菲利普斯66 (PSX) 2016 Q1 法說會逐字稿

Welcome to the first-quarter 2016 Phillips 66 earnings conference call. My name is Sally and I will be your operator for today's call.

(Operator Instructions)

Please note that his 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 Chief Executive Officer, Greg Garland; President, Tim Taylor; and Executive Vice President and Chief Financial Officer, Kevin Mitchell. The presentation material we will be using during the call can be found on the investor relations section of the Phillips 66 website, along with supplemental financial and operating information.

Slide 2 contains our Safe Harbor statement. It is a reminder we will be making forward-looking statements during the presentation, and our question-and-answer session. Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here, as well as in our filings with the SEC. With that, I'll 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 in 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're maintaining a disciplined approach to capital allocation, and believe that our strong balance sheet is a competitive advantage that positions us well to execute 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 our repurchase or exchange of 115 million shares. We continue to target a 60/40 split between reinvestment in our business, and distributions back to our shareholders, and we've targeted another dividend increase this year of at least 10%.

We've made good progress on our major growth projects. In midstream, we received all of 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 of the Sweeny hub is nearing completion. The LPG Export Terminal is 80% complete. It's on time and on budget. The completion of the terminal will represent a major step in the development of a world class energy complex with 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 increased its limited partner distributions by 5% this quarter, and remains on track to achieve it stated growth objective of a five-year 30% distribution compound annual growth rate through 2018.

DCP Midstream is reducing its cash breakeven through self-help initiatives, and expects to achieve breakeven at NGL prices below $0.35 per gallon this year. They are reducing cost, cut capital substantially, and converting commodity exposed contracts to fee base, 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 remains 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 feedstock we believe CPChem's asset base provides it with a competitive advantage.

CPChem continues to advance a US 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 will 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 in refining is operating excellence, maintaining our costs and capital discipline, and increasing returns through selective investment. We invest in projects that are quick pay out, low cost, and high return.

During the quarter, we advanced several of these refining projects. At the Wood River refinery, we're undergoing debottlenecking, and are on schedule for completion in the third quarter. At Bayway, work on the FCC modernization is on schedule.

At the Billings refinery, efforts under way 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'll turn the call over to Kevin Mitchell to review the quarter results. Kevin?

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 shareholders 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-to-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 will 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 were $72 million, down $6 million from the prior quarter, driven by lower equity earnings from Rockies Express pipeline and Explorer pipeline. NGL adjusted losses were $11 million for the first quarter. The $9 million decrease from the prior quarter was largely driven by seasonal storage activity, partially offset by lower tax expense. Adjusted losses for DCP Midstream were lower in the first quarter, primarily due to improved reliability and contract restructuring efforts, partially offset by the impact of lower commodity prices.

In chemicals, the global olefins and 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 and 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 and lower controllable costs. Adjusted earnings for SA&S increased by $7 million on higher equity earnings from increased sales volumes, due to fourth-quarter turnaround activities at CPChem's equity affiliates.

In refining, realized margins were $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 in part 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 yield 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 the deferral of some catalyst change out 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 down time. 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 reduction 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 costs and inventory impacts. Santa Maria continued to be affected by the Plains pipeline outage.

Next we will cover market capture on slide 12. Our worldwide realized margin was $7.11 per barrel versus the 321 market crack of $10.64 per barrel, resulting in an overall market capture of 67%. Market capture is impacted in part 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 premised in the 321 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. This stock 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 US 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 US marketing margins. Specialties 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 of $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 interest 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 of a US 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 Company wide, we expect the effective income tax rate to be in the mid 30%s. With that we'll now open the line for questions.

(Operator Instructions)

Doug Leggate with Bank of America Merrill Lynch.

I wonder if I could ask you about the impact of run cuts in the quarter, because my understanding is early in quarter, you had deliberately taken some steps to basically run at lower rates. And obviously I'm 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 are a little more exposed to that. I'd just love to get your perspective on how you see, if you see that cleaning up, and how you see that playing out, let's say over the next three to six months? And I'll leave it there, thank you.

