Welcome to the Third Quarter 2018 Phillips 60 6 Earnings Conference Call. My name is Julie, and I will be your operator for today's call. At this time, all participants are in a listen only mode. Later, we will conduct a question and answer session. Please note that this conference is being recorded.
I will now turn the call over to Jeff Dietert, Vice President, Investor Relations. Jeff, you may begin.
Good morning, and welcome to 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 and 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 avoid everyone 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 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. 3rd quarter adjusted earnings were $1,500,000,000 a record $3.10 per share. This quarter, we demonstrated the value of our integrated portfolio contributing strong earnings. In the central quarter, 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 6 years, contributing to our record adjusted earnings per share this quarter. We continued our commitment to distributions by returning $775,000,000 through dividends and share repurchases in the 3rd quarter and $5,200,000,000 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 Q3, Phillips 66 Partners once again achieved record adjusted EBITDA. PSXP has grown at a rapid pace during its 1st 5 years. With its scale and financial strength, PSXP is well positioned to fund sustain a significant organic capital program to drive future EBITDA growth. Phillips 66 Partners is the operator and largest owner in the Gray Oak pipeline project.
Gray 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 this
meeting up, we're building 2, 150,000 barrel per day NGL fractionators and adding 6,000,000 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 15,000,000 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 is strong interest from customers and future expansion projects.
At the Beaumont terminal, we recently placed 900,000 barrels of fully contracted new crude oil storage into service. We have an additional crude tanks under construction that will increase the terminal's total capacity to 14,600,000 barrels by the end of this year. During the Q3, 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 this opportunity. At Beaumont, we recently approved a new project to further increase crude storage by 2,200,000 barrels with completion anticipated in early 20 20.
PSXP also has a 25% interest in the South Texas Gateway Terminal under development in Corpus Christi. The terminal is connected to the Gray Oak pipeline and will provide 3,400,000 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. Sand Hills is owned 2 thirds by DCP and 1 third by Phillips 66 Partners.
In the high growth DJ Basin, DCP's Mewbourn 3 gas processing plant started up in the Q3 and the O'Connor 2 plant is expected to begin operations in the Q2 of 2019. In chemicals, CPChem has a leading position in polyethylene to supply the world's growing demand for polymers. CPChem's portfolio 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 new U. S.
Gulf Coast petrochemicals assets and is developing a second U. S. Gulf Coast project that would include ethylene and derivative capacity. TV Chem is also evaluating additional capacity across multiple product lines to debottlenecks 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 complete in mid-twenty 20. 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 Q3 of 2019. We're optimistic about future growth opportunities across our businesses.
With growing hydrocarbon production in the shale place, 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 inland crude feedstock and we see good opportunities for future chemicals expansion. We will remain a disciplined allocator of capital. We'll continue to invest in growth projects with attractive returns that are aligned with our long term strategy and will continue to provide a strong competitive growing dividend and will be a buyer 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 4, 3rd quarter earnings were $1,500,000,000 After excluding special items, adjusted earnings per share was $3.10 The 3rd 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 $2,100,000,000 Working capital impacts reduced cash flow by $1,500,000,000 Distributions from equity affiliates were $910,000,000 Capital spending for the quarter was $779,000,000 with $537,000,000 spent on growth projects.
We ended the quarter with 461,000,000 shares outstanding. Slide 5 compares 3rd quarter and second quarter adjusted earnings by segment. Quarter over quarter adjusted earnings increased $134,000,000 driven by higher earnings in marketing, midstream and refining, partially offset by lower Chemicals results. Slide 6 shows our midstream adjusted net income, which was a record $261,000,000 in the 3rd quarter. Transportation adjusted net income for the quarter was $175,000,000 up $38,000,000 from the previous quarter.
The increase was due to higher volumes, increased pipeline tariffs and storage rates and lower operating costs. Our operated pipelines in the Central Corridor benefited from strong utilization at our refineries. In addition, the Bakken pipeline average more than 500,000 barrels per day. NGL and other adjusted net income was $64,000,000 an increase of $14,000,000 reflecting increased Sand Hills and Southern Hills pipeline volumes and propane and butane trading activity. Sand Hills pipeline throughput during the 3rd 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 adjusted net income of $22,000,000 in the 3rd quarter is up $7,000,000 from the previous quarter due to increased pipeline volumes, higher NGL prices and improved hedging results. Turning to Chemicals on Slide 7. 3rd quarter adjusted net income for the segment was $210,000,000 $52,000,000 lower than the 2nd quarter.
