Welcome to the First Quarter 2017 Phillips 66 Earnings Conference Call. My name is Krista 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 now will turn the call over to Jeff Dietert. Jeff, you may begin.

Good morning, and welcome to the Phillips 66 first quarter earnings conference call. Participants on today's call will include Greg Garland, Chairman and Chief Executive Officer; Tim Taylor, President; and Kevin Mitchell, Executive Vice President and Chief Financial Officer. The presentation materials we will be using during the call today can be found on the Phillips 66's website along with supplemental financial and operating information. Slide two contains our Safe Harbor statement. It is a reminder that we will be making forward-looking statements during the presentation and our question and answer session. Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here as well as in our SEC filings. With that, I will turn the call over to Greg Garland for some opening comments. Greg C. Garland: Thanks, Jeff. Hey, good morning, everyone. Thanks for joining us today. Before we get started, I would like to welcome Jeff Dietert to the Phillips 66 team. Jeff, we are really glad that you are with us today. So, during the quarter we successfully completed several major turnarounds in Refining and Chemicals. This represents our highest level of turnaround activity in a quarter since the formation of our company. Our first quarter earnings largely reflect the impact of this downtime, but also highlight the benefit of our diversified and engraved portfolio. Our Chemicals business had solid results on strong demand and improved margins. We continue to successfully execute our Midstream growth program. Several of the largest projects we have been investing in over the last few years have now been completed, or almost complete. The LPG Export Terminal at Freeport, Texas, which is part of our Sweeny Hub complex was completed late last year. The facility operates at designed capacity in the first quarter and we are supplying customers in Europe, Latin America and Asia. We are currently evaluating opportunities to build additional fractionation capacity at Sweeny and other Gulf Coast locations, and we expect to reach FID later this year. Construction on the Dakota Access, ETCO pipeline is complete. Line fill is nearly finished, and we expect these pipelines to begin delivering Bakken crude to the Midwest and the Gulf Coast by June. Phillips 66 has a 25% interest in both of these lines. Our Beaumont Terminal expansion is ongoing. Recently, we added 2 million barrels of contracted crude storage. This morning, we FIDed additional five crude tanks, which will add another 2 million barrels of contacted crude storage by 2018. By mid-year we expect to add another 1.2 million barrels of product storage. As crude and product exports grow, Beaumont is well positioned to generate additional earnings. Phillips 66 Partners remains an important part of our Midstream growth strategy. We expect Partners to reach its growth goal of $1.1 billion in run rate EBITDA by the end of 2018. In addition to drop-downs to the partnership, PSXP is pursuing a number of organic growth initiatives. Progress continues on Partners' Bayou Bridge JV pipeline, which currently runs from our Beaumont Terminal to Lake Charles, Louisiana. The line is also being extended from Lake Charles to St. James. Earlier today, the development of a new isomerization unit was announced by Phillips 66 Partners. This project will provide fee-based earnings to the partnership and will increase the Lake Charles refinery's production of higher octane gasoline blend components. DCP Midstream simplified its corporate structure in January. The new structure better positions DCP for growth and improves capital allocation. DCP has successfully reduced its operating costs and returned to profitability. We expect to receive distributions from DCP in the second quarter. In Chemicals, CPChem is advancing the U.S. Gulf Coast petrochemicals project. The polyethylene units are on track to complete midyear, and the ethane cracker in the fourth quarter of 2017. We expect CPChem distributions to improve significantly with earnings contributions from these assets and reduced capital spending once the project is completed. In Refining, we are pursuing high return, quick payout projects. At the Billings Refinery, we're increasing heavy crude processing capability to 100%. This project is expected to be finished later this quarter. At Bayway and Wood River refineries, we're modernizing FCC units to increase clean product yields. Both of these projects are expected to complete in the first half of 2018. We continue to remain – maintain our commitment to our distributions to our shareholders. During the first quarter, we returned over $600 million to shareholders in the form of dividends and share buybacks. We remain committed to our strategy, executing our growth plans, enhancing returns and rewarding our shareholders. The projects we have coming online, they're well-positioned to increase cash flow. We believe our integrated downstream portfolio remains a differentiating factor that provides upside in a rising U.S. production environment. Before I turn the call over to Kevin to review the financial results, I'd just like to note that Monday will be our fifth year anniversary as a company. I want to thank all of our employees, contractors, business partners, the communities where we live and work, as well as the owners of our company and our board who have all enables us to accomplish so much in these past five years. Kevin? Kevin J. Mitchell: Thanks, Greg. Good morning. Starting on slide four, first quarter earnings were $535 million. We had two special items that netted to a benefit of $241 million. In Refining, we recognized a $261 million gain from the consolidation of the Merey Sweeny LP coking venture following the resolution of an ownership dispute. And in Chemicals, we had a $20 million charge related to an impairment of a CPChem joint venture. After removing these items, adjusted earnings were $294 million or $0.56 per share. Cash from operations for the quarter was negative $549 million. This includes a negative $1.3 billion working capital impact. Excluding working capital, cash from operations was $748 million. Capital spending for the quarter was $470 million, with approximately $270 million spent on growth. Distributions to shareholders