hard to forecast.

One other thing I would add is we're not seeing the adoption of scrubbers at the pace that we anticipated a few months ago. I think it's been much [slower]. And depending on the availability of the 3.5 sulfur fuel, after the changes are implemented, perhaps there may be a more rapid adoption of scrubbers. But that's going to depend on the availability of the fuel and a number of items that are just hard to predict at this time.

I guess the other thing, longer-term too in terms of newbuilds in the shipping industry, if you're really at the high end of the range, I think people have to start thinking about LNG and other options too. So I mean, these things always come into balance by many factors really working on that equation. It's not just going to be Refining capacity. It's going to be the choices of the ship owners. And so we'll see where does it go.

Next question comes from Prashant Rao with Citi.

I wanted to ask this a different way. I know we talked about IMO and the discrete window. And Greg, I agree that this is something that does get competed away. But if you think about increasing clean product yields, and specifically, you guys have a few projects in 4Q in Charles and then you did a few earlier already, there's a baseline growth of clean product demand globally and export demand. And that feels like something that is more buildable towards. So I wanted to get a sense of, IMO aside, what are your thoughts on a multiyear basis in terms of how that ramps and at what point, how you build towards that if -- in terms of incremental investment? Not the IMO impact, which feels like just an upside shock, but more the secular growth that could be multiyear that we've seen for several years here. What look can we expect in terms of incremental investment towards that?

Well, from our perspective, it's -- $300 million a year, give or take, is what we've been investing in Refining to either improve yields or to access more advantaged crude one way or the other. I think the other part of the equation that we haven't talked about today, and we could have touched on it in our gas discussion, but I think we're going to move to our higher-octane fuel. And so I think that over a period of, whatever, 10 or 12, 15 years, whatever it takes, you will see the industry invest to make a higher-octane fuel, assuming that gets done here in the next year or so. So I think there will be investable opportunities for refiners and for PSX that are, what I would say, not multibillion-dollar investments, but solid high-returning projects for us. And so we'll always do that. The industry itself seems to have the ability. Every time we do a turnaround, we replace an exchanger that was a bottleneck for us or whatever, and we can creep 1% or 2% a year. I think you'll continue to see that happen in the industry as we move forward. So I think it will be a combination of specific investments that people want to make to address a yield or advantaged crude. And then you just see the general creep that we tend to have in industry.

And to the extent there aren't attractive projects to invest in, we'll continue to buy back stock and reduce the share count and make it accretive that way.

Okay. That makes sense. And then just to follow up on something. Greg, you gave a lot of detail on this about the potential for the timing of the second cracker. But I wanted to focus more -- less on the margins and more on sort of the timing of the shift that we've seen in terms of the majors announcing their plans for petrochemical opportunities and investments and sort of over the last few months, how the industry book of projects and valuations may have been moving and if those dynamics, in any way, impact or sharpen your plans in terms of the potential plans for another cracker in the Gulf. And in terms of timing, how that -- there's a lot of moving parts there, so I just wanted to get a sense on that particular piece of it, not necessarily the margin recoveries.

Well, and certainly, it's a joint decision between the owners of CPChem. And I think we have to have an agreed view of when the appropriate time that cracker is. At the CPChem level, we're thinking about how do we move our products into the market in the most efficient manner. And we're the world's largest producer of high-density polyethylene, and these projects are generally geared towards that, although we've added quite a bit of NAO capacity over the past couple of years also. So we're thinking about how do we efficiently move these products into the market. And so that's one thing we think about in terms of the timing decision. Obviously, NGL supply, feedstock supply, those factor into those decisions of where you're going to build it and what are you going to build, ethane or some LPG cracker. And so I think that there's kind of multiple decision points that we go through when we're thinking about the timing on the cracker. One of the things we wanted to make sure, that there were some daylight in between when this Gulf Coast cracker project one came up and when we would do the second one. And so you kind of think of coming up in '18 and having most of '19, it seems like appropriate timing to us in terms of FID in late '19 and really get started in earnest in '20 and '21 on the construction.

Next question comes from Paul Cheng with Barclays.

