Welcome to the First Quarter 2016 Phillips 66 Earnings Conference Call. My name is Sally and I will your operator for today’s call. At this time all participants are in a listen-only mode. Later, we will conduct a question-and-question session. Please note that this conference is being recorded. I will now turn the call over to Rosy Zuklic, General Manager, Investor Relations. Rosy, you may begin.

Good morning, and welcome to Phillips 66 first quarter earnings conference call. With me today are Chairman and CEO, Greg Garland; President, Tim Taylor; and Executive Vice President and Chief Financial Officer, Kevin Mitchell. The presentation material we’ll be using during the call can be found on the Investor Relations section of the Phillips 66 Web site 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 our actual results to differ are included here as well as in our filings with the SEC. With that said, I will turn the call over to Greg Garland for some opening remarks.

Thanks, Rosy. Good morning everyone. Thank you for joining us. We had a good operating quarter running well across all of our businesses. However weaker margins had a significant impact on our earnings this quarter. In refining distillate crack spreads were the lowest since 2010. In chemicals benchmark industry olefin chain margins were down from last quarter, and midstream was impacted by lower NGL prices. We experienced solid results from our marketing and specialties business. Total adjusted earnings were 360 million and excluding working capital changes, we generated $722 million from cash from operations. We remain focused on operating excellence and completing our growth projects in midstream and chemicals, where we see great value and opportunity long term. We are maintaining a disciplined approach to capital allocation and believe that our strong balance sheet is a competitive advantage that positions us well to executive our plans through the commodity price cycles. During the quarter we reinvested 750 million back into the business and we distributed 687 million to shareholders in the form of dividends and share repurchases. Since May of 2012, we’ve returned 11.8 billion to shareholders through dividends and/or repurchase or exchange of 115 million shares. We continue to target a sixty-forty split between reinvestment in our business and distributions back to our shareholders and we have targeted another dividend increase this year of at least 10%. We made good progress on our major growth projects in midstream we received all the permits necessary for the Dakota access pipeline to start laying pipe in May and we would expect an on schedule completion by year end. In the Gulf Coast the Beaumont terminal expansion is going well. The terminal currently has 7.1 million barrels of storage capacity. We have 3.2 million barrels of new capacity under construction. Longer term this facility can expand to 16 million barrels of storage capacity, also development of the first phase for the Sweeny Hub is nearing completion. The LPG export terminal is 80% complete, is on time and on budget. The completion of the terminal will represent a major step in the development of a world class energy complex within integrated refining, chemical and midstream assets. PSXP remains an important part of our midstream growth strategy the fee based assets within its portfolio continue to perform well. PSXP increases its limited partner distributions by 5% this quarter and remains on track to achieve its steady growth objective of a five year 30% distribution and compound annual growth rate through 2018. DCP midstream is reducing its gas breakeven for self help initiatives and expects to achieve breakeven at NGL prices below $0.35 per gallon this year. We are reducing cost, cut capital substantial and converting commodity exposed contracts to fee based to improve financial strength and flexibility. In addition the equity contributions from the owners last year, strengthened the balance sheet, increased fee based earnings and positioned DCP for success in the future. We expect that DCP will be self-funded going forward. In chemicals demand for consumer products remained strong in response CPChem continues to run at high rates across its system. Because CPChem’s primary production centers are in North America and in the Middle East underpinned by advantaged feedstocks. We believe CPChem’s asset base provides it with a competitive advantage. CPChem continues to advance the U.S. Gulf Coast petrochemicals project it is now 75% complete with expected start up in mid 2017. Once running CPChem’s global ethylene and polyethylene capacity would increase by approximately one-third. In refining we see good gasoline supply and demand fundamentals for the remainder of the year and we expect strong demand as we head into the summer driving season. Our focus on refining is operating excellence, maintaining our costs and capital discipline, increasing returns through selective investment. We invest in projects that are quick pay off, low cost and high return. During the quarter we advanced of several these refining projects. At the Wood River Refinery we’re undergoing debottlenecking in our own schedule for completion in the third quarter. At Bayou work on the FCC modernization is on schedule. At the Billings refinery, efforts are underway to increase the amount of heavy Canadian crude we can run to 100%. Each of these projects has a projected return on investment of about 30%. So with that I will turn the call over to Kevin Mitchell, to review the quarter results.