in the first quarter totaled $611 million, including $326 million in dividends and $285 million in share repurchases. We finished the quarter with a net debt-to-capital ratio of 27%. Our adjusted effective income tax rate was 21%, reflecting a higher-than-typical proportion of earnings from lower tax jurisdictions. Slide five compares first quarter and fourth quarter adjusted earnings by segment. Quarter-over-quarter adjusted earnings increased by $211 million, driven by improvements across all of our operating segments. Slide six shows our Midstream results. After removing non-controlling interest of $35 million, Midstream's first quarter adjusted earnings were $77 million, $44 million higher than the fourth quarter. Transportation-adjusted earnings for the quarter were $56 million, up $12 million from the prior quarter, driven primarily by lower seasonal maintenance spend and increased equity earnings. In NGL, we had adjusted earnings of $4 million. This represented a $9 million increase and was largely driven by increased earnings from the Sweeny Hub assets. DCP Midstream had adjusted earnings of $17 million in the first quarter. The improvement over the fourth quarter reflects the benefit from hedges and lower operating costs, partially offset by reduced volumes. Turning to Chemicals on slide seven, first quarter adjusted earnings for the segment were $201 million, $77 million higher than in the fourth quarter. In Olefins and Polyolefins, adjusted earnings increased by $56 million, primarily due to improved margins, higher volumes driven by strong polyethylene demand and lower operating costs. Global O&P utilization was 89%, 3% higher than the prior quarter. Both periods were impacted by significant turnaround activity. Adjusted earnings for SA&S increased by $21 million due to higher margins and a gain on CPChem's sale of its K-Resin business. In Refining, crude utilization was 84% for the quarter, comparable with our low 80%s guidance. Pre-tax turnaround costs were $299 million. During the quarter, we had major turnarounds at the Ferndale, Bayway, Lake Charles and Wood River refineries. Clean product yield was 85%, down slightly from the previous quarter. Realized margin was $8.55 per barrel, up $2.08 from the fourth quarter. The chart on slide eight provides a regional view of the change in adjusted earnings. In total, the Refining segment had an adjusted loss of $2 million, a $93 million improvement from last quarter. Adjusted earnings in the Atlantic Basin were lower by $148 million. Market cracks decreased by 25% during the first quarter, and capacity utilization fell to 70% from 102% as Bayway completed a major turnaround. This decrease in Atlantic Basin earnings was more than offset by improvements in the other regions, primarily due to improved margin realizations. In the Gulf Coast, market cracks were slightly higher in the first quarter versus the fourth quarter and capture rates improved to 75% from 45%. The increase in capture is largely due to better clean product differentials. This includes pricing on cyclohexane, propylene, and benzene, as well as the absence of negative impacts from timing of product shipments made last quarter during a rising price environment. The improvement in the West Coast reflects higher volumes due the completion of fourth quarter turnaround activity at the Los Angeles Refinery along with higher margins. This was partially offset by a major turnaround at the Ferndale Refinery this quarter. Slide nine covers market capture. The 3:2:1 market crack for the quarter was $12.24 per barrel compared to $12.10 in the fourth quarter. Our realized margin for the first quarter was $8.55 per barrel, resulting in an overall market capture of 70%, significantly higher than the 53% achieved in the prior quarter. Market capture is impacted in part by the configuration of our refineries. This quarter, we made less gasoline and slightly more distillate than premised in the 3:2:1 market crack. Losses from secondary products of $2.66 per barrel were in line with the previous quarter, despite rising crude costs, as NGL and fuel oil prices increased. Feedstock advantage improved realizations by $1.58 per barrel, $0.14 per barrel less than the fourth quarter. The other category mainly includes costs associated with RINs, outgoing freight, product differentials and inventory impacts. This category improved by $2.49 per barrel from the prior quarter, primarily due to wider clean product differentials and lower RINs costs. Let's move to Marketing and Specialties on slide 10. Adjusted earnings for M&S for the first quarter were $141 million, similar to the fourth quarter. In Marketing and Other, the $10 million increase in adjusted earnings was largely due to higher realized margins, despite negative impacts from lower RIN prices. Higher margins were partially offset by lower volumes. Specialties adjusted earnings decreased by $9 million, primarily due to turnaround activity at the Excel Paralubes joint venture, which continued into the second quarter. On slide 11, the Corporate and Other segment had adjusted after-tax net costs of $123 million this quarter, compared to $119 million in the fourth quarter. The increase in net costs reflects higher interest expense and lower capitalized interest due to project start-ups, partially offset by lower environmental accruals. Slide 12 shows the change in cash during the first quarter. We entered the quarter with $2.7 billion in cash on our balance sheet. Excluding working capital impacts, cash from operations for the first quarter was $748 million. Working capital changes decreased cash flow by $1.3 billion, largely due to a seasonal inventory build. We funded $470 million of capital expenditures and investments, and distributed over $600 million to shareholders in dividends and share repurchases. We ended the first quarter with 516 million shares outstanding. We had $500 million of other cash flows. This category includes loan repayments from our WRB and DAPL joint ventures. At the end of the quarter, our cash balance was $1.5 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 mid-90%s. In Refining, we expect the worldwide crude utilization rate to be in the mid-90%s. And before tax turnaround expenses to be between $130 million and $160 million. We expect Corporate & Other Costs to come in between $125 million and $140 million after-tax. With that we'll now open the line for questions.

