Plains GP Holdings LP (PAGP) 2018 Q2 法說會逐字稿

Good day, and welcome to the PAA and PAGP Second Quarter 2018 Earnings Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Roy Lamoreaux. Please go ahead, sir.

Thank you, Anna. Good afternoon, and welcome to Plains All American Pipeline's Second Quarter 2018 Earnings Conference Call. The slide presentation for today's call can be found within the Investor Relations News & Events section of our website at plainsallamerican.com. During our call, we'll provide forward-looking comments on PAA's outlook. Important factors that could cause actual results to differ materially are included in our latest filings with the SEC.

Today's presentation will also include references to non-GAAP financial measures, such as adjusted EBITDA. A reconciliation of these non-GAAP financial measures to the most comparable GAAP financial measures can be found within the Investor Relations Financial Information section of our website.

We do not intend to cover PAGP's results separately from PAA since PAGP's results directly correspond to PAA's performance. Instead, we've included schedules in the appendix of our slide presentation that contain PAGP-specific information. Please see PAGP's quarterly and annual filings with the SEC for PAGP's consolidated results.

Today's call will be hosted by Willie Chiang, Executive Vice President and Chief Operating Officer, and Al Swanson, Executive Vice President and Chief Financial Officer. Additionally, Greg Armstrong, Chairman and CEO, Harry Pefanis, President and Chief Commercial Officer, and several other members of our senior management team are present and available for the Q&A portion of today's call.

With that, I will now turn the call over to Willie.

Thanks, Roy. Good afternoon to everyone, and thank you for joining our call. Let me start by hitting the high points of the information we released today. This afternoon, PAA reported second quarter fee-based segment adjusted EBITDA of $531 million and total adjusted EBITDA of $506 million. Our results exceeded expectations and as highlighted on Slide 3, we increased our 2018 adjusted EBITDA guidance by $100 million to plus or minus $2.4 billion.

Common unit distribution coverage was 123% for the quarter, 163% for the first half of 2018, and based on our updated guidance is projected to be 179% for the full year of 2018. Furthermore, as we will explain in more detail during today's call, we're on target with our leverage reduction plan and we have added additional projects to our 2018 and 2019 capital program. Relative to our increased 2018 guidance, we reiterate our 14% to 15% fee-based adjusted EBITDA growth in 2019 and would also like to note that we currently expect adjusted EBITDA from our supply and logistics segment to likely show year-over-year increases in 2019. We will discuss our outlook in more detail on our next earnings call in November.

With respect to the Permian Basin volume growth, although time lag associated with producer reporting of completion data always makes it challenging to pinpoint month-to-month production estimates, we can see that producer activity levels are high and volumes are certainly ramping up. We continue to expect Permian production growth to be in line with our yearend exit rate forecast of plus or minus 3.5 million barrels a day.

As shown on Slide 4, we continue to deliver meaningful Permian Basin transportation segment volume growth. Our second quarter Permian tariff volumes grew by nearly 500,000 barrels a day or 15% relative to the first quarter of 2018. We expect continued growth across our gathering and intrabasin pipeline systems and to operate at or near capacity on our takeaway pipelines throughout the second half of the year, resulting in our expected average 2018 tariff volumes of 3.8 million barrels a day for the year.

Activity levels in other major production regions remain generally in line with our expectations and our assets are well positioned to benefit from volume growth in these areas. We continue to make good progress on our capital program and we expect to place multiple gathering and intrabasin debottlenecking projects as well as terminalling and storage expansions into service throughout the second half of 2018 and the first quarter of 2019.

Additionally, as mentioned, we've increased our 2018/2019 capital primarily due to strong demand for additional Permian infrastructure. The majority of the incremental capital represents a combination of several dozen small to medium sized Permian related projects that are expected to provide attractive economic returns. Al will discuss the updated capital detail in his section. Let me just say that we're very pleased with the progress our team is making to commercialize projects, bring them into service, and as we are able, to expedite project completions.

And now just a few examples. In June we completed a 200,000 barrel a day pump expansion on our Wink to Midland pipeline system which supports additional volume pull through on our Delaware Basin gathering systems. Other debottlenecking projects we expect to be placed into service in the third quarter include a 50,000 barrel a day pump expansion on our Advantage joint venture pipeline and a 135,000 barrel a day pump expansion from Crane to McCamey. By year end, we also expect to place into partial service our 670,000 barrels a day of new pipeline capacity from Wink to McCamey, which is going to be a key component of our Cactus II pipeline. These and several other projects are highlighted in the appendix of our slide presentation.

We've also been very focused on executing on our Permian long-haul takeaway projects. Each project has its own distinct critical path challenges including several timing related factors such as securing permits and right of way, material deliveries and electrical service to power our pumps. Overall, we remain on track to ahead of schedule with the construction of our phase 1 and phase 2 expansions of the Sunrise system and with Cactus II.

As announced previously, we had targeted in-service dates for these 2 projects of no later than January 2019 for Sunrise and partial service early Q4 2020 for Cactus II. 2019 for Cactus II. As you can imagine, given higher shipper demand and commercial opportunities currently present in the Permian Basin, we're trying to accelerate both of these projects in as much as reasonably practical including incurring additional costs to expedite material deliveries and vendor services and even install temporary generators for our pumps until permanent utility power is available.

