Phillips 66 (PSX) — Q3 2018 Earnings Call Transcript

Good morning, and welcome to the Phillips 66 third 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. Before I turn the call over to Greg, I'd like to point out a change in our question-and-answer session. Based on investor feedback on how to improve our call, and to allow everyone the opportunity to ask a question, we are asking that you limit yourself to one question and a follow-up. If you have additional questions we ask you to rejoin the queue. With that, I'll turn the call over to Greg Garland for opening remarks.

Thanks, Jeff. Good morning, everyone, and thanks for joining us today. Third quarter adjusted earnings were $1.5 billion, a record $3.10 per share. This quarter, we demonstrated the value of our integrated portfolio attributing strong earnings. In the central corridor, our Refining and Midstream assets ran at record levels, capturing strong margins. We continue to benefit from advantaged feedstocks as the industry's largest purchaser of heavy Canadian crude. We achieved record Midstream earnings. And in Marketing, we realized solid margins on refined product sales. We've repurchased or exchanged nearly 30% of our initial shares outstanding over the last six years, contributing to our record adjusted earnings per share this quarter. We continued our commitment to distributions by returning $775 million through dividends and share repurchase in the third quarter and $5.2 billion for the year. Strong shareholder distributions remain fundamental to our disciplined capital allocation approach. We're investing in a robust portfolio of projects with attractive returns to create shareholder value and drive future growth. During the third quarter, Phillips 66 Partners once again achieved record adjusted EBITDA. PSXP has grown at a rapid pace during its first five years. With its scale and financial strength, PSXP is well positioned to fund and sustain a significant organic capital program to drive future EBITDA growth. Phillips 66 Partners is the operator and largest owner in the Grey Oak Pipeline project. Grey Oak will provide crude oil transportation from the Permian and the Eagle Ford to Texas Gulf Coast destinations, including our Sweeny Refinery. Supported by shipper commitments, the capacity of the pipeline will be 900,000 barrels per day and is on schedule to be in service by the end of 2019. At the Sweeny Hub, we're building two 150,000 per day NGL fractionators and adding 6 million barrels of storage at Phillips 66 Partners Clemens Caverns. We have agreements in place with multiple parties, including DCP Midstream, to supply Y-grade to the new fractionators. The Hub will have 400,000 barrels per day of fractionation capacity and 15 million barrels of storage when the expansion is completed in late 2020. Our Sweeny Hub is strategically located on the Texas Gulf Coast and directly accessible from the Permian. Gulf Coast fractionation capacity remains tight and there's strong interest from customers in future expansion projects. At the Beaumont Terminal, we recently placed 900,000 barrels of fully contracted new crude oil storage into service. We're having additional crude tanks under construction that will increase the terminal's total capacity to 14.6 million barrels by the end of this year. During the third quarter, we had about 200,000 barrels per day of exports across our dock. The continued growth in domestic crude production is expected to result in the need for higher Gulf Coast exports, and we're making investments to capitalize on those opportunities. At Beaumont, we recently approved a new project to further increase crude storage by 2.2 million with completion anticipated in early 2020. PSXP also has a 25% interest in the South Texas Gateway Terminal under development in Corpus Christi. The terminal is connected to the Grey Oak Pipeline and will provide 3.4 million barrels of crude storage upon completion in late 2019. DCP Midstream continues to expand the Sand Hills Pipeline to meet the demand for growing NGL production in the Permian Basin. DCP increased the pipeline's capacity to 440,000 barrels per day at the end of the third quarter, and further expansion to 485,000 barrels per day is expected by the end of this year. In the high-growth DJ Basin, DCP's Mewbourn 3 gas processing plant started up in the third quarter. And the O'Connor 2 plant is expected to begin operations in the second quarter of 2019. In Chemicals, CPChem has a leading position in polyethylene to supply the world's growing demand for polymers. CPChem's portfolio of cost-advantaged assets are strategically located in the U.S. and the Middle East. Abundant ethane supplies remain the cost-advantaged feedstock for U.S. Gulf Petrochemicals growth. CPChem continues to optimize its U.S. Gulf Coast Petrochemicals assets and is developing a second U.S. Gulf Coast project that would include ethylene and derivative capacity. CPChem is also evaluating additional capacity across multiple product lines to address bottlenecks on existing units. In Refining, we continue to focus on high-return projects to improve margins. We have an FCC optimization project underway at the Sweeny Refinery that will increase the production of high-value petrochemical products and higher octane gasoline. This project should be completed in mid-2020. At our Lake Charles Refinery, Phillips 66 Partners is constructing a 25,000 barrel per day isomerization unit. This new unit will increase production of higher octane gasoline blend components when completed in the third quarter of 2019. We're opportunistic about future growth opportunities across our businesses. With growing hydrocarbon production in the shale plays, we see opportunities for further midstream infrastructure build-out, including pipelines, export facilities, and NGL fractionation. Our refining system is well positioned to capture low-cost crude feedstock, and we see good opportunities for future chemicals expansion. We will remain a disciplined allocator of capital. We'll continue investing in growth projects with attractive returns that align with our long-term strategy, and we'll continue to provide a strong, competitive, growing dividend. We'll be buyers of our shares when they trade below intrinsic value. 