A number of quick questions. Kevin, I think last year or a couple of years ago, you were talking about, going forward, you may want to keep the consolidate debt to be flat so that you will reduce some of the C corp level as the -- at the MLP level going up. Is that still the objective going forward? Or that, I mean, over the past couple of years, I think overall debt has been going up. So should we assume, in the next 12 to 18 months, that the cash flow you increase further, you're going to use a portion of them to try and to pay down your debt?

Yes, Paul. It's a good question. And some of this has been a function of debt has gone up on a consolidated level over the last year or 2. And a big factor there has been the transaction we just did in the first quarter with the large share buyback. So that added $1.5 billion of debt that we hadn't anticipated doing. But as we look ahead and we see a period of reasonably strong margins, you've got new projects coming online, you've got Chemicals with the new assets up and running and expect increased distributions out of Chemicals, we think we'll have the ability to pay down some of that debt over the next couple of years. So I think you kind of got to that point that we have the ability to potentially bring debt back down in the $1 billion, $1.5 billion or so over the next couple of years if margins hold in where we think they're going to be.

But you don't want to do any more than just $1 billion, $1.5 billion from the current level, right?

It depends, I mean, it's going to be somewhat dependent on the relative -- the alternative opportunities. The $1.5 billion we just added was clearly incremental debt. So it would be nice to be able to take care of that over the next near-term period, a couple of years or so. And then it becomes opportunistic, what's the best use of available cash. And it will depend on what the investment opportunities look like, where the share price trades and opportunities around share buybacks. And so it will be that continual sort of balancing act across those capital allocation decisions.

Paul, I think one thing that hasn't changed was really how our view that we want to maintain a strong investment-grade rating. And so I think that really comes into play. We've always said around 30% debt to cap. We're probably 31% or so today, so we're probably over that. But we've used the 30% as kind of a proxy of a strong investment-grade rating. As we look at the debt and the capacity that we have today, we're comfortable with this level of debt at the company. And as we said, we've got strong investment-grade ratings today.

Greg, it seems that my understanding of the Chemical,] [even] as little as you can comment, you know as much as anyone, can you just give us a maybe easy way? With the new ethane cracker, if we're looking at today's margin, what is the contribution of the net income to you guys going to be?

Well, from an EBITDA basis, kind of at today's margins, at the CPChem level, kind of $1 billion to $1.2 billion, Paul. So $500 million to $600 million of EBITDA back to us is an easy way to think about that.

Okay. So that is -- that if today's margin holds, because that the ethylene margin is already pretty low and you already have the PE hub from last year, so incrementally, it's really just on the ethylene margin and that $1.2 billion is just on the ethylene margin, I presume?

No. That's the full chain margin.

That's ethane to polyethylene.

But you already have the PE margin from last year, right? So while I'm looking at incrementally with the [steam] cracker coming onstream, so what is the additional uptake that we should assume?

Yes, but -- first of all, we were in start-up, right, in the fourth quarter of last year. We were using ethylene that's either be inventoried or purchased, and so you really didn't get the full impact of the new cracker being up. So the new cracker is probably our lowest increment of cost as we think about our value chain and the other crackers in our system. And so I think the $1.2 billion is a good number if you want to think about this year.

Annualized.

Annualized.

Annualized. Yes.

Right. Annualized. And the final one for me. How much is the TI-Midland crude you guys can assess by pipeline into your refinery?

Paul, for commercial reasons, we don't talk about individual sourcing of feedstock for individual refineries.

Okay. Or then, can you tell us that which refinery -- I know that you run mostly in Borger, but how about Ponca City and all the other ones there? Can you give us some idea which one you may have access?

Well, I think as you look at the Phillips 66 portfolio, we're roughly 35% heavy, 35% medium and 30% light on the portfolio as a whole.

And some of that light is imported light, right?

Right. I understand. And some of the light is also not, clearly, not from Midland. It's probably from Cushing or some other places.

Right. Correct.

Right.

We now have reached the time limit available for questions. I will now turn the call back over to Jeff.

Thank you, Sharon, and I thank all of 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.