Welcome to the Second Quarter 2015 Phillips 66 Earnings Conference Call. My name is Le Ann and I will be your operator for today’s call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Kevin Mitchell, Vice President of Investor Relations. Kevin, you may begin.

Thank you, Le Ann. Good afternoon 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’ll 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 includes the utilization of 90% and also benefited from strong market cracks. We safely completed a major turnaround in pipeline replacement at our Humber Refinery in UK on time and under budget. Our U.S. refineries ran at 95% utilization. Marketing sales volumes were up reflecting increased gasoline demand. We’re executing well on our midstream growth projects. Sweeny Fractionator One is 90% complete. We expect mechanical completion this fall. The Freeport LPG export terminal is nearly 50% complete with expected startup 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; we’re up 50% versus last quarter. DCP is an important part of our NGL value chain and it is one of the nation’s largest natural gas gatherers and processors. DCP is doing a good job. They’re operating well. They’re managing cost, the Lucerne 2 plant in DJ Basin came online in the second quarter. In chemicals CPChem benefited from rising cash chain margins and ran well during the 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 U.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 flows to support midstream growth and to maintain operating integrity of our refining system. In addition compared to the first half of 2014 controllable cost are flat. We maintained our capital disciplined approach in terms to capital allocation. During the second quarter we returned over 600 million to shareholders in the form of dividends and share repurchases. We increased our dividend 12% this quarter. We have 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. Starting 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 to 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 invested 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 presents 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 during 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-venture 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’re making in Midstream. Moving on to Slide 7. Midstream's 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 impart 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 & 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 and Styrenics 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 captured decrease from 80% to 62% in the quarter due to our configuration which yields less gasoline and distillate than it is premised in the typical 321 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 were 84% consistent with prior quarter. Annualized 2016 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 downtime 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 cost at Alliance partially offset by lower realized margins. For the Central Corridor we showed moderate improvement due largely the higher volumes compared to the first quarter, we can’t plan turnarounds at the Ponca City and Borger 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 plant’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 321 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 cost associated with rents, ongoing 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 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 in 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 the 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-90s. In refining we expect the worldwide crude utilization rate to also be in the mid-90s and pre-tax turnaround expense to be about $120 million. In corporate and other we expect this segment’s after-tax cost to be lower after recognizing some infrequently occurring items in the first two quarters. We expect corporate cost 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-30s. As for 2015 capital expenditures our original $4.6 million guidance remains unchanged. With that we’ll now open the line for questions.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your line is now open.

I wonder if I could start I guess I don’t want to be too predictable here but just maybe get your latest thoughts on DCP situation and it looks like that the trailer debt multiple is certainly elevated and at this time is used basic during the [indiscernible] solution that yourself and your partner can live with? And I have got a follow-up please.

So I will start I always like to start with it is a good business. We like the business, we like the assets, we think basins there we are in are good long-term value creating basins in the Permian, Eagle Ford, DJ, Mid-Con, so we like the asset footprint, clearly we need to do some restructuring at DCP we need to deliver I think that we’re engaged in conservations with our partner at how best to do that. I think what you heard Greg say in the notes but sometime 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 have taken out a lot of cost, reduced CapEx et cetera, and so from an operational standpoint they are solid on that. And what we’re trying to do at the end of day is structured DCP for the long-term, so that it can remain the largest natural gas gatherer and the NGL gatherer in the U.S. and have a good platform which it 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, it is just going to take some time.

And I appreciate your answer I know it is not an easy thing to deal with. I guess my follow-up is really more current industry in MLP world, you have seen a number of your competitors there is some fairly aggressive things in terms of boosting their GP growth through acquisitions. You've obviously recognized your 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 growth projects that you have 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 and 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, let's say we would never entertain an idea of an acquisition there, but it would certainly have to be something down to fairway that is fee based complimentary to the assets portfolio we have today, so crude pipelines, terminals et cetera. And that we would 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 think that you have to think that all the way through in terms of the partnership.

A quick follow-up if I may. On the GP value sale, 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 markers because obviously you've got some of the margins there is something as C-Corp consolidated discount and I'm just curious on your thoughts on that? And I will leave it there. Thanks.

I would say we’ll certainly make it transparent, we’re going to tell you exactly what it is and you could read 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 C-Corp and there is probably examples on both sides of that and there is 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've said we have never considered IPOing the GP, I don't think we would ever say that. I think there may be a point in lifecycle in the MLP that leads you to do that, but it's certainly not in the near future for us Doug.

Ed Westlake from Credit Suisse is on line with a question.