So I'll start and Tim you can give the overlook on diesel. So we ran really hard in January and March, and we slowed down in February 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 really didn't affect the overall utilization as much as you might expect. But we did build some intermediate inventory during the quarter. So I think that's the major impact in terms of operations. And Tim, why don't you hit on the outlook in terms of distillate?

Doug, on the distillate side, exports are the key to really clearing the length in North America. And we're 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 by-product from a gasoline production standpoint. So I think as long as the exports markets are open, that will continue to clear the US.

Maybe just a quick follow-up. So you're planning to run your refineries back up into the mid 90s in the second quarter. So I'm 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 it will be more voluntary run cuts as we go through the next three to six months? It doesn't sound like it.

Doug, I think that we're seeing strong gasoline cracks. They've really recovered in March and now in April. The summer driving season, that's going to drive the overall refinery utilization, and 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 are looking to export, just to clear that. But I think the gasoline is pulling the refinery utilization up across the industry.

All right I'll let someone else jump on, thank you.

Blake Fernandez with Howard Weil is online with a question.

Maybe to just follow-up on Doug's distillate question. Do you have any sense that maybe once we reaccelerate activity here in the US from a drilling perspective, do you think that's a critical component 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 the equation, but right now it's probably less than 2% of total distillate demand. But it's helpful, it's maybe 40,000 or 50,000 barrels a day, is our estimate.

Okay, good that's helpful. Second piece is maybe a question for Kevin. The buyback seems to continue at a fairly robust rate, continuing the macro environment. I'm just curious, your thinking about ratability of the buyback program, and the seasonality of what we would expect on the cash flow?

So I'll take it and then Kevin can step in. So I think about this in several different buckets. So the first bucket is really, I think the first quarter is reflective of our view of what 2016 is going to be. You seen cracks have gone from $10 to $15, we've seen NGLs move from $0.37 to $0.47 to $0.48.

We're seeing good demand for transportation fuels, gasoline, we're seeing good demand for petrochemicals, we're seeing margins up a couple cents, and we margins will continue to improve in the pet chem chain. So we think that 2016 is still kind of a $4 billion to $5 billion type cash generation year from us from operations.

Second, I would say our view is that for high quality MLPs, we think that the equity markets are open, and we would expect between some combination of debt and equity, we would raise between $1 billion and $2 billion back into PSX this year. So this 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, a $1.2 billion dividend and $1 billion to $2 billion of share repurchases, given that. I will say, just looking at things going on, and we are going through every line item in the capital budget both for 2016 and 2017 and we're assuring that our premises that we started with are still valid, and these projects will generate returns that are acceptable and meet our requirements. So we'll be looking at that going forward into this year.

Thanks, Greg.

Paul Cheng with Barclays is online with a question.

Just curious that team, do you have any insight on what is the current economic between branding directly the line into the gasoline pool into the US, or to export to either Europe or Asia for the petrochemical feedstock? I think it's at this point.

I'm sorry Paul, you cut-off a little bit. Could you repeat the last part of your question?

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

Predominantly the exports are still the distillates. On the gasoline side, you're seeing strong demand around the world --

No, Tim I'm sorry, I probably did not make my question. I'm looking specifically for naphtha what is more economic to directly brand it into the gasoline pool in the US and then add octane to finish gasoline or that is better to take them out in US into the overseas to be used as a petrochemical feedstock? Any insight from you, given you're also a big petrochemical producer?

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

I see, and second question, maybe this is for Kevin. 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 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've broken out at this time.

Obviously the fractionator just started up at the end of last year, so still kind of going through that start up, a little bit of incremental costs that you wouldn't expect to be recurring, and volumes 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 3, can you tell us that where are you in the process?

So we are in the midst of really investing to deal with taking more sulfur out across our system, so we have a number of projects at our refineries that we're in the process of implementing, to complete that. But that's been a piece of our maintenance capital, or our long term maintenance capital that over the last several years, and the next year or so to complete that.