Such efforts should allow us to place the Sunrise expansion project into partial service in the fourth quarter of this year. On Cactus II, we can confirm that our JV partners have exercised and closed on their option to participate in the project and that PAA now owns 65% of Cactus II which is consistent with the ownership level we had assumed in our previous guidance.

Additionally, we received one of our permits faster than previously anticipated and we now believe that we will be able to begin partial service to the line late third quarter 2019. Full service is still targeted for April of 2020.

These two projects are a great illustration of one of our longstanding strategies to optimize our value chain which really allows us to have capital efficiency, pull through economic benefits, and the ability to put capacity into service sooner. We're also developing a number of similar opportunities to further optimize existing capacity. First, we're looking at options to increase takeaway capacity out of Cushing by expanding capacity on existing pipelines as well as a number of projects that we're developing in Canada that would increase gathering into our existing systems, specifically to take advantage of capacity on the Rainbow pipeline system or the developing plays in Western Canada and a project with potential to bring new volumes onto to Wascana pipeline system. These projects are in the early phases of development and would likely take 12 to 24 months to bring into service.

Moving on, I'll share a few comments related to the letter of intent or LOI we executed in June with Exxon Mobil for the construction of a new large diameter Permian takeaway pipeline project. We're working closely with Exxon Mobil on necessary activities to support the development including survey work, finalizing route selection, engineering, cost estimates, sourcing of long lead items, and finalization of project and commercial agreements including the formation of our joint venture. This is a very key project for Permian Basin crude takeaway and we're pleased to have been selected to work with Exxon Mobil. As shown on Slide 5, we expect the project to be designed to ship over 1 million barrels a day with origination points at Wink and Midland and delivery points in the Houston area. We expect PAA's equity participation in the joint venture to be meaningful, but well less than 50% and the majority of the capital investment to occur in 2020 with EBITDA contributions beginning in 2021. We look forward to sharing additional updates as the project continues to advance.

Before I turn the call over to Al, I'd like to make a quick comment on steel tariffs. In July, we were notified that the US Department of Commerce denied our request for exclusion from steel tariffs for the Cactus II line pipe we ordered in December of 2017. The denial was made without prejudice to our ability to refile for the exclusion which we intend to do. If we are ultimately unsuccessful in our efforts to obtain an exclusion, the Cactus II JV will be forced to bear an approximate $40 million tariff on the Cactus II pipeline we ordered -- the pipeline steel that we ordered from Greece well before the tariffs were put in place. We're moving forward with the project but believe that imposing a tax on preexisting orders is unjust, especially considering specific materials we purchased abroad were not readily available in the US. We will continue to advocate this position actively, recommending ways in which the Section 232 process can be improved and warning of the potential impacts of absolute quotas in an effort to ensure that we and others can receive the materials necessary to continue to support the US energy production growth and job growth.

With that, I'll turn the call over to Al.

Thanks, Willie. During my portion of the call, I will provide a recap of our second quarter results and discuss a few updates to our forward guidance, deleveraging plan and capital program. And I'll also comment on our working capital deficit at June 30.

As shown on Slide 6, for the second quarter we reported fee-based segment adjusted EBITDA of $531 million, reflecting year-over-year fee-based growth of $53 million or 11% and approximately $81 million or 18% after adjusting for asset sales. Year-over-year transportation segment adjusted EBITDA growth of $62 million was driven primarily by Permian tariff volume growth of more than 970,000 barrels per day or 35%, while a decrease in facility segment adjusted EBITDA was primarily due to asset sales.

Second quarter fee-based adjusted EBITDA increased $11 million over the first quarter 2018 driven by a $25 million increase in our transportation segment, principally as a result of an approximate 500,000 barrels per day of increase in Permian tariff volumes. The facility segment decreased by approximately $14 million due to a combination of nonroutine and timing related operating expenses and the impact of an asset sale.

As Willie mentioned and as shown on Slide 7, we have increased our 2018 adjusted EBITDA guidance by $100 million to plus or minus $2.4 billion. This increase is based on actual first half 2018 results as well as our outlook for the second half of the year.

The supply and logistics segment accounts for $75 million of the increase and includes some benefit from the wider Permian and Canadian crude oil differentials. Guidance for our fee-based segments was increased $25 million and we reiterated our preliminary 2019 outlook that fee-based adjusted EBITDA would grow approximately 14% to 15% over our 2018 fee-based guidance.

We also indicated that 2019 adjusted EBITDA from our supply and logistics segment would likely outperform the revised 2018 guidance for this segment. We will provide additional information on our preliminary 2019 guidance on our November 2018 earnings call.

Let me now move onto discuss our deleveraging plan and our updated 2018/2019 growth capital program as summarized on Slides 8 and 9. First and foremost, PAA remains committed to our financing strategy and returning to our targeted credit metrics within the first half of 2019. As noted on Slide 8, at June 30, 2018, PAA had a long-term debt to adjusted EBITDA ratio of 4x and a total debt to adjusted EBITDA ratio of 4.5x. These, along with other capitalization and liquidity metrics, are also reflected on Appendix Slide 13. Since the announcement of our deleveraging plan in August of last year, we have reduced debt by more than $1.2 billion and reduced the leverage metrics I just mentioned by a full turn. We are pleased with our progress to date and also pleased that S&P today recognized the progress by changing our outlook from negative to stable.