Yes I mean I guess I am following on DCP. I guess a lot of people feel that obviously the business needs new capital but we’re also hearing term the impacts or the concerns on maybe under investment is impairing DCP's actual operations and customer reputation. So I wondered if you wanted to address that, it is great ground field position but how the business is performing.

Well and so I mean we’re still investing in growth in DCP. We’re very interested in DCP's reputation. We want DCP to be viewed as a long-term reliable partner with some very large people out there. If you think about the portfolio the DCP has today. And so I would say we’re very consist with that Ed. I think they are 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 area. But the volumes are certainly holding up in core regions in the Permian and Eagle Ford et cetera. But long-term we've got to position DCP such that it has the capacity to grow and it has the capacity to be there for the folks that are out in the field, and that’s exactly what we intend on doing.

And then switching to refining, I mean you were clear that 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?

So I think our guidance remains consistent in terms of turnarounds obviously ’15 is a heavy turnaround year for us we knew that going in into ’15 and we communicated that. So ’16 probably won’t be as heavy here is what we’ve seen in ’15 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. I’ll let me Tim if you want to make some comments.

Sure. On the benefit of turnarounds clearly get clean so you can run at a high utilization post turnaround and second of all we’ve indentified that we wanted the full point improvement in refining we are on that path and about half of that a little bit more comes from cost yield reliability. So turnarounds are really the change 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 robust and so 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 in capture?

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

Okay. Thanks so much.

I should mention yield as well. We take chance to go in new distribution on vessels in terms of getting more efficient and that’s one of the ways that you can tweak declining product yield in our system.

Yes it’s really -- and sometimes it gets hard to quantify that the capacity decrease probably is 1% to 2%. If you want to think about on that basis and maybe to 1% yield improvement and so I mean the real dollars and they are certainly ones that we know how to capture it.

Jeff Dietert from Simmons is online with the question.

It looks 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. The oil prices are still low yet, your margin strengthened again and if you could talk about demand both domestically and in the export market?

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 U.S. has been good, export opportunities throughout the U.S. are good and then Middle East operations are running very well. I think as an industry the U.S. and the 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 in the next couple of years that would help pull that utilization and that is an important factor just as much as the cost piece is. But we’ve certainly seen the LPG cost in the U.S. comes down a bit more relative to crude as well which has helped. But I think this is largely kind of the demand side that we’re seeing and so we feel that the demand piece in the world is actually been fairly good from a chemical standpoint.

Yes I think our view is, I’m sure we will get to crude at some point in time, but our view is crude is going to be probably a little bit longer NGLs a little bit longer that’s directionally positive for margins and chemicals and demand from chemicals albeit I think a reason is topical news, the question is demand in Asia. What our experience is every time you see crude prices fall you see some reduced buying activity in Asia 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 U.S. is and in the Middle East are the larger suppliers on the global market and Latin America out of the U.S. is approximate market, but the large demand pull continues to be Asia and that’s really met through the U.S. and through Saudi Arabia. I think Europe has seen improvement in their economy 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 centres in the Middle East and the U.S. 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 in the growth rate but the developing piece of the world still has good demand.

Evan Calio from Morgan Stanley is on line with a question.

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

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 this has unfolded. You may have one shot at it and your currency is gone. So you want to think about it that way. So fundamentally we have a great organic backlog, we have 20 plus billion dollars 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 perspective across PSX, so we’re in chemicals, we’re aren’t buying we’re gathering and processing and so we don't feel the need, we’re shifting our portfolios on a higher multiple higher value businesses, we’re on track we’re on plan, if there was something out there that was complimentary. We would certainly take a look at it from PSXP standpoint but to somehow push the yield up by going and doing an acquisition that put commodity risk and exposure into SXP we just don’t have any interest in doing that right now.

And then may be as a natural segway to when you talk about growth organic growth you recently announced JV with Energy Transfer and Sunoco to build the pipeline and I don’t want to Charles I think I am going to say Charles sorry. Maybe you can discuss the MLP will EBITDA benefit the dual benefits there from a midstream dropdown aspect as well as potential volumes that you could get tracked with Alliance and make that refinery more competitive with that Houston arb?

Great, you've answered the question pretty well. I'll let Tim talk about its 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 that we want to increase the capacity east to that in the 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 are actually right there is a knock on effect in terms of value that we can have both at Lake Charles and Alliance. In terms of their project size it depends of the size of the pipe the number that we look at between $700 million and $900 million of investment we’re 40% owner and we get a typical midstream build multiple say of seven on that to give you some idea of the impact that it has. So it's a significant add to the MLPable Midstream EBITDA so we’re happy that and we think it has got good fundamentals so we really like that project.