Thanks Greg, good morning. Starting on Slide 4, first quarter adjusted earnings were $360 million or $0.67 per share, reported net income was $385 million. Excluding working capital cash from operations was $722 million. Capital spending for the quarter was $750 million with approximately 450 million spent in midstream primarily on our growth projects. Distributions to share holders in the first quarter totaled $687 million, including $296 million in dividends and 391 million in share repurchases. At the end of the first quarter our debt to capital ratio was 27% and after taking into account our ending cash balance our net debt capital ratio was 23%. Annualized adjusted return on capital employed was 5%, our adjusted effective income tax rate was 33%. Slide 5, compares first quarter 2016 and fourth quarter 2015 adjusted earnings by segment. Quarter-over-quarter adjusted earnings were down $350 million, primarily driven by lower results in refining. Next we’ll cover each of the segments individually. I’ll start with Midstream on Slide 6. Transportation continues to generate stable earnings, the NGL business progressed construction on the Freeport LPG Export Terminal. Fractionator utilization was reduced due to turnarounds and the impact of ethane rejection on feedstock composition. Included in the transportation and NGL results is the contribution from Phillips 66 Partners. During the quarter, PSXP contributed earnings of $32 million to the Midstream segment. Distributions to Phillips 66 from our LP and GP interests increased 7% over the fourth quarter. DCP Midstream continues to work on its self help initiatives to reduce costs, manage its portfolio and restructure contracts. On Slide 7, Midstream’s first quarter adjusted earnings were $40 million down 2 million from the fourth quarter. Transportation adjusted earnings for the quarter was $72 million down 6 million from the prior quarter, driven by lower equity earnings from Rockies Express Pipeline and Explorer Pipeline. NGL adjusted loses were $11 million for the first a 9 million decrease from the prior quarter was largely driven by seasonal storage activity partially offset by lower tax expense. Adjusted loses for DCP Midstream were lower in the first quarter primarily due to improved liability and contract restructuring efforts partially offset by the impact of lower commodity prices. In Chemicals, the Global Olefins & Polyolefins capacity utilization rate for the quarter was 93% and margins were lower, SA&S had improved equity earnings due to higher volumes at equity affiliates. As shown on Slide 9, first quarter adjusted earnings for Chemicals were $156 million down from $182 million in the fourth quarter. In Olefins & Polyolefins the decrease of $36 million was largely due to lower margins driven by reduced polyethylene sales prices. This was partially offset by higher polyethylene sales volumes from lower controllable costs. Adjusted earnings for SA&S increased by $7 million on higher equity earnings from increased sales volumes due to the fourth quarter turnaround activities at CPChem’s equity affiliates. In Refining realized margins was $7.11 per barrel for the quarter, as market crack spreads decreased significantly from the prior quarter. Gasoline market cracks were down 14% from the fourth quarter, due impart to the impact of higher than normal industry gasoline production in the fourth quarter as well as the impacts of butane blending and seasonally lower demand. Distillate market cracks were at a six year low. Market capture decreased from 74% in the fourth quarter to 67% in the first quarter. Clean product yields fell to 82% with gasoline yield at 43%. These yields reflect the impact of turnaround activity as well as accelerated maintenance on secondary units due to the low margin environment. Pretax turnaround costs were $115 million, $35 million lower than guidance due to deferral of some catalyst change activity. Slide 11 shows a regional view of the change in adjusted earnings compared to the previous quarter. The Refining segment had adjusted earnings of $86 million, down $290 million from last quarter. The reduction was largely due to lower market cracks. Atlantic Basin adjusted earnings decreased this quarter primarily due to lower volumes and inventory impacts. The Gulf Coast region saw lower margins and reduced volumes due to planned maintenance and unplanned downtime. In the Gulf Coast region as well as the Central Corridor we had unplanned down time as we undertook discretionary maintenance in a low margin environment. In the Central Corridor lower margins accounted for the majority of the reductions in adjusted earnings from the fourth quarter as market cracks were 24% lower. On the West Coast, market cracks were 26% lower reduced margins were mostly offset by improvements in controllable cost and inventory impacts. Santa Maria continues to be affected by the Plains Pipeline outage. Next we’ll cover market capture on Slide 12. Our worldwide realized margin was $7.11 per barrel versus the 3:2:1 market crack of $10.64 per barrel resulting in an overall market capture of 67%. Market capture is impacted impart by the configuration of our refineries as it relates to our production relative to the market crack calculation. With 82% clean product yield for the quarter, we made less gasoline and slightly more distillate than premise in the 3:2:1 market crack. Losses due to secondary products decreased this quarter as the price differential between crude oil and lower value products such as coke and NGLs narrowed. Feedstock advantage was slightly higher than the fourth quarter but crude differentials generally remained tight. The other category mainly includes costs associated with RINs, outgoing freight, product differentials and inventory impacts. Let's move to marketing and specialties where we posted a good quarter thanks to healthy U.S. margins and volumes. Specialty saw higher earnings on improved margins. Slide 14 shows adjusted earnings for M&S in the first quarter of $205 million, down $22 million from the fourth quarter. In marketing and other the $36 million decrease was largely due to lower biodiesel tax credits and lower margins in international marketing. This was partially offset by higher U.S. marketing margins. Specialty’s adjusted earnings increased to $43 million primarily due to improved base oil margins. On Slide 15, the corporate and other expense had after tax net costs grow $127 million this quarter, an increase of $10 million from the fourth quarter. Net interest expense increased by $7 million primarily due to lower capitalized interests associated with the start up of Sweeny Fractionator One while corporate overhead and other expenses increased by $3 million due to the timing of legal and environmental charges. Slide 16 shows cash flow for the quarter. We began the year with a cash balance of $3.1 billion. Excluding working capital impacts cash from operations was $722 million. Working capital changes reduced cash flow by $464 million. The cash benefit for the U.S. tax refund received in the quarter was more than offset by the customary first quarter inventory build and the timing of marketing receipts and crude cargo payments. We funded $750 million of capital expenditures and investments, and we distributed nearly $700 million to shareholders in the form of dividends and share repurchases. We ended the quarter with 526 million shares outstanding. At the end of the quarter our cash balance was $1.7 billion. This concludes my review of the financial and operational results. Next I’ll cover a few outlook items. In the second quarter, in Chemicals, we expect the global O&P utilization rate to be in the low 90s. In Refining we expect the worldwide crude utilization rate to be in the mid-90s and before tax turnaround expenses to be approximately $100 million. We expect corporate and other costs to come in between $120 million and $125 million and companywide we expect the effective income tax rate to be in the mid-30s. With that, we’ll now open the line for questions.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Doug Leggate with Bank of America/Merrill Lynch is online with a question.