We expect total debt to remain near current levels with variations primarily associated with timing of asset sales, execution of our capital program and margin variations associated with our hedge positions.

As Willie mentioned and as shown on Slide 9, we have increased our 2018/2019 growth capital program by $650 million which brings the combined 2-year program to $2.6 billion. The majority of this increase is expected to occur in 2018, the largest portion of which is attributable to new projects primarily related to Permian gathering, intrabasin and terminalling and storage expansions. The balance of the increased 2018 capital reflects a combination of acceleration of certain 2019 projects forward into 2018 as well as increased costs on certain projects such as the imposition of steel tariffs on Cactus II, higher right of way costs and incremental costs associated with the project accelerations.

We continue to expect the capital program to be principally funded with retained cash flow and asset sales. Thus far in 2018, we have received $426 million in sales proceeds and expect to receive an additional $34 million of payments with the passage of time and completion of performance conditions. Additionally, we continue to advance efforts on other asset sales opportunities which may enable us to exceed the targeted sales levels.

Shifting gears a little, our working capital deficit at June 30 is approximately $600 million above what we would consider normal levels. The vast majority of this increase relates to short term liabilities of approximately $460 million associated with derivatives used for hedging and a gift which we posted $426 million of cash margin. The majority of these hedges roll off by yearend and will not require the use of cash resources or debt to fund, as the incremental cash from the underlying physical business transactions will be used to settle the derivatives and liquidate the short-term debt incurred to post the margin.

One last item I wanted to comment on, our depreciation and amortization expense for the quarter was $49 million. This reduced amount includes net gains of $81 million on asset sales.

With that, I'll turn the call back over to Willie.

Thanks, Al. As you can see, it's been an active and productive time for the partnership. As discussed today and as shown on Slide 10, we're pleased to have made meaningful progress towards each of our 2018 goals. We've got some great new projects that we've sanctioned and we look forward to the benefits they'll bring to our company in 2019 and beyond. The highlights of today's call are shown on Slide 11. I do want to take a moment to acknowledge and thank our entire PAA team for their hard work to position us to deliver our 2018 plan and for future growth. We also appreciate your continued interest and investment. With that, I'll turn that call back over to Roy for a few quick comments before we open up the call for questions.

Thanks, Willie. We have included some additional reference materials in the appendix of today's presentation. (Operator Instructions). Additionally, Brett Magill and I plan to be available this evening and tomorrow morning to address additional questions. Anna, we're now ready to open the call for questions.

(Operator Instructions). We'll now take our first question from Shneur Gershuni from UBS.

Maybe I was wondering if we can start off with the CapEx increase that you talked about. I was wondering if we can get a little bit more detail around it. At the Analyst Day, you had talked about a Cactus III expansion and a Wichita Falls expansion as well too. Any updates on the potential FID on those projects as well as what's making up the CapEx revision for 2018?

Sure, Shneur, this is Willie. I would characterize the $650 million as $550 million -- predominantly all Permian projects. But $550 million of it is really associated with gathering, intrabasin and lot of the projects deep in the Delaware Basin. There is $100 million of increased costs and that captures some of the additional tariffs, the $40 million I talked about as well as some increased right of way costs and generally a more competitive market out there as we look for labor and support for some of our projects. The projects that you mentioned specifically on Cactus III is not included in that, nor is the looping of the line from Wichita Falls to Cushing. Those are some of the projects that we continue to develop.

Fair enough. And just a quick question on transportation. The margins were a little thin in transportation, kind of down from 1Q, but you kind of maintained the guidance for the full year. Is this a function of lower tariff volume coming onto your system? Or is it cost related? And are these the temporary issues that you talked about that would be fixed by bottlenecks? I'm just trying to -- any color around kind of the transportation and margins if you will.

Shneur, I'll take a shot at it. No, I mean we are seeing maybe just a little bit higher power costs, some generators. But a penny or two movement in our unit margins probably have as much to do with kind of the business mix of where we're seeing barrels. But no, there is no kind of major shift or major change. The transportation segment was in line with second quarter, but we expected actually slightly above. And we haven't seen anything that would cause us to change the outlook for the year.

Great. One final conformation. Al, in your review of the balance sheet and everything else, did you confirm whether you'll need equity or not to fund any of this, or you're able to fund it all internally for this year?

Yeah, we don't view that we need to raise equity to fund any of the capital we're talking about. If for some reason that changed, we wouldn't be looking at common equity, we would be looking at a preferred security. But we don't expect to need to do that.

We'll now take our next question from Jeremy Tonet with JPMorgan.

I was just curious on the S&L side if you could expand a bit more what you're seeing in the market and what has driven that kind of the higher estimate as far as S&L expectations for the year since a good portion of capacity was hedged it seemed like in the past. So what has changed that gives you that bit of more upside this year and in 2019? And then just curious on the fee-based side, the CapEx went up a bit there, but the 14% to 15% guidance for next year step up is unchanged. Is there kind of a delay when that CapEx starts contributing to EBITDA? Or any other kind of moving pieces there?

Harry, you want to take the S&L piece?

Sure. The S&L is really a combination of a couple of different factors. First of all, we've had much better performance in Canada with respect to some of the differentials, both with crude and to the lesser extent NGLs. And then looking forward to the end of the year, remember earlier we said we were more hedged early in the year than later in the year. As we saw, when we came into this year, we thought by the end of the year we would see probably a greater likelihood of tightness in the markets, takeaway markets out of the Permian. So those are really the drivers of the higher performance in the S&L.

