菲利普斯66 (PSX) 2015 Q2 法說會逐字稿

Welcome to the second quarter 2015 Phillips 66 earnings conference call. My name is LeAnn, 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 Kevin Mitchell, Vice President of Investor Relations. Kevin, you may begin.

Thank you, LeAnn. Good morning, and welcome to the Phillips 66 second quarter earnings conference call. With me today are Chairman and CEO, Greg Garland, President, Tim Taylor, EVP and Chief Financial Officer, Greg Maxwell, and EVP, Clayton Reasor. The presentation material we will be using during the call can be found on the Investor Relations section of the Phillips 66 website, along with supplemental, financial and operating information.

Slide 2 contains our Safe Harbor statement. It's a reminder that we will be making forward-looking statements during the presentation, and our question and answer session. Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here on the second page, as well as in our filings with the SEC.

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

Thanks, Kevin. Good morning, everyone, and thanks for being with us today. We had a strong quarter, adjusted earnings were $1 billion or $1.83 per share. Our refining, chemicals, marketing specialties businesses all made significant contributions to our operating results for the quarter.

Our global refining business improved utilization to 90%, and also benefited from strong market cracks. We safely completed major turnaround and pipeline replacement at our Humber refinery in the UK, on time and under budget. Our US refineries ran at 95% utilization.

Marketing sales volumes were up, reflecting increased gasoline demand. We're executing well on our Midstream growth projects. Sweeney Fractionator One is 90% complete. We expect mechanical completion this fall.

The Freeport LPG export terminal is nearly 50% complete, with expected start-up in the second half of 2016. Both projects are on schedule and on budget.

Our Master Limited Partnership, Phillips 66 Partners, increased its quarterly distribution by 8% over the first quarter. We expect that Phillips 66 Partners will deliver a five year 30% compound annual distribution growth rate through 2018. Total General Partner distributions to Phillips 66 continue to grow. They are up 50% versus last quarter.

DCP is an important part of our NGL value chain, it's one of the nations largest natural gas gatherers and processors. DCP is doing a good job. They're operating well, they're managing costs. The Lucerne 2 plant in the DJ Basin came online in the second quarter.

In chemicals, CPChem benefited from rising cash chain margins and ran well during quarter. CPChem also began operations of its 220 million pound per year normal alpha olefins expansion project at its Cedar Bayou facility in June. Construction continues on CPChem's Gulf Coast petrochemicals project, which is now about 50% complete, start ups mid 2017. The project remains on time and on budget.

During the quarter, we generated strong cash flow. We used $1.2 billion of cash flow to support Midstream growth, and to maintain operating integrity of our refining system. In addition, compared to the first half of 2014, controllable costs are flat. We maintained our capital disciplined approach in terms to capital allocation.

During the second quarter, returned over $600 million to shareholders in the form of dividends and share repurchases. We increased our dividend 12% this quarter. We've completed $5.6 billion of the $7 billion in share repurchases authorized by our Board, and since our formation, we've increased our dividend 180%.

With that, I'm going to turn the call over to Greg Maxwell who will go through the quarter results. Greg?

Thanks, Greg. Good morning. Start on slide 4. Second quarter adjusted earnings were $1 billion or $1.83 per share. There are two significant special items that are included in reported net income, but excluded from adjusted earnings.

First, DCP recognized a partial goodwill impairment that negatively impacted our reported earnings by $126 million after-tax. The impact of this impairment was more than offset by the recognition of $132 million after-tax deferred gain that was related to the 2013 sale of the Immingham combined heat and power plant. Excluding negative working capital changes of $300 million, cash from operations was $1.8 billion which included distribution from CPChem of approximately $800 million. We reinvested approximately $900 million on Midstream growth projects and $300 million in refining.

Through the second quarter, dividends and share repurchases have totaled more than $1.3 billion, which represents more than 70% of adjusted net Income for the first half of the year. At the end of the second quarter, our adjusted debt-to-capital ratio excluding Phillips 66 Partners was 26%, and after taking into account our ending cash balance, our adjusted net debt-to-capital ratio was 11%. The annualized adjusted return on capital employed through the second quarter was 13%, and excluding special items, our adjusted effective income tax rate was 33%.

Slide 5 compares second quarter adjusted earnings with the first quarter on a segment basis. Overall, quarter-over-quarter adjusted earnings were up $168 million, driven by increased earnings in refining and chemicals. Next we'll cover each of the segments in more detail.

Starting with the Midstream on slide 6. Our transportation business continues to be a source of stable earnings. Included in the transportation and NGL results is the contribution from Phillips 66 Partners. During the quarter, PSXP contributed earnings of $25 million to the Midstream segment.

DCP Midstream is addressing the challenges associated with the lower energy price environment, and they continue to deliver on cost reduction targets, while providing reliable service to their customers. We're continuing to work with our co-venturer to evaluate alternatives to address DCP's capital structure. Annualized 2015 year-to-date adjusted return on capital employed for this segment was 5%, and this is based on an average capital employed of $5.7 billion. The return for this segment continues to reflect the impact of lower commodity prices, as well as increased capital employed due to the significant investments we are making in Midstream.

Moving on to slide 7. Midstream second quarter adjusted earnings were $48 million, down $19 million from the first quarter. Transportation earnings for the quarter were $65 million. This is unchanged from the prior quarter.

