菲利普斯66 (PSX) 2017 Q2 法說會逐字稿

Welcome to the Second Quarter 2017 Phillips 66 Earnings Conference Call. My name is Julie, 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.

Thank you, Julie. Good morning, and welcome to Phillips 66 Second Quarter Earnings Conference Call. Participants on today's call will include Greg Garland, Chairman and CEO; Tim Taylor, President; 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 is a reminder that we will be making forward-looking statements during the presentation and our question-and-answer session. Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here as well as in our SEC filings.

With that, I'll turn the call over to Greg Garland for opening remarks.

Okay. Thanks, Jeff. Good morning, everyone, and thank you for joining us today. Adjusted earnings for the second quarter were $569 million or $1.09 per share. We delivered good operating performance and generated strong cash flow during the quarter. Utilization increased to 98% in Refining and at CPChem Olefins and Polyolefins. This represented our second highest quarter in Refining and the highest utilization CPChem has achieved in the last 10 years.

In addition, during the quarter, several of our facilities were recognize at the Annual AFPM Safety Awards. Out of approximately 275 refining and petchem facilities eligible for recognition, 11 total U.S. refineries were recognized for their strong safety performance. Of those 11 refineries, 6 were Phillips 66 facilities. And our Lake Charles refinery received the 2016 Distinguished Safety Award, the highest industry recognition. Lake Charles has gone 2 years and over 11 million hours without a recordable. We're really proud of the people at Phillips 66. Through their hard work and dedication, they're demonstrating our commitment to operating excellence and that we can achieve a 0-incident, 0-accident workplace, that every employee and contractor can get home safe to their families every day.

Cash from operations for the quarter was $1.9 billion, the highest since 2013 and includes the impact of discretionary distributions from CPChem and DCP.

We continue to maintain our commitment to shareholder distributions. During the second quarter, we raised our dividend by 11% and increased share repurchases by nearly $100 million to $380 million for the quarter. In our first 5 years as a company, we've increased the dividend at a 30% compound annual growth rate and repurchased or exchanged 131 million shares, representing more than 20% of our initial shares outstanding.

During the quarter, we made significant progress on several growth initiatives, reaching major milestones in key projects in Midstream, Chemicals and Refining. In Midstream, commercial operation started on the Bakken pipeline. The pipeline moves crude from the Bakken field in North Dakota to delivery points in Patoka, Illinois and Nederland, Texas. Phillips 66 has a 25% interest in this joint venture.

The Bakken pipeline feeds our Beaumont Terminal, which we continue to expand. This quarter, we added 1.2 million barrels of product storage, and we're building over 2 million barrels of additional crude storage. As crude and product exports grow, Beaumont is well positioned to generate additional earnings.

We're currently evaluating opportunities to build additional NGL fractionation capacity on the Gulf Coast. We plan to approve the project once commercial arrangements for NGL supply are finalized.

Phillips 66 Partners remains an important part of our Midstream growth strategy. PSXP's run rate EBITDA has increased to $675 million, and the partnership's on track to reach its goal of $1.1 billion in run rate EBITDA by the end of 2018. In addition to drop-downs, the partner's -- at the partnership, PSXP is pursuing a number of organic growth initiatives, including expansion of the Sand Hills and STACK JV pipelines. We expect construction to start this quarter on the second leg of the Bayou Bridge crude pipeline, which will extend the pipeline to St. James, Louisiana.

In addition to the Sand Hills expansion, DCP Midstream is expanding its DJ Basin footprint with the construction of the Mewbourn 3 gas processing plant, which should be completed by the end of 2018. DCP has also announced plans to participate in a joint venture on a natural gas pipeline out of the Permian.

In Chemicals. CPChem achieved a major milestone on the U.S. Gulf Coast Petrochemicals Project by reaching mechanical completion on the polyethylene units. Commissioning activities are progressing, and the 2 units should be fully operational later this quarter. The ethane cracker is scheduled for mechanical completion in the fourth quarter of this year.

In marketing, we continue to enhance our network by reimaging sites domestically and growing the number of sites in Europe. To date, we have reimaged over 1,000 sites. Gasoline volumes at the reimaged sites are improved by 3% year-over-year.

In Refining. The Billings Refinery completed a capital project in June which increased its heavy crude processing capability to 100%. The project was completed safely, on time and on budget. At the Bayway and Wood River refineries, we're modernizing FCC units to increase clean product yield. Both projects are expected to complete in the first half of 2018.

With that, I'll turn the call over to Kevin to go through the financial results.

Thank you, Greg. Good morning. Starting with an overview on Slide 4, second quarter earnings were $550 million. We had 2 special items that netted to a loss of $19 million. We recognized a $34 million net charge for pension settlement expense. This was partially offset by an insurance claim reimbursement. After removing these items, adjusted earnings were $569 million or $1.09 per share.

Cash from operations for the quarter was $1.9 billion. This includes a positive working capital impact. Capital spending for the quarter was $458 million, with $271 million spent on growth projects.

Distributions to shareholders in the second quarter totaled $741 million, including $360 million in dividends and $381 million in share repurchases. We finished the quarter with a net debt-to-capital ratio of 25%. Our adjusted effective income tax rate was 32%. Annualized adjusted year-to-date return on capital employed was 6% through the second quarter.

