Welcome to the First Quarter 2018 Phillips 66 Earnings Conference Call. My name is Sharon, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note, that this conference is being recorded. I will now turn the call over to Jeff Dietert, Vice President, Investor Relations. Jeff, you may begin.

Good morning, and welcome to Phillips 66 first quarter earnings conference call. Participants on today's call will include Greg Garland, Chairman and CEO; and Kevin Mitchell, Executive Vice President and CFO. The presentation material we will be using during the call can be found on the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information. Slide 2 contains our Safe Harbor statement. It is a reminder that we will be making forward-looking statements during the presentation and our Q&A session. Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here, as well as in our SEC filings. With that, I'll turn the call over to Greg Garland for opening remarks.

Thanks, Jeff. Good morning everyone, and thank you for joining us today. Adjusted earnings for the first quarter were $512 million, or $1.04 per share. We generated $1.3 billion in operating cash flow excluding working capital. Our solid earnings reflect the benefit of our diversified portfolio and we've seen positive impacts from U.S. tax reform. Our strategy is designed to generate long-term value for our shareholders and our employees are executing the strategy well. We've achieved significant growth milestones and completed return enhancement projects. We're developing new projects with attractive returns that complement our strategy, and by doing all this well we can continue to reward our shareholders with solid distributions. During the quarter we bought back 35 million of our shares in a single transaction and continued with our share repurchase program. All in, we'll return $3.8 billion to shareholders. Since our company formation in 2012, we've returned over $20 billion through dividends, share repurchases and share exchanges. To put this in perspective, our market cap at inception was $20 billion. Today our market cap is over $50 billion, we repurchased exchange close to 30% of our shares outstanding at the time of the spin. CPChem start-up is new cracker at Cedar Bayou which is one of the largest and most energy efficient crackers in the world. This milestone caps a completion of it's U.S. Gulf Coast petrochemicals project. The cracker reached full design rates in April. CPChem also operated well during the quarter and is fully recovered from the hurricane downtime at Cedar Bayou. With major capital spending now complete and contributions from the new petrochemicals project we expect increased distributions from our chemicals joint venture. In midstream, Phillips 66 Partners recently announced it will proceed with the construction of the Gray Oak pipeline system. The pipeline will provide crude oil transportation from the Permian Basin to Gulf Coast destinations including our Sweeney Refinery. An extension open season is underway and will determine the ultimate scope and capacity of the pipeline which could be up to 700,000 barrels per day or more. Assuming the pipeline is fully subscribed the capacity could be expanded to about one million barrels per day. The pipeline is backed by long-term take or pay commitments with primarily investment grade customers and is expected to be complete by the end of 2019. Phillips 66 Partners will be the largest equity owner in this joint venture project. Construction continues on the Bayou Bridge pipeline extension from Lake Charles to St. James, Louisiana. Commercial operations are expected to begin in the fourth quarter of 2018. Existing segment of the line from our Beaumont Terminal to Lake Charles is operating well and is providing crude optionality to our Lake Charles refinery. PSXP has a 40% ownership in Bayou Bridge. Phillips 66 continues to expand the Beaumont Terminal where we're adding 3.5 million barrels of fully contracted crude oil storage. This project will bring our total crude and product storage capacity at Beaumont to 14.6 million barrels by year end. The Sand Hills pipeline capacity was closed to 400,000 barrels per day at the end of the first quarter, further capacity expansion to over 450,000 barrels a day is anticipated in the second half of 2018. The pipeline transports natural gas liquids from the Permian Basin to the Gulf Coast of Texas and is owned two-thirds by DCP and one-third by Phillips 66 Partners. DCP continues to progress construction of two 200 million cubic feet per day gas processing plants and the high growth DJ Basin. The Mewbourn 3 plant is expected to start up in the third quarter of 2018 and the O'Conner 2 plant is scheduled for completion in mid-2019. DCP is also participating in the Gulf Coast Express pipeline project in which it holds a 25% interest. The pipeline will provide an outlet for natural gas production in the Permian Basin to markets along the Texas Gulf Coast. The pipeline has a total design capacity of approximately 2 billion cubic feet per day and is nearly fully subscribed. The pipeline is expected to be completed in the fourth quarter of 2019. In refining, we recently completed SEC unit modernization projects at the Bayway and Wood River refineries. At both facilities we replaced the FCC reactor system with state-of-the-art technology. The projects were completed on-time and on-budget. Units have been operating as planned and early operating data is showing an increased field of high value clean products as premise. At the Lake Charles refinery, we completed crude unit modifications to run more domestic crudes which improves our supply optionality. Additional improvements are planned to be completed in the fourth quarter. Finally, we're very honored that four of our refineries were recently recognized by the AFPM for excellent safety performance in 2017. Our Bayway refinery received the Distinguished Safety Award which is the highest annual safety award given by or industry. The Sweeney Alliance and Woodward refineries were also recognized for their Top Tier safety excellence. I'm very proud of the people of Phillips 66 and their strong commitment to our safety culture. So with that I'll turn the call over to Kevin to review the financials.