I mean well building at 7 and dropping at 10 and improving your refining margins pretty good business.

Paul Cheng from Barclays is online with a question.

Greg on the DCP sorry to ask that one more time, does the partner already have agreed on the timeline to find a solution, I mean that in October that they have $700 million of the debt need to be I think refinanced, so is that percent is a deadline that you need to have a solution or that doesn't really matter?

It is part of equation we’re trying to solve here to get to restructuring of DCP. I think our view is clearly it is going to be a deleveraging in that, and so the fundamental question is how do you make that happen. And I think that’s what we’re working through with our partner I mean with the folks at DCP. But I have a high degree of confidence we’ll get that done.

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

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

Greg since I got you here, do you have the preliminary 2016 CapEx number that you can share?

[Multiple Speakers] 2016?

Yes. [Multiple Speakers] 2016 anything any estimate that you can share?

Paul what we said is 3 billion to 4 billion in terms of that. We get our Board in October for approval the 2016 capital budget, so I don’t want to get too far ahead of ourselves. But as we’re thinking it through it is going to be in that range which will be down from 4, 6 this year.

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

It’s possible that it may come down some, as we’ve -- part of we openly want to do see Midstream growth funded by PSXP but we’ve got a lot of projects on our plate. We want to get done and we could easily see $2 billion of Midstream investment for the next couple of years I think. The other question is where else to get funded it is PSX to PSXP.

And final question from me, maybe this is for Tim. It seems like that the industry is having a pretty tight supply on the high octane branding component. The question is that within your system, is there any good low cost de-bottlenecking opportunity for your reformer and [indiscernible] unit?

Yes Paul, you are right. We see, I’d say octane still being a very strong demand and that we expect that to continue given light crudes to [indiscernible] that come out of that. So I think there is a continuing pull and so we’ve got a variety of small projects that we’re looking at around Appalachian units and reformers to find ways to drive a little higher production through there and then we’ll watch that market and see if there is a need for a larger solution. But there is a lot of opportunity within our existing system to drive some additional octane improvement through a variety of ways our [indiscernible] 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.

And is there something we can quantify saying that are we talking about 20,000-50,000 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 all together Paul. We can get back as we look at that 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 what we think we can do, but it’s not a massive new amount of capacity in that.

Blake Fernandez from Howard Wheel is on the line with a question.

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 last time I had a chance to visit with Tim your LP models were promoting 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 is 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 is no question whether this came in. We actually set cards on the siting. We brought imported crudes in into the system, that’s a given where our expectations are for the third quarter I’d say cards are coming off of the sitings and we’re going to import less crude given what we see going on with bps. So you think globally, we think crude is oversupplied. And we continue to think that. OpEx is up 1.5 million barrels a day versus February it looks like to us. Production in the U.S. isn’t following as fast as people kind of expected, do you want to think about that and clearly we’ve got better North American crude logistics a day than we did a year or two years ago. The dollar is strong as you want to think about that. And so I think all that just say crude is going to be oversupplied for some period of time. So as we think about the markets we kind of expect that cracks come in the fall probably the but the bps widen, so margins will still be relatively healthy is our view as we go into the fall season given turnarounds. And this 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 falls normally go so, just to sum it up it looks like there is plenty of crude out there and we’ll continue to be for some period of time and then we flex our system, we flex max gasoline in the second quarter, and any more color you want to add on that Tim.

Well I think in summary we are seeing North America supply probably increasing right now. You’re seeing the bps widen. And so I think fundamentally we anticipate less important for us in the life side going forward, better utilization of inland crude, the rail utilization is coming back up to taking to the East Coast more supply of Canadian crude and so I think that’s the dynamic that we see. So I think to build on Greg’s point that’s what we think is going to help to drive the shift in the crude slate. So we’re optimizing around that. But that would be the big change obviously given the really narrow bps 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.

Maybe I will just 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 the 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. Have you fully maximized that opportunity or where do you stand there?

I think there is still a little improvement and we did turnaround Alliance let us put in place a column to build -- run lighter crudes there. That’s a work underway for instance at Wood River which is kind of an interesting we’re going to increase -- we can increase heavy crude input but that’s because we can take the lite fractions out. So I think we’re looking around the systems still looking at ways particularly in the Gulf Coast and Mid-Con and Bayway to drive more like crude into that system, of course Ferndale is a piece of that and made progress and then California really though for us is continuing to be a focus on heavy crude alternatives. So making progress we’re running more and more type crudes I would say as we go along through if you 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 there will be opportunity to put harbour in place and let's just do that. And then the logistics solutions are a piece of that as well.