I don’t know if I could ask you about the impact of run cuts in the quarter because my understanding is that in the quarter you guys had deliberately taken some steps to basically run at lower rates and obviously I am wondering if that was part of what fell behind the refining result in the quarter and my follow-up I guess is also refining related to the diesel overhang we see currently obviously you guys are a little more exposed to that. I’d just love to get your perspective on how do you see, if you see that cleaning up and how do you see that putting out let’s say over the next about 3 to 6 months? And I will leave it there. Thank you.

So I'll start and then Tim you can kind of give the overlook on this. So we ran really hard in January and March and we slowed down in February it is really the story. I think the interesting thing is we accelerated some maintenance activity but a lot of it was on secondary units and it didn't really effect the overall utilization as much as you might expect. But we did, we did build some intermediate inventory during the quarter. So I think that's the major impact in terms of the operations and Tim why don’t you hit on the outlook in terms of distillate?

Yes, Doug on the distillate side I think exports are the key to really clearing the length in North America and we are seeing good demand in China, India, West Africa and Latin America and so I think that continues. That said I think distillate for us continues to look to be the challenge for the market as we go forward, but I think it will clear but it's really turning into more of a byproduct from a gasoline production standpoint. So I think as long as those export markets are open that will continue to clear the U.S.

And then maybe just a quick follow-up, so you're planning to run your refineries back up into the mid 90s in the second, so I am just kind of curious if margins are still challenging in your distillate heavy yield, why would you continue to, are you just going to press into that or do you think there will be more voluntary run cuts as we through the next three to six months? It doesn’t sound like it.

Yes Doug I think that we're seeing strong gasoline cracks. I mean they really recovered in March and now in April, the summer driving season that's going to drive the overall refinery utilization certainly drives our thinking and then the distillate piece. The crack spread is really relatively stable where it is and has been but I think that's the piece where we're looking to the exports to clear that. But I think the gasoline is pulling the refinery utilization across the industry.

Blake Fernandez with Howard Weil is online with a question.

Maybe just a follow-up on Doug’s distillate question, do you have any sense that maybe once we reaccelerate activity here in the U.S. from a drilling perspective, do you think that's a critical component of kind of cleaning up the disparity we're seeing between demand and maybe some of these building inventories on the distillate side?