Thank you. We will now begin the question-and-answer session. Doug Terreson is online with a question. Your line is now open.

Good morning, everybody, and congratulations on your strong results. Greg C. Garland: Thanks, Doug.

My question is on cash. And specifically while there was a decline in the position in the quarter, seasonality is normally high in this area for you guys during the first quarter because of turnarounds and other factors, too. So my question is, do you expect the normal seasonal pattern of sources and uses of cash to repeat itself again in 2017 for the company? And second, could you specify the factors that affected the change in working capital during the first quarter that you showed on one of the slides and also just comment on whether or not they're going recur in coming periods? Kevin J. Mitchell: Yes, Doug. This is Kevin. I mean you're right in terms of the seasonal comment. I mean as we think about cash and working capital, where we ended the quarter at $1.5 billion was actually right in line with our expectations. Our plan had us right at that level at the end of the first quarter. We typically have the seasonal inventory build in the first quarter. And if you look back historically, typically, the first quarter is a use of cash from a working capital standpoint. And the normal kind of seasonal trends would apply. So this time you had the increase in inventory, which dominates that change in working capital, and it's the normal seasonal effect, but also with a heavy maintenance turnaround schedule that we had, you had some additional impact from that. We also had some line fill – downhole line fill contributed to that also. And then the other component from a working capital standpoint, because of the extent of the downtime which was weighted towards the end of the first quarter, so March was our highest downtime month. You actually had a bit of a rundown in payables over the course of the first quarter, and so you'd expect that to come back. And actually, as we look at it, as of yesterday, sort of end of April on an apples-to-apples basis, our cash balance is sitting at just over $2 billion. So you've already seen some of that come back. I wouldn't go so far as to say you can absolutely assume that the entire $1.3 billion comes back over the course of the year, but certainly some of it does.

Okay. Thanks a lot. That's very clear.

It's Justin Jenkins with Raymond James on line with a question. Your line is open. Justin S. Jenkins: Great. Thanks. Good morning, everyone. I guess I got a couple on the Midstream front. Greg, you mentioned in your remarks that we've got a lot of assets at PSX that have recently reached completion or are about to, and all those look pretty attractive to move into PSXP and would also presumably have a high tax basis, making it attractive for PSX as well. So I guess just from a high level, would those assets make sense as the next candidates for drop? And then would it also be reasonable to assume that a full quarter or two of operational data is maybe the hurdle before drop-downs? Greg C. Garland: Well, we like those assets, obviously, and they're certainly good candidates for drop at some point in time. We typically don't give guidance on what assets are coming next in terms of a drop. But certainly, there's always a point that those assets someday will end up at PSXP in terms of the Midstream assets. Justin S. Jenkins: Okay. Great. That's helpful. And then on the Rodeo project proposed in the quarter, can we get a sense maybe on how that's progressing and maybe the strategy on building those type of upstream facing assets, whether it's PSX or PSXP versus maybe looking at third-party M&A opportunities?

Yes. This is Tim Taylor. Rodeo project is in the Permian and it's really a gathering system that we looked at. So we're already there operating in that with pipeline operations, so it's a nice way to extend what we have there. There is also, as everyone knows, a very active basin now in terms of additional production. So, we are in those discussions with producers, and I think there's a lot of opportunity with that. And that will develop here over the next few months to see if it's a go-forward investment for us and so I think it's just part of our extension of continuing to look for organic projects where we can in the growth basins or in the growth markets to build on our presence there. Justin S. Jenkins: Great. Thanks, guys. Appreciate the color.

Thank you.

And we have Phil Gresh with JPMorgan on line with a question. Your line is open. Philip M. Gresh: Hey, there. Good afternoon. The first question, just on the Refining performance in the quarter, Kevin you talked about the other bucket, which if I look at a couple other regions, Atlantic Basin, Gulf Coast, is actually – is a positive contributor. Typically, there is some amount of negative contribution there, and you had mentioned RINs. So I was just wondering if actually RINs was a positive in the quarter potentially. Kevin J. Mitchell: No. Philip M. Gresh: One of your peers did mention this. So I was curious. Kevin J. Mitchell: No, definitely not. RINs is still a reduction to the realized margin, it's just a less of a reduction with the RINs prices coming down over the period. The other – but it is part of the improvement, the relative improvement quarter-over-quarter. And then the bigger item are the clean product differentials that I talked about. Some of the non-gasoline distillate clean products and also the absence of the timing effects on those product shipments from last quarter. Philip M. Gresh: Right. Okay. Second question is just you're going to be running around 95% utilization in the second quarter, up from 84% in the first quarter. We are seeing several other companies in the industry talk similarly. So, Greg, I am just wondering how you feel about the outlook for Refining margins as we move into the summer here. We're already starting to see build in product inventories and it just seems like these runs numbers are quite high. So curious what your view is. Greg C. Garland: Yes, I think we've always said that we felt like 2017 was going to look a lot like 2016, particularly in the front half of the year. And we always had hope that the back half might clear and we see the opportunity for some margin improvement. I think you should also expect, though, you would have significant turnaround activity in the industry and we always come up and everyone runs better. Assets are clean, they are ready to go and people are going to run. So I think that coupled with certainly through the first quarter and into early April, on the demand side, it looks flattish to us at best on gasoline demand. Maybe distillate demand is going to be a little better. So I would say those are concerns for us as we think in the back half of the year. I think, Jeff, if you want to comment a little bit on the economy. I think we are getting more positive in the economy, so we think about the back half of the year, maybe excluding the first quarter GDP results that came out this morning.