Ryan Todd from Deutsche Bank is on the line with a question.

Maybe if I can follow-up a little bit on capture rates. If you can think little bit about capture rates in the second quarter they were a little bit lower I guess and particularly on the Gulf Coast was a little bit lower, I know there has been maintenance and distillate margins of that has hit it a little bit, but can you talk a little bit about maybe some of the drivers as 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 distillate margins going forward?

So I'll start with the Gulf Coast when we look at that we've got a lot of exposure in Louisiana and to LLS, and so those differentials are really types of brand. So I think that there was a narrowing of light heavy but in particular we've got exposure there so that is a piece of that, we also had some maintenance at Sweeny on our Humber unit, and so that took away some of the advantage on that, so there was a mix effect but largely the crude values weren't as wide or didn't offer as much opportunity help drive that. There is the issue or the crack difference between gasoline and distillate we are more heavily distillate that drives that. We do tweak machines so to speak to run more gasoline as we optimize around that given the response to the market prices. So there is an opportunity to do that, but I think fundamentally the other part of that is the secondary product values that we saw crude prices flat price increase that $10 a barrel and we saw product prices increase about $1. So you lost on that 20% of the barrel roughly that goes to the secondary products you lost the margin there as well. So all those factors combined the Gulf Coast led to a relatively low market capture versus some of the prior periods.

And maybe on the gasoline and distillate side, are you flexed as much as you can be and what’s your view over the next six months, 12 months, 18 months view. Do you view those are converging on the distillate and gasoline side, or gasoline remain stronger for longer versus distillate?

So 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 U.S. seems to be where we see 3% or 4% distillate less so, but you running max gasoline modes you are making the distillate you've got contango’s you are pushing storage you are going to get into the planning season if you are going to get in the heating oil I think that brings up the distillate demand fees in the northern hemisphere or in the U.S. 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 U.S. and China and India.

We’d probably flex gasoline demand -- or production 3% to 4%. And maybe there is a little bit more juice left in that but not a lot. Because I think we are in max gasoline mode.

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

We've not included that first of all in our MLPable when we talk about MLPable EBITDA we flex that in marketing, it is significant it’s not something that we felt that we needed to have to drive the growth, but when you look at the U.S. our marketing income has taken a piece of that of course as 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 that you can get from there, and I think that we can always consider it but it's not something that we are going to replace right now given our midstream focus.

Faisal Khan is Citigroup is on the line with the question.

Just a few questions and I'll not ask a question on DCP. For the last opportunity with Humber being down obviously your capture rates and utilization were lower on the East Coast could you just talk about what was financials or lost opportunity given where the cracks were in the Atlantic Basin?

So we are looking at each other to answer that. So I mean total turnaround in planned maintenance was about 7% for the quarter. And so Humber [Multiple Speakers] Humber was down for half of the quarter. It was a major turnaround in the pipeline replacement so it was down about 45 days to 90 days. And you can multiply that number by the crack that you work with Europe and it get close and then it was a major turnaround that was in excess of $100 million. So it was significant for us.

And just on the couple of other questions, one I guess first on the midstream side the Sweeny Fractionator One as that facility comes online towards the end of this year, where are you guys targeting sort of those products, where are you planning to move those products? And if you also talk a little bit about whether you guys are going to get involved in the -- I know you have the expert facility ramping up next year, but are you going to be moving LPG out of the country on your own account, meaning are you signing up of shipping capacity? Are you looking to sort of get involved in the global LPG trade in your marketing arm?

Okay. This is Tim Faisal so on the Frac the ethane will stay in the U.S. So the 100,000 barrel a day Frac, roughly 40,000 barrels a day of ethane that’s under commitment to U.S. customers. That leaves you the propane the butane and the heavier fraction for the other 60% right now that would be a domestic consumption largely then when the export facility starts up a year later it feels the part of the commitment that we had for the shipments that we have committed on that terminal on the propane and to a lesser extent the butane side. So that Frac is the key piece but there is a lot of flexibility in that system between Sweeny, Mont Belvieu and the chem operations there that on the propane and ethane, butane side. The demand is essentially placed with contract. On the terminal and the LPG trade we have commitments from third parties on those and they are diversified 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’d like we really are focused on getting third party business there with that the people that have that demand in end use in their business. So, and we’re looking a lot of options on supply around that, but fundamentally the most of that load it will come out of other demand centers or other companies that they have contracts across that terminal.

And you’d also say that, we’d look at things on FOB and on a delivered basis.

And there is opportunities to work that, so lot of commercial options developing around the LPG.