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 four, third quarter earnings were $1.5 billion. After excluding special items, adjusted earnings per share was $3.10. The third quarter adjusted effective tax rate was 23%. Our year-to-date after-tax return on capital employed was 14%. Operating cash flow excluding working capital was $2.1 billion. Working capital impacts reduced cash flow by $1.5 billion. Distributions from equity affiliates were $910 million. Capital spending for the quarter was $779 million, with $537 million spent on growth projects. We ended the quarter with 461 million shares outstanding. Slide five compares third quarter and second quarter adjusted earnings by segment. Quarter-over-quarter adjusted earnings increased $134 million driven by higher earnings in Marketing, Midstream, and Refining, partially offset by lower Chemicals results. Slide six shows our Midstream adjusted net income, which was a record $261 million in the third quarter. Transportation adjusted net income for the quarter was $175 million, up $38 million from the previous quarter. The increase was due to higher volumes, increased pipeline tariffs and storage rates, and lower operating costs. Our operating pipelines in the central corridor benefited from strong utilization at our refineries. In addition, the Bakken Pipeline averaged more than 500,000 barrels per day. NGL and other adjusted net income was $64 million, an increase of $14 million, reflecting increased Sand Hills and Southern Hills pipeline volumes and propane and butane trading activity. Sand Hills pipeline throughput during the third quarter was a record 421,000 barrels per day. We continue to run well at the Sweeny hub. During the quarter, the export facility averaged 10 cargoes a month and the fractionator averaged 110% utilization. DCP Midstream's adjusted net income of $22 million in the third quarter is up $7 million from the previous quarter due to increased pipeline volumes, higher NGL prices and improved hedging results. Turning to Chemicals on slide seven, third quarter adjusted net income for the segment was $210 million, $52 million lower than the second quarter. Olefins and Polyolefins adjusted net income decreased $70 million due to low margins from higher ethane feedstock costs. This was partially offset by higher polyethylene sales volumes as CPChem operated at 96% domestic polyethylene utilization and also grew from inventory. Global O&P utilization was 91% in the third quarter reflecting planned turnaround activities and unplanned downtime from a third-party power outage that impacted the Cedar Bayou facility. Adjusted net income for SA&S increased $9 million from improved margins. The $9 million increase in other mainly reflects the gain on an asset sale. During the third quarter, we received $325 million of cash distributions from CPChem. Next on slide eight, we will cover Refining. Crude utilization was 93% compared with 100% in the second quarter. Our third quarter clean product yield was 84% and realized margin was $13.36 per barrel. Pre-tax turnaround costs were $55 million, a decrease of $5 million from the previous quarter. The chart of slide eight provides a regional view of the change in refining's adjusted net income which increased $48 million in the third quarter. In the Atlantic basin, adjusted net income increased as the Humber Refinery returned to normal operations following a second quarter turnaround. This was partially offset by third quarter unplanned downtime at the Bayway Refinery. Gulf Coast adjusted net income decreased due to narrowing heavy crude differentials and unplanned downtime at the Alliance Refinery. Adjusted net income in the central corridor was $633 million. An increase of $241 million reflecting improved heavy Canadian and Permian crude differentials and higher volumes. Third quarter capacity utilization was 108%. In the West Coast, the decrease was mainly due to a 25% decline in the gasoline market crack. Slide nine covers market capture. The 3:2:1 market crack for the third quarter was $14.21 per barrel compared with $14.86 in the second quarter. Our realized margin for the third quarter was $13.36 per barrel, resulting in an overall market capture of 94%, up from 83% in the second quarter. Market capture was impacted in part by the configuration of our refineries. We made less gasoline and more distillate than we premised in the 3:2:1 market crack. Losses from secondary products of $1.62 per barrel were lower than the previous quarter by $1.19 per barrel, primarily due to improved NGL and coke prices relative to crude oil. Feedstock improved realized margins by $2.50 per barrel, a decline of $0.65 from the prior quarter due to narrowing Gulf Coast heavy crude differentials, partially offset by improvements in the central corridor. The other category includes impacts associated with product differentials, RINs, outgoing freight and inventory. This category improved realized margins by $0.26 per barrel. Let's move to Marketing and Specialties on Slide 10. Adjusted third quarter net income was $290 million, $95 million higher than the second quarter. Marketing and Other increased by $98 million due to higher realized margins in the U.S. and Europe, reflecting seasonally stronger market conditions. U.S. branded marketing volumes increased 2% sequentially. We re-imaged $384 domestic marketing sites during the third quarter, bringing the total to over 2,100 since the start of our program. Refined product exports in the third quarter were 190,000 barrels per day. Specialties adjusted net income decreased $3 million during the quarter from lower base oil margins. On slide 11, the Corporate and Other segment has adjusted net costs of $187 million, up slightly from the prior quarter. Lower interest expense was due to a second quarter debt repayment and higher capitalized interest. Corporate overhead increased primarily from employee severance costs and taxes. Slide 12 highlights the year-to-date change in cash. We entered the year with $3.1 billion in cash on our balance sheet. Cash from operations excluding the impact of working capital was $5 billion. Working capital changes reduced cash flow by $1.6 billion. This reflects a $1.5 billion use in the third quarter due to an inventory build that included the impact of unplanned downtime at Bayway and Alliance, as well as the timing of crude cargo receipts and payments. We received $1.2 billion from the first quarter issuance of debt net of second quarter debt payments. During the year, we funded $1.6 billion of capital expenditures and investments, and we returned $5.2 billion to shareholders through the repurchase of shares and payment of dividends. Our ending cash balance was $924 million. This concludes my review of the financial and operational results. Next, I'll cover a few outlook items for the fourth quarter. In Chemicals, we expect the global O&P utilization rate to be in the mid 90s. In Refining, we expect the worldwide crude utilization rate to be in the mid 90s, and pretax turnaround expenses to be between $110 million and $130 million. We anticipate Corporate and Other costs to come in between $170 million and $190 million after tax. In closing, next quarter we are changing our segment reporting to be on a pretax basis. Income taxes will only be reflected at the consolidated company level. This change will make our segment reporting more comparable to our peers. With that, we'll now open the line for questions.