Slide 5 compares second quarter and first quarter adjusted earnings by segment. Quarter-over-quarter, adjusted earnings increased by $275 million, driven by improvements in Refining and Marketing and Specialties.

Slide 6 shows our Midstream results. Transportation adjusted net income for the quarter was $74 million, down $4 million from the prior quarter, mainly due to seasonally higher maintenance spend. In NGL, we had adjusted net income of $14 million. The $3 million decrease was driven by seasonally lower propane sales and higher turnaround impacts at equity-owned fractionators, partially offset by improved results at the Sweeny Hub.

DCP Midstream had adjusted net income of $13 million in the second quarter. This represented a $4 million decrease from the first quarter, reflecting the impact of lower commodity prices and higher integrity spend. This was partially offset by a gain on an asset sale. After removing noncontrolling interest of $37 million, Midstream's second quarter adjusted earnings were $64 million, $13 million lower than the first quarter.

Turning to Chemicals on Slide 7. Second quarter adjusted earnings for the segment were $196 million, $5 million lower than the first quarter. In Olefins and Polyolefins, adjusted earnings increased by $18 million, primarily due to improved margins and higher volumes. Global O&P utilization was 98%, an improvement of 9 percentage points over the prior quarter.

Adjusted earnings for SA&S decreased by $24 million due to the absence of the first quarter gain on CPChem's sale of its K-Resin business as well as lower equity earnings. The reduction in equity earnings was driven by lower margins and unplanned downtime.

In Refining, crude utilization was 98% for the quarter, 14 percentage points higher than the first quarter. Pretax turnaround costs were $154 million, down from almost $300 million in the first quarter. Clean product yield was 85%. Realized margin was $8.44 per barrel, down slightly from last quarter.

The chart on Slide 8 provides a regional view of the change in adjusted earnings. In total, the Refining segment had adjusted earnings of $233 million, a $235 million improvement from last quarter. This increase was driven by significant improvements in the Atlantic Basin and West Coast regions, partially offset by decreases in the Gulf Coast and Central Corridor. Adjusted earnings in the Atlantic Basin were $159 million higher than last quarter. This increase was driven by improved market cracks, lower turnaround costs and higher utilization. Market cracks improved by nearly 40% during the second quarter, and capacity utilization increased from 70% to 103% as the Bayway Refinery completed a major turnaround during the previous quarter. These increases were partially offset by lower clean product differentials as European cracks lagged pad 1 cracks.

In the West Coast, adjusted earnings improved $120 million over the previous quarter. This increase was primarily due to a higher gasoline crack and the positive impact on volumes and costs of completing a major turnaround at the Ferndale refinery during the first quarter.

The Gulf Coast saw lower adjusted earnings despite higher utilization and lower turnaround expenses as these improvements were more than offset by low margins driven by reduced feedstock advantage and lower clean product differentials.

In the Central Corridor, adjusted earnings decreased by $33 million from the prior quarter, in large part due to the cost and volume impacts of the second quarter turnaround at the Billings Refinery and reduced feedstock advantage on Canadian crudes. The Billings turnaround was completed in June.

Slide 9 covers market capture. The 3:2:1 market crack for the quarter was $14.06 per barrel compared to $12.24 in the first quarter. Our realized margin for the second quarter was $8.44 per barrel, resulting in an overall market capture of 60%, down from 70% in the prior quarter. Market capture is impacted in part by the configuration of our refineries. During the second quarter, we made less gasoline and slightly more distillate than premised in the 3:2:1 market crack. Losses from secondary products of $2.44 per barrel were slightly lower than the previous quarter due to falling crude costs and higher coke prices. Feedstock advantage improved realized margins by $0.63 per barrel, $0.95 per barrel less than the first quarter, as light medium and light heavy crude differentials tightened during the second quarter.

The other category mainly includes cost associated with RINs, outgoing freight, product differentials and inventory impacts. This category reduced realized margins by $1.30 per barrel compared with $0.67 per barrel in the prior quarter, mainly due to lower clean product differentials.

Let's move to Marketing and Specialties on Slide 10. Adjusted earnings for M&S in the second quarter were $218 million, $77 million higher than the first quarter. In Marketing and Other, the $61 million increase in adjusted earnings was largely due to higher margins and volumes. Specialties' adjusted earnings increased by $16 million, primarily due to improved base oil margins.

On Slide 11, the Corporate and Other segment had adjusted after-tax net costs of $142 million this quarter compared to $123 million in the first quarter. The increase in net costs reflects lower capitalized interest due to project start-ups as well as certain tax adjustments.

Slide 12 shows the change in cash during the second quarter. We ended the quarter with $1.5 billion in cash on our balance sheet. Excluding working capital impacts, cash from operations was $1.2 billion. Working capital changes increased cash flow by about $700 million and include the benefit of returning to normal operations following the high turnaround activity in the first quarter. We funded approximately $500 million of capital expenditures and investments and distributed over $700 million to shareholders in dividends and share repurchases. We ended the quarter with 512 million shares outstanding, and our cash balance was $2.2 billion.

This concludes my review of the financial and operational results.

