Welcome to the second quarter 2019 Phillips 66 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 Phillips 66 second 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 two 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. In order to allow everyone the opportunity to ask a question, we ask that you limit yourself to one question and a follow-up. If you have additional questions, we ask that you rejoin the queue.
With that, I'll turn the call over to Greg Garland for opening remarks.
Thanks, Jeff. Good morning, everyone, and thank you for joining us today. Adjusted earnings for the second quarter were $1.4 billion or $3.02 per share. We generated $1.9 billion of operating cash flow. We delivered solid operating performance and strong earnings during the quarter. Refining operated at 97% utilization and captured favorable margins driven by improved gasoline cracks. In midstream, growth projects completed over the past two years contributed to record segment earnings. During the quarter, we distributed $861 million to shareholders through dividends and share repurchases. We're dedicated to a secure, competitive and growing dividend, and this quarter we increased the dividend by 12.5%. This is the ninth increase since our inception, resulting in a 25% compound annual growth rate. Disciplined capital allocation remains fundamental to our strategy, and we know that it creates value for our shareholders.
Our long-term objective is to reinvest 60% of our operating cash flow back into the business and return 40% to our shareholders through dividends and share repurchases. We'll buy our shares back when they trade below intrinsic value, and we're buying shares today. Consistent with our strategy, we're executing a robust portfolio of midstream growth projects with attractive returns. These new projects will provide us with continued future earnings growth. During the quarter, we announced joint ventures to construct the Liberty and Red Oak crude oil pipeline systems. These projects are backed by long-term volume commitments. The Liberty pipeline will provide transportation from the growing Rockies and Bakken production areas to Cushing, Oklahoma. Liberty will have access to the Gulf Coast via the Red Oak pipeline. We own a 50% interest and will construct and operate Liberty.
The Red Oak Pipeline system will connect Cushing and the Permian Basin to multiple locations along the Gulf Coast, including Corpus Christi, Ingleside, Houston and Beaumont. We own a 50% interest and will operate Red Oak. Both pipelines are in supplemental open season, seeking additional commitments for the limited remaining capacity. The pipelines are targeted to begin initial service in the first quarter of 2021. Phillips 66 Partners continues to construct the Gray Oak Pipeline. The 900,000 bbl-per-day pipeline will transport crude oil from the Permian and Eagle Ford to the Texas Gulf Coast, including our Sweeney refinery. We received all major permits, acquired all right of way, and installed 80% of the pipe. The project remains on track to start up in the fourth quarter of this year. Phillips 66 Partners owns 42.25% interest in the joint venture.
Gray Oak will connect with multiple refineries and export facilities in the Corpus Christi area, including the South Texas Gateway Terminal, in which PSXP owns a 25% ownership. The terminal will have two deepwater marine docks, 7 million barrels of storage capacity, and up to 800,000 bbl per day of throughput capacity. The terminal is expected to start up by mid-2020. With Liberty, Red Oak, Gray Oak, and our existing network of pipelines, we will serve all the key shale oil-producing regions with connectivity to the major Gulf Coast market centers. Our pipeline network is integrated with our central quarter and Gulf Coast refineries, as well as our Beaumont and South Texas Gateway export terminals. We believe this integration is a competitive advantage that further enhances the value across our portfolio. We continue to expand the Sweeney Hub to meet increasing domestic NGL production and global market demand.
We're moving forward with construction of a fourth fractionator that will have 150,000 bbl per day of capacity and is expected to cost approximately $500 million. Frac 4 is backed by customer commitment and is expected to be completed in the second quarter of 2021. Construction of Fracs 2 and 3 is progressing well, and we're on track to start up in the fourth quarter of 2020. Upon completion of Frac 4, the Sweeney Hub will have 550,000 bbl per day of fractionation capacity. In connection with our expansion at the Sweeney Hub, PSXP is increasing storage capacity at Clemens Caverns from 9 million barrels- 15 million barrels.
Completion of the expansion is expected in the fourth quarter of 2020. Also at the Sweeney Hub, PSXP will construct a 16-inch ethane pipeline from Clemens Caverns to Gregory, Texas. The C2G pipeline will serve petrochemical customers in the Corpus Christi area.
The pipeline will have 240,000 bbl per day of capacity and is expected to be complete in mid-2021. In chemicals, CPChem is expanding its strategic partnership with Qatar Petroleum to develop petrochemical assets in the U.S. Gulf Coast and in Qatar. Pending final investment decisions, these projects will add world-scale ethylene and high-density polyethylene in advantage feedstock locations with access to global markets. This further enhances CPChem's leading polyethylene position to supply the world's growing demand for polymers. In refining, Phillips 66 Partners recently completed construction of the 25,000 bbl per day isomerization unit at the Lake Charles refinery that will increase production of higher octane gasoline blend components. This unit is expected to reach full production in the third quarter. At the Sweeney refinery, we're upgrading the FCC to increase production of higher valued petrochemical feedstocks and higher octane gasoline.