Thank you, Greg. Hello, everyone. Starting with an overview on Slide 4, first quarter earnings were $524 million. We had special items that netted to a gain of $12 million. After excluding special items, adjusted earnings were $512 million or $1.04 per share. Operating cash flow excluding working capital was $1.3 billion. Capital spending for the quarter was $328 million with $171 million spent on growth projects. First quarter distributions to shareholders consisted of $3.5 billion in share repurchases and $327 million in dividends. Slide 5 compares first quarter and fourth quarter adjusted earnings by segment. Quarter-over-quarter adjusted earnings decreased by $36 million driven by lower refining results, mostly offset by improvements in chemicals, midstream and marketing; highlighting the benefit of our diversified portfolio. Slide 6 shows our midstream results; transportation adjusted net income for the quarter was $136 million, up $28 million from the prior quarter. The increase was primarily due to lower taxes and operating costs. Volumes were lower in the first quarter due to the impact of turnarounds at certain of our refineries. NGL and other adjusted net income was $73 million compared with $20 million in the fourth quarter. Our first quarter earnings reflect improved realized margins and positive inventory impacts. We continue to one run well at our Sweeny Hub [ph] this quarter averaging about nine cargos a month at the export facility, and 95% utilization at the fractionator. However U.S. Gulf Coast to Asia margins remain challenged. DCP Midstream had adjusted net income of $24 million in the first quarter. The $10 million increase from the previous quarter was due to the timing of incentive distributions, hedging gains and lower taxes. The increase was partially offset by lower volumes. DCP has steadily improved it's financial condition, EBITDA is growing, it's generating positive cash flow and making distributions to our owners [ph]. Turning to Chemicals on Slide 7; first quarter adjusted net income for the segment was $232 million, $111 million higher than the fourth quarter. In olefins and polyolefins, adjusted net income increased $129 million from higher margins and volumes reflecting the Cedar Bayou facilities return to full operations. Global O&P utilization was 96%, up from 79% in the fourth quarter. Adjusted net income for SA&S decreased by $16 million due to turnarounds. In Refining; crude utilization was 89% compared with 100% in the fourth quarter. Clean product yield was 83%, a decrease of 4 percentage points. Both, our utilization and clean product yield were lower due to turnaround impacts. Pre-tax turnaround costs were $245 million, an increase of $146 million from the previous quarter; this excludes the turnaround costs for our joint venture WRB. Realized margin was $9.29 per barrel, up from $8.98 per barrel last quarter. Although the market crack decreased 6%, our actual realized margins improved 3% from wider crude differentials, specifically heavy Canadian. The chart on Slide 8 provides a regional view of the change in adjusted net income. In total, refining's first quarter adjusted net income was $89 million, down $269 million from last quarter due to lower volumes and higher costs associated with turnarounds; this decrease was partially offset by higher realized margins. In the Atlantic Basin, the $193 million decrease in adjusted net income was mostly due to a major turnaround at the Bayway refinery. The Gulf Coast adjusted net income decreased $71 million mainly due to turnarounds at the Sweeney and Alliance refineries. Adjusted net income in the central corridor was $203 million, an increase of $11 million from higher realized margins driven by Canadian crude oil differentials. The impact from the fourth quarter completion of Ponca City refinery turnaround was more than offset by first quarter turnarounds at the Wood River and Boga [ph] refineries. In the West Coast, adjusted net income decreased $16 million from the previous quarter mainly due to lower volumes. Slide 9 covers market capture [ph]; the 3:2:1 market crack for the first quarter was $13.12 per barrel compared to $13.98 in the fourth quarter. Our realized margin for the first quarter was $9.29 per barrel resulting in an overall market capture of 71%, up from 64% in the fourth quarter. Market capture is impacted in part by the configuration of our refineries. We made less gasoline and more distillate on premise in the 3:2:1 market crack. Losses from secondary products of $1.47 per barrel were lower than the previous quarter by $0.52 per barrel. Feedstock advantage improved realized margins by $1.63 per barrel which was $0.81 per barrel better than the prior quarter from the widening WTI/WCS differential. The other category mainly includes costs associated with RINs, outgoing freight, product differentials and inventory impacts. This category reduced realized margins by $2.08 per barrel compared with $2.39 per barrel in the prior quarter. The improvement was driven by lower RINs costs. Let's move to marking and specialties on Slide 10. Adjusted first quarter net income was $174 million, $50 million higher than the fourth quarter. In marketing and other, the $42 million increase in adjusted net income was due to improved realized margins and lower taxes and operating costs; this was partially offset by lower volumes. During the first quarter we exported 190,000 barrels per day of refined products, we continue to see strong export demand during the quarter. Specialties adjusted net income was $45 million, an increase of $8 million from the prior quarter mainly due to lower taxes. During the first quarter we completed the restructuring of our XL Power Loops [ph] lives joint venture, both partners contributed their base oil businesses to the venture to create an integrated manufacturing and marketing business. The JV restructuring provides XL Power Loops [ph] with greater agility to provide quality base oil solutions to our customers. On Slide 11 the corporate and other segment had adjusted net costs of $162 million this quarter compared with $140 million in the prior quarter. The $22 million increase reflects the ongoing impact of lower tax rates on our corporate costs. Slide 12 highlights the change in cash during the quarter. We entered the year with $3.1 billion in cash on our balance sheet. Cash from operations excluding the impact from working capital was $1.3 billion. Working capital changes reduced cash flow by about $800 million largely due to normal seasonal inventory builds. We funded approximately $300 million of capital expenditures and investments, and we distributed $3.8 billion to shareholders through dividends and the repurchase of over 37 million shares, and in the quarter with 466 million shares outstanding. We also received $1.5 billion from the issuance of debt. Our ending cash balance was $842 million. 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 a global O&P utilization rates to be in the mid-90s. In refining, we expect the worldwide crude utilization rate to be in the mid-90s and pre-tax turnaround expenses to be between $90 million and $120 million. We anticipate second quarter corporate and other costs to come in between $170 million and $190 million after-tax. The increased guidance reflects interest expense associated with our first quarter issuance of debt. With that, we'll now open the line for questions.