Next, I'll cover a few outlook items. In the third 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 before-tax turnaround expenses to be between $50 million and $80 million. We expect Corporate and Other costs to come in between $125 million and $140 million after tax.

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

(Operator Instructions) Your first question comes from the line of Phil Gresh with JPMorgan.

First question, just on the capital spending. Obviously, you're trending quite well. Greg, I didn't hear anything about a reduction in the full year capital budget. I think last year at this time, you did give a reduction because you're trending pretty well. So just what are your latest thoughts on CapEx for the full year?

Yes. Well, first of all, I don't think you can take the first 6 months and double it to get an annual number. But I would say we're going through our midyear capital review now. And I think in the next month or so, we'll -- we're going to give you some guidance around that. The question for us is really FID on the fracs and when do we take those. But I think we're kind of at that point of the year even if we do -- even FID them in the third quarter, we're not going to spend a lot of capital this year. It'll probably be an '18 and '19 lift for us on those. So I think you're going to see we're going to guide down in terms of capital by several hundred million dollars.

And how would you put that in the context of the longer-term outlook for capital spending, kind of the framework that you've laid out in the past?

Yes. I still think the framework of $1 billion-ish of sustaining capital, $1 billion to $2 billion of growth capital is still, we think, an appropriate -- the appropriate level for us going forward.

Got it, okay. And then just the second question, in light of the commentary on Midstream -- and there's several moving pieces here on the NGL side of things. But where are we on the $300 million to $500 million total EBITDA from the frac and the LPG export? Obviously, there are some other factors here in the quarter as well, but how would you frame that up? And when do you think we can hit that full run rate?

Yes. So I'll take a quick stab at it, and then Taylor can come over in the top and correct me maybe if I get it wrong. So the frac -- we've seen a lot of ethane rejection. We've seen heavier feeds going into the frac, and we struggled to hit design rates on the frac. We have done some debottlenecking around the C-4s, which is where our limits were in. So in the second quarter, we actually ran the frac at rate 800,000 a day for the first time since we started it up. So I think we've got that issue solved in terms of frac. So it's generating kind of that $60 million to $70 million of EBITDA that we kind of laid out originally. On the export facility, I think there's some market structure issues that we need to just think through in terms of being able to deliver on the promises that we made there. We're currently doing the 8 cargoes a month. Although in the second quarter, I think we did 20.5 cargoes. We're 3.5 cargoes short. We're kind of in that seasonal part of the year where you see those declines. And I would say, as we're moving into August, we're more than fully loaded coming into August. So I think we see good results there. As you know, dock utilization across the industry is in the low 80s. And I think we're going to have to see that utilization move up to the 90s before we can actually get the fees up. And so where we premised kind of $0.12 to $0.14. Fees, they're running $0.07 to $0.08. And so I think all in, where we're at right now, we're probably somewhere around $200 million to $250 million-ish of EBITDA in that facility against the $400 million to $500 million that we had promised, Phil. Now -- and I think as we come in to the back half of '18, we see NGLs coming at us. There's been new fracs announced. We're obviously working on 2 new fracs. And so I think that we're going to see the NGL supply, particularly propane, increase. I think you're going to see the -- it's going to be necessary to export those propane volumes out of the U.S. to clear them. And so I do think that utilizations start to improve as we move in the back half of '18 and '19. And then I think that's when you see the opportunity for those fees to increase. And I'll turn it over to Tim, and he can add some color on that.

Yes. I think that, really, the issue is that as you think about NGL price relative to crude has strengthened, particularly propane. And so I think as supply increases, you see that coming back into balance. And then it would structurally be helpful to have a higher crude price. And that has an impact as well as you think about substitution economics in the various markets, whether it be for heating or for petchem. So I think you'd like to see crude market strengthening, increased NGL supply in the U.S. That brings your utilization up and gets the chance to really open those arbs up. And until you see that -- and we think that happens out these next 18 months or so. Until you see that, you really, I think, kind of see where we are. So we work hard on optimization, reducing our cost and making improvements that we've done in terms of run rates, operating cost and the values that we get for the products. So made good progress on that, but the real breakthrough has to depend on the market improving.

Your next question is from Paul Sankey with Wolfe Research.

Greg, I might have misheard you, but did you say that the Gulf expansion -- the Gulf facility is going to be mechanically complete later this year? Because I saw a press release from you guys -- well, at least from CPChem, saying that it was already mechanically complete.

So yes, the polyethylene is mechanically complete. And I think we're really close to putting hydrocarbon into those units. So they'll be up and running this quarter. The cracker is not going to be mechanically complete until the end of the year, Paul.

Okay, I got it. And so we would expect a contribution financially next year pretty early on?

I think the big -- yes, the big contribution will be in 2018, but we'll get some contribution off the polyethylene units in the back half of this year.

Yes, got it. Can you talk about the next phase there? And by the way while you're on the subject, would you mind just looking back at the original decision to build this thing and how the market has changed, both from your own point and also the competitive environment down there?