Olefins and polyolefins adjusted net income decreased $70,000,000 due to lower 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 and P utilization was 91% in the 3rd quarter, reflecting planned turnaround activities and unplanned downtime from a 3rd party power outage that impacted the Cedar Bayou facility. Adjusted net income for SA and S increased $9,000,000 from improved margins. The $9,000,000 increase in other mainly reflects the gain on an asset sale.
During the Q3, we received $325,000,000 of cash distributions from CPChem. Next on Slide 8, we will cover refining. Crude utilization was 93% compared with 100% in the 2nd quarter. Our 3rd quarter clean product yield was 84% and realized margin was $13.36 per barrel. Pretax turnaround costs were $55,000,000 a decrease of $5,000,000 from the previous quarter.
The chart on Slide 8 provides a regional view of the change in Refining's adjusted net income, which increased $48,000,000 in the 3rd quarter. In the Atlantic Basin, adjusted net income increased as the Humber Refinery returned to normal operations following a 2nd quarter turnaround. This was partially offset by 3rd 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 $633,000,000 an increase of $241,000,000 reflecting improved heavy Canadian and Permian crude differentials and higher volumes.
3rd quarter capacity utilization was 108%. In the West Coast, the decrease was mainly due to a 25% decline in the gasoline market crack. Slide 9 covers market capture. The three-two-one market crack for the 3rd quarter was $14.21 per barrel compared with $14.86 in the 2nd quarter. Our realized margin for the Q3 was $13.36 per barrel, resulting in an overall market capture of 94%, up from 83% in the Q2.
Market capture was impacted in part by the configuration of our refineries. We made less gasoline and more distillate than 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 Q3 net income was $290,000,000 $95,000,000 higher than the 2nd quarter. Marketing and other increased $98,000,000 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 reimaged 384 domestic marketing sites during the Q3, bringing the total to over 2,100 since the start of our program.
Refined product exports in the Q3 were 190,000 barrels per day. Specialties adjusted net income decreased $3,000,000 during the quarter from lower base oil margins. On Slide 11, Corporate and Other segment had adjusted net cost of $187,000,000 up slightly from the prior quarter. Lower interest expense was due to a 2nd 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 $3,100,000,000 in cash on our balance sheet. Cash from operations excluding the impact of working capital was $5,000,000,000 Working capital changes reduced cash flow by $1,600,000,000 This reflects a $1,500,000,000 use in the 3rd quarter due to an inventory build, which included the impact of unplanned downtime at Bayway and Alliance, as well as the timing of crude cargo receipts and payments. We received $1,200,000,000 from the Q1 issuance of debt, net of 2nd quarter debt payments. During the year, we funded $1,600,000,000 of capital expenditures and investments, and we returned $5,200,000,000 to shareholders through the repurchase of shares and payment of dividends.
Our ending cash balance was $924,000,000 This concludes my review of the financial and operational results. Next, I'll cover a few outlook items for the Q4. In Chemicals, we expect the global O and 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 pre tax turnaround expenses to be between $110,000,000 $130,000,000 We anticipate corporate and other costs to come in between $170,000,000 $190,000,000 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.
Thank you. We will now begin the question and answer session. As we open the call for questions, as a courtesy to all participants, please limit yourself to one question and a follow-up.
Greg, you guys have been a leader in the whole energy industry and 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 philosophy that you might have on capital spending for 2019 beyond?
Yes. Well, I'd start from the guidance we've given. Long term, we want to reinvest 60% of cash from all sources back in the business and 40% goes back to our shareholders who have strong dividend and share repurchase. And obviously, it's 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. We'll hit sixty-forty, but it's going to be the other way, given we're already at $5,200,000,000 of share repurchases for the year. But there's no question, I think, that we're working the capital budget for 2019 now. We go to our Board in December for approval. So I don't want to get too far out ahead of that.