Good morning everybody, and congratulations on another great result.

Good morning, Doug.

Hi, Doug.

Greg, you guys have been a leader in the whole energy industry in pledging to balance your spending and distributions. And while it's worked very well for shareholders, it obviously starts with disciplined capital spending. And so on this point, while you may not have your specific guidance yet, I wanted to see if you could provide some color or maybe your philosophy on capital spending for 2019 and beyond?

Yes, I'd start from the guidance we've given that long-term we want to reinvest 60% of cash from all sources back into the business, and 40% goes back to our shareholders, so a strong dividend and share repurchase. I don’t see us deviating from that, Doug, over the longer-term. Any given year we could bounce around a little bit. This year is going to be hard to hit the 60-40 split, but it's going to be the other way, given we're already at $5.1 billion of share repurchases for the year. But there's no question I think that we're working the capital budget for 2019 now, and we go to our Board in December for approval. So I don't want to get too far out ahead of that. So we have Grey Oak, and the fracs. And of course, Grey Oak, even though it's a PSXP, it gets consolidated up into PSX. So at the consolidated level we're probably looking at something between $2 billion and $2.5 billion in '19. We'll tell you what the number is when we get to the Board in December.

Sure. Thanks a lot, guys.

You bet.

Good morning, everyone. Congratulations on a strong quarter. I have two questions specific to this quarter, but I'd like to see if we can extend the discussion into the future. One significant factor contributing to your outperformance compared to projections has been in the mid-continent within your central corridor business. Can you share your outlook for this segment as we move into the fourth quarter and into 2019? Additionally, I'd like your thoughts on Brent, WTI, Western Canadian crude, and gasoline margins in the region. I also have a follow-up question.

Okay. That was five questions packed into one Neil, but we'll try to deal with it. So let me just start at a high level and then I'll have Jeff step in and kind of give our views. So I think, first of all, no question large differentials on WCS, but also WTS differentials were strong in the quarter. We're able to capture that at Borger and to some degree into Ponca. And we ran really well, so 108% capacity utilization. So where we needed to run really well, we ran well and we were able to capture that opportunity. And I'll let Jeff comment on our future views in terms of WCS spreads.