This project's on track to complete in the second quarter of 2020. This morning, we announced the elimination of incentive distribution rights at PSXP. This transaction improves PSXP's cost of capital, simplifies its capital structure, and further aligns the GP and LP economic interests. Our ownership in PSXP will increase to 75% after the transaction closes. We believe the transaction is attractive for both Phillips 66 shareholders and PSXP unit holders. PSXP is a premier MLP and remains a key component of our midstream growth strategy. Before I turn the call over to Kevin, we'd ask that you hold the date November 6th for an analyst and investor day that we'll be hosting in New York City. With that, Kevin, you can go through the financials.
Thank you, Greg. Hello, everyone. Starting with an overview on slide four, we summarize our second quarter financial results. Adjusted earnings were $1.4 billion or $3.02 per share. Operating cash flow, including working capital, was $1.9 billion. Capital spending for the quarter was $631 million, including $408 million on growth projects. We returned $861 million to shareholders through $406 million of dividends and $455 million of share repurchases. We ended the quarter with 449 million shares outstanding. Moving to slide five. This slide highlights the change in pre-tax income by segment from the first quarter to the second quarter. During the period, adjusted earnings increased $1.2 billion, mostly driven by refining. All segments had improved results. The second quarter adjusted effective tax rate was 20%. Slide six shows our midstream results. Second quarter adjusted pre-tax income was $423 million, an increase of $107 million from the previous quarter.
This quarter, we achieved strong results in the midstream segment, driven by record pre-tax income in both the transportation and NGL businesses. Transportation adjusted pre-tax income was $245 million, up $42 million from the previous quarter due to higher volumes on our wholly-owned and joint venture pipelines and terminals. NGL and other adjusted pre-tax income increased $53 million, driven by higher margins and volumes at the Sweeney Hub, as well as improved butane trading results. The Sweeney Hub had record earnings and strong operations during the quarter. The LPG export facility loaded a record number of cargoes, and the Sweeney Fractionator achieved utilization of 118%. DCP Midstream adjusted pre-tax income of $35 million in the second quarter is up $12 million from the previous quarter due to favorable hedging impacts. Turning to chemicals on slide seven.
Second quarter adjusted pre-tax income for the segment was $275 million, $48 million higher than the first quarter. Olefins and Polyolefins adjusted pre-tax income was $260 million, up $41 million from the previous quarter. The increase reflects higher polyethylene margins driven by lower NGL feedstock costs, as well as lower utility costs related to falling natural gas prices. Global O&P utilization was 95%. Adjusted pre-tax income for SA&S increased $8 million following first quarter turnaround activity. During the second quarter, we received $190 million of cash distributions from CPChem. Moving to refining. The chart on slide eight provides a regional view of the change in refining's adjusted pre-tax income. Refining second quarter adjusted pre-tax income was $983 million, up $1.2 billion from last quarter. The increase was mostly due to higher realized margins and volumes.
Realized margins for the quarter increased 57%, from $7.23 per barrel to $11.37 per barrel, driven by higher gasoline cracks. Crew utilization was 97%, compared with 84% in the first quarter. The first quarter was impacted by significant turnaround activity as well as unplanned downtime. The second quarter clean product yield was 84%, and pre-tax turnaround costs were $67 million. Slide nine covers market capture. The 3-2-1 market crack for the second quarter was $15.24 per barrel, compared to $9.77 per barrel in the first quarter. Our realized margin was $11.37 per barrel and resulted in an overall market capture of 75%. Market capture was impacted by the configuration of our refineries. We make less gasoline and more distillate than premised in the 3-2-1 market crack. During the quarter, the gasoline crack increased 169%, while the distillate crack decreased 8%.
Losses from secondary products of $1.35 per barrel increased $0.72 per barrel from the previous quarter due to declining NGL prices relative to crude, partially offset by improved coke margins. Our feedstock advantage of $0.01 per barrel declined $2.07 per barrel from the prior quarter due to narrowing crude differentials. The other category reduced realized margins by $0.21 per barrel in the second quarter. This was improved $3.52 per barrel from the prior quarter, with the largest driver being clean product realizations. Moving to marketing and specialties on slide 10. Adjusted second quarter pre-tax income was $353 million, $148 million higher than the first quarter. Marketing and other increased $156 million from higher domestic and international margins associated with falling spot prices during the quarter. Specialties decreased $8 million, primarily due to lower lubricant margins. Refined product exports in the second quarter were 187,000 bbl per day.
We reimaged approximately 400 domestic branded sites during the second quarter, bringing the total to approximately 3,300 since the start of our program. Slide 11 shows the change in cash during the quarter. We started the quarter with $1.3 billion in cash on our balance sheet. Cash from operations was $1.9 billion, which included a $251 million working capital benefit primarily related to inventory draws. During the quarter, we funded $631 million of capital spending and returned $861 million to shareholders through $406 million of dividends and $455 million of share repurchases. Our ending cash balance was $1.8 billion. This concludes my review of the financial and operating results. I'll cover a few outlook items for the third quarter. In chemicals, we expect the global O&P utilization rate to be in the mid-90s.