Yes, GDP results were a little bit lower than the consensus, but there were a number of items worth highlighting. U.S. consumer confidence was very high. The April number was the second highest since 2001. When you look at the U.S. manufacturing PMI statistics, they're at the high-end of the five-year range, business investment up 9% year-on-year. So some of the factors that drive gasoline demand and diesel demand have been strong domestically and PMI's have been improving internationally across Europe and Asia as well. Greg C. Garland: Yes, I think our view – and same thing in the petrochemicals business. We are seeing good, solid demand, really globally, at the petrochemicals business. So you kind of factor in – we may actually have better economic conditions in 2017 versus 2016 and that should be a positive direction for us. You want to comment, Tim?

I just think on the demand side, it's flattish or same side store sales, when we look at the retail side of our business, the market side, we were down about half a percent in the first quarter. I think we're really – what you have to see to balance the market is you've got to see some uptick now in the summer driving season and you've got to balance with some exports. And we have seen good demand there, but I think those are two key parts of how you get the demand to catch up with the supply piece. And that's going to be the critical verticals that watch going forward. Philip M. Gresh: Okay. Thanks.

I just might mention the emphasis on exports as well. We had a very strong fourth quarter, 175,000 barrels a day of product exports. The first quarter number was 144,000 barrels a day, a little bit softer due to some maintenance at Alliance, which is one of our major export facilities. But also we are positioning the portfolio for continued export growth at Beaumont, where we have 400,000 barrels a day going to 600,000 barrels a day of crude and product export capacity. Philip M. Gresh: Right. Okay. And then just last question is just on the capital spending. The first quarter number was actually quite low, and especially on Midstream we haven't seen a number this low in a while. So just curious how you're expecting that to progress, do you expect the Midstream spend to start ramping up or should we be thinking maybe that the guidance have some room to come down? Greg C. Garland: Yeah, I wouldn't annualize that first quarter number, certainly. It's clear, we finished the heavy lifting around the Sweeny Hub project. And I think purposely as we thought about the 2017 capital budget, we've built in quite a bit of flexibility. We had some concern over margins and cash generation in 2017, so we left ourselves a lot of flexibility this year to adjust CapEx if needed. But I do think that – we're still guiding to the 2.7 (25:39) today, mid-year we'll give you an update on that, but we have a lot – and we have a lot of good opportunities. I think, you think about FID'ing the frac but we've always thought that would be the back-half of the year. And so I think you will see things pick up, Phil. Philip M. Gresh: Okay. Thanks a lot, Greg. Greg C. Garland: You bet.

Ed Westlake is on line with a question with Credit Suisse. Your line is open.

Yes. Good morning. Thanks for your time this morning. Just on the Chemicals. Obviously one of the big, big drivers of the improvement in cash flow as you look into 2018 is going to be not spending on the cracker and getting your share of the EBITDA, and then distributions. Maybe just a reminder of just sort of the latest thoughts on CapEx in 2017 and then 2018 at CPChem. And then a question on how the processes of distributions, presumably there'll be a board meeting at some point early next year, and if the cracker is up and running you'll decide to increase distributions, maybe some color there? Thank you. Greg C. Garland: Yeah, well, just a couple. So CPChem's budget this year is $1.375 billion, and I think they're probably going to be right on top of that number it looks like to us at this point in time. But that's down quite a bit, about $600 million from last year. So certainly we are finishing up the polyethylene units, the cracker will be towards the end of the year as we finish that up. And then so that should generate between $1.2 billion and $1.4 billion mid-cycle at the CPChem level, so we're anxious to see that. I mean the policy of CPChem is essentially to distribute the cash. We pay all the expenses, but then most of the cash gets distributed. I think the – I mean, the question a lot of people have is when is the second cracker coming? And I suspect that we would not FID the second cracker in 2018. It could be towards the end – or 2019 is what we're looking at right now. So I think our expectation is we'll have a full year of 2018 cash flow out of the new project. And, Tim, you may want to comment on timing.

Yeah. So as we look at the Gulf Coast project, as Greg alluded to in his comments, the polyethylene unit completes this summer. We should start to see the earnings impact on those derivatives in the third and fourth quarters, you got to get through the startup piece of that. And then the cracker completing late in the year in the fourth quarter, we really see the earnings for the full stream really come on in the first half of 2018 to hit that run rate EBITDA. But I think we've got a very strong possibility that we've got a much increased cash flow that translates back to distributions to the owners. Kevin J. Mitchell: Yeah, Ed, this is Kevin. I would just add, we are expecting distributions from CPChem this year. We haven't had discretionary distributions in a little while, but we are anticipating some of that starting this year. Obviously that will increase quite a bit next year with the combination of capital coming down and the EBITDA from the new project.

And then one for, Tim, just on – always good color on the NGL arb and exports. Maybe we just need higher prices, but it does feel like there's going to be a wall of NGLs coming, and so there should be some excess return from the infrastructure you're putting in. But any comment on the current market conditions would be helpful.

Yeah. Well, it's been interesting. In the first quarter the LPG markets in general, whether it be ethane, propane, butane, have really entered into the cracking slate. So fairly – some variability during the quarter in each of those components being favored. So that kind of added some demand on the propane, butane side. We've continued to export very heavily as an industry, almost 1 million barrels a day of propane. And so we've seen inventories fall. And so I think the demand-side has been really strong. The challenge is we need more supply from our perspective to really load that. But the high propane prices narrowed the arb into various markets. So if it continues, but we need to see more volume supply side to really widen that and a little bit higher crude price. So I think as we look forward, we think NGLs will continue to come on stream based on what we see, building into 2018. But we think in front of that, in 2017, we would expect the international arb to be a bit narrower until we get that piece sorted out. But overall, we're seeing a lot of production opportunity developing, and that's why it still gives us a very bullish case we believe long-term on the NGL supply, chemicals production here, as well as exports out of the U.S.