Transportation benefited from increased volumes, offset by the benefit of a claim settlement in the first quarter. Our NGL business had lower earnings due in part to lower seasonal propane volumes. DCP Midstream had adjusted losses in the second quarter that were higher than the prior quarter, and this is mainly due to asset sales which account for $11 million of the negative variance.

Moving on to slide 8. In Chemicals, the global olefins and polyolefins capacity utilization rate for the quarter was 91%, reflecting lower turnaround activity compared with the prior quarter. Both the O&P and SA&S business lines benefited from higher margins. The 2015 annualized year-to-date adjusted return on capital employed for our Chemicals segment was 21%, based on an average capital employed of $4.8 billion.

As shown on slide 9, second quarter adjusted earnings for Chemicals were $295, million up from $203 million. In olefins and polyolefins, the increase of $84 million was largely due to higher cash chain margins. O&P equity affiliate earnings improved as a result of higher sales prices, as well as increased volumes due to the completion of turnaround activity in the first quarter.

The segment also benefited from $28 million in insurance proceeds related to CPChem's 2014 Port Arthur ethylene plant outage. Specialties, Aromatics & Styrenic earnings improved on higher styrene margins from CPChem's equity affiliates.

Moving next to refining. Realized margins for the quarter were $11.70 per barrel, largely driven by strong market conditions. Market capture decreased from 80% to 62% in the quarter, due to our configuration which yields less gasoline and more distillate than is premised in the typical [3:2:1] crack spread. In addition, we saw tighter crude differentials along with higher losses on secondary products.

Refining crude utilization increased from 90% from 84% in the first quarter, and clean product yields in the first quarter were 84% consistent with prior quarter. Annualized 2015 year-to-date adjusted return on capital employed for refining was 16%, and this is based on an average capital employed of $13.5 billion.

Moving to the next slide. The refining segment had adjusted earnings of $604 million, up $109 million from last quarter. Overall, the improvement this quarter was primarily due to improved gasoline crack spreads, partially offset by lower distillate margins and higher secondary product losses. Adjusted earnings were higher than the first quarter in every region.

Atlantic Basin, adjusted earnings reflected down time from the planned Humber turnaround, but benefited from higher margins and the lack of foreign exchange losses that occurred during the first quarter. The Gulf Coast was up from last quarter, reflecting improved capacity utilization and reduced maintenance costs at the Alliance partially offset by lower realized margins.

For the central corridor, we showed moderate improvement due largely to higher volumes compared to the first quarter, which had planned turnarounds at the Ponca City and border refineries. This was partially offset by lower margins driven by narrower differentials on Canadian crudes.

And for the western region the improvement was driven mainly by increased margins. Despite crude supply impacts on our San Francisco refinery as a result of the Plain's pipeline outage, the western region utilization rates improved to 94%. We continue to pursue permitting of the Santa Maria rail rack project to increase our crude supply optionality.

Next we'll cover market capture on slide 12. Our worldwide realized margin was $11.70 per barrel versus the 3:2:1 market crack of $18.94, resulting in an overall market capture of 62%. Our configuration allows us to produce roughly equal amounts of diesel and gasoline which reduced our realized margin relative to market, as the improved market crack was driven by the strength in gasoline.

Benefits from feedstock advantages were not high enough to fully offset secondary product losses, which were substantial given the rise in crude price relative to coke and other secondary product prices. The other category, mainly includes costs associated with ren's, outgoing freight, product differentials and inventory impacts. A regional view of our market capture is available in the appendix.

Moving on to marketing and specialties. This segment posted another strong quarter, thanks to higher domestic marketing volumes and continued strong margins in our lubricants business. Annualized 2015 year-to-date adjusted return on capital employed for M&S was 25%, on average capital employed of $3 billion.

Slide 14 shows adjusted earnings for M&S in the second quarter of $182 million, down $12 million from the first quarter. In marketing and other, the $10 million decrease was largely due to foreign exchange losses, as the dollar weakened against the pound and the Euro, and this decrease was partially offset by higher domestic marketing volumes.

Moving on to corporate and other. This segment had after-tax net costs of $127 million this quarter, which included fixed asset write-offs, and an environmental liability accrual together totaling $15 million. Net interest expense and corporate overhead decreased, compared to the first quarter.

Next I'll talk about our capital structure. Consistent with last quarter we're showing our capital structure both with, and without Phillips 66 Partners. Excluding Partners, we ended the quarter with an adjusted debt balance of $7.9 billion, an adjusted debt-to-capital ratio of 26%, and a net debt-to-capital ratio of 11%.

The next slide shows our cash flow during the quarter. Starting on the left, excluding working capital, cash from operations was $1.8 billion. Working capital changes resulted in a negative impact of $300 million primarily due to the timing of federal income tax payments.

We funded $1.2 billion of capital expenditures and investments, and distributed over $600 million to shareholders in the form of dividends and the repurchase of over 4 million shares, resulting in 538 million shares outstanding at the end of the quarter. And we ended the quarter with a cash balance of $5.1 billion.

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

For the third quarter, in chemicals we expect the global O&P utilization rate to be in the mid 90%s. In refining, we expect the worldwide crude utilization rate to also be in the mid 90%s, and pre-tax turnaround expense to be about $120 million.

