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 2nd quarter 2018 earnings conference call. The slide presentation for today's call can be found within the Investor Relations News and Events section of our website at plainsallamerican.com. During our call, we'll provide forward looking comments on PA's outlook. Important factors that 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's since PAGP's results directly correspond to PAA's performance. Instead, we have 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 Chang, 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 and 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. And let me start by hitting the high points of the information we released today. This afternoon, PAA reported 2nd quarter fee based segment adjusted EBITDA of $531,000,000 and total adjusted EBITDA of $506,000,000 dollars Our results exceeded expectations. And as highlighted on Slide 3, we increased our 2018 adjusted EBITDA guidance by $100,000,000 to plus or minus $2,400,000,000 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 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 and 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 year end exit rate forecast of plus or minus 3,500,000 barrels a day.
As shown on Slide 4, we continue to deliver meaningful Permian Basin Transportation segment volume growth. Our 2nd quarter Permian tariff volumes grew by nearly 500,000 barrels a day or 15% relative to the Q1 of 2018. We expect continued growth across our gathering and intra basin pipeline systems and to operate atornearcapacity on our takeaway pipelines throughout the second half of the year, resulting in our expected average 2018 tariff volumes of 3,800,000 barrels a day for the year. Activity levels in other major producing 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 intra basin debottlenecking projects as well as terminaling the storage expansions into service throughout the second half of twenty eighteen and the Q1 of 2019.
Additionally, as mentioned, we've increased our 20 eighteen-twenty 19 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 3rd quarter include a 50,000 barrel day pump expansion on our Advantage joint venture pipeline and a 135,000 barrel day pump expansion from Crane to McKamey. By year end, we also expect to place into partial service our 670,000 barrels a day of new pipeline capacity from Wink to McKamey, 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 the 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 two projects of no later than January 2019 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 cost 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 Q4 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 of the line late Q3 2019. Full service is still targeted for April of 2020. These two projects are a great illustration of one of our long standing 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 for the developing place in Western Canada and a project with potential to bring new volumes onto our 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 ExxonMobil for the construction of a new large diameter Permian takeaway pipeline project. We're working closely with ExxonMobil on necessary activities to support 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 ExxonMobil.
As shown on Slide 5, we expect the project to be designed to ship over 1,000,000 barrels a day with origination points at Lincoln 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 U.
S. 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're ultimately unsuccessful in our efforts to obtain an exclusion, the Cactus II JV will be forced to bear an approximate $40,000,000 tariff on the Cactus II pipeline we ordered from 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 pre existing orders is unjust, especially considering the specific materials we purchased abroad were not readily available in the U.
S. 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 With that, I'll turn the call over to Al. Thanks, Willie. With that, I'll turn the call over to Al.
Thanks, Willie. During my portion of the call, I'll provide a recap of our 2nd 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 Q2, we reported fee based segment adjusted EBITDA of $531,000,000 reflecting year over year fee based growth of $53,000,000 or 11% and approximately $81,000,000 or 18% after adjusting for asset sales. Year over year Transportation segment adjusted EBITDA growth of $62,000,000 was driven primarily by Permian tariff volume growth of more than 970,000 barrels per day or 35%, while a decrease in Facilities segment adjusted EBITDA was primarily due to asset sales. 2nd quarter fee based adjusted EBITDA increased $11,000,000 over the Q1 2018, driven by a $25,000,000 increase in our transportation segment, principally as a result of an approximate 500,000 barrels per day of increase in Permian tariff volumes.
The Facilities segment decreased by approximately $14,000,000 due to a combination of non routine and timing related operating expenses and the impact of an asset sale. As Willie mentioned, as is shown on Slide 7, we have increased our 2018 adjusted EBITDA guidance by $100,000,000 to plus or minus $2,400,000,000 This increase is based on actual first half twenty eighteen results as well as our outlook for the second half of the year. The Supply and Logistics segment accounts for $75,000,000 of the increase and includes some benefit from the wider Permian and Canadian crude oil differentials. Guidance for our fee based segments was increased $25,000,000 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 on to discuss our deleveraging plan and our updated 20 eighteen-nineteen growth capital program as summarized on Slides 89. 1st and foremost, PA remains committed to our financing strategy and returning to our targeted credit metrics within the first half of twenty nineteen. As noted on Slide 8, at June 30, 2018, PA 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 $1,200,000,000 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 and 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 is shown on Slide 9, we have increased our 20 eighteen, 19 growth capital program by $650,000,000 which brings the combined 2 year program to $2,600,000,000 The majority of this increase is expected to occur in 2018, with the largest portion of which is attributable to new projects, primarily related to Permian gathering, Intra Basin and terminalling 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 $426,000,000 in sales proceeds and expect to receive an additional $34,000,000 of payments with the passage of time and completion of performance conditions. Additionally, we continue to advance efforts on other sales 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 $600,000,000 above what we would consider normal levels. The vast majority of this increase relates to short term liabilities of approximately $460,000,000 associated with derivatives used for hedging and against which we posted $426,000,000 of cash margin. The majority of these hedges roll off by year end 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 $49,000,000 This reduced amount includes net gains of $81,000,000 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 the call back over to Roy for a few quick comments before we open it up for the call for questions. Thanks, Willie. We've included some additional reference materials in
the appendix of today's presentation. As we enter the Q and A session, we ask that you please limit yourself to one question and one follow-up and then return to the queue if you have additional follow ups. This will allow us to address the top questions from as many participants as practical in our available time this afternoon. Additionally, Brett, Miguel 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.