West Coast meets tier 3 standards so it's the other refineries we're investing in, and those investments are included within the $700 million of sustaining capital that we've outlined.

Greg, outside West Coast, how many of the other facilities already in compliance this year, or are all of them will need to wait until neat year before you're in compliance?

They will come in compliance at different times, given the investment schedule through 2018, that we will hit, Paul. So I think we have investments at most of the other refineries for tier 3. Some more than others.

The final question, Greg, I hear you about how to balance the cash flow and expecting $1 billion to $2 billion of the NPL ex the cash contribution through the C-corp. To the degree, if that didn't materialize, should be assume you're going to continue to fund the temporary shortfall on the buyback, or that the buyback will take a back seat?

Let me rephrase your question, Paul. To the extent we can't access the market--

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

Well I think that we said we could flex between $1 billion to 2 billion, and that's the guidance we've given. But I would just reiterate, we feel pretty strongly that the markets are going to be open to us.

All right, thank you.

Evan Calio with Morgan Stanley is online with a question.

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

So I would say we kind of guided or said that we're on a glide slope to a $3 billion capital program in 2017 and 2018, with $1 billion sustaining, and $2 billion worth of growth capital, primarily directed at midstream growth opportunities. In terms of the $3.9 billion 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 million-ish in terms of the amount of flex that we actually have this year.

Got it. And second on midstream, results were weaker than expected there, at least versus our numbers. Maybe you could discuss some of the drivers there, likely related to frac start up and how those factors impacted results, and made trends for 2016. I imagine some of those will unwind?

Yes, it's Tim. So basically look at transportation segment, consistent earnings quarter to quarter. So the DCP was slightly improved as well, so 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.

Right and anything relating?

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

Got it good. That makes sense.

Yes I'd just add Evan on DCP, so it was improved results, but it was still a loss for the quarter on an adjusted basis. And that reflects the 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.

Got it. Appreciate it.

Roger Read with Wells Fargo is online 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 what you would anticipate as we go into the summer? You made the comment about as long as the market remains open. Just curious what that means in numerical sense.

Yes, we've been running essentially at mid 90s utilization, so that's not changing so this last quarter we ran 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 stays where we were, so I think that's the key, for our Gulf Coast refineries 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 the say next 12 months or so?

Yes, I think we've been running pretty much max gasoline, as most of the industry has. We can flex about 3% to 4% between gasoline and diesel. So we do have some projections that are coming on that will directionally move us more towards gasoline, like the modernization of the FCC at Bayway is a good example of that, and some of the things we're doing at Wood River. But I think on balance you should expect we're going to be at 43% to 45% type gasoline yields for 2016.

Okay. Appreciate it, thank you.

Phil Gresh with JPMorgan is online with a question.

First question, on the third-quarter call last year, I'd asked about the timing of reaching a 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 2017, what level are you, of the $400 million to $500 million, are you confident with at this point?

So the $400 million to $500 million is really the total for that fractionation, and that's a smaller piece of that total for the LPG terminal and the access. And we've always said 20% to 30% of that is commodity type of exposure, so I think there's always where the market structure is going to be, and where it's going to be between the Gulf Coast and the export markets in Asia, Europe or Latin America. So as the 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 to get late this year in 2017.

And the real question is going to be what is that commercial piece of that going to be? So that's why we've 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 arb naturally when we see that, so I think that's a variable piece of that.

So ex the RPC, just on the execution front and the rest, you're comfortable like mid 2017 you could hit the full run rate on the rest?

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

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

So I think as we've thought about the, and we'll call it the LPG side, we're basically seeing parity today between ethane, propane and butane, in terms of the value and the cracking slate. And our view has been that the export net back price will set 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 feedstocks you select.

But the export netback really becomes the upper limit of what we set for the cracking value. Ethane, in our view, coming out of rejection, and what we see on the start up for the projects, should still remain at a competitive disadvantage for the long term. And so I think it really is an 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 the ethane back out of the gas stream.