Very helpful. Thank you.

Paul Cheng with Barclays is online with a question. Your line is open.

Hey, guys. Good morning or good afternoon from New York. Greg C. Garland: Hey, Paul.

Yes, I think, Greg, that you mentioned that the new ethane cracker, once that is fully operational, $1.2 billion to $1.4 billion EBITDA mid-cycle. How you define as mid-cycle? Or that if you can tell us maybe the other way, is that based on the first quarter market condition, what that EBITDA contribution may look like?

Paul, just – yeah. So that cracker's about 3.3 billion pounds a year of ethylene. And so very simply, if you think that the first quarter cash margins in that low $0.30 per pound range. So when you multiply that out, you get about $1 billion at today's conditions, maybe slightly more. And as we think longer-term, we think with continued low ethane pricing, improvement strengthening the crude, that that comes up another – into the mid-cycle range in the mid-$0.30s, which drives the $1.2 billion to $1.4 billion.

So based on the first quarter, it's about $1 billion?

Yeah, I would say...

That's (31:49) polyethylene?

Yes. That's the full chain. So that's polyethylene plus the ethylene.

Okay. And, Tim, do you have maybe some number can share about the LPG Export Terminal and the NGL fractionator, what's the run rate in the first quarter? And what kind of EBITDA contribution there may be?

So the LPG Export Terminal, we ran it – eight cargos a month is kind of what we define as capacity. We hit that. But overall utilization was in the 90% range, a little bit higher. On the fractionator, we were still running in the mid-80s, 80,000 barrels a day and 100,000 barrels a day. We've just recently been successful optimizing that unit a little bit right around 100,000 barrels a day at capacity. So I think we continue to find ways to improve and optimize around the asset. I think the run rate EBITDA, I'd still say very dependent on the arb, but we're somewhere in the range. If you look at the total, we're probably still in the range of around $200 million for the year, I would say, in these current market conditions. Just because the differentials between the U.S. and Asia and Europe are expected to remain pretty narrow.

Kevin, that first quarter turnaround cost end up to be lower than your previous guidance. Does – it means that for the full year, we should correspondingly assume it's going to be lower by the same amount? Or that the full year turnaround costs will still be about the same? Kevin J. Mitchell: Yeah, Paul, we haven't revised the full year guidance number. But it probably pushes you more to the lower end. We gave a pretty big range, $625 million to $675 million. And so realistically it probably pushes you more to the lower end of that range.

Or maybe let me ask it in this way. I mean the lower in the first quarter turnaround costs is just because you guys have been doing a better job and coming in below the budget. And maybe that even a little bit faster, not because that you have pushed some of the activity into the other quarters? Right?

Right. Right. For the most – that's right.

(34:08) that If you don't have cost overrun in the remainder of the year that we should see the same amount of that being come down in the full year.

Right.

In theory.

Right.

And final question that, Tim, for DAPL. With that up and running, does the pipeline operation, will in any shape or form, change the way how you source your refinery crew (34:32) or how you run your refinery? Or that doesn't really impact you, because that is not going all the way to the Louisiana side yet?

I didn't catch the last part of that, Paul. Not going all the way...

To Louisiana, since that (34:47) refinery in the Gulf Coast is in Louisiana.

Yeah. Well, we've seen recently the disruption in heavy Canadian crude has put a call on the Bakken crude in the northern tier. So I think as we think about DAPL startup, we see pretty good pull on that supply, generally. Certainly for some of our refining operation, that remains a very viable supply. You bring it to the Gulf Coast, you get to Beaumont. We've got the opportunity to get to Lake Charles. We're working on the extension to St. James. So I think then, you now see light crude from North Dakota lining in the Gulf Coast and you're going to see some rebalancing. So I think as we look at it, it all depends on the yield and the pricing. But we think Bakken will be an attractive supply crude within our system, particularly in Louisiana and in Wood River and some of our Mid-Con refineries. So I think that, from our standpoint, it's always good to have that extra option. And in the end, I think it helps rebalance the light sweet crudes on the Gulf Coast.

But have you make any changes to your operation yet or not really?

No. When we look at the Bakken, it's just really nothing required much there from the different – from what we've run traditionally in a light crude unit.

Okay. Thank you.

Neil Mehta with Goldman Sachs is online with a question. Your line is open.

Hey, guys, and, Jeff, congratulations on the new role. It's great to have you on the other side.

Thanks, Neil.

A couple questions on the crude side of the equation. And I guess the first is related to the OPEC cut and the potential extension later in May and your thoughts on the impact of the reduction in OPEC's supply on the light, heavy, and the medium sour barrels for your coastal refineries.

Yeah. On the OPEC, we're still seeing evidence of good compliance from the standpoint of OPEC reducing that. It certainly impacted the supply of medium and heavy sour crudes. And then you've had the Canadian crude outage as well, so that alone has kind of bid up, if you will, the price of the heavy medium sours. And then you put increased production of light crudes in the U.S. on top of that and you've seen that narrow. So our expectation is that this tightness lasts until the Canadian crude comes back on, widens out a bit. But depending on how much OPEC continues with the cut, that could continue to keep that differential tighter but maybe widening a bit with Canadian supply coming back. But I think generally, our view is it's still going to remain tighter than what it has been, say, for the last several years just because of the increased light and decreased supply of heavy sour.