Yes, so PSX is the largest importer of Canadian crudes, and we benefit from these wider discounts. Production growth is continuing to exceed infrastructure development, production up roughly 300,000 barrels a day both in 2017 and 2018 with further growth coming in 2019 as well. The pipelines are full. Enbridge Line 3 is the next one lined up for year-end next year. It's only 370,000 barrels a day incrementally. And then Keystone and Trans Mountain are kind of a 2022 plus. For the time being the rails are full as well. When you look at the DOE stats for Canadian imports, we've imported right at 200,000 barrels a day for the last four months. That looks to be about what we can do at this point as an industry. There are some long-term contracts that have been signed, and we expect the rail capacity to increase later this year and really more so next year. Canadian storage is at record high levels, and it typically rises during the fourth quarter. So things continue to be tight with Canadian differentials.

And then the other area was marketing. You guys put up very strong results. I guess, there's a seasonality element to that, but it seems like gasoline wholesale margin is holding as well. So talk about your view for the marketing and specialties business and can we carry some of the strength forward?

Yes, so there is seasonal strength there. The third quarter has got July and August, two summer months with the Fourth of July and Labor Day weekend in there as well, versus only one summer month in the second quarter. And so there is a big seasonal component there. When you look at wholesale gasoline prices, they were relatively flat in the third quarter versus more volatility in the second quarter, and it's easier to push through the margins in a more stable price environment. We had strong margins in Europe as well, so really strong performance overall for the marketing segment.

But Neil, as you look into the fourth quarter, you would typically expect that demand will decrease seasonally as it usually does. Thus, you would anticipate weaker results from that segment as you move from the third quarter into the fourth.

Makes sense. Thanks again, guys.

Thanks, Neil.

Yes, thanks, good morning and a very impressive quarter.

Thanks, Roger.

Thanks, Roger.

Just to dive in here, maybe a little bit of a follow-up on Neil's question as we think about capturing the central corridor and throughputs. So should we generally think about it as it's a Hardesty price adjusted for transportation or is there a component of WCS you get, you know, south of the border, that doesn't have a price? I'm just trying to think about it in margin capture potential over the next few quarters until crude by rail has an opportunity to maybe narrow the differentials up.

So Roger, I think the easiest way to look at this is just on a quarter-on-quarter change in the Canadian heavy discount 2Q versus 3Q in this case and as we go into 4Q just compare the difference in the discount at Hardesty and factor that in. We do see about a 30-day lag. And so I think it makes sense to lag that a little bit as well. But the easiest way to look at that is just sequential changes.

All right. I appreciate it.

The other thing I'd add is Roger, we have invested in infrastructure that allows us to capture that. So we have things at Hardesty; we've got commitments on pipes coming south. And so I think we're really well-positioned to capture that opportunity when it's there.

Great. Thanks. And then the unrelated follow-up, PSXP, obviously there's been some pressure on refining MLPs across the space. You're structured differently in terms of assets and the size of the business. Just wondering, are you seeing issues where you may ultimately roll PSXP up or that you need to do something about the IDR? I was just wondering how you're evaluating that business to time a little bit of change maybe overall in the sector?

Yes, that's right. I'd point out we're at a different spot than some of the ones that have rolled up. It's a billion dollar plus EBITDA, we've grown at a 30% compound annual growth rate in the distributions. On our call later this afternoon for PSXP, we're going to lay out a great organic portfolio of projects that's investable. We've kind of made the pivot from a drop-down story to an organic growth story. PSXP on its own has substantial capacity to invest. And so, we just look at it as a vehicle to help us grow our midstream business. And so we like that component. We think PSXP is a strong entity and a valuable part of our portfolio. Now, IDRs this is certainly a topical question and I don't think we'd go a meeting that we don't get asked about IDRs and what we are going to do with IDRs. I would say that we don't think that there's a constraint on growth created by the IDRs today. Although, we do acknowledge that there's a lifecycle to MLPs. We certainly understand that. I would say that the path to how you deal with IDRs is a well-worn path and well understood by most people. And the only guide rails that we would put is we're certainly willing to deal with the IDRs at the appropriate time, but it's going to have to be in a manner that is fair to LP unit holders but also to the PSX shareholders. So we'll get to the IDRs at some point.

All right. Thanks. I'll stick to the one in one.

Okay.

Yes, thank you. First question would just be on chemicals, Greg, obviously there's been some tightness here on the feedstock costs and there's been a little bit of pressure on the margin on the product margin side as well. Maybe you could just talk about how you're viewing those fundamentals in 2019, how long it'll take to resolve some of the fractionation issues. Obviously, you're going to help contribute a bit to that recovery, but just any thoughts you have?