It's part of a question but I mean right now it's probably less than 2% of total distillate demand, but it's helpful what is maybe 40,000 or 50,000 barrels a day is our estimate.

The second piece and maybe there is a question for Kevin, the buyback seemed to continue at a fairly robust rate, continuing the macro environment, I am just curious your thinking about ratability of the buyback program and kind of the seasonality of what we would expect on the cash flow?

Yes. So I'll take it and Kevin can step in. So I kind of think about this in several different buckets, so the first bucket is really I don’t think the first quarter is reflective of our view of what 2016 is going to be. You have cracks have gone from 10 to 15 bucks we have seen NGLs move from $0.37 to $0.47, $0.48. We're seeing a good demand for transportation fuels gasoline is seeing good demand for petrochemicals. We're seeing margins up a couple of cents and we think margins will continue to improve in the pet-chem change. So we think that ’16 is still kind of a $4 billion to $5 billion type cash generation year from us from operation. Second I would say our view is that for a high quality MLPs. We think that the equity markets are open and that we would expect between some combination of debt and equity we would raise between $1 billion to $3 billion back into PSX this year. So this kind of moves you to $5 billion to $7 billion of cash, if you want to think about it that way we can afford a $3.9 billion capital program, 1 billion to dividend and $1 billion to $2 billion of share repurchases given that. I will say just so we're looking at things going on and we're going through every line item in the capital budget both for ’16 and ’17. And we're assuring that our premises that we started with are still valid and that these projects are going to generate returns that are acceptable and meet our requirements. And so we'll be looking at that going forward into this year.

Paul Cheng with Barclays is online with the question.

Just curious so Tim do you have any insight what is the current economic between branding directly the line naphtha into gasoline pool in U.S. or that to export to either Europe or Asia for the petrochemical feedstock [Multiple Speakers] at this point.

I am sorry Paul you cut out a little bit could you repeat that the last part of your question?

No I am just trying say that, who is actually getting the more economic at this point that you're keeping lesser in this country and branding directly to the gasoline pool or they are being export to overseas to be used for petrochemical feed?

Predominantly the exports are still the distillates on the gasoline side, I mean you’re seeing strong demand around the world and so…

No Tim I’m sorry, Tim, Tim, I am sorry I probably did not meet my question, I’m looking specifically for naphtha [Multiple Speakers] naphtha that whether it is more economic to directly brand it into the gasoline pool in U.S. and then as octane to bring in the finished gasoline or that is better to kick them out in U.S. into the overseas to be used as a petrochemical feedstock any insights from you guys given your also a big petrochemical producer?

Yes clearly naphtha demand has increased around the world but we still see the best value to go into gasoline pool here, pull it with octane to blend it up but with the demand that we’re seeing in gasoline that’s still the preference that we have.

I see. And second question, and may be this is for Kevin that do you have a number that you can share what is the Sweeny NGL Fractionator One, the contribution in the first quarter?

So Paul, we haven’t broken out at that level of detail, as you know we report at the sort of NGL sub-segment within our Midstream business at the PSXP level you can see there what they see on the Fractionator but that’s a different look to the Phillips 66 look so at this point that’s not a level of granularity that we have broken out at this time, obviously the Fractionator just started up at the end of last year, so still kind going through that start up a little bit of incremental cost that you wouldn’t expect to be recurring and volume is a little bit lower than capacity given the feedstock composition, but ultimately the full value is going to come when you see the export terminal up and running and get full contribution.

Tim on tier 2, can you tell us that where are you in the process?

So we’re in the midst of really investing to deal with the taking more sulphur out across our system, so we’ve a number of projects at our refineries that were in the process of implementing to complete that but that has been a piece of our maintenance capital our long term maintenance capital, over the last several years and next year or so to complete that.

Can you tell me…

I will probably just say West Coast meets tier 3 standards so it is the other refineries who are investing in and those investments are included within the kind of 700 million of sustaining capital that we’ve outlined.

Right, Greg our Ozark West Coast is the, is how many of the other facility is already in compliance this year or that all of them will need to win until next year before you’re in compliance?

That will come in compliance at different times giving the investment schedule through 2018 that we will hit Paul, so I think we’ve investments at most of the other refineries for tier 3, some more than others.