In refining, we expect the third quarter crude utilization rate to be in the mid-90s and pre-tax turnaround expenses to be between $150 and $180 million. We anticipate corporate and other costs to come in between $210 and $240 million pre-tax. 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. If you have a question, please press star then one on your touch-tone phone. If you wish to be removed from the queue, please press the pound key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touch-tone phone. Neil Mehta from Goldman Sachs, please go ahead. Your line is open.
Good morning, team.
Morning, Neil.
Morning.
Morning. The first question I had was, when I think about your CPChem business, historically you've grown this business organically, and you've announced a couple really good projects here, one in Qatar, one on the Gulf Coast. That kind of reinforces that historical strategy. There's been some press reports that the potential for you guys to do a large step out type of transaction here, which I guess would be inconsistent with the historical way you have grown this business. Without asking you to speculate here, anything you could do to clarify the way you think about building this business would be helpful for investors as we think about it.
Dave. Well, first of all, as a practice, we just don't comment on market rumors or speculation. Even outside of chemicals, you step back and you think across our entire portfolio, we've followed an organic path for the last seven years. Where we've done things inorganically, it's been on the asset side. Think about the Beaumont terminal or the River Parish or SCOOP/STACK with Plains. We have been opportunistic on the inorganic side from time to time. For us, anything we would do inorganically would have to essentially compete with the returns we can generate on the organic side. You've read the reports this morning. We have a really strong portfolio of organic opportunities, and so I'd just leave it at that. I think we're like everyone. We look at everything that's out there.
We struggle to find things that we think that are accretive to returns. We'll continue to look.
All right. Fair enough. The follow-up question is just NGLs have certainly come under a lot of pressure. When we think about PSX at a consolidated level with all the moving pieces recognizing you have DCP, and there's some element of NGL product yield that comes off your refiners, but you have a large ethane-consuming business in your chemicals business. How should we think about the company on a consolidated basis? Do you do better if NGL prices are lower?
Well, I think we're a net buyer of ethane at CPChem. On the low ethane prices definitely benefit our chemicals business. The lower propane prices given our export position and the strong arbs we're seeing particularly to Asia today, that's a benefit for us on the LPG export side. There is impact at DCP across the DCP portfolio to lower NGL prices.
On balance, we have offsetting across the portfolio.
I would say within the PSX and PSXP portfolio, many of those pipes and fractionators are fee-based, so we benefit from growing volumes, but not really exposed on the commodity side. With regard to DCP, they've been successful converting some of their historical commodity priced contracts to more fee-based contracts, and they're hedged against the majority of their remaining exposure.
Doug Terreson from Evercore ISI, please go ahead. Your line is open.
Congratulations on your results, guys.
Thanks, Doug.
In refining and marketing, Phillips 66 seems to be consistently outperforming peers due to several factors, one of which may be higher volume. On this point, one of your peers suggested recently that U.S. product demand may be exceeding government estimates, and that positive revisions to demand may be forthcoming. I wanted to see whether you share that view and to get your overall outlook for products demand in the U.S. and export markets too, please.
Yeah. I think when you look at the U.S. consumer, he's in pretty good shape. Low unemployment, healthy wage growth, consumer confidence is in good shape. We saw gasoline demand maybe down slightly in the first quarter, it rallied and was up in the second quarter. The vehicle miles traveled up strong in April and up again in May. I think demand we're seeing is kind of flattish on the gasoline side year to date, and what we expect in the back half of the year. On the diesel demand side, we see it flat to slightly up, and that's compared to very tough comps with 2018 diesel demand being up 6% year-on-year. Still very healthy demand on the diesel side as well.
I think as we went through the quarter and some of the flooding in the Mississippi River delayed some of the planting. The industry did finish strong. What we thought was going to be a loss of 70,000 bbl or 80,000 bbl a day of demand in the planting season, maybe it was closer to 30,000 bbl or 40,000 bbl a day. That's been a little bit better than was feared.
Okay. Good summary, Jeff. In midstream, it seems like there are a lot of shale-related takeaway, export, and processing projects planned by the industry, even though shale output growth is decelerating and future spending may have to decline further if E&Ps want to sustain current returns valuation and share prices. Of course, if we were to ever have consolidation, E&P spending and output would be pressured over the medium term too. My question is: How does the company think about and manage the risks for scenarios such as this one, such that prospective returns on investment in midstream are protected?
Well, we start with partnering. You see these big pipes. We've got partners in these pipes, strong partners. Secondly, when you look at the volume commitments, throughput commitments, these are seven- to 10-year commitments, with strong investment-grade parties. That's the way we try to mitigate the risk, Doug.
Okay. Thanks a lot, Greg.
You bet.
Phil Gresh from JPMorgan, please go ahead. Your line is open.