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

Well certainly CPChem in the U.S. is a customer and with the growth in their business you can logically be a piece of that. I think the LPG for us the customer base is broader than CPChem and given their position to 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 is 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.

I think we saw the distributions come through in the quarter from CPChem with the sort of 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 do we right size the balance sheet of that entity especially given where oil prices are maybe there is another incentive bring a partner to take that more cash at this point in time.

Faisal this is Greg. Certainly we’re always looking at that, but as you know that was sort of onetime event for us to take the $1.4 billion of that at CPChem and distributed fifty-fifty to their 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.

Phil Gresham from JPMorgan is on line with a question.

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 uplift potential as we move forward from running more propane?

So in the U.S. CPChem is running about 10% more propane than it 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 that the total value of either ethylene or propylene and so there hasn’t been just a huge shift in the products slate, the input slate to one propane versus ethane. So the margins have been quite strong in the ethylene chain and that’s really pushed toward ethane still but you have begun to put some more propane in and I think that that’s a general comment that you would see around the industry. And so I think that’s something we would anticipate you can bleed more and so to speak, but we still see a heavy ethane guide at this point.

And then on Midstream, with the start up of frac-1 at LGP export next year you've given the long-term targets of what the EBITDA contribution from those two specifically should be I guess at this stage would you say you are on track with that contribution and how much specially should we think you would be able to get in 2016 will you would be running full on frac-1for example. Just any color you could give there?

So frac-1 would our anticipation we’ll be running full based on our supply commitments that we have in place for the raw NGL and so that’s 100,000 barrels a day with usual mixture of ethane, propane, and butane the LPG terminal it comes up in the last part or later part of 2016 so that really starts to hit utilization in ’17. And so we haven't broken out the EBITDA between the two we've just given the total.

Right, the total is the 400 million to 500 million correct?

That is right, right and we've 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 would still be fee based.

Last question just on distillates, or just on general on refining products, how much do you export in the quarter and if you could just give us your thoughts on the distillate export fundamentals in light of weakening margins in the rest of world Asia specifically?

So the 100, we had a little for 140,000 barrels a day last quarter, most of that was distillate and it's really Gulf Coast oriented Alliance is back on line. So we've opportunities in Latin America I think Asia is feeling the impact of the start up of Middle East but that’s really not have been a large trade area for us out of the U.S. Gulf Coast. So I think that the opportunities are likely to still be there, U.S. is still there, 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 is really going to be a pull I think on gasoline distillate that you have a U.S. or European shale versus another international opportunity but I think we've been relatively flat on export U.S. for some time and I don't expect that to really change.

Neil Mehta from Goldman Sachs is one line with a question.

So in the quarter it looks you returned about 60% to 65% of the earnings in terms of the buyback in 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?

The guidance we've been giving is it would be consistent today it's kind of 60-40. And if the cash from all sources 60% from go in reinvestment 40% is going to be returned to shareholders through dividends and share repurchases, as long as we are trends of value we’re going to be buying shares and we’re buying shares every day. You want to look at it on basis of others we've 71% of net income turns 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 guys are going to continue to lean into the buyback relative to the dividend based on what you think the intrinsic value of the PSX is?

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

And then 2016 the commentary that CapEx likely down a $1 billion recognizing that we’ll wait a couple of months to get more granularity in terms of the specific projects but at least directionally can you talk about some things that are rolling off '15 to '16 that will help us get there.

Well certainly we’ll finish the frac and you got the LPG export facility still yet to complete but DAPL still under construction at that point Bayou bridge the connectivity around Beaumont that we’re looking at. So I mean there we've plenty of projects. I think as you think about this year was really a heavy last year for us with 4.8 billion in capital and we've consciously dialed that down on a go forward basis.

And then last question for me is just in terms of we’re just seeing through the wholesale network and then on the retail network then you are connected there from a demand standpoint and any granularity by product would be helpful as well?

I think fundamentally we view at that 3% to 4%.

And originally Tim I don’t know if you are seeing differences.

It's kind of across the U.S. the vehicle model is driven or up, you can get that stat and look at MasterCard date and look at EIA. We look at our unbranded branded rack sales and we kind off see those numbers in that rig. So it just tends to all come together in that 3% to 4% range and it’s across the U.S. good response in California for instance as well, but we’re really seeing that around the U.S. So I think generally the driving public on the gasoline side is responded to lower prices but by travelling more and that’s being supported now I think across as you look at all the data sources across that. So I think as long as gasoline prices stay in this range we’re continue to see increases in gasoline demand from last year.

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’ll be able to find a transcript of the call posted on our website shortly and if have any additional questions please feel free contact me or CW. Thanks again.

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