Yes, well, I think, during the quarter, I think I had a wild ride, you know, in the high 30s more than doubled and went back down into the high 30s and it's below that today. And I think the industry just had a hard time keeping up with that. So it did cause some margin compression. And frankly, we always thought with the new unit that had come on, three so far, that there would be some compression in margins as these materials started hitting the market. I think that thing that we all missed was how quickly the frac capacity built up. And it was really you know, that frac capacity going up that drove the ethane prices so quickly and rapidly. I think that KIMS did a great job of adjusting their feedstock slates and obviously by cracking more propane and then putting pressure on ethane and you saw the result on the ethane prices. But I think we're going to be at this tension point until we can get some more frac capacity on and we'll see some coming on in '19. There's two or three fracs coming on in '19 and then a couple of more fracs including our frac 2, frac 3, another 300,000 a day in '20. So I think as we move into '19 and '20, we'd start to resolve that issue around feedstock.

Great. For my second question, I would like to direct this to Kevin since it was mentioned in your prepared remarks. You discussed secondary products, specifically that coke, which I assume refers to needle coke, was a key factor in the margin improvement I noticed in the Atlantic base where your secondary margins were particularly strong. Could you please provide more details on the contribution from that area?

Yes. So it's a combination. It's not that you've got then NGL impact, the strong NGL prices, and you had improved pricing across all grades of coke, so petroleum coke, and coke, needle coke and so strong pricing across the board and so that all contributes to that; that's a secondary product impact.

Okay. And you feel that sustainable?

Well, that depends on where the markets go. I mean, that category as if you look back over time. That moves around it can move around quite a bit in terms of the overall impact on capture, so it will move as market conditions do so.

Okay, it sounds good.

They were also down during that period of time and so that they're probably impacted that the amount of the positive direction on secondary products but I think the coke market globally has improved, there's no question around that. We have two refineries certainly like troughs in Humber that are probably most impacted particularly by the specialty grade cokes. The last two, three years we've been working to develop new markets for specialty grade cokes; one of those is the anodes and lithium-ion batteries and we've made good progress there in developing a new high-valued market for us. A lot of the other specialty coke goes into our furnace production and that's tied to the global economy and so you have to answer the questions as sustainable or not have become common and it continues to do well. I think this business will continue to do well for us but if it's a relatively small component in the overall mix for Phillips 66 it was completely overshadowed by the margin improvement we saw in the central corridor around, you think about Billings, you think about Wood River and the $25 spread there.

Bill, I think it's important to note that we have multiple grades of needle coke for many different applications and depending on the grade, the quality and the makeup of the needle coke. They trade at different prices. In addition, for commercial reasons we don't disclose the duration of our sales contracts which can influence the prices that we capture.

Thank you, good morning. Hi guys. Could we take a little bit more about chemicals, I thought what they would actually be that weaker than the results that you achieved, could you just give us an outlook for both volumes and margins your best guess that would be great. Thanks.

Well, specifically to that third quarter, we had to turnaround at quarter author on the ethylene side but we're selling out of inventory. Ethylene inventories are still relatively high and that's also leading to some of the margin compression we're seen in ethylene. I don't when see becomes a case, but actually built inventory to cover the derivatives startup from last fall to the new cracker came on and the new cracker came on better, quicker and ran higher rates than we expected and so we've been adjusting inventories and so became to bring that inventory down. So then you come back and you think about okay, what's happening going into next year. The sales lines are still strong polyethylene sales volumes are up quarter-over-quarter we're seeing strong demand growth in really across all regions also. I would say we're constructive on the outlook for margins going into 2019.

Are you hitting maximum volumes is not correct in terms of your sales?

I think they certainly the Middle East assets are running at capacity we had a global O&P rate of 91% but that was influenced by the power outage at our Cedar Bayou facility which ticked down the new cracker and the old crackers Cedar Bayou, so that really impacted operations but I would, we've given guidance of kind of mid-90s for the fourth quarter and I think we feel pretty comfortable with that guidance. Yes, I think you're right.

Correct, Jeff, that was extremely helpful. Maybe you should think about yourself that made? Thanks guys.

Thanks, Paul.