[Operator Instructions] And you have a question from Doug Terreson with Evercore ISI.

Good morning, everybody and congratulations on having the financial strength to be able to repurchase 7% of your equity in one quarter, we don't see that often, that's pretty impressive. So my question is about AMO 2020 and specifically, how you guys are thinking about the type of products that are likely to be provided to the market as it seems that many of these deals are still in the design phase and there is still lot of unknowns in that area? And when you think about marine fuel blends, how challenging the issues of compatibility and stability are likely to be? And also availability along the marine field network as the market goes through the transition in coming years. So two questions on AMO 2020.

While we know the star -- the sulfur content of marker fuels, we don't have the detailed specifications yet, they're still evolving. We do expect a significant influx of diesel into the bunker category, we talked about last quarter kind of 2 million to 3 million barrels a day, increased diesel demand. Secondly, we do expect low sulfur cat cracker feed to be an attractive stock for bunker fuels as well which will support the gasoline markets also. We're expecting the turnover of tanks and blending infrastructure to start next year perhaps some time around mid-year and so it's a big shift and we're preparing for that. I think one of the things that I would mention is just that our portfolio -- our existing refining assets are well positioned for this IMO transition, we've got very high distilled yield, about 41% last year, $1 a barrel distillate change margin is $300 million in EBITDA. In addition, we expect fuel oil to weigh on heavy crude prices. We have heavy crude of about 700,000 barrels a day or about 35% of our total portfolio. We have more coking capacity at 470,000 barrels a day than the peers, every dollar per barrel change in heavy crude discount is about $250 million in EBITDA. So our portfolio is well positioned the way it stands today.

It sounds like it -- I just wanted to follow-up on your point about diverting vacuum gas all around the crack or straight to the marine fuel pool. I mean it seems that that would surely enhance marine fuel supply but it also seems like it would come at the expense of gasoline supply and that might make it somewhat of a zero sum game. So would you disagree with that, number one? Number two, how commonly is that practice been employed in the industry; meaning is this something that you guys have done frequently or have we seen this before?

This is something that we expect to be more of a new activity which converting from Max gasoline to Max diesel during the summer months as well as pulling some of the cat cracker feed. I think we'll support gasoline margins as well as supporting diesel cracks.

Next question comes from Neil Mehta with Goldman Sachs.

First question I had was just around capital spending. I know it's really early in the year but CapEx was below -- certainly, the annualized run rate that you've kind of guided to -- can you just speak to the guidance and whether there is a downward factors to it and just the timing of spend as well?

Neil, I think we're consistent with the guidance around the 2:3. I think that we were a little lie the first quarter and we knew we were going to be when we put the plan in place but 2:3 is still good guidance for us this year.

Second question on the quarter; Midstream big part of the beat, NGL and other was a driver of that and other some inventory benefits there, can you just kind of speak to what some of those dynamics were and how we should think about the run rate going forward?

As you look at that, so I think the NGL segment reported $73 million of income in the quarter. About $20 million of that is associated with inventory LIFO related items, nothing specifically unusual in what happened, it's just that the magnitude and it's positive in the quarter and these things will happen from time to time and it can go in the opposite direction also. But as you look at that and try and think about our run rate going forward, you probably ought to back out somewhere in the order of $20 million from what we reported in the first quarter.

That's helpful. And last question for me; on Permian differentials you guys have a good perspective on this, it's just over the next two years their absence of major pipeline is still the back half of 2019; how do we get the crude to market from West Texas?