Okay, the final question, Greg I hear you about that the how to balance the cash flow and expecting 1 billion to 2 billion of the NPL ex the cash contribution to the CCAR, to the degree if that didn’t materialize should we assume that you’re going to barrow money there to continue funding the temporary shortfall on the buy back or that the buyback will take a back seat?

Let me rephrase your question Paul to the extent that we can’t excess the market…

So if in the event that the MLP market is not available there to raise additional equity or debt for PSXP and so as a result that, you won’t get that 1 billion to 2 billion of the cash you expect from the subsidiary into the CCAR should we assume because we view it as a temporary development that you would just borrow money in the CCAR to fund the buy back or that the buyback will take a pause and wait until that you have the cash to do so?

I think that we said we could flex between 1 billion to 2 billion and that is kind of the guidance we have given but I would just kind of reiterate we feel pretty strongly that the markets are going to be open to us.

Evan Calio with Morgan Stanley is online with a question.

My first question Greg is it relates to your capital flexibility in 2016 and ’17 as we see some volatility in your business, I mean I know you talked about the expected recovered cash flow yet, as much as the, how much of the capital plans are flexible when you think about 2016 and then 2017 and what drives, how you flex that?

Yes. So I would say, we kind a guided or said that we are on a glide slope to kind of a $3 billion capital program in ’17 and ’18 with 1 billion sustaining and 2 billion worth of kind of growth capital primarily directed at Midstream growth opportunities. In terms of the 39 this year and how much flex do we have, I would say we’re still working through that and looking at that, but it's probably 500 millionish in terms of the amount of flex that we actually have this year.

And second on Midstream and results were a little weaker than expected there at least versus our numbers. So maybe you could discuss some of the drivers there. I mean likely related to frac start up and then how those factors impacted results and made trends for ’16 I imagine some of those were to unwind?

Tim?

Yes Evan it is Tim. So, basically you look at transportation segment consistent earnings quarter-to-quarter so the DCP was slightly improved as well that leaves you with the NGL and that’s largely the impacts of some commercial impacts on inventory, some higher costs associated with the start up of the frac and that’s really as we line that out we expect that to come more in line [Multiple Speakers].

And anything related to the…

Yes I think we should mention we had a turnaround at our GCF frac so the expenses were up as well because of that turnaround.

Yes, that makes sense.

I would just add Evan on DCP. So it was improved results but it was still a loss for the quarter.

Adjusted.

On an adjusted basis and that reflects the sort of mid-30s NGL prices which have recovered quite a bit since then, so that result should be getting back to something a little bit more respectable.

Roger Read with Wells Fargo is on line with a question.

I guess maybe coming back to a little bit of the question on the ability to run at the high levels on the refining side and the export market. Can you give us an idea of what export volumes have been and kind of what you would anticipate as we go into the summer? I mean you made a comment about as long as the market remains open and just kind of curious what that means in a numerical sense?

We’ve been running essentially at mid-90s utilization so that’s not changing. And so this last quarter we’re run at 126,000-127,000 barrels a day of exports. And so from our standpoint that’s a very manageable amount to place. But our utilization really kind of stays where we were and so I think that’s the key out of our Gulf Coast recoveries to balance that distillate.

And anymore or any particular level of flexibility we should consider here between gasoline and the distillate side? Or are you pretty well where you can go in next 12 months or so?

I think we’ve been running pretty much max gasoline as most of the industry has. We can probably -- we can flex about 3% or 4% between gasoline and diesel. So we do have some projects that are coming on that will directionally move us more towards gasoline like the modernization of FCC and that was a good example of that. Some of the things we’re doing at Wood River. But I think on balance you should expect we’re going to be in kind of 43% to 45% type gasoline yields for ’16.

Phil Gresh with JPMorgan is on line with a question.

First question on the third quarter call last year I had asked about the timing of reaching full run rate on the two projects, the 400 million to 500 million. I was just wondering if you could give an update on that. Obviously it's a little bit of a slow start on the NGL side, sounds like LPG is on time. But there is a market exposure piece there. So, as we go through ’17, I mean what level are you of the 400 to 500 are you confident with at this point?

So the 400 to 500 is really the total for that fractionation and that’s a smaller piece of that total, the net LPG terminal and the access, and we’ve always said 20% to 30% of that’s commodity type of exposure. So I think there is always where the market structure is going to be, and where their arm is going to be between the Gulf Coast and export markets in Asia, Europe or Latin America. So as this export terminal completes late this year, you go through start up. I think you start to see that impact really full chain value impact really starts at late this year in 2017 and I think the real question is going to be is what is that commercial piece of that going to be. So that is we boys framed it a bit from the 400 million to 500 million in terms of where the market goes, but if crude prices recover globally I think that increases that are naturally when we see that, so I think that’s a variable that’s a piece of that.