Well, maybe I'll start backwards. I think that we're -- we still think it's a good decision to build the facility. I -- it's really made possible by the shale revolution in the U.S., and we still think that North America and the Middle East are the 2 best places to make petrochemicals. And so there's nothing that fundamentally around that view has changed. A lot of other people have jumped in and are building capacity. So no question, there's a lot of capacity that's coming up in this kind of '17 and '18 time frame. But we're still constructive on the market view. I think that this market is still growing at 1.5x GDP. As we look around the world, if anything, the economies are doing better than we kind of expected. We're seeing good results in Europe. Asia continues to be strong. We're seeing good economic results in the U.S. And so I think we feel good around the fundamentals. And we're not as concerned about the supply and demand balances out in '18 and '19 as some people are. I think that you're going to see some compression on margins as these crackers do come up. But fundamentally, I think that you kind of need 4, 5 crackers a year just to keep up with demand. And so I think we'll certainly push through that relatively quickly. I don't know, Tim, if you want to add any color on that.

Yes. I just think back on -- or reflect back a bit. I think we've anticipated that margins would come in, but they're still quite good today in the order of that -- in that near $0.30 a pound, which still provides incentive and reinvestment economics. And I think as you look out, you still see the supply of ethane in the U.S. increasing, and you're seeing already additional announcements. So I think from an industry standpoint, this still looks like a very competitive place in North America to build. The world's appetite is there. And as Greg said, I think the markets have continued to be strong. And as you think about the supply side for a couple of years, I think we've got a little flatter spot here on utilization in the next 18 months. After that, it begins to tighten up again. So I think it's still a pretty constructive market situation. And we still like investing here in North America and then in the Middle East as well. But we continue to look at options around the world.

So the first part of the question was around what are we doing on the second project. So kind of give an update on that.

Yes. So we're in the -- actually in the engineering phases of site and technology, looking at ways to be more capital-efficient. And still thinking that in the U.S., it's likely to be the next site for that. But really, an FID on that cracker, we'd see sometime after next year, sometime post 2018. We're still advancing down that because we still see the need for growth. It still leverages CPChem's technologies, and we still think it's going to be a very attractive market.

Your next question comes from the line of Doug Leggate with Bank of America Merrill Lynch.

I got one housekeeping one and one strategic one, if I may. Kevin, the housekeeping one is deferred tax. Can you help us a little bit with how you see that trending? Because it continues to be a fairly substantial piece of the cash flow year-to-date. I think it's now overtaken the full year's deferred tax for last year at this point. And I got a follow-up, please.

Yes, it is. And you'll have noticed that it was higher in the first quarter than the second quarter. So we would expect to continue to see some deferred tax benefit in our cash flow, and the primary driver there is the impact of tax depreciation versus financial. So we have the benefit of bonus depreciation on new assets that is significantly higher than financial depreciation. And so you see that effect flow through the cash flow statement on deferred tax. The first quarter was a bit of an anomaly because of the item that for earnings was a special them, the consolidation of the MLSP. And the gain on that triggered a sizable deferred tax impact there. So I would kind of ignore some of the big jump in the first quarter on that. But over the course of the year, we're still going to see a reasonable deferred tax benefit for the full year. And it will be more than what we saw last year, as you've already pointed out.

Okay, I appreciate the guidance on that. My follow-up is really more about the drop-down schedule for PSXP. And just obviously, we're halfway through the year, and I'm guessing we're anticipating something in the second half. So I wonder if you can speak to how you see the timing of the next wave of drop-downs to get to your $1.1 billion EBITDA target. More specifically -- and Greg, maybe this is for you. The corporate bond that you did at the end of last year had some unique attributes to it, and I'm wondering how that might feature into the likely funding of a PSXP drop-down as it relates to the parent-level total debt. And I'll leave it there.

Okay. Well, let me start at the high level, and then I'll let Tim and Kevin kind of wade in. We still think that 20% to 30% debt to cap on a consolidated basis at PSX is the right target for us. There was some unique characteristics about how we structured the refinancing of the debt that we did earlier this year, with the intent that we could make that drop -- debt essentially droppable into PSX as we dropped assets. And Kevin can go through a little bit more of the details. And just in terms -- we don't guide in terms of timing of drops. I mean, clearly, we're at $675 million. We said we're going to be at $1.1 billion run rate by the end of '18. And people can do the math around that and come up with their ideas. I do think that we'll have a drop in 2017 and also in 2018 or maybe multiple ones. But I still think that we have a path to get to the $1.1 billion, and we're very comfortable with that path. So Kevin, do you want to talk a little bit about the debt and how we structured that?

Yes, I will, Doug. And you're referring to the $1.5 billion of PSX bonds that matured actually in the second quarter. It was May 1 maturity. We refinanced those in April to take care of that. They were refinanced with short-term floating-rate notes and a -- and term loans that are assignable to PSXP. And so what that means is we can, as part of a drop transaction, move debt down with the drop as part of that funding, and then PSXP would have the flexibility to go out into the market and term out over a longer period of time that debt financing. So that, in and of itself, means the -- that component of the payment, if you like, for that drop would not generate cash at the PSX level, but it's also consistent with how we've talked about PSX-level debt dropping as the MLP debt increases. The MLP structure, obviously, is a leveraged structure, and it will increase debt as it grows. And so to manage consolidated debt, this is one way of accomplishing that, that we're effectively moving debt down from the parent level into the MLP.