We got Gray Oak and the fracs. And of course, Gray 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 $2,000,000,000 $2,500,000,000 in 2019. But we'll tell you what the number is when we get to the Board in December.
Sure. Thanks a lot, guys.
You bet.
Neil Mehta from Goldman Sachs. Please go ahead. Your line is open.
Hey guys, good morning. Congrats on a good quarter here. I had 2 quarter specific questions, but also then want to see if we could extrapolate them forward. And so if I think about where the driver one of the big drivers of outperformance our model, it was in the Mid Con and your Central Corridor business. So can you talk about how you see that outlook going into the Q4 and into 2019 as well?
And there are a lot of components to that question. So your views on Brent WTI, Western Canadian crude also just gasoline margins in the region? And then I have a follow-up.
Okay. That was 5 questions packed into 1, Neil. But deal with it. So let me just start at the high level, and then I'll have Jeff step in and kind of give our views. 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're 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 1718 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 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 4 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 Q4. 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 margins held in as well. So just 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 3rd quarter has got July August, 2 summer months with the 4th July and Labor Day weekend in there as well versus only 1 month, summer month in the second quarter. And so there's a big seasonal component there. When you look at wholesale gasoline prices, when you look at wholesale gasoline prices, they were relatively flat in the Q3 versus more volatility in the Q2 and it's easier to push through the margins in a more stable price environment.
We had strong margins in Europe as well and so really strong performance overall for the marketing segment.
But Neil, this is Kevin. As you look into 4Q, you would normally expect to see the demand will come off seasonally as it typically does. And so you would expect weaker results from that segment as you go into the Q4 from 3rd.
Roger Read from Wells Fargo. Please go ahead. Your line is open.
Yes, thanks. Good morning and very impressive quarter. Thanks, Roger. Just to dive in here, maybe a little bit of a follow-up on Neil's question. As we think about capture in the central corridor and throughputs.
So should we generally think about it as it's a Hardisty price adjusted for transportation or is there a component of WCS you get south of the border 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 Hardisty 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, just Roger, we have invested in infrastructure that allows us to capture that. So we have tanks at Hardisty. We've got commitments on pipes coming south. And so I think we're really well positioned to capture that arb 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 IDRs?
Just wondering how you're evaluating that business at a time of a little bit of change maybe overall in the sector. Yes.
So I just I'd point out, we're just we're in a different spot than some of the ones that have rolled up. It's a $1,000,000,000 plus EBITDA. We've grown it at 30% compound annual growth rate. The distributions on our call later this afternoon for PXXP, we're going to lay out a great organic portfolio of projects that's investable. We kind of made the pivot from a drop down story to organic growth story.
The SXP 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 KXP 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 go to a meeting that we don't get asked about IDRs and what are we going to do with IDRs.
I would say that we don't think that there is a constraint on growth created by the IDRs today, although we do acknowledge that there is a life cycle 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 unitholders, but also to the PSX shareholders. So we'll get the IDRs at some point.
All right. Thanks. I'll stick to the 1 and 1.
Okay.
Bill Gresh from JPMorgan. Please go ahead. Your line is open.
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 will take to resolve some of the fractionation issues? Obviously, you're going to help contribute to that recovery, but just any thoughts you have?
Yes. Well, I think during the quarter, ethane kind of had a wild ride in the high 30s, more than doubled, went back down in 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 units that have come on 3 so far that there would be some compression in margins as these materials started hitting the market.
I think the thing that we all missed was how quickly the frac capacity filled up. And it was really that frac capacity filling up that drove the ethane prices so quickly and rapidly. I think the 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. So I think we're going to be at this tension point until we can get some more frac capacity on. We'll see some coming on in 2019.
There's 2 or 3 fracs coming on in 2019 and then a couple more fracs including our frac 2, frac 3, another 300,000 a day in 2020. So I think as we move into 2019 2020, we start to resolve that issue around feedstock. So in the interim, what will happen is I think the export price of propane sets the ceiling, if you will, on ethane price. And of course, fuel value is always a floor on ethane price. Our views are still $600,000 or more a day in rejection across the U.