Okay. Thank you.

But the bottom line is we're still bullish on the operating rate side on chemicals as well as the competitive advantage that you get from ethane and LPG cracking.

The thing we would say about the petrochemical environment right now, it is a demand pull that's pulling values, and it's really not feedstock costs that's sending values in the market today.

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

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

Okay, thank you.

Jeff Dietert with Simmons is online with a question.

Following up on the chemical margin discussion, are you seeing margins widen 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 the first quarter. Could you talk about those topics?

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

Second, following up on the gasoline versus distillate yield, it's my understanding, once gasoline cracks are higher than distillate cracks, there's a shift towards maximizing gasoline. But as you look at distillate cracks at half the level they were last year, are there incremental things you can do year on year to increase gasoline yield, and perhaps moderate distillate yield?

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

Thanks for your comments.

Paul Sankey with Wolfe Research is online with a question.

You've gone beyond the answer to this question, which is about the NGL market. You've talked about pricing. Could you just update us, given the changes on the market on how volumes have shifted, both in terms of just over the past year, but also to an extent that your outlook has shifted? And especially the impact you might have on the market? I know you've addressed this from a price standpoint, but could you talk about volume? Thanks.

On the raw NGL volumes, Paul?

We always struggle with this market because it's a nebulous area.

Okay, so what we're seeing is, we're seeing NGL volumes still hanging in there. You would expect with drilling activity, you would eventually expect to see that to break over a bit. But we're still seeing good NGL volumes coming in, into the Gulf Coast. The Permian, in particular looks really good. I think that ties back to what you see on the crude side.

The Eagle Ford being, we're seeing decline rates both in NGL and crude. But overall NGL volumes have been up to holding flat. And in fact, we had record propane production, but you've got a refinery input on the propane side as well, which may tie back to gasoline mode. So I'd say on the NGL side, we've seen it hold, and as crude oil prices recover and drilling resumes, and if you believe that North America is going to have that incremental call, we're still bullish that the NGL supply is going to continue the increase.

What would you attribute the volume surprisingly holding up to?

Yes, I think that just see the same story on the crude side. I think there's a lot of latent activity there, and then I think the economics behind the drilling in the basins we're touching are driving that. So we've seen that hold and I think that 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 come back, and I suspect we'll continue to see NGL volumes holding steady, perhaps decline a bit. And then it takes time, I think, would be our view on the E&P side to restart all of that activity. And your guess is as good as mine about exactly where they are, but with the capital expenditures budgets 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 back up.

So sustained crude oil prices would help drive that, and we think over a period of months, that's what you'll begin to see. But I think we're -- our view is, we're probably getting closer to the bottom. We may stay here awhile, and we're certainly going to continue to see volatility.

Understood, thanks. I was working on the idea that your guess would be better than mine. This may be a very quick answer, and I fully understand if it is. But you've had a significant shift in shareholder structure over the past year or so. Has that had any impact on your Board, or on your strategy? Thanks.

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

Thank you.

Brad Heffern with RBC Capital Markets is online with a question.

I was hoping to ask a question about Rockies Express. You obviously had the ROFR and chose not to exercise it. So I'm curious how strategic do you view that pipeline longer term?

We look at REX, and I'd say Tallgrass has done a good job of creating value around a pipeline that was designed to go West to East with what they've done. So we like what they've done from a value standpoint. In terms of the ROFR, we have got a pretty expansive organic program that really fits around our chemicals refining NGL assets, and that's where that capital goes, so we elected to stay where we are with that, and it really didn't scale our investment side to that. But we think Tallgrass is doing a good job creating value, so we like the REX pipeline with that, and it gives us some insights into the gas market as well.

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

I think on a volume side we haven't wavered, that it will come up, there will be good demand globally, you always get the cracker stable, so that's good news. On the margin side, the spread between ethane and crude, and ultimately that crude price sets those polyethylene or derivative price, that's narrowed a bit. I think our view would be, that's a up front, a little bit of a headwind. But as you look out, and if you believe crude comes back to 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 at 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 this will be a very strong profit driver for CPChem for us. Our share of that on the EBITDA basis incrementally as the cracker starts up, is roughly $500 million, with some upside.