So ex the RPC say it's just on the execution front on the rest you’re comfortable like mid ’17 you could hit the full run rate on the rest?

Yes and I think the fraction would be when you think about composition, you think about that, that comes up it's a relatively small contribution and it's really about the cargos, we have eight cargos that we’re looking at. So continue to work contracts and then we have commercial opportunity and there is always spot business with that, but we believe the supply is there to fill that.

Okay. Second question is just out here on the NGL side, particularly from the chemicals angle. Just kind of wondering how you’re thinking about input cost pricing with respect to ethane, propane. Obviously there is some improved sentiment here around the export impact of demand, impact on NLGs, I am just wondering how you're think about both availability and the cost of the NGLs for your chemicals business?

So I think as we thought about and we'll cost the LPG side, we're basically seeing parity today between ethane, propane and butane in terms of value in the cracking play. And our view has been that the export net back price will step a price for propane, butane and then the ethane could reach that perhaps in terms of cracking parity. But the balance really comes about which of those feed stocks you select. But the export net back really becomes the upper limit of what we set for the cracking value. Ethane in our view given coming out of rejection and what we see on the start up for the projects should still remain a competitive disadvantage for the long-term and so I think it really is that interplay somewhere between gas value and propane, butane parity on the cracking that determines that. But we would expect when the new crackers start up that ethane prices will come up somewhat to pull some of that ethane back out of the gas stream. The bottom line is we're still bullish on the operating rig items chemicals as well as the competitive advantage that you get from ethane and LPG cracking.

We think about the petrochemical environment right now, you really, it is demand pull that's pulling values and is really not feedstock causes any values in the market today.

So you say the margins that you have achieved in the first quarter, you'd see sustainable even if input costs rose because of the demand?

I think the margins ruled off in first quarter in the market side, but we're seeing improvement and I think as demand side continue to get better so we're seeing tightening on that and so I think the demand side is actually going to be a positive as we look out to the rest of the year.

Okay. Thank you.

Jeff Dietert with Simmons is online with the question.

Following up on the chemical margins discussion, are you seeing margins widened as we move through April with the increase in oil price and I noticed that utilization actually was going down in the second quarter relative to first quarter, could you talk about this topic?

So we hit the utilization first and I would say that with turnaround in the industry and CPChem currently has a cracker in turnaround as well. They are just seeing utilizations fall from turnaround perspective and we've always felt 2016 is going to be a fairly heavy turnaround for the U.S. industry. And as far as the current pricing, we are seeing strengthening in that on the derivative side and I think that's both the response to both demand as well you are now seeing the move up in crude oil. So you are seeing two things that kind of influenced that price from a global standpoint on that say the polyethylene is the key derivative for that.

And second, following up on the gasoline versus distillate yield, it's my understanding once gasoline cracks are higher than distillate cracks just kind of shifts towards maximizing gasoline, but as you look at distillate cracks at the half the level they were last year, are there incremental things you can year-over-year to increase gasoline yield and perhaps moderate distillate yield?

But I think, Greg alluded some of the things we're doing to increase conversion across FCCs and cover some of that fee into that, beyond that it's a longer term investment and we have to see longer single. But I look at distillate also say that if the economy industrially across the world picks up, you will see more distillate demand and that's benefactor in the distillate sluggish distillate demand that we're seeing, we're seeing good consumer demand, weaker industrial. And so I think you got to take a view that industrial piece at some point thus come back and I think we’re seeing signs of perhaps in Asia. But that's a big piece of trade piece and distillate really drives the industrial side. So I think we look at this and say it's not clear that you got to a permanent separation as you have to think about that from an investment standpoint.

Thanks for your comments.

Paul Sankey with Wolfe Research is online with the question.

Hi good afternoon. You have kind of gone beyond the answer to this question which is about the NGL market, you talked about pricing, could you just update us given the changes in the market on how volume have shifted both in terms of just over the past year but also to the extent your outlook has shifted and especially the impact you might have in the market. I know you adjust this kind of from a price standpoint, but could you talk about the volume? Thanks.

On the NGL volumes Paul?