Jeremy, on the CapEx number, the 14% to 15% increase, it's over the new fee-based number for 2018. And of course, we'll give better guidance on that in November as we think about 2019. But the new fee-based number for this year is 2.25, so 19 would be an appropriate uplift of 14% to 15% on that new number.

That's helpful, thanks. And I just wanted to go back to Sunrise. It seems like that could come on a little bit earlier as you were saying. So I didn't know if you could kind of frame that a little bit more as far as what hat could look like. And also, I just wanted to build on what you said at the Analyst Day as far as well there's 500 into Wichita Falls, it seems like there's only a further 220 egress thereafter out of the basin. And so that 280 balance, have you guys found other opportunities to capitalize on that capacity? I think a competitor earlier in the day was talking about looking to do something like that, so I was just wondering in-house if you guys had any other thoughts there.

I'll make a few comments and maybe Harry can jump in. This is Willie again. I want to give you a little bit on the degree of difficulty on Sunrise. We're building this section and there's really 2 sections, one from Midland to Colorado City, Colorado City to Wichita Falls. You've got a lot of pieces that have to come together in a very tight labor market to get this done. We're always said January 1. We've been pleased we've been able to get a little bit ahead of schedule. One of the critical paths on this project is power availability. So what our plan is, is actually to start the system up on generators before permanent power is hooked up which gives us the ability to start it up a bit earlier than we originally had thought. So I don't have a firm number for you on the exact date we will be starting up, but it will be in the fourth quarter and there will be a normal ramp up as we start up again. We'll have 10 generators, roughly 10 or 11 generators for the system. So again, it's not an easy task to get this started up to full rates, but you should expect something, we expect something in the fourth quarter.

On the capacity issue, kind of reiterating what we said at our Investor Day presentations, we looped the line 500,000 barrels a day capacity into Wichita Falls. It provides sort of the ability to expand to either Cushing or to markets east longer term. On a nearer term basis, the 220 is 120 that was subject to open season going to Cushing, taking advantage of available capacity on the basin pipeline system and then Bolero has 100,000 barrels a day of capacity. So the incremental volume, I mean in the short term that's basically what we get paid to do is try and find some incremental homes for that volume. It's probably not a long-term solution, but it's what we'll be punching on here in the short term to see if we can take advantage of some of that capacity.

So from the end there, above the 220, could it be kind of trucked to other local refineries there? Or just kind of that's it for now until you get another leg of capacity expansion from Wichita Falls into Cushing, that's really the only way to really maximize or take advantage of that 280?

There's some connecting pipelines in Wichita Falls. To the extent that there's windows to put some capacity in some of those pipelines, I mean that's probably more realistic than trucking it out of there. There's not really anything close out of Wichita Falls that would lend itself to some easy trucking economics. You could truck it out of there, I'm just saying it's not an easy job.

We'll now take a question from Tom Abrams with Morgan Stanley

A couple of questions. One, in the transmission segment, just looking at what you call as Gulf Coast and Canada declining for several quarters, what makes those things arrest those declines and maybe grow again? That's the first question.

On the Gulf Coast, it's principally been a combination of asset sales or volumes coming off of Capline with the Diamond, the Diamond going into service. So none of those were really surprising. Basically, kind of as expected. And the other one, Tom, was Canada?

Yes.

Canada is, a large part of Canada is driven by the curtailment on the mainline pipes. So as the mainline pipes are curtailed, that pushes back into some of the feeder pipes and that's what's driven some of the declines on that in Canada.

And what I would say is if you're looking at kind of the year-over-year on second quarter, the majority of that is actually volume off of Wascana as DAPL went into service. That's the project that we talked about in our Investor Day of a potential reversal. So actually a substantial amount of that came off. It wasn't the nature of declines, just the changing market.

Thanks for that reminder. I wanted to ask also, in the S&L, as you think about your guidance evolving during the year, what precisely is changing? Is it just more capacity available? Or people dropping off FT and making some things available to you or just what's happening there?

Basically, what I mentioned a few minutes ago. The wider Canadian difs, a little better margins on the NGLs and not as heavily hedged in the latter part of the year as we were in the first part of the year.

So what's the surprise there then? I mean you knew the capacity was available, so it must be the difs then widening?

Wider Canadian difs, better NGL margins and yes, the WTI Midland difs are wider than they were earlier in the year.

Okay. Then I wanted to ask about the Red River utilization, where's that now out of Cushing?

We don't have an exact number for you, Tom, on that.

About 140,000 barrels a day I think is total volumes. Not all of that is to our interest though, okay? So that's total volumes on the Red River pipe. Bolero has part of that interest as well.

We'll now take a question from Michael Blum from Wells Fargo.

I think most of my questions were addressed. But one question I wanted to ask was just on this proposed Exxon JV pipeline. Can you just kind of walk through what you see as kind of the differentiating factor that would cause this pipeline to kind of get it, reach FID? As I'm sure you know, there are tons and tons of pipelines vying to get FID. So I just wanted to try to understand where the differentiation is for you guys. Thanks.