In corporate and other, we expect this segments after-tax cost to be lower after recognizing some infrequently occurring items in the first two quarters. We expect corporate costs to run between $110 million and $120 million for each of the next two quarters, and company-wide, we expect the effective income tax rate to be in the mid 30%s. As for 2015 capital expenditures, our original $4.6 billion guidance remains unchanged.

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

Thank you

(Operator Instructions)

Doug Leggate from Bank of America.

Thank you, good afternoon, everybody. Hopefully, you can hear me okay. I wonder if I could start -- I guess, I don't want to be too predictable here, but just maybe just get your latest thoughts on the DCP situation. It looks possibly the trailing debt multiple is fairly elevated, [and at this point just curious if you had any thoughts] to a solution that yourself and your partner can live with? And I've got a follow-up please.

Yes, so I'll start. I always like to start with, it's a good business. We like the business. We like the assets. We think the basins they are in are good long-term value creating basins in the Permian Eagle Ford, DJ, the Mid-Con, so we like the asset footprint. Clearly we needed to do some restructuring at DCP. We need to delever.

I think that we're engaged in conversations with our partner on how best to do that. I think what you heard Greg say in the notes, but sometimes this fall we expect to get to a resolution on that. DCP is doing all the things they need to do, in our view in terms of running the business safely, reliably. They've taken out a lot of cost, and we've reduced CapEx, et cetera. And so, from an operational standpoint, they're solid on that.

And what we're trying to do at the end of the day, is structure DCP for the long-term, so that it can remain the largest natural gas gatherer, the largest NGL gatherer in the US, and have a good platform which you can continue its future growth. And so, I think with that we'll get to the right resolution for DCP. I'm confident of that, Doug. It's just going to take some time.

All right, and I appreciate the answer, Greg, and I know it's not an easy thing to deal with. I guess, my follow-up is really more the current industry in the MLP world, we've seen a number of your competitors do some fairly aggressive things, in terms of boosting their GP growth output through acquisitions. You've obviously announced your joint venture on the pipeline, but I'm just curious as to structurally, are you thinking differently about how to bring forward that GP value, or are you still happy to move forward, with your growing growth projects that you've got in place right now?

Well as you know, we've got a nice backlog I would say, but we've got a great opportunity and organically to grow the MLP. We certainly have a lot of existing EBITDA left at PSX, also in terms of that, and so our view. But as we think about the MLP, I think we've come to the conclusion that we want PSXP to be a fee-based entity going forward with high growth rates. We think we create the most value by doing that.

Not saying we would never entertain an idea of an acquisition there, but it would certainly have to be something down the fairway that is fee-based, complementary to the assets portfolio we have today, so crude pipelines, terminals, et cetera, and that we maintain that fee-based structure going forward. And then I think you also have to acknowledge that everyone gets treated fairly, whether it's the GP or the LP unitholders. And so, I think that you have to think that all the way through in terms of the partnership.

Maybe a quick follow-up if I may. On the GP value itself, I know it's still relatively early days, but is the intention at some point to make moves, to make out the value more [transparent], in other words take out public or? Because obviously you've got some of [one would imagine there is] C-corp consolidated discount in there? And I'm just curious on your thoughts on that? And I'll leave it there, thanks.

Okay, well. Thanks for your questions, Doug. So I would say we'll certainly make it transparent, and we are going to tell you exactly what it is, and you can read it in the report. I think the question I keep asking is, do you have to put a public marker out there to realize the value back into the C Corp. And there's probably examples on both sides of that, and there's probably no guarantees either way. I don't think we're in a hurry to answer that question.

I think we'll be patient. I think we say that we would never consider it IPO'ing the GP. I don't think we would ever say that. I think there may be a point of life cycle in MLP that leads you to do that, but it certainly is not in the near future for us, Doug.

I appreciate it, thanks, guys.

Absolutely, thanks.

Edward Westlake from Credit Suisse.

Yes, I guess, following on DCP, I mean, I guess a lot of people feel that obviously the business needs new capital. But we're also hearing that the impasse, or the concerns or maybe underinvestment is impairing DCP's actual operations and customer reputation. So I wondered if you wanted to address that great brownfield position, but how the business is performing?

We're still investing in growth in DCP. We're very interested DCP's reputation. We want DCP to be viewed as a long-term reliable partner with some very large people out there, of you think about the portfolio that DCP has today. So I would say we're very sensitive to that, Ed.

I think they're operating well, their volumes are solid. Where we're seeing some volume degradation, is mostly around ethane rejection that's coming out of the let's say, the Mid-Con Rocky areas. But the volumes are certainly holding up in core regions in the Permian and Eagle Ford, et cetera. And so, but long-term, we've got a position DCP such that it has the capacity to grow, and it has the capacity to be there for the folks that are out there in the field, and that's exactly what we intend on doing.

And then switching to refining, you were clear this year was going to have a little bit more maintenance. Maybe a little bit of an update on the outlook for the second half of this year, and whether this period of maintenance extends into 2016? And maybe a little bit of color on any benefits that you've driven into the plant, as you've taken the opportunity to take some of these plants down?