Yes. Hello, Greg. It's been quite an active couple of months here for PSX with all these project announcements and midstream and chemicals. I can certainly see why it's time for another Analyst Day to dive into that. In advance of that event, I was hoping you could talk about what looks like a re-accelerated growth philosophy, especially given where we are in the economic cycle. Obviously, we're a bit late in the cycle. Perhaps, Kevin, if you could help maybe detail out some of the financing plans behind these projects and kind of help us think through how that foots with the 60/40 band over the next couple of years. Thank you.
I'll just start at a high level, Phil. Mid-cycle cash, we've moved from four to five to six to $7 billion. If you just take the low end of the range at six and 60% reinvested, you're at a $3.6 capital budget. I think that we're going to live within that. In any given year, we could probably be on balance above or below that. Certainly you've seen in the past where we didn't have investable opportunities, we pulled CapEx way down. We like the suite of projects that we have. They're all very attractive returns that we think build value across the portfolio.
Just from that standpoint, I think we're consistent with what we've been saying for the past seven years in terms of kind of the 60/40 investment return to shareholders kind of paradigm that we've been in, and we're comfortable with that. We think it's about right for the company. As we've talked in Doug's question, we try to mitigate the risk on these projects, certainly by taking on partners, looking at volume commitments with good counterparties on the other end of that. Kevin will speak to the project financing. That's another way we use to de-risk these projects. On balance, I think we're positive about the organic profile that we have. We're positive about the cash generation of the company. We still think that the first dollar cash we generate is going to go to sustaining capital at $1 billion a year.
Second dollar is going to go to our dividend at $1.6 billion. Then we have options. Certainly we can be within $1.5 billion-$2.5 billion in terms of our growth, and $1.5 billion-$2.5 billion in terms of our share repurchases, and we can make that all fit within the existing cash flow. Kevin, I'll let you talk to the project financing.
Yeah, thanks. Just walking through a couple of these projects. Gray Oak, as we've talked about in the past, we had communicated our intention to finance that, and we closed on the financing in the second quarter. That $1.3 billion facility is in place and should effectively cover most of the remaining CapEx spend this year on that project. The Liberty and Red Oak pipelines, on a gross basis, the numbers we've put out there combine those two projects. That's just over $4.1 billion of CapEx. We are 50% in each of them. While we haven't gone down the full project financing path yet, we've structured those projects to where they will be financeable. It would be our intention to put project-level financing in place on those joint ventures also. The other one I'll just comment on is Well, actually two more.
Also in midstream, we're constructing the, you got Fracs 2 and 3 under construction. We just sanctioned Frac 4. Those are all being funded by us, no financing in place on those projects. That spend comfortably fits within the overall capital allocation framework as Greg just outlined. Just lastly on chemicals, the two projects that were announced, bear in mind that these are not FID level yet, there's still a ways to go. Given the structure with these being partnerships at the CPChem level, they should be amenable to financing. Now, the reality is you've got four parties need to align around those funding plans. Between QP, CPChem, us, and Chevron need to align around that. They should be structured in a way that if the owners are in alignment, there's potential for financing around those.
Overall, when you put all this together, this still very much works in the context of our overall capital allocation framework.
That's very helpful. Just to clarify, Kevin, when you say project financing at the CPChem level, should we be thinking of some combination of free cash flow at the entity plus maybe raising some debt there, plus maybe even project financing at the CPChem level?
Well, the reality is it could be any or all of the above. You have the potential at the project level. If you take the Qatar project or you take the Gulf Coast project, you have the potential to do two project-level financing at that point. There's also the potential for CPChem at the CPChem entity level to take on debt. They have a very strong balance sheet and so they have that capability as well. All of these things require the owner alignment around path forward on funding.
Okay, great. Just my follow-up will be to Neil's question, maybe more specifically on the refining business itself. Is there any additional disclosure you could provide around your exposure to these petchem products, NGLs, naphtha, propylene, and the like? I know others have been talking about it, and unless I've missed it, I haven't seen any specific disclosure with your exposures there to help think through the moving pieces. Thanks.
As we go through our secondary products, Kevin summarized it in the opening remarks. When you look at the products that are there, really, naphtha is de minimis within our refining products. NGL yield is about 4%, coke yield about 4%, and fuel oil yields between 2% and 3%. Those are the primary products. There are a lot of smaller products that are included in there as well. That would give you a high level of our exposures to individual products within the secondary product category.
Doug Leggate from Bank of America Merrill Lynch, please go ahead. Your line is open.
Thank you. Good morning, everybody. Greg, I don't want to front-run the November Analyst Day too much here, but it seems that the EBITDA mix of the company is going through another bit of a fairly rapid evolution as it relates to de-emphasizing refining. I'm just wondering if that read is correct. How should we think about the mix shift as we go forward? With the list of projects you've got right now on a mid-cycle basis, where do you see refining stacking up relative to the rest of the portfolio?