Michael, this is Willie. I'll make a couple of comments and maybe others, Chris Chandler can comment on it. When you think about this line, it's speaking a little bit on behalf of Exxon Mobil, you've got their production, their equity production in the Permian Basin, significant amount of refining capacity in the Gulf Coast. So essentially, you've got a sponsor of the project that's got the need to move barrels and a lot of barrels. So that by itself sets the economic basis for a larger line. You combine with that our ability to aggregate in a system that we've built in the Permian and particularly around the Delaware Basin, it's really just a good fit as far as aggregating volumes, being able to get it to points. And then you've got a large volume that you can work with to bring it to the Gulf Coast which should make us more competitive than others. So I think at the end of the day, you're going to have a lot of volumes that will be committed to it and a very cost effective pipe with certainty of needing to get it from A to B.

Yeah, Willie, this is Chris Chandler. The only thing I would add is, remember Exxon has refineries the receiving end that will have significant demand pull for the pipeline. So yeah, the production feeding the pipe, the refineries taking the production at the receiving end, and a large pipe that brings a lot of economies of scale.

And a large global -- Michael, the other thing is they've got a large global footprint as well. So when you think about volumes that could flow, you've got not only the refining capacity they've got in the Gulf Coast, but you also have access to additional markets.

We'll now take a question from Tristan Richardson from SunTrust

Just you talked about evaluating projects to expand egress capacity out of Cushing. Is there any of that in the 2018 and 2019 budget? And if not, just sort of generally the capacity size or options you're reviewing there?

None of it's in the plans for next year. Sunrise, I mean not Sunrise, Red River is probably the magnitude of 100,000 barrels a day. Diamond could probably be expanded up to 200,000 barrels a day. We've got a little bit of capacity on our Midway pipeline system as well. So that's sort of the magnitude of the expansions that could be potentially developed out of Cushing.

That's helpful, thanks. And then just sort of the latest update on Capline after the sort of nonbinding solicitation that was launched last fall.

It's still a developing process with the owners. There's a lot of interest on the owners to have an alternative movement out of, on the Capline system, but there are 3 owners and it does take a little while to work through the project.

We'll now take a question from Dennis Coleman from BofA Merrill Lynch.

I'd just like to start if I can just back on the I guess it's $550 million of incremental CapEx that's not tied to the tariffs or rising costs. The project, how much of this is -- I guess what I'm trying to get at is to some questions that have already been asked, but how much of this has been pulled forward and how much is new projects did you say?

There's roughly -- again, $550 million is new projects. We've got $100 million that's kind of a slight change in scope, combination increased tariffs. We've pulled $100 million from 2019 into 2018. So there are definitely some costs in accelerating some of the projects. But again, everything is around gathering, intrabasin and more efficiency around the takeaway out of the Delaware Basin.

Okay so it's $550 million that are brand new, okay. So that -- these are projects that are likely to be completed that will roll into the 14% or 15% upside to the fee-based EBITDA that you talked about?

Yes. So every project will have a different startup ramp, but yes, these are all projects that I'll call shorter term in nature with the except for the Exxon Mobil project that we talked about that will be multiyear.

Okay, thanks for that. Then on the Sunrise early startup with generators, I gather that will be at the higher cost option but with the bottlenecks. Is that something, a cost that you can push through to shippers?

No it's all tariff based. That was under an open season process as well. So those tariffs are set.

I see. Okay, then shifting, not to confuse tariffs and tariffs, but the $40 million tariff that you'll pay on the Cactus pipe, I'm just thinking as you look at the Exxon Mobile project and think about where you would source steel for that, obviously a lot of projects going on. Is there -- are you concerned about the ability to source steel in the US for that kind of project or is there capacity constraint there?

Dennis, this is Willie. The type of steel that you select for different size lines can be different. The point we were making, I actually had the opportunity to testify in front of the House Ways & Means Committee, was the whole issue around the tariffs, particularly in our case which was retroactive, we felt was unjust. And going through the process with the Department of Commerce on an exclusion process needs more transparency. So it was really around warning the -- warning against the ramifications of a non-transparent process as far as exclusions, retroactivity which impacts the sanctity of business decisions you make when you sanction a project. And then certainly one of the last things that's a significant piece is if we end up going with quotas, the difficulty of that on how you set your benchmark and whether or not you can even meet a quote or bring any steel into the United States. But if you don't get all of your steel, it's the example of a bridge that's 80%, 85% done, it's 0% effective. So quotas, tariffs, all could have significant ramifications on not only our company but just the entire industry on the buildout of the energy industry which has been so successful over the last number of years.

Willie, if I might, this is Greg. I would just add, I think if I understood your question correctly, do we have concerns about whether or not we would be able to source domestic products. And the answer is we don't. In the case of the Cactus II, we were looking for a specific type of steel and specifications that generally weren't available in the US. And so we went to an outside supplier. Our goal is always to try to buy domestic, buy American. We just weren't able to do it in that case to meet our timelines. With respect to the type of steel and the size specifications for the Exxon Mobile pipeline, we feel like we'll be able to get that domestically and so it shouldn't raise an issue there as the same issue doesn't come up.

Okay, so it's size, but it's quality as well? I mean it's the same, basically the same crudes that you're putting in it, right?