I think it's a good question. You're correct, the next major pipelines are scheduled for the back half of 2019. We saw about 750,000 barrels a day of new capacity that was added late last year and early this year, and it certainly appears that that pipeline capacity is filling up more rapidly than anticipated. As we look at alternative route options, trucking is one. That's kind of a $12 a barrel movement at this point although that's not going to be a steady number. A typical truck can haul about 180 barrels of crude, it's roughly a 500-mile haul from the Permian to the Gulf Coast, it's a day -- 2-day round trip, so you need 100 trucks to move 10,000 barrels a day. It's not really realistic to expect to move 100,000 barrels a day or 200,000 barrels a day, it's just not really practical. From a rail perspective, there is not a lot of rail facilities. Most of the rail facilities in the Permian Basin are now designed for frac sand and not crude movement, and so that's not a great option. So we are in need of new pipeline capacity serving the Permian Basin. I think there's a lot of talk on the crude side and when you look at the Midland differential to East Houston, it's out to $9 a barrel, when there was enough infrastructure that was kind of $3 a barrel differential. When you look at natural gas as well, waha [ph] prices have declined about $1 in MMBTU relative to where they were last year, and that sets a lower price for natural gas and ethane rejection; so we may see some additional ethane production coming out of the Permian Basin as well.

Next question comes from Blake Fernandez with Scotia Howard Weil.

First one is just more housekeeping, probably for Kevin. The tax rate seemed really low in the quarter, I'm just trying to figure out if that's maybe some one-off issues driving that or if that's kind of sustainable?

Yes Blake, it is a little bit low and it really reflects the mixed effect of certain items in the portfolio; so the higher proportion of international earnings than I would say normal in part because of the amount of U.S. refining turnaround activity we had, so relatively low U.S. refining earnings contribution. Some of that dynamic as you look in the chemical segment, the Middle East joint ventures that CPChem has -- so that's in Qatar and Saudi Arabia, those are equity method accounting accounted at the CPChem level and those equity earnings are after-tax. So the entities themselves pay tax and that flows through after-tax. And so that has the impact of reducing the overall effective tax rate and it's more pronounced than a period where the other pre-tax income is lower because of -- for example, turn around impacts. You also have the effect of non-controlling interest in the effective tax rate calculation. We factor that into our overall guidance range effective tax rates but again when the rest of the portfolio is in a relatively low earnings quarter it has a slightly bigger impact. So all in, as we look at where this -- where we expect this to be on an ongoing basis, we'd still come back to -- it should be low 20s from an effective tax rate standpoint.

Got it, thank you. Greg I'll go out on a limb and assume that the buyback level of $3.8 billion in the first quarter is not sustainable. As we kind of get our bearing straight after that big slug; do you have any thoughts around the way we should think about that moving forward?

Yes, I think we'll stick with our guidance of $1 billion to $2 billion of share repurchases in 2018. We maybe towards the lower end of the range given what we've done in the first quarter but yes, we'll still be buying shares, we're buying today.

Next question comes from Phil Gresh with JPMorgan.

First question is just on some of the cash flow items, I guess that's for Kevin. The ending cash balance obviously given the repurchase in the quarter; how do you think about managing the cash balances and where you'd like to have them? And I guess a related question to that is -- should we be thinking of dropdowns to PSXP as a -- I guess the driver of some cash that would potentially make it's way to the parent company this year or with the organic opportunities available at PSXP is that not necessarily something that we would be thinking about?

Yes Phil, so a couple of comments on that. Obviously the drawdown in the cash was a function of the buyback, so we did a $3.3 billion buyback with Berkshire and we issued $1.5 billion of debt; so we consumed a fair amount of cash in doing that. Part of the reason we were able to do that is, if you think back to tax reform and the ability to get access to cash that previously was -- it wasn't trapped internationally but there was a greater cost to accessing that cash, and so we've taken advantage of that. And so what that means is, on a go-forward basis we have the ability to utilize more -- get more access to overall available cash balances. In terms of as you look out the year, we typically don't give what we haven't given guidance on dropdown plans around that. But as we commented or stated in the PSXP earnings release, we're not that far from our stated 2018 EBITDA guidance at the MLP level. So there is potential with organic growth projects underway at the MLP. Dropdown needs would be pretty minimal from an MLP growth standpoint and I wouldn't imagine we'd be in a situation where we would just force a draw to provide funding back up to the parent; all those decisions are made from us at a long-term MLP growth perspective.

That's very helpful, thanks. I guess the second question; a bit more of a strategic one for Greg. Just thinking about the current environment for chemical margins, obviously your cracker coming on-stream sounds like it's going really well in terms of the startup. If you look at the margin profile out there, ethylene margins are challenged but the full chain margins are still holding in pretty strongly. So how do you think about the chemical environment and what it might mean for the timing of a second cracker?