Well, if you just look at averages, kind of 12- 18, refining's about $4 billion of EBITDA. Our midstream business is now about $2 billion. Our marketing specialties at $1.4 billion. Our distributions from CPChem, about $1.2 billion. Then you think of about $800 million of corporate interest and $1 billion or so of taxes. That gets you kind of that $6.5 billion of cash flow that we've been talking about. That's how we think about the portfolio. Certainly, we've made investments in the refining business, but they've been quick payout, kind of lower capital items that we've chosen to invest in. For instance, upgrading the FCCs, upgrading our Billings vacuum tower.
We generate $200 million of EBITDA in our refining business through these investments, and we still have, probably in the next three years, another $300 million-$400 million of EBITDA coming our way from the investments we're making in refining. On the midstream side, if you want to look all the way through 2021, there's probably $800 million-$900 million of EBITDA coming in on the midstream business. The strategy around growing our midstream, growing our chemicals business, and investing smartly in our refining business has been the strategy of the last seven years, and we're really not departing from that. I don't know, Jeff, if you want to comment over the top.
Go ahead, Jeff.
Jeff gave me an A on that. Okay, Jeff.
Yeah. That was a good summary. Go ahead.
No, I was just going to say, it looks to us at least with the list of projects you've got right now, before we consider further drop-downs, we're moving well under 50% of the portfolio for refining on a mid-cycle basis. Does that sound reasonable? Once these projects are complete, once you've moved through Obviously we haven't got definition on the chemicals joint ventures yet, but with what you've got going on in the midstream, would it be fair to assume that refining is trending towards under 50% of the corporate mid-cycle EBITDA?
Yeah.
Yeah.
If you're excluding our marketing specialties business from refining, I think that's probably a true statement, yeah.
Yeah. I'm separating that out right.
Especially as you think 2020, 2021 timeframe.
Okay. Thank you for that clarity. My follow-up is actually, I want to kind of, I guess go back a couple of years to some of the questions that used to come up around Tier 3 gasoline. Gasoline certainly was, as you know, was our primary basis for being pretty cautious in the space the last couple of years. It seems to us that with the chatter about a potential VGO swing towards bunkers from next year and the three-year runway for Tier 3 gasoline kind of, I guess, coming to an end at the beginning of next year, are there grounds for a little bit more optimism that gasoline actually has some structural positives supporting, maybe offsetting a little bit the lightening of the crude slate that has lifted supply here?
I'm just curious on your broader perspective as to whether Tier 3 and VGO issues amongst perhaps lower utilization rates across the industry can finally put a little bit of support under that market. I'll leave it there.
Yeah. I think Tier 3 is an excellent point with the average sulfur content last year at over 20 parts per million, moving to 10 parts per million at the start of next year. The credits that are available, Tier 2 credits, are swelling the gasoline pool somewhat currently. I think as you look at the IMO situation, it's still, I think, a challenge to figure out exactly how that's going to play out. It doesn't look to us as though there's going to be 2 million barrels a day of incremental diesel production to meet that incremental marine fuel market. Some is going to have to come from other products, and certainly some of that could be VGO. We're struggling to really predict what that percentage will be or how much that total will be, but it should take some gasoline out of the gasoline pool.
I think with regard to Phillips 66, we're currently producing gasoline with a sulfur content comfortably below where the overall industry is. We are in good shape to meet the Tier 3 standards. The vast majority of the capital spending has already occurred, and what little Tier 3 spending is left will fall within the normal range of our sustaining capital spend. When we look at premium gasoline, for example, we're upgrading more gasoline into the premium grade than the industry average and will benefit from a couple of growth projects. One, the 25,000 bbl-a-day Lake Charles ISOM unit, which is scheduled to come up this quarter, as well as next year's Sweeney FCC optimization. Both of them will allow us to increase premium gasoline production.
Roger Read from Wells Fargo, please go ahead. Your line is open.
Yes. Good morning. Thank you. Thanks for the explanation on the gasoline side there, Jeff.
Done some nice work on Tier 3, Roger.
Thank you. Thank you. Hoping maybe to change gears a little bit back to the Midstream side. Great performance here in the quarter. I think back to when the Sweeney fractionator and the LPG export docks were first talked about, the numbers were pretty big. I'm wondering when we go back to then, is that what we're now seeing? I mean, 118% utilization of the fractionator obviously is a little bit beyond the typical budget. And then with LPG volume exports at a record, did we hit maximum there? I guess what I'm kind of getting at is, was Q2 in that particular area as good as it gets, or is there something else in the tank? And then as a little extra to that, did we see operating leverage come through here with the additional throughputs and that's what really drove the margins?