No, no, I was talking about quality of steel. So for example, we were able to get 75-foot joints basically on the 26-inch that we bought. And that could be manufactured in Greece. That eliminates or cuts by probably a third the number of wells that we have to do. And when you talk about issues with respect to integrity management and corrosion management, that was a big issue on that. When you get into some of the larger diameter pipes that are available here, kind of off the shelf, we don't have the same issue. So I didn't want to get into the real details of the engineering specifications, but there was distinct difference between what we could get in a 26-inch pipe, 75-foot joints on the particular specifications versus what we would do for a larger diameter pipe that's readily made here in the US.

There's also welding differences and a number of other specification differences that are taken into consideration. We've got the mills on advance, so a lot of things that go into the decision.

We'll now take a question from Christine Cho from Barclays.

I just want to start with the Sunrise expansion. Do the contracts with the customers for the expansion start when it goes into partial service later this year? Or do the contracts with customers still start up at the beginning of next year?

The contracts start when -- there's some flexibility there, but I'm sure the contracting customers will want to take advantage of the space when it's available.

Is any of the S&L -- I'm sorry?

I said I would feel pretty confident that they would want to take advantage of the space as it's available.

Okay, so they have an option to take it and none of the S&L increase for this year is driven by the acceleration of this pipeline being put into service?

Correct.

Okay. Then you -- should we assume that the pipeline with Exxon will be 50/50? Or do you expect to get more partners for this?

So Christine, we certainly haven't finalized that. In my comments, our portion I said would be meaningfully less than 50% just to give you a flavor of how much CapEx that we would be looking at. But that decision is yet to be made and there will be more partners, more than just Exxon.

Okay. Then lastly, you have a competitor talking about building a pipe from Cushing to St. James. Does that change how you and your partners view the potential or timing for reversing Capline and extending Diamond?

Let me just say this. I think it's a fair statement that a reversal of pipeline and expanding the capacity on existing pipeline can be done faster, cheaper and better than building a brand new one.

We'll now take a question from Jean Ann Salisbury from Bernstein.

You mentioned during your Investor Day that you expected the Corpus Christie export capacity to lag Cactus II startup and that was why it was in phases. Can you give a little bit more detail about what's involved in the Corpus export capacity? And is this a problem that you expect all the new pipes to Corpus to have, so that you might see a pretty big headline number start next year but it can't actually go anywhere?

I think there are 2 issues here. First of all, our pipe goes into Ingleside then crosses over to Corpus. So we think coming into Ingleside we'll be in service faster than the leg back into Corpus. So that's a part of the reason. And then second, yes, there is dock expansions that are in progress for some of the pipeline expansions too and it seems like the pipes are probably a little faster paced than the docks.

That makes sense. Then it seems like you need maybe a slight year on year S&L step-up to meet your new CapEx budget and your leverage metrics for next year. I was just wondering if you have hedged or otherwise locked any of 2019 in or is your estimate kind of based on where the forward curve is at today?

I'd say it's a combination. I mean clearly, we're a company that hedges when it makes sense. There are in some cases issues that you don't want to hedge and then find out you don't have the commercial or the physical capability to follow through. So there's a balance. But we felt comfortable enough making the statement that we expect year-over-year 2019 to be greater than 2018 and we just increased 2018.

We'll now take a question from Colton Bean with Tudor Pickering Holt & Company.

On the updated facilities guidance, is that just a flow through of the improved base operations? Or are there any read-throughs there to divestiture timing?

None on the latter. Nothing to do with divestitures. We've just seen a little better performance across several --

Better activity at a number of the facilities.

More throughput on some of our crude terminals, a little better performance in gas storage, slightly lower operating expenses for the year, although some chatter between quarters.

A little more rail activity forecasted.

A little more rail. So.

I guess just to follow-up on some of the commentary around Canadian crude volumes, you noted the upstream apportionment and then the impact from Wascana. I think last quarter you had talked about some opportunities there to expand cross border capacity and get more volumes onto the western corridor system. Any updates to what you guys are looking at there and maybe expected timing around that?

Those are still projects that we're continuing to advance. I don't think we have any timing updates. Those are projects that are being developed.

Again, that's mostly intended to be line oil moving across border?

Yes. So the western corridor is going to be limited in capacity. It's not going to be, I think we talked about this in Investor Day, it's not going to be a huge quantity, but it will help debottleneck Canadian constraints to some extent.

Go ahead, I didn't mean to interrupt you.

I was just going to ask if that was intended for the existing Rockies refineries there, if you had any capabilities to connect further downstream?

We're connected all the way to Cushing on that, on those pipes. So obviously the Rocky Mountain refineries would have first shot at that crude, but it could move all the way to Cushing.

And Colton, I did mention Wascana and our desires to bring more barrels onto that in our comments.

We'll now take a question from Keith Stanley with Wolfe Research.

I wanted to revisit just the funding plan with higher CapEx. So in the financial commentary you said you expect debt to stay flat at about $9 billion, so no incremental debt funding. Just how do you bridge the cap on the incremental CapEx? And then also any update on other asset sales? Is $700 million still the target or could you do more there?

On our comments, I mean clearly, we believe that the increased capital is going to be funded principally by retained cash flow and our asset sales program. Clearly some of the margin money that we posted will come back to us over the next 2, 3 quarters. And there will be some potential mismatches between quarters, but we feel very comfortable with our funding plan.

Okay, so it still assumes $700 million for the asset sales then?