Thank you. I have some questions, and Paul just raised one, so I'm going to direct this to Jeff if that's alright. The gasoline situation has been a potential issue given the strength of runs in the U.S. My question is about the export of light sweet crude, particularly with the Gray Oak and capacity expansion on the Gulf Coast, along with the International Maritime Organization regulations for European refiners. It seems that the combination of higher runs and lighter yields could pose a challenge for gasoline in 2019. I'm interested in your thoughts on how you foresee the gasoline market performing in relation to these changes next year and into 2020.

Well, I think the gasoline market's going to be challenged through the winter months. I think as we shift into next year there's going to be a focus on emphasizing distillate yields in an effort to improve distillate yields with confidence that, that's a longer-term event with IMO coming, as opposed to the U.S. that really tries to maximize gasoline yield in the summer months. It's certainly possible that we could have maximizing diesel yields year-round for the next number of years and so we're looking at those yields shifting as IMO approaches feedstock in FCC feedstock is a good Marine blending component which could have the impact of reducing FCC runs as well and shifting more product yield into distillate and added gasoline. I think that's how we get out of this, but gasoline's probably going to be soft through the winter months.

I appreciate it. I am only going to take the rest of the one offline, but my follow up is for Greg and Greg, you're going to hear this because I ask it every couple of quarters I guess and it's clearly the split between the dividend and the buyback and I want to be very specific and we agree with you that your stock is undervalued but you never tell us what your number is, we unfortunately have to publish our number, so we're kind of there now exposed sort to speak but the point is that you're not immune to the seasonality the weakness, the market weakness and all the rest of it. So my question is are your buybacks, are you committed to ratable buybacks, are you a bit more to selling and when you execute your buyback program and in this environment, why wouldn't you swing the benefit of your diversified portfolio back towards more of a dividend cut than a buyback cut in terms of the cash, and I'll leave it there. Thanks.

Well, so we've never contemplated cutting the dividend…

What I mean is the split. When I say 'Cut,' I mean that which favors dividends as opposed to buybacks.

It was the Scottish definition of got me, okay. Look, I think we've consistently kind of guided to $1 billion to $2 billion of share repurchases over the past couple of years. Obviously, this year we had an opportunity in February to take a big swing with Berkshire, and we did, but I think the guidance is still pretty good guidance going forward. We look at this stock price every quarter. We have a grid, we reset that grid every quarter Doug, so in the past two weeks we've been buying a lot more stock than we would normally buy, the share price fell, and I think you'd want us to do that but we look at that every quarter, and as I think out into 2019 kind of that $1 billion to $2 billion consistent range of share purchases will be the guidance that we'll give for 2019 also.

Yes, I guess I was sort of looking for that desirability as well as looking for. Thanks a lot Greg.

Thanks for taking the question. I wanted to circle back on cash flows in particular cash flow from operations. One of the step-ups that we saw queue on queue in the equity affiliate distributions and just to become being a more material part of GFFO, wanted to get a sense of I don't want to front-run anything you're going to say on CSSP call, but maybe just sort of to get a sense of where that cadence could move as we sort of model cash flows going forward and think about how much that could be an offset to any CapEx needs coming up on midstream and any further on in chemical.

Yes, this is Kevin. I mean fundamentally the way that what drives the distributions from the equity affiliates are the operating cash flows within the equity affiliate, less in the case of CPChem, WRB less the capital spending that they're undertaking at that level at the JB level. In the midstream, it's a little bit different because most of those affiliates are distributing most of their operating cash flow is not all and then the growth capital expansion capital is being funded by contributions back into those entities. So you've seen a robust distribution so far this year so just over $900 million in the third quarter, the year-to-date through the third quarter is just over $2 billion of distributions coming out and so you think about WRB, which both refineries have benefited very well from the overall crude differential environment that we're sitting in and WRB will essentially distribute most of its cash. There's no incentive, neither owner is incentivized to have the partnership sit on more cash than it needs to fund its ongoing operations, so that's part of it as WRB does well and so the cash distributions coming back will do so with CPChem, some of this has been a function of the capital spend has come off significantly with a big project complete that's all behind us now and so the capital spending program this year is quite a bit lower than it had been. And so, they're in a position to continue with pretty healthy distributions. We had guided to perceive became $600 million to $800 million of distributions for the year we've done $725 million through the third quarter, and it's certainly possible that could be another distribution coming in the fourth quarter, so pretty healthy outlook from that standpoint.

Thank you very much. That's very helpful. Just a quick follow-up, Kevin. I apologize if you covered this in your prepared remarks, but regarding the working capital swing we observed this quarter, should we expect most of that to reverse in the next quarter? Will we end up breaking even on that volatility for the full year, or is there anything that will remain that we should be aware of?