I think in terms of the export facility and the frack, both are running at well above design rates. We're kind of at 200,000 bbl a day across the dock. We've had strong arbs in Asia. We've had lower propane prices. That's driven arbs and the profitability. We've seen dock fees bottom in the $0.05-$0.06 range a couple years ago, and they were up in the low double digits in the second quarter. You kind of had the, if you will, the Sweeny hub running, approaching kind of a $300 million annualized EBITDA run rate, which is at the low end of what we had thought when we approved the project. We thought there'd be some more room to play the arb above that, we had numbers out there as much as $500 million. We're still underperforming our expectations there.
Certainly, this is probably the best quarter we've ever had across the frack and the LPG export facility. There is some capacity coming on later this year and next year. There's also another 1 million for frac capacity coming on. Our view is that the docks are going to be quite active over the next couple of years, needing to clear the propane to the export markets.
Yeah. We've seen healthy demand in Asia, new units coming on, widening the arb as well as strong supply domestically as Greg mentioned. That arb between the Gulf Coast and Asia, as well as Gulf Coast and Europe, has been widening. The shippers have taken a disproportionate share of that, we're seeing some benefit there as well.
The one thing I'd add, Roger, as you think about fracs two and three coming on in 2020, so next year. That provides some other additional uplift because we'll be able to essentially fill out the export dock with the LPGs coming off the fracs. We're not having to pay to move propane down from Belvieu. You get some uplift at that point when those assets are complete.
Okay. Yeah. Thanks. Then back to one of the questions earlier. Distributions from CPChem, I think the number was $1.2 billion. As we look at the build-out of the facility in Qatar and in the U.S., and talked about the different financing. We think about that $1.2 billion as a pretty good baseline. Obviously, margins operating levels will impact that, but that's a good baseline that'll be maintained even through the build-out and CapEx phase of these next two big projects.
Yeah, I think that's a reasonable base assumption to use. You hit the nail on the head that it's very much subject to what the margin environment's looking like, exactly what the spend profile of those two projects is. Remember, it's two major projects, but it's 50% of one and 30% of another. On a cost basis, it's still less than doing one world-scale Gulf Coast project. For planning purposes, it's probably a reasonable assumption. Recognize there's just going to be a lot of moving parts as we get closer to that point in time.
Okay, great. Thanks. I'm looking forward to the Analyst Day and wondering, Greg, if you're going to provide us that intrinsic value at the Analyst Day.
You'll just have to come to find out, Roger.
All right. Appreciate it. Thank you.
Take care.
Thanks.
Prashant Rao from Citigroup. Please go ahead. Your line is open.
Thank you. Good morning. Thanks for taking the question. I wanted to touch back on one of the things that Jeff mentioned in a previous answer about the uncertainty around how IMO 2020 gets resolved, and get your views on some indications that we could be seeing commodity spreads and some other indicators saying that we're getting the first movements of an IMO 2020 impact, specifically high sulfur fuels. We're seeing time spreads in Asia start to widen out perhaps on the forwards, storage rates for low sulfur fuel, more announcements of blended new compliant marine fuels. It's a bit early still. I think we're hitting that window where we were all expecting something to start to emerge in the coming months. Always appreciate your views on this. You tend to be more moderated and measured.
Anything you'd have to share in terms of color, would appreciate getting that from you.
Yeah, I think you're hearing more about the different blends. We're taking advantage of our Bartlesville technology center and testing blends there. We're expecting conversion of tanks in the September-ish timeframe and expect shippers to be buying compliant fuels in the fourth quarter. I think there are some early indications of compliant marine fuels for CAL 2020 trading at $12-$15 a barrel over Brent. There's not a lot of liquidity in that market. It's still early. We are starting to see inventories build. I've seen reports of up to 12 VLCCs in Singapore in anticipation of the transition. I think things are starting to move in that direction. I think it's still early to have a high degree of confidence exactly what impact it's going to have on diesel cracks, on compliant fuel, on high sulfur fuel discounts.
I do see it being a positive for the industry. It does substantially reduce the industry's footprint from an emissions perspective as well.
Thanks. Appreciate that. Other question, I'll just touch back on the agriculture or the ag exposure, given the weather issues in the quarter, and it sounded like there was a strong finish to the quarter there, which was nice to see. Wondering your sense of if you could help us think about total economic exposure for Phillips as a consolidated entity there. As we think through the back half of the year in 2020. What's been missed in planning this year. We're seeing some price signals there that'd be making up for the planning next year. As we look out through the next, call it six, 12, 18 months, maybe get a sense of how we should be thinking about the cadence of that and maybe how material or not material any upside impacts might be.
I might take the first question. I think with regard to drivers, the global economy is a meaningful driver for product demand in our Refining business. It's a meaningful component to the chemicals business as well. I think with regard to Midstream, the major drivers there are production growth, U.S. shale opportunities there. I think I would put those as the primary drivers for those three businesses.
Oh, I meant with, sorry, just to clarify, with specifically with reference to the agricultural exposure, because we were hearing there could be a little bit, when you talked about the continent diesel demand, that there could've been a little bit of impact on the distillates and fuels, like what we were seeing in the U.S. from flooding issues that didn't appear as much as we'd feared before. I was thinking more specifically about that. Sorry if I didn't clarify.