S. So there's plenty of ethane. We just need the frac capacity to get it out. And then finally, I'd just say, as we look into 'nineteen, we're still constructive in terms of the margin outlook globally. We'd see good demand growth really globally, but in the U.
S, Europe and Asia. And we just like the supply demand fundamentals that we see looking out into 2019 2020.
Okay, great. Second question, I guess this one will be for Kevin since you mentioned it in your prepared remarks. You talked about in secondary products that Coke, I presume that maybe that's needle Coke was a contributor to that margin improvement. If I look in the Atlantic basin, your secondary margins were really strong there. So maybe you could just elaborate on the contribution that you're getting there?
Yes. So it's a combination. It's not you've got an NGL impact, the strong NGL prices, and you had improved pricing across all grades of coke. So petroleum coke, anode coke, the needle coke, so strong pricing across the board. And so that all contributes to that secondary product impact.
Okay. And do you feel that's sustainable?
Well, that depends on where the markets go. I mean that category, 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. That's right.
Bayway was also down during that period of time. And so that probably impacted that the amount of deposit direction on secondary products. Look, I think the coke market globally has improved. There's no question around that. We have 2 refineries certainly like Charles and Humber.
They're probably most impacted and influenced particularly by the specialty grade cokes. The last 2, 3 years, we've been working to develop new markets for specialty grade cokes. One of those is 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 arc furnace production, and that's tied with the global economy. And so to answer the question is it sustainable or not, if the economy continues to do well, I think this business will continue to do well for us.
But 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 quarter around you think about billings, you think about Wood River and Ponca City and Borger and capturing a $25 spread there.
Phil, 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, 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.
I appreciate it. Thank you for the additional color.
You bet.
Paul Sankey from Mizuho Securities. Please go ahead. Your line is open.
Thank you. Good morning. Hi, guys. Can we talk a little bit more about chemicals? I sort of thought that they would actually be a bit 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 the Q3, we had a turnaround at Port Arthur 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 seeing in ethylene. I know in CPChem's case, we've actually built inventory to cover the derivative start up from last fall until 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 at CPChem to bring the ethylene inventories down.
So then you come back and you think about, okay, what's happening going into next year, the sales volumes are still strong. Polyethylene sales volumes were up quarter over quarter. We're seeing strong demand growth and really across all regions, Paul. So I would say we're constructive on the outlook for margins going into 2019.
Are you hitting maximum volumes now, Greg, in terms of your sales?
I think the certainly, the Middle East assets are running at capacity. We had a global O and P rate of 91%, but that was influenced by the Port Arthur turnaround. Then we had a power outage at our Cedar Bayou facility, which took down the new cracker and the old cracker at Cedar Bayou. So that really impacted the operator. But I would we've given guidance kind of mid-90s for the Q4, and I think we feel pretty comfortable
found, a little found a little bit counterintuitive if we're in a generally in a rising price environment. I don't know if there's anything to add on that. But if additionally, you could talk a little bit about what looks like very weak gasoline markets at the moment and whether that's a transitory effect or or really what's going on there? Thanks.
Yes. I think as you look at New York Harbor gasoline trading at $8 a barrel crack, That's the weakest in 2 years. New York Harbor distillates trading at $29 a barrel. That's a 7 year high. So we're definitely seeing that split.
Seasonality is a big factor with the RVP change, butanes coming into the blending pool, gasoline inventories are high even relative to seasonal norms. What we're seeing is more pressure in the Atlantic Basin, especially on the European side of the Atlantic. Simple refining margins in Europe are negative and we are starting to see economic run cuts in Europe. We are in the U. S.
Starting to see gasoline import slow. Earlier this year they were running about 800,000 barrels a day, and they fall into 500,000 barrels a day and recently only 300,000 barrels a day. In addition, gasoline exports to South America are improving. You look at October of 2017 was 700,000 barrels a day. We're up over a 1000000 barrels a day this year.
So the other side of that equation with strong distillate is encouraging runs on the distillate side, but really the U. S. Is well positioned relative to the international markets. When you think about attractive crude discounts, strong diesel demand and cracks, low fuel and operating costs and competitive taxes that we enjoy here. And as you look into 2019, 2020, we expect high complexity refining capacity to benefit from the IMO environment and higher runs for high complexity, lower runs for low complexity refining.