Well, I think our guidance for the year remains consistent in terms of turnarounds. Obviously, 2015 is a heavy turnaround for us, we knew that going into 2015, and we kind of communicated that. I think 2016 probably won't be as heavy year as what we've seen in 2015. It will be more of a normal year of turnarounds for us. We are trying to get on five year cycles between the major assets, and we're doing a pretty good job of getting there in our view. And I'll let Tim, if you want to make some comments?

Sure. On the benefit of turnarounds, clearly you get cleans, so you can run at a high utilization post turnaround. And second of all, we've identified that we wanted a 4 point improvement in refining, we're on that path. And about half of that or a little bit more comes from cost, yield, reliability. So turnarounds are a chance for us to do things like the flash column at Alliance for light crude. It's ways to upgrade controls, improve reliability. And so, we take that opportunity to really improve, I guess, you might call it the robustness of the operation. So we anticipate going forward that it provides us additional consistency and reliability as we get through that.

So we should mainly see it in OpEx, and maybe a little bit of capture?

Yes, I think on operating utilization and OpEx, you bet.

Okay, thanks very much.

I should mention yield as well. We take chance to go in and do distribution on vessels, and in terms of getting more efficient, and that's one of the ways you can tweak the clean product yield in your system.

It's really sometimes gets hard to quantify, but capacity creates probably 1% to 2%, if you want to think about it on basis, and maybe up to a percent yield improvement. And so, they are real dollars, and they're certainly ones that we know how to capture, Ed.

Thanks very much.

Jeff Dietert from Simmons.

Good morning.

Good morning.

It looked like a very strong performance in the chemical segment this quarter. I was hoping you could talk a little bit about the fundamentals in the business. Oil prices are still low, yet your margin strengthened again. And if you could talk about demand, both domestically and in the export markets?

Yes, Jeff. Really what we're seeing on chemical side, is I think we're still in the up cycle in terms of a demand driven cycle. When you look at supply increasing relatively modestly, and we're just seeing really good demand around the globe The US has been good. Export opportunities out of the US are good, and the Middle East operations are running very well.

I think as an industry, the US and Middle East run full. Europe is coming back a bit with some of that slack, as well as Asia. But I think it just speaks to the fundamentals. We have seen that demand improve, and we anticipate over the next couple of years that will help pull that utilization. And that's an important factor, just as much as the cost piece is, but we've certainly seen the LPG costs in the US come down a bit more relative to crude as well, which has helped. But I think this is largely kind of on the demand side, that we're seeing. And so, we feel that the demand piece in the world has actually been fairly good from a chemical standpoint.

Yes, I think our view is -- I'm sure we'll get to crude at some point in time, but our view is crude is going to be lower longer, NGLs lower longer. That's directionally positive for margins and chemicals and demand from chemicals, albeit I think recent, and it's topical news, the question is in demand in Asia. But what our experience is, every time you see crude prices fall, you see some reduced buying activity in Asia, as folks are trying to time the bottom there. And so, I don't think we're concerned about the fundamentals of demand in Asia, at this point in time.

Any information you can share on exports, chemical exports, regionally, Asia continuing to be a large percentage? How are those exports evolving as far as regional markets?

Well, I think the US is and the Middle East are the large suppliers on the global market, and Latin America out of the US is a proximate market. But the large demand pull continues to be Asia, and that's really met through the US and through Saudi Arabia.

I think Europe has seen improvement in their economy, but that's largely self-supplied. So I think the global recovery that we're seeing in demand kind of spread evenly. But in the end, it's that pull from Asia which is the largest pull, and then you serve that really from the low cost centers in the Middle East and the US. So a lot of opportunity built around that. But generally, I would tell you that we see good demand relatively in almost every geography. It obviously depends on which geography and the growth rate, but the developing piece of the world still has good demand.

Thank you for your comments.

You bet, thanks.

Evan Calio from Morgan Stanley.

Good afternoon, guys.

Good afternoon.

Let me lead off, with really a follow-up to Doug's earlier strategic question. Greg, what's your view on the Midstream asset or corporate markets, where we seen two major transactions that could be the beginning of a bigger consolidation wave? I mean, do over time, do you still see PSX as a potential and natural consolidator, given the GP uplift at PSXP, and currency premium in the MLP? Or has DCP really been occupying your near-term bandwidth?

No, I wouldn't say DCP is occupying our near-term bandwidth at all. I think, it's obviously something we want to get done and get fixed, and I think we're on path to get that done. I mean, it's interesting to watch how all of this has unfolded, there's -- you may have one shot at it and your currency is gone, if you want to think about it that way. But we like -- well, so fundamentally, we have a great organic backlog.

We have $20 billion-plus of backlog of projects, and we don't feel the need to rush out and do something. We already have a Midstream business, so we don't need to move there. We have a diversified portfolio across PSX, so we're in chemical, priming, gathering and processing, and so we don't feel the need.

We're shifting our portfolio to higher multiple, higher value businesses. We're on track, we're on plan. If there was something out there that was complementary, we would certainly take a look at it from a PSXP standpoint. But to somehow, push the yield up, by going and doing an acquisition that put commodity risk and exposure into PSXP, we just don't have any interest in doing that right now.

Right. Maybe that's a natural segue to, when you talk about growth, organic growth. You recently announced a JV with Energy Transfer and Sunoco to build a pipeline in Netherland to St. Charles -- Nederland to St. Charles, sorry. Maybe you can discuss the MLP, will EBITDA benefit? The dual benefit's there from a Midstream drop-down aspect, as well as potential volumes that you could contract with Alliance and make refinery more competitive with the Houston ARB?