That's helpful. And... Greg C. Garland: Yes.

Sorry, go ahead. Greg C. Garland: I just – I think our base case assumes that there's extension on May 25 in terms of OPEC.

Yes. It seems like we're lining up that way. The follow-up is just on U.S. oil production. As it continues to tick up, it feels like more of this light crude is coming down to the Gulf Coast. And there's increasing questions we're getting from investors about crude export capacity, and so it's more of a macro question for you guys. If the U.S. continues to grow at this 800,000 to 900,000 barrel a day annual pace, do you think we have enough crude export capacity on the Gulf Coast to clear the basin? And, ultimately, there's more crude export capacity to be built?

I think there's capacity today. We talked about Beaumont. Greg talked about that going to 600,000 barrels a day. You can always look at additional capacity there as well. And then you look around the system. And as you start to get beyond that utilization, perhaps there's an opportunity. So I think everyone is looking in the Texas Gulf Coast, Louisiana Gulf Coast at ways to increase export capability. And so our view would be is you may get some shorter-term tightness, but we'll probably find ways to continue to export should that continue to grow but it's also an infrastructure opportunity like what we're seeing around the Beaumont Terminal. Greg C. Garland: I think our view – certainly, we've demonstrated we can export, as an industry, over 1 million barrels a day pretty efficiently. I think as you start approaching that 2 million barrel a day mark, though, I think there's going to be additional investment required, is our view. And then the other issues, I think Luke (39:34) is probably the only facility that could really handle the big ones...

Correct. Greg C. Garland: ...very large crude carriers. And to my knowledge, I don't think there's any work going on there thinking about turning that around and going the other way. So I think there's going to be some additional infrastructure opportunities around crude exports out of the U.S. in the next couple of years, particularly as we see Permian, light sweet ramping up, and all that's going to hit on the Gulf Coast.

Thanks, Greg. Thanks, Tim. Greg C. Garland: Take care.

Paul Sankey with Wolfe Research is on line with a question. Your line is open.

Hi, everyone, and welcome to Jeff. Greg, excellent decision to hire a sell-side oil analyst that you wildly overpaid. If we could ask you a long-term strategy question, Greg, we know your view on Refining, I'm certain, that hasn't changed. When we think beyond the major projects stuff over the next year, where do you think the growth in the business – what's your view of how you will generate growth? Is it going to be a second major project that's been alluded to on this call? Thanks. Greg C. Garland: Yes, I think there will be certainly opportunities. You're starting to see the second wave of crackers being planned in the U.S. and, certainly, we think that the feedstock will be there for another additional wave of crackers and we want to be in that lineup ultimately with CPChem. I think there will be continued opportunity for infrastructure around the crude and the product side, so I think Midstream will certainly continue to be a growth vehicle for us and we'll continue to use the master limited partnership to help fund that and be a part of that growth as we move forward. I think in Refining, I think Refining is a good business. It's just, long-term, I just don't see it growing. I think that we've seen some decent gasoline demand growth over the last two years in the U.S. but, ultimately, I think there's just too many factors that are going to hit you in terms of efficiencies of vehicles, trending in terms of vehicle ownership in the U.S. and how we do that. So I actually think demand rolls at some point in the next couple of years in the U.S. and that we're going to need less transportation fuels. So I think exports are a really important part of that, that equation, and you see us, and many others, gearing up to try to handle that as we think a little differently about where our markets are going to be in the future. But really to invest in refining to add capacity still doesn't make sense to us. I think to invest to reduce your cost structure, gain access to advantaged crudes and grew some yields, those are all good investments that we should be making and what you will see us continue to do that around refining.

Yeah, that was actually where this all had started, where you finished, Greg, which is the export story., U.S. exports on every level are way exceeding overall market growth. Where are we taking market share? I know part of it is poor refining operations in certain parts of the world, but I just wonder how we should think about the long-term potential of the market when we must be making someone lose out somewhere, right?

Yeah, Paul, it's Tim. I think when you think about the Gulf Coast with the types of assets there are with access both inbound, outbound on product and crude is going to be really the place where you see the exports. That puts you naturally into Latin America. And you're right, there has been operating issues within that. But we're also competing directly, if you will, then with the European refineries. And I think with the cost position that we have, the proximity to the market, I think that's where we continue to see it. And then West Africa continues to be a developing market and growing that the Atlantic Basin and the Gulf Coast will continue to serve. It's just a question of how much can those grow and who supplies the Asian demand? But we still feel, to us, like, the Middle East and Northeast Asia are still going to be the big suppliers into Asia. That's quite a haul from the U.S, and so I think, logically, the trade patterns start to sort out that the export markets for the U.S. will likely largely be in that Atlantic Basin. Greg C. Garland: The other thing, just not long-term, Paul, but maybe near-term, mid-term, kind of 2018, certainly 2017, we see less refining capacity coming on globally than what we've seen in the past few years. I think in our balances, we have about 800 (44:15) a day coming on in 2017 and 2018.