I know it's kind of a complicated issue, just a quick point of clarification. So if you're moving debt off the balance sheet at PSX to nonrecourse at PSXP, obviously, you're not getting the cash in the door from the debt they might otherwise have raised. So how does this impact the buyback schedule as opposed to debt reduction as a relative priority of use of cash?

Yes. So it's -- but -- so a couple things. It is still consolidated debt on the PSX balance sheet. So on the PSX financial statements, that debt is still there, okay? So it does -- it reduces the net incoming cash to the overall corporation because all we've done is move debt between entities. But when we step back and look at the cash that's generated from the business from the equity markets -- and it's not that PSXP won't be doing any debt financing of its own incremental to what's coming from PSX. So we still think -- we look across holistically across all that. And it still works in terms of being able to fund the capital program, fund the dividend, fund the share buybacks.

And also, we don't have to drop the debt, right?

That's true. That's true.

Your next question is from Neil Mehta with Goldman Sachs.

I thought we'd start off on the Specialties and Marketing business. Relative to our model, that was the standout area in the quarter. So one, if you -- I'd love for you guys to talk about what was the driver of relative strength in the business. And then on Specialties in particular, anything that you would call out and whether the strength was sustainable or not?

Yes, Neil. This is Tim. On the Specialties business, it's really the improvement in our lubes business. And we talked about improved base oil margins. We also did -- Lake Charles was in turnaround in the first quarter, which is where the base oils unit is. And so this is much more what we would have expected versus the prior quarter. So I think it continues to be a business for us that's one where we continue to see fairly stable earnings. And so I look at the second quarter, and that's something that we would expect to continue more at that level versus the first quarter. So good improvement as a result of that. On the other side of the marketing side, it's really strong results in our European marketing and strong results in our U.S. marketing. And it just reflects, from a standpoint -- the spread between the rack and the wholesale margin expanded in that market environment. And it fluctuates. But generally, that's been a pretty strong performer. And so I think a pretty consistent cash flow on the marketing side and EBITDA in those businesses. And we've been, I think, pleased with the strength that we've seen both in Europe and the U.S. in terms of that spread between the rack and the wholesale margin.

I appreciate the comments. The follow-up is just around the health of the product markets. And we appreciate your guys' views in terms of what you're seeing and your outlook in terms of your views on distillate and gasoline and the outlook going into the back half of this year.

In the gasoline market. I think it's roughly flat in the U.S. We look at same-site sales. We look at reimaged sites. We're seeing strength in various regions across the U.S. being a little bit different. But it still feels to us like this year will be a lot like last year in terms of total demand. The real upside is coming, from a U.S. perspective, with the export side. The short that we've seen in Latin America, particularly in Mexico with some of the things we've had there, both in the Gulf Coast and the West Coast, have actually improved that. Europe, as Greg mentioned earlier, is doing better as well. And Asia continues to be on a global basis there. So I think we're encouraged on the demand side, but it's not over-the-top growth. But it's still been fairly good growth if you just step back and look at the global side. And the distillate crack has actually improved versus last year. And I think what we're seeing is a little more industrial activity around the world helping to support that. In the U.S. perspective, we've been able to export, and there's just been support this year on that distillate crack and with strong distillate JET sales et cetera, that have improved the overall crack in the market. So unlike 2016, I think that's helped balance the proportion of distillate to gasoline and has improved the overall profitability in the segment as a result, but still not what I'd call a supply-constrained market. And so I think that we see seasonal strength coming through the third quarter and then some tail-off in the fourth and first quarter.

If you look broadly at manufacturing PMI, U.S. level for May was the highest since 2014. Germany PMI has really spiked. China year-to-date is the highest since 2012. So manufacturing activity, the indicators we're seeing more broadly are supportive of distillate demand.

Are you seeing that translate into your U.S. marketing business as well, Jeff? And any comments in terms of what you're actually seeing on the wholesale side?

I would say, on the distillate side, we continue to see very much what we see when you think about the more retail-oriented piece of that. We see very much what we see with gasoline. Kind of volatile up and down, but not strong increases. Some increase with the oilfield, and some of those activities coming back and transportation movements, largely offset probably by efficiencies even in the diesel market. And so I think that it's related more to infrastructure additional activity around the world in that in the construction side. But I would say the distillate and gasoline markets look fairly similar in terms of just fundamental demand in the U.S. in terms of year-on-year growth, with JET being probably the one exception, where it's really been a strong market around the world.

Your next question is from the line of Paul Cheng from Barclays.

Kevin, what is the cash distribution from CPC and DCP this quarter?

Yes, Paul, so we don't disclose the specific distributions. But I can tell you that -- so it's $422 million of total distribution this quarter. If you look back over the last previous 5 quarters or so, the average distributions were $150 million per quarter, $422 million this quarter. The increase is essentially explained by what's coming out of those 2, and the bulk of it's CPChem. So we did receive distribution from DCP, but it's small compared to CPChem. And I'd also say it's still not ratable. So we probably had disproportionately more in the second quarter than you'd expect to see on a normal quarterly basis. Maybe not so much so if you look at the second quarter if you kind of -- if you think about that as a first half, then more in line with what you'd expect to see annualizing a half year number.