Well, I mean first of all it was a great startup, I think it's one of the better startups we've had in the last few that we've executed. So kudos to the CPChem folks who are doing a great job to get that cracker up and running it at full rates. The derivatives were up in the fourth quarter last year, Dow is up and so we've been up since really the fourth quarter and the market -- so the market facing element of those projects are out there in the markets and you look at kind of the full chain margin which is what we really care about, what that's spread between ethane and say polyethylene, and particularly high density polyethylene and as you said, those margins are pretty similar. So we've been able to move the products into the markets without a really detrimental effect on the margins at this point in time, the chain margin; and I think that really speaks to the demand that we're seeing out there, we're seeing good fundamental demand growth in North America, Europe, Asia for petrochemicals but specifically for polyethylene. You've got ExxonMobil coming up later this year, then you have two crackers coming up in '19, and what's happened -- we thought these crackers are all going to hit in 2017, it just didn't happen and so they are getting spaced out and the markets being able to absorb these volumes that are coming on -- couple with good demand growth globally. And so as we start thinking about that next cracker, we like what we see in terms of NGL supply, increasing NGL is coming particularly out of Permian but from the U.S. Gulf Coast is a good place to build the next cracker we believe. We're still kind of 2019 probably for an FID on that facility.

Next question comes from Mina [ph] with Credit Suisse.

I had a quick question on the Mitcon [ph] results which were very strong. So I'm trying to understand how much of WCS you were running in the Mitcon and did you actually uptake the intake of WCS in your Mitcon system which got reflected in those very high capture?

We imported 550 million of Canadian imports on average for 2017 or 1,000 million, sorry, thank you. And some of that was for -- our net -- we were about 450 million and 80% of that was Canadian heavy. And -- so that's the range of what we'd expect to run on an annual basis, we don't intend on updating that on a quarterly basis but we continue to import as we could on the Canadian heavy front.

Jeff, my phone up is on the question that Phil also asked was; I'm trying to understand were you actually shot ethylene in 1Q '18 because what I'm trying to get to is the $232 million net income you reported; would that have been like $250 million and $260 million had your ethylene cracker actually been running and you were not shot of ethylene in that period?

No, weren't short of ethylene. We had an ethylene inventory and there was plenty of ethylene available in the industry and I think that's what you're seeing in terms of just say ethylene margin itself.

Next question comes from Roger Read with Wells Fargo.

I guess if we could maybe hit the midstream segment one more time, I mean that has just been going back to the last year, year and a half; pretty tough sector until the fourth quarter, now the first quarter. So can you kind of walk us through how much of this is sort of market conditions changed, right oil prices recovered and how much of it is -- you know, the new project is coming online as well as just internal restructuring and so forth? And then, maybe kind of help us understand the sustainability here going forward, Exxon oil price continuing to increase, you're holding at these levels.

I think you want to start -- NGLs have certainly recovered versus say a year ago in terms of pricing. First quarter volumes were seasonally -- they were lower than the fourth quarter or third quarter but that's just seasonal, weather related impacts, particularly around the NGL side for us. You have the Sweeny Hub that's performing albeit not at the level that we would expect if you take the first quarter, then you kind of analyze those results we get to pay $130 million, $140 million of annualized EBITDA out of the Hub. We've laid in the plan as we said previously, $150 million of EBITDA for the Hub this year; and that's against an expectation of kind of $300 million to $400 million without the ARB [ph]. So I think that that asset still has room to go and as we look at the NGLs are coming at us out of the Permian this year, we do think that these across the doc are going to go up to get in the back half of this year and certainly into next year, so we see continued improvement there. We certainly have the new pipe Stapel [ph] is on, Bayou Bridge is on, so a lot of it is around the new assets that we've been bringing on that have been driving this.

Roger, I might just highlight; I know you're aware but in our supplemental reports on Page 6, we identified midstream adjusted EBITDA and if you look at PSXP and other midstream, it generated about $363 million of EBITDA in the first quarter. If you were to annualize that it's about $1.45 billion. We've also got about $300 million of refining assets and that's -- ties back with the $1.8 billion to $2 billion of EBITDA that we've talked about in our presentation material. So that supplemental report will give you a scorecard to keep track on our progress.

And then maybe you could just -- a complete change of direction here; RINs, you mentioned in the presentation part that lower RINs -- it helps out a little bit. Just curious what your expectation is if anything for -- let's call it potential RINs reform as we see '18 unfold.

So I'd answer the question this way, wherever hopeful. I'm just not sure we're going to get there. There is a lot of good work that's going on, AFPM, API; management teams are in Washington talking to Congress about potential reform. Our view is that it's broke, the system is broke, we need to fix it and so we'll see but I don't hold a lot of hope for 2018. Now some of my friends in the business are a lot more optimistic than I am that we'll get something done in 2018. I guess the other impact that you're seeing is the small refinery exceptions and that has certainly had an impact on the RINs prices. So we'll continue to follow, we'll continue to work it and continue to be hopeful we get to a resolution there.

Next question comes from Justin Jenkins with Raymond James.

I guess maybe in midstream with the Gray Oak projects, not sure how far I'll get here but have to try. Can we get a ballpark of maybe total capital cost fairly the range on that project? And then along that line maybe the confidence you had to push the spend down directly to PS 60 at the outset here?