Well, you've answered the question pretty well (laughter). I'll let Tim talk about his new pipeline.

Yes. So it's a great extension of our Beaumont terminal, good partners with Sunoco and Energy Transfer. This is a 30-inch line coming out of Beaumont over to Lake Charles, and we just announced a supplemental open season to determine if we want to increase the capacity east of that into St. James, as part of this announcement. But we're actually under construction now from Beaumont to Lake Charles.

It starts to bring those Texas crudes into Louisiana, a lot of interest, a lot of demand, and you're absolutely right. There's a knock on effect in terms of the value that we can have both at Lake Charles and Alliance. In terms of the project size, depending on the size of the pipe, the number that we look at is between $700 million and $900 million of investment. We're a 40% owner and we get a typical Midstream build multiple say, of 7 on that, Gives you some idea of the impact that it has. So it's a significant add to the MLP-able Midstream EBITDA. So we're happy. I mean, it's got good fundamentals, so we really like that project.

Well, building at 7 and dropping at 10, and improving your refining margins, pretty good business. Thanks, guys.

Yes, got good fundamentals.

Thanks, Evan.

Paul Cheng from Barclays.

Hi guys, good afternoon. Greg, on the DCP, sorry, to ask that one more time, does the partner already have agree on a timeline to find the solution? I mean, that in October that they have $700 million that of the debt needs to be, I think that refinanced. So is that a [set] as a deadline, that you need to have a solution or that doesn't really matter?

Well, I think that's part of the equation we're trying to solve here, to get to a restructuring of DCP. I think our view is clearly, there's going to be a deleveraging event. And so, I mean the fundamental question is, how do you make that happen? And I think that's what we're working through with our partner, and with the folks at DCP. So but yes, I have a high degree of confidence we'll get that done.

But I guess, Greg, my question is there already a time line is being agreed between the two partners, in that when you guys will need to find the solution? Or that you are just going to continue to work on a solution, but not really have a time line in mind?

Paul, this is Greg. As fact as liquidity perspective, you're aware DCP has a $1.8 billion revolving credit facility. I think what you're referencing is the $200 million bond that comes due at the LLC level in mid October. Still has some liquidity available under the existing revolving credit facility. So from that perspective, it's not a bright line of October that has to have something completed. However, we are as Greg indicated, working with our partners to get something done from a restructuring perspective as soon as we can.

Okay, Greg since I've got you here do you have a preliminary 2016 CapEx number that you can share?

2016? (multiple speakers)

Oh, 2016? (multiple speakers)

Yes. (multiple speakers) 2016 any preliminary estimate that you can share? (multiple speakers).

Paul, what we said is $3 billion to $4 billion in terms of that. We go to our Board in October for approval of the 2016 capital budget. So I don't want to get too far ahead of ourselves. But as we're thinking it through, it's going to be in that range, which will be down from $4.6 billion this year.

Should we also assume that by 2017 that number will be further down?

It's possible that it may come down some. But as we -- but part of what we ultimately want to do is see Midstream growth funded by PSXP. And but we've got a lot of projects on our plate that we want to get done, and we could easily see $2 billion of Midstream investment for the next couple of years I think. And then the question is, where does it get funded, at PSX or PSXP?

And, final question for me. Tim, maybe this is for Tim. Seems like that the industry is having a very tight supply on the high octane brand component. The question is that within your system, is there any good low cost debottleneck opportunity for your reformer and alkylation unit?

Yes, Paul, you're right. We see, I'd say octane still being a very strong demand, in that we expect that to continue given light crudes, the paraffinic and naphthas that come out of that. And so, I think there's a continuing pull. And so we've got a variety of small projects that we're looking at around alkylation units and reformers to find ways to drive little higher production through there. And then, we'll watch that market, and see if there's a need for a larger solution. But there's a lot of opportunity within our existing system to drive some additional octane improvement through a variety of ways, the [osonomerization] units for instance, et cetera. So a lot of things on the table, given what we see and given the outlook that we think is going to be there for the need for octane.

Tim is there something you can quantify saying, we are talking about 20,000 or 50,000-barrel per day kind of opportunity in terms of expansion? Any kind of data that you can share?

Kind of in the preliminary piece. I haven't summed it altogether, Paul. We can get back, as we look at a little more detail. But it's not huge in terms of the size of a new plant, but I'll get back to you on kind of the rough estimate of what we think we can do. But it's not a massive new amount of capacity in that.

I see, thank you.

Blake Fernandez from Howard Weil.

Yes, good morning. Greg, you kind of invited the question on crude. So I'd be curious to get your thoughts there. But more specifically, I think the list time I had a chance to visit with Tim, your LP models were prompting kind of a shift from heavy to light, and more specifically, a focus on imported barrels rather than domestic barrels. And I'm curious if you can update us with the current landscape, if that's still the situation right now?

Yes, I'll take a stab at it, and then Tim can come clean up behind me here. So to start backwards, there's no question, was [diffs] came in, we actually set cars on the siding. We brought imported crudes in, into the system. I'd say, given where our expectations are for the third quarter, I'd say cars are coming off the sidings, and we're going to import less crude given what we see going on with [diffs].