Actually, Kevin, I mean, with the CPChem expansion, the spending has pretty much come to an end. I'm actually surprised that you didn't expect the distribution going to be higher from the CPC than what we've seen in the first half.

Well -- and it will be as you look forward into next year especially. So you have 2 effects going on. The capital spend is coming down. So this year's CapEx at the CPChem level is about $500 million, $600 million lower than the previous year, lower than '16. And then as you look ahead to 2018, you drop off by a similar amount on capital expenditure. And by 2018, you'll see some -- you'll see the operating cash flow from the new assets as well. So you will, as you look forward, see that cash ramping up.

Okay. And the next one is for -- I think for Tim and Greg. Some of your competitors that -- have decided to move into Mexico (inaudible) and maybe bidding on some of the physical assets to -- as an extension of their export strategy. Just wondering, that -- is that a business that you guys would be interested or that you view differently?

Paul, this is Tim. We've had a long, established relationship in Mexico. So it's been a trade partner with us, so we continue to access that market. And I think you have to look at the infrastructure and say, "Is that something that you need to serve that?" So it's something you can think about for consideration. I think the second part of the question, though, is what you think about exports. And we continue to expand at Beaumont. We continue to look at ways to access additional exports out of our Gulf Coast refineries. And so that's something that we think about in terms of a Midstream and Refining investment that may be a way to leverage and really take care of, so to speak, the demand side that we're seeing from the international side. So -- and we have projects under way to look at dock expansions, those kinds of things, to increase access to all those markets, not just the Mexico market.

Right. But Tim, I guess my question is that will you -- so that sounds like that you are not yet in the camp that you necessarily need to own the physical asset in Mexico in order to expand your export capability or your wallet in that country.

I think that we'll evaluate those. But I think right now, we've been comfortable with our existing relationships that we've been able to serve that market quite well. So it really depends. If the market structure changed, then I think we'd have to think about that. But right now, we're comfortable with where we are.

Okay. The final one. If we look back, the Sweeny NGL hub, as you mentioned earlier, that right now is probably running maybe about 60% to 50% of the EBITDA of what you originally expect. Just curious that -- from a look-back standpoint, does it -- in any shape or form, does that change the way how you evaluate projects in FID, the process, going forward? Or you believe that this is somewhat unique by itself? And also, it's just a temporary event so it doesn't really change the way how you look at projects going into the future?

Yes. I think for better or worse, we're -- we kind of live in a commodity world, Paul, and we're used to both kind of volumes and margins fluctuating on us. And we really can't call the timing that well. We do think about the trends in long term, and we're always talking about the mid-cycle and thinking about the mid-cycle case. And I do think that you -- we'll have the opportunity to grow margins in that business. Certainly, the volumes are there. And as we look at what's coming at us out of the Permian over the next couple of years out of U.S. shale, I do think that we'll have the opportunity to improve the earnings in that asset. But we FID-ed it in a $100 crude world, and we're in a $50 crude world today. And so that is a big difference. In retrospect, we might have moved sooner and faster maybe to tie up some of these longer-term contracts. So I think that's a learning for us on that one, Paul. But I do think that we're still very comfortable taking commodity risk as -- at the PSX level.

Your next question is from Blake Fernandez with Scotia Howard Weil.

The cash flow was really strong, and I know you addressed a couple of the different drivers. But one was working capital, and it looks like you unwound about half of the hit that you witnessed in 1Q. So I'm just curious if you have any thoughts on how that could change here in the back end of the year.

Yes, Blake. It's Kevin. That's right. It is about half of the hit we took in the first quarter. Remember, the first quarter, you had the impact of a pretty sizable inventory build. And also, the -- we were hit on payables especially, with all the turnaround activities here effectively running down the payables balance. And so we got the payables component back to kind of more normal levels. And then the rest is just normal kind of ins and outs. So we had a slight benefit on receivables with the falling price. We had a slight reduction in inventory. And so you kind of get back to that $600 million to $700 million working capital improvement. I don't think -- as you look ahead to the third quarter, absent -- there'll be fluctuations based on prices and all that, but I wouldn't anticipate anything significant in the context of the third quarter. And then as you go into the fourth quarter, you typically have the inventory drawdown. And then it's just a question of how much of that flows through to cash versus carries forward as receivable.

Got it, okay. And then that kind of leads me to my second question, which is on the buybacks. Obviously, there was a pretty healthy step-up -- step change from where we had been trending the previous several quarters. And I guess I'm just trying to figure out, is that a function of the improvement in working capital, just a one-off quarter where we have additional cash? Or are you guys trying to strategically kind of change the profile of the distributions?

No. I think we're still at the highest level, kind of at the 60-40 split we've always talked about, Blake. I think that -- a couple things. One is we pulled capital down a lot in '16. We pulled share repurchase down in '16, just given the fact that we generate half the cash that we generated in 2015. There are always questions around where the margins were going to go in '17. And then the share price took a dip. And we just bought more shares as the share price dipped. But I -- we guided to $1 billion to $2 billion of share repurchase in 2017. I think I've also said I -- we don't intend to be at the bottom of the range this year, if that helps.

Your next question is from Roger Read with Wells Fargo.