I mean we always struggle with this market because it's sort of nebulous area.

Okay so what we're seeing and we're seeing NGL volumes still hanging in there. You would expect with drilling activity, you would eventually expect to see that the break over bit, but we're still seeing good NGL volumes coming into the Gulf Coast. The Permian in particular looks really good. I think its price back what on improved side. The Eagle Ford being we're seeing decline rates both in NGL and crude. But overall NGL volumes have been up to kind of holding flat and in fact we had record propane production but you got refinery input on the propane side as well which may tie back to gasoline mode. so I would say on the NGL side we've seen a whole then as crude oil prices recover and drilling resumes and if you believe that North America is going to have incremental call, we're still bullish that the NGL supply is going to continue the increase.

What do you attribute the volumes surprisingly holding up to?

Yes, I think it's just seeing kind of the same story in the crude side, I think there was just a lot of latent activity there and then I think the economics behind the drilling in the basins that we're touching are driving that. So you've obviously seen that hold and I think it just reflects what the production side of the business is seeing on the E&P side.

So, you might almost be thinking that we're actually bottoming out in terms of volumes and actually will hold or go higher from here?

I think you've got to see that drilling resume to really start to see that comeback and I suspect we'll continue to see NGL volumes kind of holding steady perhaps decline a bit and then it takes time. I think would be our view on the E&P side to kind of restart all that activity and your guess is as good as mine about exactly where they are. But with the capital expenditures where they are on the upstream. It's hard to see that you're going to see a lot of extra volume over the next 12 months until that program ramps buck up and so sustained crude oil prices will help drive that and we think long - over a period of month. That's what you begin to see but I think we're kind of and I think our view is we are probably getting closer to the bottom and may stay there while and we're certainly going to continue to see volatility.

I was looking on the idea that your guess would be better than mine. Great, this may be a very quick answer, I fully understand if it is, but you've had a significant [indiscernible] in shareholders' structure over the past year or so, has that had any impact on your Board or on your strategy?

I think we're pretty open about what our strategy is, it's been very consistent and so you can draw your own conclusion from that, Board is still the same, we have a great Board, we have a great shareholder base, so I think yes, I tried to answer your question.

Thank you.

Brad Heffern with RBC Capital Markets is on line with the question.

I was hoping to ask the question about Rockies Express, you obviously had been the [Rofer] (Ph) and so it's not exercised it, so I'm curious, how strategic you view that pipeline in a longer term?

So, we look at [indiscernible], I would say tall Tallgrass has done a good job of creating value around our pipeline that was designed to go west to east to with what they've done. So we've liked what they've done from the value standpoint, in terms of the Rofer we've got a pretty expensive organic program that really fits around out chemical refining NGL assets and that's where the capital goes. So, we'd like to stay where we are with that and it really didn't scale our investment side of that but we think Tallgrass is doing a good job creating value. So, we like it the retro pipeline with that and it gives us midsize in the gas markets as well.

And I guess we're going back to CPChem, thinking about the cracker, I'm curious your outlook for the economics for that project now versus the investment case, obviously and you wouldn't have assume that oil prices were going to be as well as they are, but at the same time I assume that demand is probably better than you expected. So what are kind of the puts and takes there?

I think on the volume side we haven't waivered that, it's going to be come up to be good demand globally, we always going to get the cracker stable so I think that's the good news. On the margin side the spread between ethane and crude and that ultimately that crude price shifts those say polyethylene or derivative price. That's narrowed a bit, I think that our view would be that that's a step front little bit of a headwind, but as you look out and if you believe crude comes back to a another level above $60 and I think we looked at the premises still are pretty much in line with our investment thesis. So I think we still like it and from a return standpoint even today's margins there's a significant cost advantage with this new complex just on the operating side of the business that offsets some of that margin but I think we still have expectations that this will be a very strong profit driver for CPChem for us as our share on the EBITDA basis incrementally as that’s just the cracker structure, it was roughly $500 million with some upside.

So, another way I think about that is, you look at kind of industry markers today, full chain margins, ethane is $0.28, $0.29, that's certainly well above reinvestment levels and so I think you'd be happy with that investment with today's margins out there.

Okay, thanks for the answers.

Faisel Khan with Citigroup is on line with a question.

Thanks good afternoon. Just a couple of questions, one LPG, one gasoline, on the LPG side you guys talked about the sort of looking for additional contracts on the capacity that you still have open. But just curious is that capacity or is that market to export off your docks is that still in that $0.13 a gallon sort of range, is that still the market price or is it something different?