Yes, we have not updated that target. As I commented in the prepared remarks, I mean we continue to work on different things, and if we're successful, it could go up, but no, we haven't modified that target.

Okay, great. And one thing to clarify from earlier as well. The 14% to 15% fee-based growth, and you indicated it's off the new guidance for 2018, should we think of the incremental CapEx in the new projects, Cactus II coming on a little sooner, as putting upward pressure on this? And kind of the message is you guys are going to update that in the next quarter? Or are there offsets elsewhere to the contribution from some of the new projects?

I think it's fair to say, and somebody asked the question earlier, I mean we're adding a lot of capital, $650 million. But there's a time lag between the time you incur the capital and you get the full runup. So I think most of the uplift from this incremental capital is going to show up maybe it's late 2019, but it's really into 2020. So the message that we were really conveying is that we've raised our fee-based for 2018, we're still holding to a 15% to 14%, 14% to 15% uplift in 2019. And most of that is really coming from a combination of incremental run rate of just carrying through the volume uplift that we're experiencing in 2018 through all of 2019, plus the added contribution from 12 months of Sunrise, Cactus coming on the end of the year. And then we'll be carrying some momentum out of 2019 into 2020 for further uplift just based again off that momentum of the projects that we already have. Plus, these new projects will show visibility into 2020 and beyond

Keith, what we've seen as we've been building projects is the impact of the run rate has been pretty substantial from year to year. If you start a project up certainly in the second half of the year, you've got a significant carry through into the next year.

We'll now take our next question from [Patrick Wayne] from Baird.

Just a quick one for me. Just related to those CapEx pull forward comments, can you elaborate if those decisions are at all reflecting customer tone around potential new activity levels for 2019? Or are they based purely on the current production situation? And then have you heard at all any anticipations for a leveling off in activity?

So Patrick, I'll take a piece of that. On the CapEx pull forward, a lot of these projects that we pulled forward really help the basin evacuate. So it's pulling tanks forward, it's accelerating some projects. As we've been looking at it, certainly the growth early in the year was quicker than we anticipated and I think we shared that with everyone as we talked about it. So we really have pulled a lot because our view of the basin is that continued growth is coming.

we've certainly seen some fluctuation on a specific area, given areas I should say, where somebody has laid down a rig but they picked up something somewhere else. I would say overall the wells are coming in as good or better than what we had modeled them in our type curves. The rig count is higher than what we forecasted. I think we did our forecast off of 415 horizontal rigs and they're running about 440 right now. So we're just building a lot of DUCs. So unless you believe people are drilling wells and putting them in inventory and calling them DUCs and saying we just want to have them on the shelf, ultimately they're going to pull those off the shelf and we need to be ready for them. So part of it is I think they'll start completing it when they know they've got markets. If we give them markets, they'll start completing. We'll make tariff money and they'll make oil production. So overall, I think it's a pretty robust outlook for what's going on. It appears that some of the concerns that we had about perhaps frac spreads being available, that's been addressed. We've actually seen a fairly big ramp up there. Labor continues to be an issue and probably will be for as far as we can see. But again, if you give enough incentive out there, we think you're going to be able to fill the need. So far, we don't want infrastructure to be the gating item on building production volumes out of the Permian. So therefore, by pulling this stuff forward, we've given the producers a chance to get to market. Certainly those that are on our system, where we've got guaranteed takeaway capacity and now we can give them intrabasin transportation efficiency, it just makes all the sense in the world to accelerate.

Patrick, just another data point, we typically have been kind of at a completion crew limit in the basin and from what we've seen and people we've talked to, we've definitely seen an increase in completion crews to the point where there may even be a little bit of surplus in completion crews toady.

We'll now take a question from Chris Sighinolfi with Jefferies

Willie, one clarification question if I could. Appreciate your answer to Jeremy in regard to how Sunrise comes up earlier with the aid of generators, etc. So I was just wondering, for both Sunrise and Cactus, if the earlier in-service would be at advertised capacities or if we should assume any earlier as something diminished relative to what you published in terms of sizing?

Yeah, Chris, I would think about it that way. Clearly, having generators is not the optimal solution, you want permanent power. And the way we've designed our system, the capacity under generators is not as at capacity as if you have regular power. So clearly, we'll probably start up slower and ramp up, but we'll have to see how things go on the generators.

Okay, but you would expect to have regular way power under the time profile you were guiding before? By 1Q for example?

Yes, correct.

Great. Then my follow-up is, in regard to Cushing, I think it was either Greg or Harry at the Analyst Day offered some thoughts about sort of the market hub itself and your positioning there. But we have seen a consistent draining of regional stocks in the weeks since the Investor Day. I realize that we've seen some low levels at Cushing before, but I'm just curious your thoughts on operationally, does it become a problem at a certain point? Do shipper decisions get changed at a certain point? Obviously, you guys might have a different position or you might be operating up there a little differently than peers, but you have a big position, so I'm just curious, operationally at Cushing, anything you could offer us on that front?