I guess maybe coming back to some of the Midstream. Specifically in my case, DCP. That has continued to struggle. And I'm just kind of wondering, you put a lot of effort into you and your partners fixing it, restructuring it and all. And still, the results are a little bit on the soft side. So I'm just wondering, what's the thought process there? Is it an improvement in margins? Or is there additional sort of internal restructuring we should be waiting for?

I think that we did the major restructuring early this year, where essentially, what we get now out of DCP is the LP and GP distributions. There's some level of holdback at the GP level that can happen dependent on cash needs at DCP today. But you really kind of need to think about the distributions that we're going to see out of DP as really going to be related to our LP and GP ownership, which is about 38% today at the LLC level. The good news is, with the restructuring, we're getting distributions out of DCP, which is new. But when you think about DCP, I think in kind of a mid-50, let's say, NGL price environment, I think they'll be able to cover their distributions. So I think that -- I don't know if DCP is completely fixed, if you want to put it that way. But I do think we made a lot of great progress in terms of the cost structure, the contract portfolio work that's been done. And then just the fact that the NGLs are kind of trading up in that mid-50 range has been very constructive for DCP. And so I -- as we move forward and we think about NGLs going forward, I think we're still pretty constructive on the NGL prices going forward, particularly as ethane starts to come out in rejection.

Roger, it's Tim. So as ethane comes out, the volumes come up. And if you look at DCP, some of the opportunity that they're seeing is the DJ Basin, the Permian, particularly with Sand Hills, the debottleneck. And so the volumes have been increasing there. So I think that you need a stronger environment where we're seeing, and the crude gas and NGL markets would help that. But then beyond that, it's just continuing to increase that fee-based business. And that's where they really put their emphasis, and they're looking to expand their G&P footprint as well as your pipeline connections to do that. So I think it takes some time. But at the current market rates, they're in a pretty good position with the backstop and the GP IDRs to help that transition period.

Okay great. And then to completely change gears here, on the Refining side. Light/heavy diffs have been narrowing. You seem to come through Q2 without too much trouble on that. I was just wondering, as you look at Q3, and then obviously some risk on Venezuelan barrels one way or the other, how you're looking at the light/heavy. Have you switched aggressively to a light barrel? Is there -- what is your flexibility from this point forward? Kind of what other measures would you take at this point?

I think in second quarter, we ran about 6% less heavy crude, 3% more medium, 3% more light. I think our view is that just given all the operational issues in Canada, what's going on with the crude cuts in the Middle East and troubles in Venezuela, I think you're going to see light/heavy diffs kind of pressure into the third quarter. I think as we come in the back half of the year, you'll see some of the operational issues may be solved, Mildred Lake and different places. You get into a refining turnaround season and the fall turnaround season, you might see those diffs open up a little bit more. But I would expect coming into the third quarter, they're going to be pretty narrow.

Your next question is from Justin Jenkins with Raymond James.

I guess I'll start with a dovetail on Roger's question there on -- and get one on light crude differentials. It seems like Brent versus WTI has been reasonable, and the Permian has shown a few signs of life in terms of discounts. Is there the potential that we see PSXP maybe look to get a bigger -- even bigger presence with upstream customers to maybe gain better control of those barrels or, at least, maybe the quality of the barrel?

Yes. Justin, it's Tim Taylor. So I think PSXP continues to look at the Permian and the areas of SCOOP/STACK. You've seen that JV. We're expanding that work, extending the reach. That's a very attractive barrel, for instance, in our Ponca City refining system. Plus, it has trading opportunities around the Cushing hub. So I think we all continue to look at ways to tap into that increasing light supply. I do think that the Brent-WTI differential just ends up being -- kind of stays narrow because of the opportunity to export now. So it's also letting us, at PSX, expand at Beaumont as we've seen a demand for movement across the dock as well as storage there. So I think as this continues to develop, there are opportunities in the Midstream to capture that liquids inflow. But I don't think that you're going to see light differentials between Brent and WTI really come out unless we get truly infrastructure-constrained, and that doesn't look like it's going to happen in the very near term. It will take a substantial increase in the Permian or the -- some other play to really drive that, and we'll see if that goes. But I think now with exports, you really limit that opportunity for a "blowout".

I think our view is that infrastructure seems to be keeping up at this point in time.

Okay, sounds about right. And then I guess staying in Midstream, it seems like the capital program there has also trended a bit below the 2017 budget. Is it something that's back-end loaded? I guess maybe it's one of the potential fracs maybe being in PSXP.

Well, I think most of our growth capital is in Midstream, and so I think that's where -- as we give the guidance here in the next month or so that's where you're going to see most of the cut. And you're right, it's a lot around the timing of the fracs and the uptake of the fracs in terms of actual versus what we had budgeted.

We've also seen about 1/4 slippage in the Bayou Bridge, which was with our joint venture with Energy Transfer and Sunoco, eastbound out of Lake Charles over to St. James. And so that's affected the spending and the timing a little bit. But I think that we -- in the Midstream, we just carefully evaluate the opportunities, still growing Beaumont and some of the options around our basic skeleton. But I think that you've got to see those commitments on the producer side, and I think they've grown a bit more cautious on that.

Your next question is from Faisel Khan with Citigroup

Just I want to clarify the distributions from CPChem. As the project -- the ethane cracker sort of reaches completion, is it -- is there some other -- is there some debt that has to be paid down at the joint venture? Or should we expect that distributions sort of ramp up as the profitability takes off?