Yes, so two parts. First part is really can't comment, we're an extension open season and the actual volumes that we end up with will dictate the size of the pie, the actual capital cost. You should expect that I would say 45 to 60 days will get this wrapped and then we'll come back and we'll tell you what the capital cost is going to be on the line. And we started at kind of 380 in the open season, I would just tell you we obviously did got more interest than that and that really kind of encouraged us to move on with the extension of the open season. So I think we're really optimistic on the line and we're the ultimate capacity, it lands on that line. And then as you think about the decision of where to place it, we've always said we want to execute as many of the organic projects as we can at PSXP and given this pipeline, we have increased the budget of PSXP for this year and Gray Oak is part of the reason we increased that. But you shouldn't look at that increase as the total cost of the pipeline if you want to think about it that way. So anyway, I think that Gray Oak is a great opportunity for our Company, it's certainly a great opportunity for Phillips 66 Partners, and we'll continue to make decisions about where do we place these projects, either PSX or PSXP obviously. But we'll continue to put as much as we can to PSXP and execute as much organic growth as we can at the MLP and that's very consistent with what we've been saying for the past couple of years.

And I guess shifting gears maybe on cash returns; I understand you answered Phil's question earlier about the buyback but how should we think about maybe the mix of returns going forward? Here we've got a good problem to have with the dividend yield, maybe as low as we can remember in a while but the mix of the buyback versus dividend growth or maybe faster dividend growth going forward?

Yes, I still think that if you think we're kind of $5 billion to $6 billion of cash at mid-cycle generation we can afford to -- first, $1 billion outstanding capital, the dividends of $1.04 billion, now that gives you a lot of room to grow the dividend but also execute a $1 billion to $2 billion growth program and $1 billion to $2 billion share repurchase program. And so that's how we continue to think about it at mid-cycle. Certainly as these new projects come on and we're going to add another $1 billion to $1.5 billion of EBITDA that increases our capability to fund or reinvest in the Company but we'll -- we're sticking with the 60:40 guidance, it's going to be really hard to hit that this year because we're already 3:8 distributions against the 2:3 capital budget and we just don't see ourselves really materially changing the capital guidance at this point in time in the year. So we'll be having on the distribution side in '18 but long-term we do like that 60:40 mix.

And just to add Justin on dividend, no change from what we've said in the past in terms of secure, competitive and growing. So we'll continue to grow the dividend, just because we did the big share buyback this year doesn't preclude us from increasing the dividends as well this year.

Next question comes from Doug [ph] with Bank of America Merrill Lynch.

A couple of follow-ups actually on that last question Greg, if I may. Obviously your share price is substantially above when you set the original distribution policy I guess. What about the mix between dividends and buybacks as part of that 60:40 split? Do you see yourself skewing more to back to the dividend or is -- are you kind of agnostic to the share price as it released to where you're buying back shares?

No, I wouldn't say we are -- well, first of all, on share repurchase it's all intrinsic value. And as we've said, we're using historical multiples and our view of EBITDA essentially, kind of two years out. As long as shares trade below that we're going to be buying shares. When you think about the dividend to Kevin's point; secure growing -- I think investors need to see that we have runway to continue to grow the dividend and we want to grow the dividend every year. We think it needs to be competitive, we look around and kind of what's the S&P to 100 yields or what's the yields of our competitors; and so we make sure we've got a very competitive dividend in the group. So we'll always grow the dividend but we'll grow it within those parameters in the extent that we're balancing between reinvestment and share repurchase, we'll buy the shares in.

So is it dividends per share or dividends per se; in other words, when you buy back stock is that counted as part of the dividend growth per share or not?

We're looking at dividends per share.

All right. So my follow-up is more of a macro question Greg, and it kind of goes back to the dinner you hosted back in December. I think you talked about the IMO issues has been more -- I don't know if it's worse in a month or more kind of transitory when it happens and not something that you would expect to work through the system. I'm just wondering your views of changed or not? I understand you're well positioned for it regardless of what happens but do you see it as more enduring or still somewhat short-lived when it gets implemented in 2020?

Yes, my own personal view and Jeff can jump in on this if he has to do. This is -- I don't know if it's going to short-lived but I think within a couple years you'll see that actually competed away.

Next question comes from Brad Heffern with RBC Capital Markets.

I was wondering on the crude export front, since you guys have Belmont and so on. We're export over 2 million barrels a day now, most people are expecting a million barrels a day of growth in the U.S. So is there the infrastructure in place to or will be in place to export 3 million plus barrels a day next year? And then 4 million in 2020 and on down the line?

Yes, you're right, we've seen a number of weeks over 2 million barrels a day of exports. We've expanded our capacity at Belmont to go from 400,000 barrels a day to 600,000 barrels a day. You saw we're participating in the Buckeye facility in corpus as well associated with the Gray Oak pipeline. We are seeing the expansion of export capability, it's one part of the value chain that's going to have to grow in order to continue to export and we think the majority of the incremental production is going to be exported. So we think maybe there's 3 million barrels a day capacity today but that number is growing, we don't see an immediate issue there at this point.