Okay. I apologize. Yeah, so from an industry-wide perspective, we were initially looking maybe 70,000 bbl a day of negative impact from the planning season as we were looking midway through or partway through the planning season. The planning activity picked up at the end more than anticipated, and so I think the closer estimate is something like 30,000 bbl or 40,000 bbl a day, and that's industry-wide, not specific to Phillips 66.
Paul Cheng from Scotia Howard Weil, please go ahead. Your line is open.
Hey, guys. Good afternoon.
Hi, Paul. Welcome back.
Welcome back, Paul.
Thank you. Thank you, Jeff. Two questions, if I may. One, Greg or Jeff, on the IMO branding to the very low sulfur fuel oil. From Phillips' standpoint, are you guys going to use the VGO as the primary ingredient, or that you're trying to brand a high sulfur fuel oil?
One of the challenges with the industry is that this is really kind of a refinery by refinery evaluation. I think as we look, we've got a number of different alternatives, where as you know, a high diesel yield portfolio within refining. We've got another 25,000 bbl a day of diesel coming from projects that are underway. Those projects were justified with economics that didn't include IMO, but they will benefit from wider distillate cracks in an IMO environment. There's definitely a diesel component to the way that we're approaching marine fuels. I think as we look at the VGO component, we see that as being challenging. Really what you're looking for are heavy barrels resid or diesel barrels that are low in sulfur. The naphtha and light barrels don't perform well in marine engines.
The challenge is that most of your heavy molecules also tend to be sour, and most of your light naphtha-based tend to be sweet. You're really looking for specific flows of VGO that might make sense in the marine fuel market. I think those are tough to identify.
Right. I presume you guys have looked at the patent out there by Exxon and Shell, and I assume that you guys believe you will be able to brand around that and not infringing their patents?
We have no intention of infringing anyone's patents. We're looking at our own blends, and we will be able to participate in that market, and our commercial people are open for business there.
A final one from me. Greg, on CPC with Qatar, that joint venture, I assume that would mean the CPC own Gulf Coast second ethane cracker, why not probably on the whole replaced by that. Is that a strategic shift in the CPC? That's how going forward in terms of the expansion going to look like or this is really just a one-off deal?
If you're talking about the strategic partnership with Qatar on the Gulf Coast cracker-
Yes. I'm sorry. Yes.
I think it was an opportunity to do two projects. By partnering with a great partner that we've had a long relationship with, we're able to reduce risk, right? To share in two projects versus doing one. We like the balance of risk from that investment opportunity that was given to us. Rather than picking one or the other, we found a way to do them both.
Manav Gupta from Credit Suisse. Please go ahead. Your line is open.
Yeah. Hey, guys. A quick question. I want to focus on the Gulf Coast, and specifically the capture on the Gulf Coast. You showed a higher capture quarter-over-quarter on the Gulf Coast. I'm trying to understand what were the drivers of the higher capture, as well as if you could talk about how much of a role did Bayou Bridge actually play in that higher capture quarter-over-quarter on the Gulf Coast?
As we look at 1Q to 2Q, we did have a fair amount of maintenance activity in the Gulf Coast in the 1Q with Lake Charles and Sweeney being down for turnarounds. That impacted capture rates. I think with product pricing, clean product pricing, we saw improvement in the second quarter relative to 1Q as well. As we look at Bayou Bridge, it connects or extends the DAPL pipeline into Beaumont, and our facility's there. Bayou Bridge brings barrels up from Beaumont into Lake Charles. It gets access to Lake Charles of domestic and Canadian barrels that are easily accessible by pipeline, and we do see a benefit there from a Lake Charles refining profitability perspective.
We've completed the expansion of Bayou Bridge from Lake Charles to St. James, which also opens up the ACE project that we've talked about, which would connect St. James to Clovelly, and then into our Alliance refinery as well. We're looking forward to trying to keep that project moving forward as well.
Manav, it's Kevin. The big driver in terms of the capture quarter-over-quarter was the turnaround activity in Q1. A fair amount of activity across the Gulf Coast system in Q1 that you didn't see to near the same extent in the second quarter.
Perfect. A quick follow-up is that I think Suncor made some comments that Wood River could have done even better, but because of flooding, there were pipeline outages and other problems. I'm just trying to understand if there is a number in terms of that you can give us as to how much better Wood River could have done had those flooding issues not happened.
Yeah. That's a true statement. Wood River was impacted by flooding in the quarter, but that's not something we're going to give a sort of what if type number around.
Justin Jenkins from Raymond James, please go ahead. Your line is open.
Great. Thanks. Morning, everyone. I guess I want to start going back to Doug's question on maybe midstream risks, and even beyond whatever might happen on commodity prices. It does seem like it's become harder to build pipelines. Maybe just want a sense of your comfort level with the routing plans specifically for Red Oak and Liberty, and maybe how you might address any potential construction issues if there are any.