Yeah. It's interesting because ever since the export trend started, it's been surprising us to the upside, and I'm slightly struggling to know how far it can go. It's obviously outright positive for you guys. Just if I could ask a follow-up. You've had a bit stronger Chemicals results than some of the other results you've seen, perhaps Dow and Exxon, would be what I'm thinking of here. Was there anything particularly differentiated about why your results were that bit better in terms of relative to your competitors? Thanks. Kevin J. Mitchell: I think first of all, the demand regardless of chemicals, we think about aromatics and plastics, it's all been really strong and so I think we were obviously benefiting; the industry did from a really good market condition. And then it comes back to, Paul, your advantage feedstock will be produced in the Middle East, will be produced in North America off of that. So we continue to have an advantage feedstock. And then fourth quarter results were probably weaker than we would've expected so the quarter-on- quarter improvement sequentially somewhat reflected better operating, less turnaround activities, et cetera, but then fundamentally, margins were better and that's really about how you capture those, you have got to have access to markets and you like to work on that competitive advantage on the feedstock. And so I think those two showed up. Greg C. Garland: Yes, we saw good strength though, in both ethylene and polyethylene. We saw good strength coming off our Middle East joint ventures, our aromatics business did much better quarter over quarter. And then I think the other thing is kind of lost in the conversation maybe as we had quite a bit of turnaround activity at CPChem. So again your 33, (46:00) which is a large ethylene cracker; Sweeny was down for most of the quarter. Q-Chem I was down for turnaround, M-Sty (46:08) had a big turnaround, and so in spite of pretty substantial turnaround activity at CPChem, they had a really solid quarter.

Yes. Okay. Thanks, guys.

Doug Leggate with Bank of America Merrill Lynch is online with the question. Your line is open.

Thank you. It's still morning here. Good morning, everybody. Jeff, we are going to hit you around the holes over here. Congratulations on your move.

Thank you Doug.

So I'm not sure if this is for Kevin or Greg, but last quarter I think, Greg, you talked about having $500 million to $750 million of discretionary capital budget. I'm trying to wrap everything together in your comments about softer refining, or I guess similar to last year , and then the trend, the cash burn trend, and then all the visibility of the dropdowns that you have. So there's a lot of flexibility. But then I'm looking at the trend in net debt to cap for your balance sheet. Where do you want that balance sheet to be? And how long do you think you can extend the buybacks beyond your commitments to 2017? I think you talked about a couple billion dollars for this year. Greg C. Garland: Yes, so maybe start with CapEx. I think we've said $500 million to $700 million of flexibility in capital this year in 2017 that we've built into the plan. Obviously the further you get into the year, the harder it is to adjust that as we FID projects and kind of move forward. And I think we'll continue to look at where margins are and save some ability to adjust capital, certainly through midyear, let's say, Doug. We continue to think about the business on mid-cycle basis. We should generate $4 billion to $5 billion of cash kind of mid-cycle. We still expect that we'll be able to generate $2 billion out of the MLP through drops. And with that we can certainly afford $1 billion of sustained capital, $1.3 billion dividend, growing that dividend. And then you think about we have a choice. Do we buy shares, do we reinvest in the business? I think you can certainly afford kind of a $1 billion to $2 billion growth program and a $1 billion to $2 billion share repurchase program. And so that's kind of how we think about the business. I think the first quarter certainly – I probably wouldn't use the word cash burn in terms of that. I think we certainly plan to bring cash down to this level given all the things that we had going on. We did not have a drop in the first quarter. And you certainly – as we move through 2017, you expect that we're going to do something around growing PSXP. You were at $630-ish million dollars run rate EBITDA. We're committing to get to $1.1 billion run rate by the end of 2018. And so in this year and next year we're going to have to be moving directionally to do that. So I think we can make it all balance in terms of a strong share repurchase program, strong dividend program, and continue to fund both our sustaining and growth CapEx.

So, Greg, I guess what I was getting at is looking at the trend, the slide 17 trend, is there a kind of a range that you would have us expect your balance sheet to live within over time? Not necessarily this year but longer-term, where would we expect your balance sheet to sit through the cycle? Greg C. Garland: Yes. I think we'll continue to target 20% to 30% debt-to-cap. And of course we're at the upper end of that range today. I think, Kevin, you may want to talk about the debt and the restructuring of the debt and an ability to draw up an MLP. But you should expect that we'll pull PSX debt down and that you'll see the debt at PSXP grow. Kevin J. Mitchell: Yes. I think that's an important point, Doug, that as you – with the growth of the MLP, debt will increase at the MLP. That's going to happen. And our expectation is that over time – and it may not be a perfect match, but generally at the PSX level debt will come down so that such – that on a consolidated basis we're staying about flat. We just recently issued about $1.5 billion of short-term debt. That is pre-funding for a maturity. We have a $1.5 billion maturity that will be taken care of next week. That is all at the PSX level, but we've structure that debt in such a way that we can move it down into the MLP with – as part of a drop-down transaction. And that way you're kind of far funding the drop by moving debt from the parent company into the MLP. And so we're managing leverage that way.

That was extremely helpful. I appreciate the full answer, guys. My follow up maybe is a quick one, maybe not. But I wanted to go back to one of the operating result on refining. Versus our numbers at least it was particularly strong in the Gulf Coast. And what's really behind my question is I'm trying to understand is there anything unusual about this particular quarter that caused that. And I guess one of the earlier questions was alluding to the RIN issue. So I realize, Kevin, you were pretty assertive in your answer to this. But there still seems to be a debate as to whether RINs are in the crack or not. And obviously as it relates to things like moving the point of obligation and so on, I'm just curious if the collapse in RIN prices in Q1 was one of the reasons that refining did a little bit better. And maybe if you've answered the question already, I apologize, but I just wanted to get some clarity around that. Kevin J. Mitchell: Yes, certainly. The reduction in the RIN cost is a component on the improved – it really shows up in capture, right, the improvement in the capture rate, which was pretty significant for us, especially on the Gulf Coast. The other component which I touched on are some of those other clean products. And I don't know how sustainable that is. There's always some degree of benefit from those sort of chemical grade products. But you saw a spike in the relative margin on those products, and so that was part of it as well. And that benefit was concentrated in the Gulf Coast also.