Well you're right, I think that on a contract basis, we haven’t disclosed the terms specifically. And it's a range of things. I would say that the contract market long-term is higher than the spot market it's maybe how I would like to answer that. So I think as you see these budgets come on the contract piece would link that we’re seeing or the short that we’re seeing on demand side has moved that spot market down, but we’re still seeing good contract prices, and I think the customers that you talk to have a vision about long-term supply and that’s an important division. So I think with all aspects you just have to look at the mix and decide which way you can go.

And did I hear your comments right that on the LPG demand full size from the export side equation that that right now is fairly pricing elastics because of the demand for light feedstock into global petrochemical capacity or is that - did I hear that wrong?

No, I was talking about we’re fairly neutral in the U.S. about what we chose to crack and so the link in the LPG still needs to be exported. We’re still seeing good demand for PDH propane de-hydro units for cracker feeds around that. So it was really comments around the U.S. with its existing petrochemical operations, fairly stable and we’re posting different in terms of feedstock and every producer has their own preference to which feedstock they crack. And so that leaves you with there is excess LPG it still needs to be exported. You’re seeing propane, butane and some of the C5 and now you’re starting to see some things happen on the ethane side as well.

And what about ethylene, is that something that if you move across feedstocks as well?

So ethylene is actually been exported in limited quantities out of the U.S. in other parts it's a more specialized trading. But yes there is some interest in increased ethylene export capacity and the ethane export capacity based on refrigeration is pretty similar. So it's just the dock capacity is there fully around the refrigeration and how would you export that and so can you convert what you have or just add to that, maybe add ethylene dimension.

Okay understood. On the gasoline side equation, so I understand that the projects that you guys have outstanding right now to potentially increase some of your gasoline yield. But if I’m looking at this coming summer versus last summer, I believe some of you also somewhat max out in gasoline production capacity. Can you produce or would you think that do you guys think you will produce more gasoline, finished gasoline this summer versus last summer?

I think we pretty much are running where we can. I would say on the industry side one thing is different this year is inventories are higher. So that may cap somewhat what you could see in terms of price response at the same time demand is up. So day sales in inventories actually haven’t grown as much as the gasoline absolute levels within case. So I think we still expect a fairly strong gasoline driving season and a good gasoline crack through the next couple of quarters.

It sound like you could produce much more gasoline out of your system summer versus last summer?

We really are running essentially about maximum capacity on the crude input side as well as the conversion side.

Go it. okay, thanks for the time guys. I appreciate it.

Neil Mehta with Goldman Sachs is on line with a question.

Just want to reach out on the West Coast here. That’s a place where the results came in a little bit soft relative to our expectations. Is there anything unusual in the first quarter it's actually the Plain side blind outage or some turnaround activity that could have impacted those results? And then as we have some of these SEC to come back on line over the next couple of months, do you think the West Coast environment stays relatively strong just because we’re going through a summer demand season? Or do you think we’re going to see some margin compression out there?

We had San Francisco down on turnaround first quarter and so that impacted results versus what we would have thought. We saw some impacts to Plain it's about some $10 million for the quarter. But we’re trying to mitigate that extent that we can. And then I think as [indiscernible] comes back up it's going to have an impact in California. The good news is demand is up quite a bit relative to last couple of years. And so I think we still got good demand going for you there. But I do think that you’re not going to see the volatility in California that we’ve seen in the past year or two.

And then stepping back as you think about your whole portfolio here, is everything that’s part of PSX right now would you consider core I mean I know the West Coast has come up in the past as a potential asset divestiture target. But what are your thoughts in terms of how your portfolio looks right now and whether anything you would consider non-core here?

So, we do have a process underway at Whitegate and we expect that we will conclude that process this year. California we talked about a lot the hold cost or the option value is really not much there is not a lot of capital in front of us in California last few year margins have been very good in California so it's a net cash contributor. And you think about could you sell asset probably but could we did good value for it, probably not and so I think we just hold it at this point in time they're good assets, they're probably mid back in terms of where they set their cost structure, but given the option value to keep, I think it'll just hang on.

All right guys. Thank you.

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

Thank you, Sally. We thank you for your interest in Phillips 66. IF you got additional questions, Debby [ph] now and I are available to take your call. Also I want to remind the transcript for our call will be posted on our website shortly. Thank you.

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