Thanks. Well, Jeff, that was
Doug Leggate from Bank of America Merrill Lynch. Please go ahead. Your line is open.
Thanks. I'm actually going to do my questions in reverse given Paul just asked that one. So I'm going to do a follow-up, Jeff, if I may. And Smed probably for you. To us, this gasoline situation has been an accident waiting to happen given the strength of runs in the U.
S. But my question is, when you think about export of light sweet crude with Gray Oak and capacity expanding on the Gulf Coast, Along with the IMO impact for European refiners, in other words, higher runs, that combination seems to us to be another threat to gasoline in 2019, higher runs, lighter yields. I'm just curious if you can offer your thoughts on how you see the gasoline market improving in an IMO world next year or going into 2020, I guess?
Well, I think the gasoline market is 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 SEC 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 add a gasoline. I think that's how we get out of this. But gasoline is probably going to be soft through the winter months.
I appreciate that. I'll maybe take the rest of that one offline. But my follow-up is for Greg. And Greg, you're going to hit this because I ask it every couple of quarters, I guess, and it's really 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 numbers, so we're kind of out there and exposed, so 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 discerning on 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. So that's one point.
No, no, no. What I mean is the split. When I say cut, I mean like which way it cuts in favor of dividend versus in favor of buybacks by choice of phrase, sorry.
It was a Scottish definition of cut that got me. Okay. So look, I think we've consistently kind of guided to $1,000,000,000 to $2,000,000,000 of share repurchase this year for the past couple of years. Obviously, sure, we had an opportunity in February to take a big swing with Berkshire, and we did. But I think that guidance is still pretty good guidance going forward.
Look, we look at the stock price every quarter. We have a grid. We reset that grid every quarter, Doug. So in the past 2 weeks, we've been buying a lot more stock than we would normally buy as 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 $1,000,000,000 to $2,000,000,000 consistent range of share repurchases will be the guidance that we'll give for 'nineteen also.
Yes. I guess that's what I was looking for, the discernibility is what I was looking for. Thanks a lot, Greg.
Prashant Rao from Citigroup. Please go ahead. Your line is open.
Thanks for taking the question. I wanted to circle back on cash flows, particularly cash flow from operations. One of the step ups that we saw Q on Q in the equity affiliate distributions and seems to become being a more material part of CFFO. Wanted to get a sense and I don't want to front run anything you're going to say on the PSXP 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 maybe CapEx needs coming up, both in the midstream and then maybe further on in Chemicals?
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 affiliates less in the case of CPChem, WRB, less the capital spending that they're undertaking at the at that level, at the JV level. In the midstream, it's a little bit different because most of those affiliates are distributing most of their operating cash flow, if not all. And then the growth capital, the 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 $900,000,000 in the Q3.
The year to date through the Q3 is just over $2,000,000,000 of distributions coming out. And so you think about WRB, which both refineries have benefited very well from the sort of 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 we'll do so. With CPChem, some of this has been a function of the capital spend has come off significantly with the big project complete. That's all behind us now. And so their 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 for CBCAM $600,000,000 to $800,000,000 of distributions for the year. We've done $725,000,000 through the Q3. And it's certainly possible that there could be another distribution coming in the 4th quarter. So pretty healthy outlook from that standpoint.
Okay.
Thank you very much. That's very helpful. And then just a quick follow-up. Kevin, I apologize if you did detail this in your prepared remarks, but the working capital swing that we saw in the quarter, should we expect most of that to reverse out next quarter? And so for the full year, we sort of end up breakeven on that volatility?
Or is there something anything that sort of would be residual that we should be mindful of?
No, I think that's a reasonable assumption. It's always hard to get forecast working capital with too much precision given the amount of moving parts that 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.
Paul Cheng from Barclays. Please go ahead. Your line is open.
Hey guys. Good afternoon. Two quick questions. First, on the needle coke, is there any capability for you guys in the short term, say within the next 6 months or so 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 Cook business is within the Humber Refinery and the Lake Charles Refinery. So it shows up in our refining portfolio or refining segment. In that segment, we highlight the most important capital projects every year and you've seen us with Wood River and Bayway FCCs with now the Sweeny FCC. We highlight all the large capital projects. And so the fact that we haven't highlighted a large capital project, it's probably a reasonable assumption that there's not one.