No, I think that's a reasonable assumption. It's always hard to forecast working capital with too much precision given the amount of moving parts there are within that but high level we would expect that to reverse and so the full year working capital is something reasonably close to breakeven.

Hey, guys. Two quick questions, first on the needle coke, is there any capability for you guys to short term say within the next six months or so have be able to increase the production on that and also that on the medium term, do you have any plan to increase the capacity?

The refining businesses are part of the Humber Refinery and the Lake Charles refinery, which are included in our refining portfolio. In this segment, we highlight the most significant capital projects each year. You’ve seen our focus on Wood River and Bayway FCCs, and now Sweeney FCC. We emphasize all major capital projects. Therefore, since we have not highlighted any large capital project, it is likely safe to assume that there isn't one.

Hey, good morning, everyone. Switching back to chemicals, I was wondering, you guys were a little more candid this quarter talking about progressing a second U.S. Gulf Coast project, can you give a sense of the timeline there when it could potentially see a fighting and so on?

Well, as a joint decision with our partner, I think that timing we've kind of guided to kind of a late '19, early '20 type FID, we are progressing work around the site location, the permits required initial designed around that facility. But I still think that it's late '19 or early 2020 in terms of FID for that facility.

Okay, got it. Thanks. And then, I guess on the frac capacity side, I was wondering if you could just talk about sort of the path forward for NGL production in the U.S. over the next 6, 9 months when there is an incremental frac capacity in Mt. Bellevue. Do you guys see what grade is getting produced in the tanks or does it get rerouted to Conway or Appalachia or how do you see that playing out?

Yes, it's going to be interesting to see how we move forward, we'll probably see rejection maintained at high levels of the gas plants as people attempt to ship and fractionate the heavier barrels. So I think that rejection will stay relatively high. I think this will encourage additional NGL pipeline capacity and additional fractionator capacity because supply is likely to continue to grow as we go forward, drilling activities continuing in the Permian. We are drilling 600 wells a month and only completing 400 wells a month. So the duck inventory is growing by 200 every month, once the infrastructure comes online, then those completions will accelerate and fill the infrastructure. So I think we're going to add infrastructure, add supply then add infrastructure then add more supply. We are kind of in that cycle.

Hey, good morning, everyone. I was intrigued by the comments of the bottleneck in existing chem’s unit. Could you give a sense of just the general capacity that you'd be talking about here as well as the timing and also with some of these de-bottlenecks occur at your brand-new cracker in PE units?

The answer is yes, I think we probably have room to de-bottleneck the new cracker. But we across the platform, I would say we have opportunities and some of the older assets to do some additional de-bottlenecking. So we are not going to give a number today in terms of the volumes on that. But I think that CPChem has a great portfolio of opportunities kind of internal to the existing asset portfolio where they can get some more value out of those assets. As you know, the bottlenecks are the easiest ones to do highest returning projects typically in the portfolio, so we will prosecute those. Yes, what were your Bakken rail volumes to Bayway if any in the quarter and how would you expect this to potentially ramp going forward, do you see de-bottlenecks just a lack of the 117J railcars? Yes, we benefit from blocking differentials as an owner and shipper on the Bakken pipeline. We do rail volumes to both the East Coast and the West Coast. We haven't disclosed those specifically; we really don't talk about specific refinery feedstock procurement but we are seeing an acceleration and growth in the Bakken oil productions up over 200,000 barrels a day year-on-year, but it's actually accelerating it's up 75,000 barrels a day quarter-on-quarter. The pipelines are largely full; the rail logistics are tight. I think you are right with the new compliant railcars being a bottleneck there. We have had some heavy refining maintenance in the mid-continent this quarter which will lead up as we get into later in November and December but we do expect Bakken differentials to remain wide.

Hi guys, so PSX is one of the global leaders in coking capacity given IMO indicating no chance of a delay, ignoring of the administration, would PSX be open to investing in any resin destruction or resin upgrade projects. I mean, and you look at the Sweeney Refinery location, it's right next to John's Creek. So you can source a lot more WCS there, so this could be a good candidate to build a Coker, so just wanted your views on it?

Yes, so we are the global leader in coking capacity and we really achieve this through a number of previous investments and we are well positioned with our portfolio, higher diesel yields relative to our peers and significant hydro treating capacity, so our portfolio is really well positioned without significant future capital investment requirements for the IMO environment.

Good afternoon.

Good afternoon.