So you think globally, we think crude is over-supplied, and we continue to think that. OPEC is up 1.5 million barrels a day versus February, it looks like to us. Production in the US isn't falling as fast as people kind of expected, if you want to think about that. And clearly, we've got better North American crude logistics today than we did a year, or two years ago. And the dollar's strong, as you want to think about that. And so, I think all that just says crude is over-supplied for some period of time.

So as we think about the markets, we kind of expect that cracks come in the fall profitably, but diffs widen. So margins will still be relatively healthy is our view, as we go into the fall season, given turnarounds. And distillate looks problematic to us globally, as we think about -- there seems to be plenty of distillate around the world today. Gasoline demand continues to be pretty good, but that will peak this summer and tail off in the fall as it normally goes. So, just sum it up, it looks like there's plenty of crude out there, and will continue to be for some period of time. And then, we flex our system, we flex max gasoline in the second quarter. And I don't know -- any more color you want to add-on that Tim?

Well, I think in summary, we're seeing North America supply probably increasing right now. You've seen the diffs widen, and so I think fundamentally we anticipate less imports for us on the light side going forward, better utilization of inland crudes. The rail utilization is coming back up, particularly to the East Coast, more supply Canadian crude. And so I think that's the dynamic that we see, so I think to Bill and Greg's point that's what we think is going to help drive the shift in the crude slate. So we're optimizing around that. But that would be the big change I'd see, given the really narrow diffs that we saw. But in response to that, we increased imports, and I think at this point we'd anticipate that would go back down.

Okay that's great. Maybe I'll use that as my follow-up then. Tim, earlier you were talking about the opportunity to increase capture and a lot of that associated with yield. If I recall you guys had previously provided kind of an outlook on increasing your ability to process domestic crude in your system. And I was just trying to see where we are in that process, if you fully maximized that opportunity or where do we stand there?

No, I think there is still incremental improvements. We did turnaround Alliance, let us put into place a column to be able to run lighter crudes there, got some work underway at, for instance at Wood River, which is an interesting one. We can increase heavy crude input, but that's because we can take the light fractions out.

So I think we're looking around the system, still looking at ways, particularly in the Gulf Coast and Mid-Con and Bayway to drive more light crude into that system. Of course, Ferndale is a piece of that, and made progress. And then, California really though for us, has continued to be a focus on heavy crude alternatives. So making progress. We're running more and more tight crudes, I'd say as we go along through, as we look back quarter on quarter. And so, we're just finding lots of ways to debottleneck and optimize around that system. And then, during these turnarounds sometimes, we have the opportunity to put hardware in place that lets us do that. And logistics solutions are a piece of that as well.

All right. I'll leave it there, thank you.

Thanks.

Ryan Todd from Deutsche Bank.

Thanks, maybe if I could follow-up a little bit on capture rates. If we could talk a little bit about capture rates in the second quarter, they were a little bit lower. And I guess, in particularly in the Gulf Coast was a little bit lower. I know there has been maintenance and distillate margins have had a little bit. But can you talk a little bit about maybe some of the drivers of the lower capture rate in the Gulf Coast region? And maybe in that same context, I think you mentioned -- have you maxed out your gasoline yield? Is there anything more you can do to swing the system in that way? And what's your view on gasoline and distillate margins going forward?

Yes, so I'll start with the Gulf Coast. We look at that, we've got a lot of exposure in Louisiana and to LLS. And so, that was the reason -- those differentials are fairly tight to Brent. So I think that there was a narrowing of light heavy, but in particular we've got exposure there, so that's a piece of that. We also had maintenance at Sweeney on our heavy unit, and so that took away some of the advantage on that one, so there was a mix effect. But largely the crude values weren't as wide, or didn't offer us much as opportunity to help drive that.

There is an issue -- or issue or the crack difference between gasoline and distillate were more heavily distillate. That drives that. We do tweak the machine so to speak, to run more gasoline, as we optimize around that given the response to the market prices. So there's an opportunity to do that. But I think fundamentally, the other part of that is the secondary product values, and we saw crude prices, flat price increase about $10 a barrel, and we saw product prices increase about $1. So you lost on that 20% of the barrel roughly that goes to secondary products, you lost some margin there as well. So all those factors combined on the Gulf Coast, led to relatively low market capture, versus prior -- some of the prior periods.

Thanks. And maybe on the gasoline and distillate side, are you flexed as much as you can be? And what's your view, I mean, over the next 6, 12, 18 months, do you view those as converging on the distillate and gasoline side, or are gasoline remains stronger for longer versus distillate?

No, I think gasoline continues to be strong with demand. We're seeing that. We're six months in, and we look at our data, industry data, about 3% increase in the US seems to be kind of where we see 3% or 4%. Distillate less so, but you're running max gasoline mode, so you're making the distillate. You've got contangos. You're pushing storage, you're going to get into the [planting season], you're going to get into heating oil. And I think that brings up the distillate demand piece in the Northern hemisphere or in the US. So we would expect them to come closer together. But I still think gasoline is going to show stronger demand versus distillate as we go forward, as long as the price of gasoline continues to stimulate the driving in the US and China and India.

We probably flex gasoline demand or production 3% or 4%, and maybe there's a little bit more juice left on that, but not a lot. Because I think we're in max gasoline mode.