Yes, Faisel, it's Kevin. There is debt at CPChem that matures in 2018. And so one of the questions that the owners need to answer is, do we use the cash flow to pay off that debt as it comes due. Or do we refinance and term some of that out, which would obviously enable more cash for distribution. So that's something that we'll work through with our other owners around that. So that can be a factor. But nonetheless, even with paydown of debt, we would still assume an uptick -- incrementally higher distribution in 2018 compared to 2017.

Okay, got you. And then the -- separately, the Jones Act tankers that you guys sort of contracted for a few years ago, when are those up for -- when are those contracts up? And do you see yourself sort of coming back into the market to continue to move crude, I guess, from the Gulf Coast up to the Eastern seaboard? Or has that opportunity sort of evaporated?

No. I think there's still Jones Act demand on the product and the crude side, and so we have various phases on commitments on that. So we just look at that every time those commitments come up as that makes sense in that term. But it's not as tight as it was a couple of years ago. So I think we leave that more as an optimization as those leases come up. But we have a -- I think I'd say we have a comfortable position with our commitment exposure on Jones Act.

Your next question is from Craig Shere with Tuohy Brothers.

Do you see enhanced vertical integration with a potential FID of a second Sweeny frac later this year helping to ultimately widen out and stabilize LPG terminal margins?

Okay. So as -- if I interpret your question, a, I think the next incremental investment is more cost-effective. And as you increase the production of propane in your internal fracs, there's an uplift as well. So the incremental decision has more traction. That said, we still need to make sure it makes sense in the context of total return. But it would be an improvement with the already sunk investment in pipes, caverns and the LPG dock to help drive higher utilization across that system.

Well, that's a good point, that the second frac is definitely going to be more economic and cheaper to build. And you all also foreshadowed that you might be lowering 2017 growth CapEx. Kind of as a segue, if recharging Midstream growth CapEx takes longer than expected, can you see share buybacks continuing to trend up possibly above $2 billion? Or would you be looking to possibly build cash over time in an environment with fewer initial growth opportunities?

Well, I'll take a stab at that. At a higher level, I still think we're comfortable with $1 billion to $2 billion of growth capital longer term and $1 billion to $2 billion of share buybacks longer term. I think you can tweak that in any given year, given where you see your investable opportunities, where you see cash going on. And certainly, we did that in 2016. But long term, we're committed to investing in the business. Our investments have to hit our hurdle rates, obviously. And then in terms of the share repurchase, as long as we're trading below intrinsic value, we're going to buy our shares. And so we think it makes sense in today's environment, so we're buying today.

Your next question is from Spiro Dounis with UBS Securities.

Just wanted to start off with, I guess, the concept of moving maybe more product into pad 1 from pad 2. Obviously, some news out there about pipeline reversals. And just given your unique position, I guess, on both sides of that, do you view something like that as viable or even makes sense over the longer term?

Well, this is Tim Taylor. So today, the Gulf Coast, for instance, the Colonial arb is still closed. And so I think if there's anything that connects these markets, makes them more efficient, pad 2 is different than pad 3. And it may make sense from a pad 2 perspective that, that excess material can go, so to speak, can go into pad 1. So I think that has to rest on its own merits of what you believe those long-term diffs would be and where the product placement on utilization could be. So I can't speak to the merits of that directly because that's not a project we're looking at. But if you think about balances, it may be a way to balance pad 2 length with that. And then you either adjust Colonial or imports or a similar type of supply into pad 1, which is still an import region in the U.S.

Okay. So it sounded like flows would still be pretty seasonal. So if there was a pipeline reversal, it's not like it's going to be utilized all year round it sounded like.

It really just depends on the value of imports versus where you are on supply out of the U.S. system. So it could very well be structural as well as seasonal.

Got it, appreciate that. Second quick one here just on the Refining configuration. It seems like you took a bit of a larger hit this quarter on it, and so just curious maybe what was driving that. And more broadly if you'd comment either for you or your peers if you're skewing a little bit more towards gasoline or distillate these days.

Spiro, it's Kevin. Specifically on our variance on capture driven by configuration. If you look at the market crack, the way we calculate our global market crack, the entire improvement in market crack was gasoline. Distillate crack was essentially flat quarter-over-quarter. And so that will drive a larger impact to that configuration component of the reconciliation from market down to realized.

Yes. I think maybe about 45% gasoline and 38% distillate in the second quarter.

Got it. And then just in terms of where you're running these days, either max gasoline or distillate, how you're thinking about that.

So I think that this is the peak driving season, so you definitely skew it toward more gasoline on the supply side. But unlike last year, there's still support at distillate. So I would say that you've got to just optimize around each and every refinery and their configuration. But this is the peak season, so you do tilt more toward gasoline. As you get to winter, you're going to tilt more toward the distillate.

Yes. We're pretty close to max gasoline right now.

Yes.

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

Thanks, Julie, and thank all of you for your interest in Phillips 66. If you have additional questions, please call Rosy, C.W. or me. Thank you.

Thank you, ladies and gentlemen. This concludes today's conference. You may now disconnect.