Right. Jeff, thank you for that. But I think needle coke is a function of what type of oil that you choose going into the cooking into the cooker. So maybe I get you wrong that is the cooker you said is actually need to be specially designed because I don't think it is, but maybe that you guys can help me understand a little bit better?
Well, we do have industry leading technology associated with needle coke production. It is a different process. And so we are very unique in that regard.
Brad Heffern from RBC Capital Markets. Please go ahead. Your line is open.
Hey, good morning, everyone.
Good
morning. 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 FID 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 2019, early 20 20 type FID. We are progressing work around the site location, the permits required, initial designs around that facility. But I still think that that it's late 2019 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 isn't incremental frac capacity in Mont Belvieu? Do you guys see Y grade just getting produced in the tanks? Or does it get rerouted to Conway or Appalachia? How do you see that playing out?
Yes. I think it's going to be interesting to see how we move forward. We'll probably see rejection maintained at high levels at 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 fractionated capacity because supply is likely to continue to grow as we go forward.
Drilling activities continuing in the Permian, We're drilling 600 wells a month and only completing 400 wells a month. So the DUC 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 supply then add infrastructure then add more supply. We're kind of in that cycle.
Okay. Appreciate the thought. Thanks.
Matthew Blair from Tudor, Pickering, Holt. Please go ahead. Your line is open.
Hey, good morning, everyone. I was intrigued by the comments of debottlenecking existing chems units. Could you give a sense of just the general capacity that you'd be talking about here as well as the timing? And also would some of these debottlenecks occur at your brand new cracker and PE units?
The answer is yes. I think we probably have room to debottleneck the new cracker. But across the platform, I would say, we have opportunities in some of the older assets too to do some additional debottlenecking. So we're not going to give a number today in terms of the volumes on that, but I think that CPE chem 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 debottlenecks are the easiest ones to do highest returning projects typically in the portfolio.
So we'll prosecute those.
Right, right. And then, over in refining, 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 the bottleneck as just a lack of the 117 J railcars?
Yes. We benefit from Bakken 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 in growth in the Bakken. Oil production is 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're 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 let up as we get in to later in November December. But we do expect Bakken differentials to remain wide.
Thank you. You bet.
Manav Gupta from Credit Suisse. Please go ahead. Your line is open.
Hey, guys. So PSX is one of the global leaders in coking capacity. Given IMO indicating no chance of a delay, ignoring the administration, would PSX be open to investing in any resit destruction or resit upgrade projects? I mean, when you look at the Sweeny refinery location, it's right next to Jones Creek. So you can source a lot more WCS there.
So this could be a good candidate to build a coker. So just wanted to hear your views on it.
Yes. So we are the global leader in coking capacity and we really achieved 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.
Okay. And a quick follow-up. In the Mid Con, besides WCS, did you actually increase an uptick on the Permian crude that helped drive that big delta up?
So PSX benefits from discounts on Permian barrels at its border refinery as well as transporting volume into the Mid Continent and the U. S. Gulf Coast refineries as well. We also benefited PSXP from the ownership in the 900,000 barrel a day Grayway Pipeline in the South Texas Gateway Facility. So those were the primary beneficiaries of the wide Permian diffs during the quarter.
I think we also ran our first train out of the Permian this year around to or this quarter around to Beaumont. So I think we're doing everything we can around the portfolio to create value out of these opportunities.
Thank you, guys. Thank you so much.
You bet.
Craig Shere from Tuohy Brothers. Please go ahead. Your line is open.
Good afternoon.
Good afternoon.
Picking up on Roger's PXP question a bit, kind of apart from collapsing the MLP 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 MLP 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 in the midstream space. Are you just comfortable having this kind of dual pronged some at PSXP, some at PCX approach or do you envision a longer term kind of simplification around how to think about midstream?
I just well, first of all, you're right. We probably have $700,000,000 to $900,000,000 of EBITDA at the PSX level. That's MLP qualifying EBITDA, although $300,000,000 or so of 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 and it has the balance sheet and the capability to execute those projects, that I suspect that, it will be a long time before we get to the need to do any drops.