And then maybe for Kevin; you guys gave the mid-90s utilization guidance for CPChem. I assume that that's off of a new base, so if you could just clarify that if that's the case and if that's for the whole quarter and sort of what the new capacity number is that that 95% is based on?

Brad, you're correct that with the crackers starting up, the declared commercial operations on it in April, and so that adds it into the denominator from a total capacity standpoint. So the new polyethylene units were already reflected in the denominator, the new cracker is in effective second quarter; so that 96% includes our assumptions around what all the new units will be running.

Next question comes from Ryan Todd with Deutsche Bank.

Maybe I want to start off on product exports. I mean can you talk about the dynamics that you're seeing right now in product exports due to sequential decrease I think quarter-on-quarter. But it seems like we're also seeing reports that demand to ship is colonial [ph] has dropped to very low levels. I mean what are you seeing in terms of sequential drivers? What are you seeing in terms of relative netbacks, so that you can see domestically versus export and your ability to kind of capitalize on that going forward?

You're right, our product exports were down 190,000 barrels a day this quarter, about 90,000 barrels a day of that was gasoline and 100,000 barrels a day was diesel. We had refinery maintenance at Alliance in particular that reduced the availability of product that we could put into the export market. We are continuing to see strong demand, continued struggles with refining capacity in Latin America and so we expect that to hold up longer term.

And then maybe of a follow-up on -- since you brought up your personal views Greg on the duration of the IMO benefits; how do you think that it gets -- how do you think the ARB [ph] gets competed away. I mean, I don't disagree that it will be but at this point we've seen from for the most part independent refiners holding a relatively good line in terms of incremental investment; you're not planning for any large scale material investments to kind of compete away the ARB [ph]. How does it get competed away and who is that? Is it the majors and the global NOCs of the world and Asia that kind of competes the way they are how do you think that plays out?

I think you'll see continued investment in Asia in refining capacity, that's a big fuel market obviously. I suspect there will be continued discipline, we don't plan to make big investments, really just swing the portfolio. I think we've got plenty of capability as we sit today, there may be small things that we do along the way but I just -- it's just -- this industry, we just have a long history of being able to compete away really good margins and whether it's $5 or $15 on the distillate crack, I don't know what that's going to be; probably on the low end of that one for a couple years. But I think you're in a time, certainly '19 or '20 when we're going to really like the refining business and the margins and the cash is coming off this business but you know, to get out another three or four years ago it gets really hard to forecast.

One other thing I would add is we're not seeing the adoption of scrubbers at the pace that we anticipated a few months ago. I think it's been much lower and depending on the availability of the 3.5 [ph] fuel; after the changes are implemented, perhaps there may be a more rapid adoption of scrubbers but that's going to depend on the availability of the fuel and a number of items that are just hard to predict at this time.

I guess the other thing longer term too in terms of newbuilds in the shipping industry; if you relate the high end of the range I think people have to start talking about LNG and you know other options too. So I mean these things always come into balance by many factors really, we're working on that equation, it's not just going to be refining capacity, it's going to be the choice of the ship owners and we'll see where does it go.

Next question comes from Prasant Rao [ph] with Citi.

I wanted to ask this a different way, I know we've talked about IMO and the discrete window and Greg I agree this is something that does get competed away. But if you think about increasing clean product yields and specifically you guys have a few projects in 4Q, in trials and then you did a few earlier already. There is a baseline growth of clean product demand globally and export demand, and that feels like something that is more buildable towards. So I wanted to get a sense of IMO aside, what are your thoughts on a multi-year basis in terms of how that ramps? At what point -- how you build towards that in terms of incremental investment, not the IMO impact which feels like just an upside shock but more the secular growth flick could be multi-year that we've seen for several years here; what can we expect in terms of incremental investment towards that?

From our perspective it's $300 million a year, give or take is what we've been investing in refining to either improve yields or to access more advantage crude, one way or the other. I think the other part of the equation that we haven't talked about today and we could have touched on it in our past discussion but I think we're going to move to a higher octane fuel. And so I think that over a period of whatever 10 or 12 or 15 years, whatever it takes, you will see the industry invest to make a higher octane fuel assuming that gets done here in the next year or so. So I think there will be investable opportunities for refiners and for PSX that are -- what I would say not multi-million dollar investments but solid -- high returning projects for us; and so we'll always do that. The industry itself seems to have the ability, every time we do a turnaround we replace an exchanger that was a bottleneck for us or whatever; and we can create 1% or 2% a year, I think you'll continue to see that happen in the industry as we move forward. So I think it will be a combination of specific investments that people want to make to address the yield or advantage crude and then you to see the general creep [ph] that we tend to have in industry.

There aren't attractive projects to invest in, we'll continue to buyback stock and reduce the share account and make it accretive that way.

And then just a follow-up on something; Greg you came a lot of detail on this about the potential for the timing of the second cracker but I wanted to focus more and less on the margins and more on sort of the timing of the shift that we've seen in terms of the majors announcing their plans for petrochemical opportunities and investments and sort of -- over the last few months, how the industry book of projects in valuations may have been moving this and if those dynamics in anyway impact or sharpen your plans in terms of the potential plans for another cracker in the Gulf and in terms of timing how that -- there is a lot of moving parts there, so just wanted to get a sense on that particular piece of it, not necessarily the margin recoveries?