Great, thanks, that's helpful. And maybe on a different note, a number of your peers have talked about it, or tried to quantify the EBITDA associated with the fuel distribution, kind of an MLP EBITDA number. Any thoughts from your side, on what you might have in your system, and any interest in doing that?

We have not included that, first of all-in our MLP-able. When we talk about MLP-able EBITDA, we've left that in marketing. It is significant. It is not something that we felt that we needed to have to drive the growth. But you look at the US, our marketing income, and the second piece of that, of course, is our wholesale piece. So that gives you some rough magnitude of the dollars involved. But our organic portfolio generates a lot more of that EBITDA than you can get from there. I think that we can always consider it, but it's not something that we got in our plate right now, given our Midstream focus.

Great thanks, that's helpful. I'll leave it there.

Okay thank you.

Faisel Khan from Citigroup.

Thanks, good afternoon. Just a few questions, and I will not ask a question on DCP (laughter). Yes, just for the lost opportunity with Humber being down, obviously capture rates and utilization were lower on the East Coast. Could you just talk about what was the financial sort of lost opportunity, given where cracks were in the Atlantic basin?

So we're looking at each other for an answer to that. So total turnaround and planned maintenance was about 7% for the quarter. And so Humber we probably (multiple speakers). 5%, yes (multiple speakers)

Humber was down for half of the quarter.

That's true.

It was a major turnaround, and a pipeline replacement. So it was down, what 45 days --

Yes it was.

45 days, and you can multiply that number by the crack that you see in Northwest Europe and --

You get close.

You get close, and then it was a major turnaround. It was in excess of $100 million.

Yes, it's a big one.

So it was significant, Faisel.

Okay. Got you, and just on the -- a couple other questions. One, I guess, first on the Midstream side. The Sweeney Fractionater One, as that facility comes online towards end of the year, where are you guys targeting those products, where do you plan to move those products? And you also will talk a little bit about whether you guys are going to get involved in the -- I know you have the export facility ramping up next year, but are you going to be moving LPG out of the country on your own account? AI mean, are you signing up for shipping capacity? Are you looking to sort of get involved in the global LPG trade as -- is it in your marketing arm?

Okay, this is Tim, Faisel. So on the frac, the ethane will stay in the US. So your 100,000 barrel a day frac, roughly 40,000-barrels a day of ethane, that's under commitment to US customers. That leaves you the propane, the butane and heavier fraction for the other 60%. Right now, that would be a domestic consumption largely. And then, when the export facility starts up a year later, it fills the part of the commitment we have for the shipments we have committed on that terminal on the propane, and to a lesser extent the butane side.

So that frac is a key piece, but there is a lot of flexibility in that system between Sweeney and Mont Belvieu and the chem operations there, that on the propane, and ethane, butane side, the demand is essentially placed with contracts. On the terminal, on the LPG trade, we have commitments from third-parties on those, and they're diversified. So you have commitments in Latin America, you have commitments in Asia. We're working on Europe. So yes, we'll be a piece of the global LPG business. And I anticipate that we will take a piece of that, but really we would like -- we are really focused on getting third-party business there with that, with people that have that demand and end use in their business. So and we're looking at a lot of options on supply around that. But fundamentally, the most of that load will come out of other demand centers, or other companies that have contracts across that terminal.

I think you could also say, that we look at things on an FOB and on an delivered basis.

That's right, and there's opportunities to work that. So a lot of commercial options developing around the LPG.

Okay. And then, are you also looking at commercial options for that LPG into your own facilities at CPChem? Meaning the assets you have in Asia and Europe, would you consider delivering LPG into those facilities, or even bridging that with potential expansions, or capital projects at those facilities?

Well certainly, CPChem in the US is a customer, and with the growth in their business, it could logically be a piece of that. I think the LPG for us, the customer base is broader than CPChem. And given their positions of where they want LPG, it's really the Middle East, and it's in North America. So not a lot of opportunity for CPChem in Asia or into Europe at this point. So it's really the focus has been on markets, either heating markets or pet chem markets, with customers in those other regions and not reliant on the CPChem operations.

Okay. Got it. Last question for me, just I think we saw the distributions come through in the quarter, from CPChem with the sort of the debt offering there. Can you talk a little bit about how much more capacity you have at CPChem to raise debt? Are we going to see more distributions from CPChem, based on sort of maybe right-sizing the balance sheet of that entity? Especially given where oil prices are, maybe there's another incentive for your partner to take back more cash at this point in time?

Faisel, this is Greg. Certainly, we're always looking at that, but as you know that was sort of a one-time event for us to take the $1.4 billion of debt at CPChem, and then distribute 50/50 to the partners. We never say never, we'll continue to look at it. But at this stage of the game I would say, we don't have plans to further lever CPChem's balance sheet.

Okay, got it. Thanks for the time guys. Appreciate it.

Phillip Gresh from JPMorgan.

Hi, good afternoon.

Afternoon.

First question, on the chemical side, how much propane are you running today versus say, three to six months ago? And do you see a significant up lift potential, as we move forward from running more propane?