It gives us comfort that we have them there if we need them. But I would just say we're comfortable with the structure. We think about PSXP as a vehicle to grow our midstream business. I think we said many times we'd be very comfortable of all the investments we're making in midstream could be executed at the PSXP level. And indeed, we've grown from almost zero capital budget to $750,000,000 this year and this afternoon we're going to tell you a budget over $1,000,000,000 for PSXP over 2019.
So you can see the strategy it's evolving. And so it's doing what we needed to do in terms of helping us to grow our midstream business. We're 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 barrel a day design, we've demonstrated kind of 200,000 barrels a day. We're running at 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, the Eagle Ford and the other basins, we're going to need to export LPGs to clear the U. S.
Markets because the U. S. Demand is just not going to grow fast enough to absorb that. So I think we're 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're seeing is the markets pivoting around the tariffs today. So we have Chinese buyers that aren't necessarily shipping to China today and then maybe trading out for Air Gulf Cargo, but the market's working in our view at this point in time. And I just think longer term, we'll certainly solve the tariff issue. So I don't think we're 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 this 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 2019, we see those utilization improving and 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 point
From a dimension 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, would you think that a multiyear economic contracting market could begin to return by second half twenty nineteen?
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.
Chris Sighinolfi from Jefferies. Please go ahead. Your line is open.
Hi, guys. Thanks for the outlook this afternoon.
Good morning, Chris.
I just want to quickly circle back on CPChem. It was really helpful color on the inventory sales in the Q3 and some of the outages, power related complications you had encountered. But I guess as we look into future periods, I'm just curious with regard to the inventories you mentioned and as they 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 for 4Q?
I think from an industry's perspective, the excess inventory is really in the ethylene part, not the derivative part of the chain. So it's really people making adjustments on the ethylene production side to bring the ethylene inventories back into line. And I mean, when you look at we look at the full chain margin. And so what you've seen is the margins really shifted into the derivatives over the last couple of quarters. And I mean, that's a value of being totally integrated from that perspective.
But I suspect that as ethylene inventories kind of come back to more normal, some of that margin shifts back into the ethylene side. But from a CPChem perspective, they're kind of agnostic because they capture that full value through the chain. And so managing inventory is just part of good blocking and tackling and capital discipline around working capital. So I think that what we fundamentally look at, we look at the Middle East, are the assets running, is inventory stacking up at the docks? It's not.
China continues to be a strong buyer and inventory seem to be clearing through that system. And of course, demand in the U. S. Appears very good to us fundamentally. So I just we're constructive in our outlook in 2019, 2020 2021 from a fundamental supply and demand balance issue.
We see increasing operating rates, which I think is constructive towards margin as we move forward in that business. And so I think the comments around inventory were really specific around kind of the 3rd Q4. I think as you get into 'nineteen, those start to clear out in terms of the ethylene slide side.
Okay. That's really helpful. I guess real quickly, just switching gears and I don't want to run front run the PSXP call, but two questions if I could on Gray Oak. One is the upsize of initially targeted capacity to 900 from 800. Is that purely just based on additional contract volume secured or was there something else influencing it?
And then second is, just as Enbridge provided any early indication to you as to what it will do with its option. I guess I'm asking the context of your earlier comments regarding capital budgeting and discussions with the Board at this point or entering 4Q about what 2019 looks like?
Yes. So I would say there is multiple parties involved and they uplift to 900,000 barrels a day. But the line we're building a 30 inches line regardless. And so but it was nice to be able to firm up those commitments. And certainly Enbridge has an option to come in.
That option expires in November, I think. And so I think by the Q4, you'll have visibility in whether they decide to exercise that option or not. I hope they do. They're a great partner. If they don't, we're willing to keep their share.
It's a great project. So you'll have some more insight into that. In fact, all the other people that have options to come into Gray Oak have to do so by November. If I was going to bet you money on it, I think our ownership is going to be 42.25 percent because I think these people will exercise their options and come into the line. I know I would.
Thanks.
Thank you for your interest in Phillips 66. If you have additional questions, please call Rosie or me. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. You may now disconnect.