Yes. Maybe just a comment on the chemicals piece. So that's really aromatics out of Alliance. It's solvents and cyclohexane for instance out of Sweeny. So we have pretty good exposure on those two refineries into that. And the strength in the chemicals business was evident really across that. So I think as we think about the chemicals business, we believe that in the aromatics and the solvents businesses, that strength is going to continue.

That was really my follow up, was so that has continued so far both on the RIN side and on the derivative petrochemical side. They're both – those two trends have continued into Q2 so far?

Yes. So far it's positive. There's obviously volatility in those chemical prices. But when you look back at the results across the various value chains in chemicals, feels like a pretty good pull on all those. And then, you're right, the RINs prices being lower does impact and improve the capture rate.

Really helpful. Greg C. Garland: Yes. We continue to believe that the RIN is essentially captured in the crack, though. I think it's hard to see sometimes, but I think our view is that it is.

Yes. I think we're kind of in between. We actually believe it's in the crack largely. And we also believe there's an element at that that you see in the market side as well. But largely to us, we think it's in the market crack.

Appreciate the answers, guys. Thanks so much. Greg C. Garland: Thank you, Doug.

Brad Heffern with RBC Capital Markets is online with a question. Your line is open.

Hi, everyone. I was wondering if we could dig into the Frac Two potential FID that you mentioned for later this year. So obviously Frac One hasn't contributed, I think, the EBITDA that you had anticipated. So what gives the confidence to potentially FID it later? Is it just that the economies of scale are so overwhelmingly attractive there?

Yes, I think the next tranche of capital investment will be lower, which is always a good thing from a project standpoint. Second of all, the first frac in terms of the frac fees I think are – is still a very attractive piece. And now we're leveraging lower CapEx, improve that, and now we're able to run it closer to that design capacity which impacts things as well. And for us, a second frac based on NGL helps us with our costs around the export terminal and some other things. So as we build out more, you actually start to leverage up across that entire hub in terms of incremental EBITDA and in terms of improved cost. And again, we're still looking long-term and saying, this is what's needed from an industry standpoint, and it ties back with things like what we're doing with Sand Hills to expand its capacity. We're just seeing increased NGL needed eventually for more cracks as ethane comes back into the mix more out of rejection, and then that's stronger than we see in exports.

Okay. Understood. And then I guess kind of along the same lines, I was wondering if we could talk about something that hasn't been brought up in a couple of years I think, which is the condensate splitter. I think in maybe in 2014, that was something that seemed like it might make sense for you guys. Is there any chance that that project comes back to life? And I'm thinking particularly about how light some of these Delaware Basin crudes are.

Yes, well, I think we have to see that supply, but we're watching that. And some of those gravities that we're seeing around that 50 degree mark – that kind of revives that whole discussion I think around what exactly would be produced. And so I think that that's one where you've got to see the supply come in before you would get on that path. But it will be interesting to see if the Permian comes back in that light fraction, if there's sufficient volumes there to really say that the best way to manage that is a splitter versus blending or direct export. So that's just an option that we're watching. So nothing planned right now, but it – it's one that we are aware of and thinking about.

Okay. Thanks.

Blake Fernandez with Scotia Howard Weil is online with a question. Your line is open.

Folks, good morning. Jeff, I would also congratulate you for escaping the purgatory of energy sell-side these days. I just wanted to revisit a couple of items that came up. Beaumont, I realize, we're expanding the storage capacity and the opportunity to export. Is that oil export arb open today? I'm just wondering, are you maxing out your capability there, or is this really a kind of second half of the year event once all of the pipelines are up and running and bringing crude down?

Well, as an industry, you've certainly seen it, and those differentials drive that. And what we're seeing is – I'll frame it this way. We're seeing a lot of interest in the storage to be able to create that option. And so we have done oil exports out of Beaumont already in this year, and so I think we look at it and say as long as those new pipelines get connected, the volumes are coming via from North Dakota, the Mid-Con and the Permian, et cetera, then that will continue to build. So I think right now, you see it very volatile as those differentials come in and out of play. But longer-term, if you believe light oil production is going to increase, we're just – we see that as a continuing need.

Right. Okay. Greg C. Garland: I think – just tactically, I think once you see that WTI-Brent get above $2.50 a barrel, people get a lot more interested in exporting.

Sure, okay. Tim, I think earlier you had mentioned Canadian outages, and my question is pretty simple. Just into 2Q with the outage or syncrude, are you seeing any meaningful impact on the system whether it be direct or indirect?

Well, we've obviously – the availability has caused us to look at other crudes to run. We've not seen a problem from a supply standpoint. There's plenty of crude options available. But it does cause us to re-jigger across some of our system because we are not bringing down as much Canadian crude as we were. And so I think from our viewpoint, operationally, it's been a minimal impact, but it has created different options for us around the system.

Right. So think about it more in terms of capture rate, I suppose, like paying out for crude rather than lack of surplus, I suppose?

Yes. We go back to the economic optimization of what's the best thing to run.

Got it. Okay. Thanks.

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

Thank you, Krista, and thank all of you for your interest in Phillips 66. If you have additional questions, please call Rosy, C.W. or me. Thank you.

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