So another way to think about that as you look at 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.

Thanks for your answers.

Faisel Khan with Citigroup is online with a question.

Just a couple questions. One on LPG, or one on gasoline. On the LPG side, you talked about looking for additional contracts on the capacity that you still have open. I'm just curious, is that capacity, or is that market to export off your docks, is that still in that $0.13 a gallon range? Is that still the market price, or is it something different?

I think 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, is maybe how I'd like to answer that.

So I think at you see these projects come on, the contract piece with the 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 the customers talk about a vision with long term supply, and that's an important dimension, so I think with all assets, you just have to look at the mix, and decide which way you can go.

Did I hear your comments right, that on the LPG demand pull, on the export side of the equation, that right now it's fairly price inelastic, because of the demand for light feedstock into global petrochemical capacity? Or did I hear that wrong?

No, I was talking about, we're fairly neutral in the US about what we choose to crack. And so the link in the LPG still needs to be exported, we're still seeing good demand for PDG, propane dehydro units for cracker feeds around that. So it was really a comment around the US, with its existing petrochemical operations, fairly stable, and we're close to indifferent in terms of feedstock and every producer has their own preference for which feedstock they crack. So that leaves you with that there's excess LPG, that still need to be exported. You're seeing it with propane, butane and some of the C5, and now you're starting to see some things happen on the ethane side, as well.

What about ethylene? Is that something that you can move across these docks as well?

So ethylene has actually been exported in limited quantities out of the US and other parts. It's a more specialized trade, but yes, there's some interest in increased ethylene export capacity, and that ethane export capacity, based on refrigeration, is pretty similar. So it's just, you have the dock capacities there, it's really around the refrigeration and how would you export that? And so can you convert what you have, or just add to that, to maybe add an ethylene dimension?

I understand, and on the gasoline side of the equation, so I understand the projects that you have sort of outstanding right now, to potentially increase some of your gasoline yield, but if I'm looking at this coming summer versus last summer, because I believe last summer you were also somewhat maxed out an gasoline production capacity. Can you produce or would you, do you 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 that's 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 days sales in inventories actually haven't grown as much as the gasoline absolute levels would indicate. So I think we still expect a fairly strong gasoline driving season, and a good gasoline crack through the next couple quarters.

Okay, so it doesn't sound like you could produce much more gasoline out of your system this summer, versus last summer?

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

Got it. Okay. Thanks for the time, appreciate it.

Neil Mehta with Goldman Sachs is online with a question.

Just wanted 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. Was there anything unusual in the first quarter potentially the Plains pipeline outage, or some turnaround activity, that could have impacted those results? And then as we have some of these FCCs come back online 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?

Yes, so we had San Francisco down on turnaround in the first quarter so that impacted results versus what you would have thought. We still have some impact to Plains. It's less than $10 million for the quarter, but we're trying to mitigate that to the extent we can.

And then I think, as Torrance comes back up, it will have an impact in California. The good news is, demand is up quite a bit, relative to the last couple years. So you still have got good demand going for you there, but I do think that you are not going to see the volatility in California that we see in the past year or two.

That's helpful. And stepping back, as you think about your whole portfolio here, is everything that is part of PSX right now, would you consider core? 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 under way at White Gate and we expect that we will conclude that process this year. California, we have talked about a lot. The hold cost or the option value to hold is really not much. There's not a lot of capital in front of us in California. Last few years, margins have been very good in California.

So it's a net cash contributor, and you think about, could you sell the asset? Probably, but could we get good value for it? Probably not. And so I think we just hold it at this point in time. They are good assets. They are probably mid back in terms of where they sit in their cost structures, but given the option value to keep, I think we'll just hang on to them.

All right, 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 have additional questions, [Debbie Mallen] and I are available to take your call. Also want to remind you a transcript from 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.