Sure, this is Willie again. I'll make a couple of comments and maybe others can jump in. Clearly, I think we're testing the lower limits of Cushing inventories and the ability to operate. It is much more difficult to be ratable at low, low inventories and what's key is if you are -- the more transfers and movements that you have to make, the more difficult it is. So clearly our assets are in kind of what we call the priority, the good area as far as connectivity and the ability to move barrels. So I think it hurts us perhaps less than others. In some cases, I think if you're farther away and you have less flexibility, you may not even be able to move barrels back and forth. But clearly at this level, it is more difficult to move barrels. When you think about Cushing and moving barrels out longer term, you've also got to think in as far as the additional production that may come out of Powder River Basin, DJ and other volumes that go into Cushing. So I think this is a shorter term problem right now. Going forward, I think in a couple, 3 years, it could be a much more different picture.

I would also point out, I mean effectively, once we bring Sunrise on let's say first of the year at full volume, you're going to be sending effectively, directly or indirectly, about 220,000 barrels a day into Cushing that's not currently moving in that direction right now. So I think relief is on the way. I would also just say, and Willie kind of alluded to it, if you put an airplane up there today and you fly over Cushing, you're going to see a lot of tanks sitting down very, very low on the roofs and you're going to see the most oil in Cushing is in our tanks.

Okay. And Greg, does that -- I mean if you're running at low levels there and it's more difficult to move as a result does that sort of raise the cost on activities within the hub? You follow me?

I don't know that it raises the operating cost so much, it just makes the operating complications and coordination become super critical. And there's a chance for third parties to not be able to make their deliveries. Part of it again, we're the operational kind of center of the hub. As Willie said, we probably move disproportionately more crude than anybody else relative to tank capacity. That's because we built the [manifold] system about 20 years ago, hard for me to say that, but a little over 20, that's designed to be able to do simultaneous receipts and deliveries out of just about every pipeline. So I don't know that it raises the costs, but it raises the complications and it can cause some market aberrations and that creates opportunity if you're able to capitalize on it.

Yeah, I think Willie touched on it earlier, ratability is really the key there. Because if you get behind early in the month and you're low on inventories, it's very difficult to catch up.

Yes, typically with more inventory, you can move larger batches. You can do it over a longer period of time. When you get low inventories, just think about you can only pull a little bit out and it just makes the staging of all the volumes very, very difficult.

That's very helpful, guys. I really appreciate it. Willie, I know I'm over my limit, but if I could just ask a clarification question to something you said earlier. Sorry if I missed it, but the Cactus cost increase that stemmed directly from the tariff, the federal tariff on the steel, is there an opportunity to pass that through or do you and the partners eat that cost?

That's the owners' costs.

We'll now take a question from Danilo Juvane with BMO Capital.

I just had one quick follow-up question regarding funding. You mentioned no equity will be needed going forward here, but the possibility for [BRETs]. What would trigger the need to issue BRETs?

Again, we don't foresee the need to, but if for some reason we see other opportunities or we have asset sales that we were counting on that doesn't come to fruition, etc., that would be a fall back. That's fairly consistent with how we've thought of it for say the last year. It is a tool that's still there, there's been several done recently, but we don't expect to need to.

Okay. And there's been some assets in the Permian recently becoming available for sale. What are your thoughts on maybe M&A versus organic growth going forward?

Well, we always look at M&A. We look at a lot of different things. But unless it makes sense and we're buying it at a good value with lots of synergies, that's probably not something we're going to go chase.

Got it. Last question for me has to do with S&L EBITDA gains for the balance of the year. You increased the guidance by $75 million. Should we think of 3Q now as less negative? I think you were guiding to a negative number. Or should we think of 4Q being much more strong than what you initially expected?

We haven't been -- quarterly guidance I think is too, the resolution is too fine on that. So we would just -- I'll stick with the year's guidance.

I think we're going to take -- we're kind of beyond the top of the hour, we're going to take one more analyst question. Then if there are others in the queue, feel free to get on with Brett or me afterwards and we can walk through your questions. But we'll take one more analyst question.

We'll take our final question from Rebecca Followill from U.S. Capital Advisors.

In the facilities segment, the guidance implies that the second half would be down about $20 million to $25 million versus the first half. Is there, is that conservative or is there something else going on?

No, the first quarter was really strong, Rebecca, relative to say the second quarter. And so no. I mean there's some chatter between quarters, but if you look at it relative to second quarter, it's pretty much in line, just slightly down. There was an asset sale that closed during this year, so that is a little bit of it.

Thank you. And then the next question -- go ahead, Willie.

I was also going to say that there is some noise between quarters around timing of operating costs, so that impacts it as well.

Yes, I think the average for 3Q and 4Q, if you averaged them, is probably $2 million, within $2 million of the second quarter number.

That's what I get. Thank you. And then the last question is on -- so you're incurring higher expense to get Cactus II online earlier by putting these generators on line. But it's not a pass through within the tariff. So is this a customer goodwill thing or is there something else that you get in exchange?

It's Sunrise, Becca. You said Cactus, but it's Sunrise. I think it's a little bit of all of the above.

We've got a lot of customers on our system that need takeaway capacity, so it does help when you think about pulling through volumes. It does help our gathering business as well.

The more we can move on takeaway, the more we can move on our gathering and on our intrabasin systems. So again, the value chain comes into play. And I assure you on a consolidated basis, it makes sense to incur that incremental cost.

Anna, at this time, I think we're going to close off the call. Thank you all for joining. We really appreciate it. And look forward to keeping you updated as we go forward in the coming months.

Once again, that does conclude today's conference. We thank you all for your participation. You may now disconnect.