Well, I mean certainly it's a joint decision between the owners of CPChem and I think we have to have an agreed view of when the appropriate time that cracker is. At the CPChem level we're thinking about how do we move our products into the market in the most efficient manner, and we're the world's largest producer of high density polyethylene and these projects are generally geared towards that although we've added quite a bit of NAO capacity over the past couple of years also. So we're thinking about how do we efficiently move these products into the market; and so that's one thing we think about in terms of the timing decision, obviously NGL supplied feedstock supply those factor into those decisions of where you're going to build it and what are you going to build, ethane or some LPG cracker. And so I think that there's kind of multiple decision points that we go through when we're thinking about the timing on a cracker. One other things we wanted to make sure that there were some daylight in between when this Gulf Coast cracker project one came out and when we would do the second one. And so you kind of think of coming up in '18 and having most of '19; it seems like appropriate timing to us in terms of FID in light '19 and really getting started in earnest in '20 and '21 on the construction.

Next question comes from Paul Chang with Barclays.

A number of quick questions. Kevin, I think last year or a couple of years ago, you were talking about going forward you may want to keep the consolidate debt to be flat, so that you would reduce some of the C-corp level at the MLP level going up; is that still the objective going forward or that -- I mean over the past couple of years I think all that has been going up. So should we assume in the next 12 to 18 months that the cash flow increase further? Are you going to use a portion of them that trying to pay down your debt?

Some of this has been a function of -- debt has gone up on a consolidated level over the last year or two, and a big factor there has been the transaction we just did in the first quarter with the large share buybacks, so that added $1.5 billion of debt that we hadn't anticipated doing. But as we look ahead and we see a period of reasonably strong margins, you've got new projects coming online, you've got chemicals with the new assets up and running and expect increased distributions out of chemicals. We think we'll have the ability to pay down some of that debt over the next couple of years or so, I think you kind of got to that point that we have the ability to potentially bring debt back down a $1 billion or $1.5 billion or so over the next couple of years if margins hold in where we think they're going to be.

But you don't want to do even more than just $1 billion, $1.5 billion from the current rate?

It depends, I mean it's going to be somewhat dependent on the relative -- the alternative opportunities. The $1.5 billion we just added was clearly incremental debt, so it would be nice to be able to take care of that over the next near-term period, couple of years or so; and then it becomes opportunistic, what's the best use of available cash and it will depend on what the investment opportunities look like, where the share price trades and opportunities around share buybacks, and so it will be that continual sort of balancing act across those capital allocation decisions.

I think one thing that hasn't changed is really our view that we want to maintain a strong investment grade rating. So I think that really comes into play, we've always said around 30% debt to capital or 31% or so today, so we're slightly over that. But we'd used the 30% as kind of a proxy of a strong investment grade rating. But as we look at the debt and the capacity that we have today, we're comfortable with this level of debt at the Company. And as we said, we've got strong investment grade ratings today.

Greg, it seems that my understanding of the chemical is as you comment, you know as much as anyone; can you just give us a maybe easy way. With the new event cracker, if we're looking at today's margin, what is the contribution off the net income to you guys going to be?

Well, from an EBITDA basis, kind of it at today's margins at the CPChem level kind of $1 billion to $1.2 billion. So $500 million to $600 million of EBITDA back to us is an easy way to think about that.

Okay. So that is -- if today's margin hold because there the ethylene margin is already pretty low and you already have to pick it up from last year; so incrementally as Sweeny [ph] just on the ethylene margin. And that $1.2 billion is just on the ethylene margin I presume?

No, that's a full chain margin.

But you already have the PE margin from last year, right. So yes, I'm looking at incrementally with these clean cracker come on-stream; so what is the additional uptake that we should assume?

First of all, we're in startup right in the fourth quarter of last year. We're using ethylene that it either be inventoried or purchased and so you really didn't get the full impact of the new cracker being up. So the new cracker is probably our lowest increment of cost as we think about our value chain and the other crackers in our system, and so I think you -- the $1.2 billion is a good number if you want to think about this year, annualized.

Final one for me; how much is [indiscernible] can assess by pipeline into your refinery?

Paul, for commercial reasons we don't talk about individual sourcing of feedstock for individual refineries.

Okay. Or that can you tell us that which refinery -- I noted that you've won mostly in Berga [ph] how about the Ponca City and all the one, can you give us some idea which one may have assess?

Well, I think as you look at the Phillips 66 portfolio, we're roughly 35% heavy, 35% medium and 30% light on the portfolio as a whole.

And some of that light is imported.

I understand. And some of the light is also not from Midland [ph], it's probably from cushing or some other places.

Right, correct.

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

Thank you, Sharon. And thank all of you for your interest in Phillips 66. If you have additional questions, please call Rosie or me. Thank you.

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