So in the US, CPChem is running about 10% more propane than they would have at the end of last year. And the real optimization around the crackers is that as you feed more propane in, you can actually diminish your ethylene production. So it's an optimization about the total value of either ethylene or propylene. And so, there hasn't been just a huge shift in the product slate, or the input slate to run propane versus ethane. So the margins have been quite strong in the ethylene chain, and that's really pushed it toward ethane still. But you have begun to put some more propane in. And I think that's a general comment that you'd see around the industry. And so, I think that's something that we would anticipate you can bleed more in so to speak. But we still see a heavy ethane guide at this point.

Sure, okay. Got it. And then, on Midstream with the start up of Frac One, LPG export next year, you've given the long-term targets of what the EBITDA contribution from those two specifically should be. At this stage, would you say you're on track with that contribution? And how much specifically should we think you would be able to get in 2016? Will you be running full on Frac One, for example, just any color you could give there?

So Frac One, our anticipation is we will be running full, based on our supply commitments that we have in place with the raw NGL. So that's a 100,000 barrels a day, with the usual mixture of ethane, propane and butane. The LPG terminal comes up in the last part or later part of 2016. So that really hits -- starts to hit its utilization in 2017.

And Phil, we haven't broken out in EBITDA between the two. We've just given the total.

Right, the total is the $400 million to $500 million, correct? (multiple speakers).

That's right. And we have said that, roughly 80% of our EBITDA is in the fee-based arrangement, as we look at the Midstream 20% commodity. This is one of those projects that will have some degree of commodity opportunity or ARB. But it's not -- the predominant piece of this, will still be fee-based.

Got it. Last question, Just on distillates or just in general on refined products, how much did you export in the quarter? And if you could just give us your thoughts on the distillate export fundamentals, in light of some weakening margins in rest of world, Asia specifically?

So the -- we have little over 140,000-barrels a day last quarter, most of that was distillate, and it's really Gulf Coast oriented. Alliance is back online, so we have opportunities in Latin America. I think Asia is feeling the impact of a start up of the Middle East. But that's really not been a large trade area for us out of the US Gulf Coast. So I think that the opportunities are likely to still be there. The US is still very -- the Gulf Coast is still very competitive in that market. And so, I think the Atlantic Basin will still remain the natural trade area. And it's really going to be a pull, I think on gasoline distillate, about do you have a US or European sale versus another international opportunity? But I think we've been relatively flat on exports out of the US for some time, and I don't expect that to really change.

Okay, got it. Thanks a lot.

Neil Mehta from Goldman Sachs.

Good afternoon.

Good afternoon.

So in the quarter, it looks like you returned about 60% to 65% of the earnings in terms of the buyback and dividend. Is that a reasonable run rate as we think on -- as we look forward, and how do you think about the allocation of the buyback versus dividends here?

So the guidance we've been giving is -- and we'll be consistent today, is kind of 60/40. The cash from all sources, 60% is going to into reinvestment, 40% is going to be returned to shareholders through dividends and share repurchases. So as long as we're trading under intrinsic value, we'll be buying shares, and we're buying shares every day. You want to look at it on the basis of others, we kind of 71% of net income, turns to distributions back to shareholders. I don't really think about it on that basis. But I think about it on a cash basis, and I think about it in terms of intrinsic value long-term.

And based on those comments it seems like you will continue to lien into the buyback, relative the dividend based on what you think the intrinsic value is?

Well I think it's both. We've given guidance 2014, 2015, 2016, expect double-digit dividend increases. We're good with that, and then share repurchase that is going to be there.

Terrific. And then 2016, the commentary that CapEx likely down $1 billion, recognizing that we'll wait a couple months to get more began granularity in terms of the specific projects. But at least directionally, can you talk about the things rolling off 2015 to 2016 that will help us get there?

Well, certainly we'll finish the Frac, and you've got the LPG export facility still yet to complete. But [Dapple] is still under construction at that point. The [Biobridge], the connectivity around Beaumont that we're looking at. So I mean, we have plenty of projects. I think as you think about this year was really a heavy lift year for us with $4.6 billion of capital, and we've consciously dialed that down on a go forward basis.

Thanks. And then last question for me, is just in terms of what you're seeing through the wholesale network? And then, on the retail network to the extent you're connected there, from a demand standpoint? And any granularity by product would be helpful as well.

(Multiple speakers) the ethylene demand, I think fundamentally we view it's [up] 3% to 4% (multiple speakers).

And regionally, Tim, I don't know if you're seeing differences.

It's kind of across the US, so vehicle miles driven are up. You can get that stat, you look at MasterCard, you look at EIA. We look at our unbranded branded rack sales, and we kind of all see those numbers in that range. So it tends to all come together in that 3% to 4% range, and it's across the US. Good response in California, for instance as well But we're really seeing that around the US. So I think generally, the driving public on the gasoline side has responded to lower prices, but by traveling more. And that's being supported now, I think across the -- as you look at all of the data sources across that. So I think as long as gasoline prices stay in this range, we're going to continue to see increases in gasoline demand from last year.

That's great. Thanks a lot, guys.

Appreciate it.

And this concludes our Q & A session. I will now turn the call over to Kevin Mitchell for closing remarks.

Thank you very much for participating in the call today. We do appreciate your interest in the Company. You will be able to find a transcript of the call posted on our website shortly, and if you have any additional questions, please feel free to contact me or CW. Thanks, again.

This concludes today's conference. Thank you for participating. You may now disconnect.