Picking up on Roger's PSXP question a bit, kind of apart from collapsing the NLP structure or worrying about the IDRs at this point, it seems a lot of industry peers have either gone one direction or the other in terms of to the extent they still have an NLP putting all their midstream down there and then of course the opposite which is just consolidating it all back to the parent, you still have substantial existing assets and major growth projects at the C-Corp and the midstream space, are you just comfortable having this kind of dual pronged PSXP, PSX approach or do you envision a longer-term kind of simplification around how to think about midstream?

Well, first of all, you are right, we probably have 700 to 900 million EBIT at the PSX level, that's MLP qualifying EBITDA although 300 or so that resides in our refining business today. We just don't see the need to do that, we have such a strong portfolio of organic opportunities investable at PSXP and it has a balancing and the capability to execute those projects that I suspect it will be a long time before we get to the need to do any drops, it gives us comfort that we have in there we need them, but I would just say we are comfortable with the structure, we think about PSXP is a vehicle to help grow our midstream business, I think we said many times, we will be very comfortable of all the investments we are making a midstream, could be executed to PSXP level. And indeed, we've grown from almost zero capital budget to $750 million this year. And this afternoon, we are going to tell you a budget over a billion dollars for PSXP over 2019. So you can see that the strategy is evolving. And so, it's doing what we needed to do in terms of helping us to grow our midstream business and we are comfortable with it.

Fair enough. And my second question, can you all update a little bit on how the market is looking for incremental LPG export contracting opportunities?

Well, so I would say that, our export terminal which was 150,000 barrels a day design we've demonstrated kind of 200,000 barrels a day we are running about 180,000 barrels a day. Our view, we're constructive on the export market growth for LPGs and indeed, when we look at all the NGLs coming at us, out of the Permian, Eagle Ford and the other basins, we are going to need to export LPG to clear the U.S. markets because the U.S. demand just not going to grow fast enough to absorb that. So I think we are comfortable with the growth profile we see out there. I think a lot of people have questions around tariffs and what tariffs are doing, what we are seeing as of the markets pivoting around the tariffs today. So we have the Chinese buyers that aren't necessarily shipping to China today and then maybe trade now for Gulf cargo but the markets working in our view at this point in time and I just think longer term we will certainly solve the tariff issue, so I don't think we are concerned about that on a medium to a long-term basis. So we like the profile, we see. I think that the issue is that the asset from our view is still underperforming our expectations even at kind of these 180,000 to 200,000 barrels a day given where dock fees are, we think dock utilizations in the U.S. are still around 83%, 84%. Let's say, as we move into '19, we see those utilizations improving. We think the opportunity to earn fees will improve. But in this market today, I don't think we would be interested in taking a long-term contract at $0.06.

From a demand perspective, we see continuing growth in the residential and commercial side for LPGs internationally, especially in Asia, as well as for chemical feedstocks.

And just in summary, what would you think the a multi-year economic contracting market, could begin to return by second half '19?

Yes, as utilization of the existing LPG export capability moves from the 80s to the over 90%, we expect that those margins will start to widen out across the dock. And there will eventually be a need for additional capacity which will push those margins up and offer some opportunity for contracting.

Hi, guys. Thanks for the added color this afternoon.

Yes, thanks.

I just want to quickly circle back on CPChem, it was really helpful color on the inventory sales in the third quarter. And some of the outages power-related complications you had encountered. But I guess, as we look into future periods, and curious with regard to the inventories, as you mentioned, and as I get normalized, how that might shape the sales profile, I guess implicitly, what I'm asking is how much of that excess inventory that you talked about, having built up remains to be liquidated, and how might that shape what we should think about 4Q?

I think from an industry perspective, the excess inventory is really in the ethylene part, not the derivative part of the chain.

Okay.

People are making adjustments in ethylene production to balance ethylene inventories. When we evaluate the full chain margin, it's evident that margins have shifted towards the derivatives recently. This demonstrates the advantage of being fully integrated. However, as ethylene inventories normalize, we anticipate some margin will shift back to the ethylene side. From CPChem's standpoint, they remain neutral since they capture value throughout the chain. Managing inventory is essential and requires good discipline with working capital. In the Middle East, assets are operational, but inventory is piling up at the docks. There is still strong demand, and inventory appears to be moving through the system. Demand in the U.S. looks robust, which supports a positive outlook for 2019, 2020, and 2021. We are seeing an improving supply-demand balance with increasing operating rates, which bodes well for margins. The inventory comments primarily pertain to the third and fourth quarters, and as we progress into 2019, we expect to see those inventories clear on the ethylene side.

Thank you for your interest in Phillips 66. If you have additional questions, please call Rosie or me. Thank you.