I think certainly there's been many pipelines constructed without an issue. I think that you get out early, and you work with all constituents along the route. You pick the best route to go there. That's what our company does. We'll be obviously executing on Liberty Pipeline. We'll actually be executing on Red Oak in terms of construction. On Gray Oak, I think that the guys doing that did a great job in terms of we're 80% pipes in the ground. We've really had no major issues there along that right of way. We're expecting that these will be executed well. We'll deal with the issues, if they come up, when they come up.
I think part of it's just living our values every day and working with safety, honor, and commitment in mind with all the folks and all constituents along the right of way areas. We believe we'll get it done.
Understood. Appreciate that, Greg. Follow-up here is on PSXP here with the IDR issue resolved. Does this change anything in terms of maybe the scope of organic growth that PSXP can pursue, or maybe how you're thinking about drop-downs? Is this just the next step in the evolution here?
I think it's just the next step in the evolution of the MLP. Thinking back over the past 18 months, I don't think I've had a conversation with investors when they haven't encouraged us to do something with the IDRs. Just from a simplification standpoint, structure, cost of capital, et cetera, even though we haven't gone to the equity market since 2017, if you think about for an LP investor, if we do a 10% return project at PSXP, they're effectively getting a 5% return. It does impact cost of capital, even organic for our LP unit holders. We just need to restructure that. We're trading at a 6%-7% yield, and that's kind of 15x multiple into the sum of the parts at PSX. We're going to be incented to grow the master limited partnership to the extent that it can.
As you can see, we're executing essentially $1.3 billion worth of projects today, and this year. Of course, with the project financing, that gets cut down towards $700 million-ish in terms of cash out the door. Still, we'll put as much growth as we can into PSXP as long as it makes sense, and the multiples would incent us to do that.
Matthew Blair from Tudor, Pickering Holt, please go ahead. Your line is open.
Hey, Greg. Your chems business outperformed peers in Q2. What do you think the drivers were behind that? Also, could you share your near-term outlook for U.S. ethane and PE prices, just given all the new fracs, crackers, and PE plans on deck?
Well, I think that you kind of look at CPChem's portfolio if you want to think about performance relative to the peers. Assets primarily in the Middle East and in the U.S., assets that are primarily LPG or ethane-based. Those margins have certainly been very good relative to, say, naphtha crackers in Asia or Europe. CPChem ran well, certainly during the quarter. That always helps. On ethane, I can't give you a forecast on the pricing for ethane because it'll be wrong. What I would say is we still think there's 600,000, 700,000 bbl a day of ethane rejection today. We've got a 1.4 million barrels a day of frac capacity coming on this year, next year. There will be more ethane available.
You also have some projects in startup mode, although some of them are probably slower than what people thought. We'll just have to put all that together. Our view is that ethane is going to be available out into the next few years, that ethane is going to be attractively priced relative to the heavier feeds globally, and that the Middle East and the U.S. Gulf Coast assets will be very competitive on the global stage.
Sounds good. IHS shows CPChem as net long U.S. ethylene by about 600 KT. Could you talk about what you do with your excess ethylene today? Is that sold on a contract basis into the domestic market or exported on a spot basis? Would you consider any sort of ethylene derivative projects to reduce that net length?
Yeah. We have one of the smaller ethylene units at Sweeney shut down today. We get kind of the mid-90s on operates. Our intent would be to bring that unit back up at the appropriate time. Certainly, CPChem has debottleneck opportunities to take care of some of that length out in the future, and they have plans on deck to make investments and in terms of debottleneck. Around that olefins, polyolefins, alpha olefins chain that CPChem has today. We don't look at the length as a big issue. There are some spot sales or contractual sales, I should say, in the ethylene business from CPChem. Primarily our strategy has been to pair the derivatives with the ethylene capacity over the long term.
Jason Gabelman from Cowen, please go ahead. Your line is open.
Yeah. Hey. Thanks for taking the question. It looked like equity affiliate distribution cash was a drag on the quarter or a bit lower at least than we had anticipated. Was there any timing issues there on the distributions from the affiliates in 2Q?
Yeah, Jason, it's Kevin. Really not. I mean, the equity earnings were $640 million, $648 million. The distributions were just over $500 million. That's not too far off of what you would normally expect. I mean, generally speaking, you would expect the distributions to be a little bit less than the equity earnings, given that those equity affiliates have CapEx, their own capital programs to fund as well. I don't think there's anything significant there. I think it was a little bit different. I think you had some disproportionate distributions in the first quarter that had that go the other way. When we look at this on a year-to-date basis, it's all very reasonable from how we look at the cash flow.
Thank you. We have now reached the time limit available for questions. I will now turn the call back over to Jeff.
Thank you, Julie. Would like to remind you again, put November 6th on your calendars, Analyst and Investor Day in New York City. With that, we thank you for your interest in Phillips 66. Brent and I would be happy to answer any follow-up questions you have. Thank you.