Thank
And we'll now take our first question from Shneur Gershuni from UBS.
Hi, good afternoon guys. Maybe I was wondering if you 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 Wichita Falls extension 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 $650,000,000 as $550,000,000 will predominantly all Permian projects, but $550,000,000 of it is really associated with gathering, intra basin and a lot of the projects deep in the Delaware Basin. There's 100,000 or 100,000,000 barrels 100,000,000 excuse me, of increased costs and that captures some of the additional tariffs, the $40,000,000 I talked about as well as some increased right away 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 and nor is the looping of the line from Wichita Falls to Cushing.
Those are some of the projects that we continue to develop.
Okay, 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 will 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 and some generators, But a $0.01 or $0.02 movement in our unit margins probably have as much to do with kind of the business mix of where we're seeing barrels. But there is no kind of major shift or major change. The transportation segment was in line with 2nd quarter, what we expected actually slightly above. And we haven't seen anything that would cause us to change the outlook for the year.
Great. And one final confirmation. Alan, your review of the balance sheet and everything else, did you
need 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'd be looking at a preferred security, but we don't expect to need to do that.
Perfect. Thank you very much guys. Really appreciate the color.
Thanks, Shneur.
And we'll now take our next question from Jeremy Tonet with JPMorgan.
Good afternoon. Congratulations on the strong quarter here. I was just curious on the S and 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 and L expectations for the year, since a good portion of capacity was hedged, it seems like in the past. And so what's changed that gives you a 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.
So is there kind of a delay in that when that CapEx starts contributing to EBITDA or any other kind of moving pieces there?
Harry, you want to take the S and L piece?
Sure. The S and 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 a lesser extent NGLs. And then looking forward to the end of the year, if you 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 that 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 and L.
Jeremy, on the CapEx number, the 14% to 15% increase is it's over the new fee based number for 2018. 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 percent. So 2019 percent would be an appropriate uplift of 14% to 15% on that new number.
That's helpful. And just want to go back to Sunrise. It seems like that could come on a little bit earlier as you're saying. So I didn't know if you could kind of frame that a little bit more as far as what that could look like. And also just want to build on what you said at the Analyst Day as far as well this 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 kind of capitalize on that capacity? I think a competitor earlier in the day was talking about looking to do something like that. So just wondering in house, if you guys had any other thoughts there?
Yes. 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 difficulty on Sunrise. So we're building this section and there's really 2 sections, 1 from Midland to Colorado City, Colorado City to Wichita Falls.
You've got a lot of pieces that are that have to come together in a very tight labor market to get this done. We've 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 Q4 and there'll 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 Q4.
So on the capacity issue, kind of reiterating what we said in our Analyst Investor Day presentations. We moved 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 near term basis, the 220,000,000 is 120,000,000 that was subject to an open season going to Cushing, taking advantage of available capacity on the basin pipeline system. And then Valero has 100,000 barrels a day of capacity.
So the incremental volume, I mean, that's in the short term, that's basically what we could pay to do is try and find incremental homes for that volume. It's probably not a long term solution, but that's what we'll be crunching on here in the short term to see if we can take advantage of some of that capacity.
Got it. So from the end there, I mean, above the $220,000,000 could it be kind of truck to other local refineries there? Or just kind of that's it for now until you get another leg of a capacity expansion from Wichita Falls into Cushing that's really the only other way to really maximize that take advantage of that 280?
There's some connecting pipelines in Wichita Falls to the extent there's windows to put some capacity in some of those pipelines. I mean, that's probably more realistic than trucking out of there. There's not really anything close out of Wichita Falls that would lend itself to some easy trucking economics.
You can't track out there. I'm just saying
it's not an easy job.
That's helpful. I'll get back in the queue. Thank you.
Thank you, Jeremy.
We'll now take a question from Tom Abrams with Morgan Stanley.
Hi, thanks a lot. A couple of questions. 1, 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 going into service. So none of those were really surprising, basically kind of as expected. And the other one, Tom, was Canada?
Yes.
Yes, Canada is a large part of Canada is driven by the curtailments 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 lines on the in Canada.
And what I would say is if you're looking at kind of the year over year on Q2, 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 has came off. It wasn't the nature of declines, just a changing market.
Thanks for that reminder. I wanted to ask also in the S and L, as you think about your guidance evolving during the year, what precisely is changing? Is this more capacity available or people dropping off Feet and making some things available to you? Or just what's happening there?
Basically what I mentioned a few minutes ago, the wider Canadian dips, a little better margins than the NGL and not as heavily hedged in the second in the latter part of the year as we were in the 1st part of the year.
So what's the surprise there then? I mean you knew the capacity was available, so it must be the diffs been widening?
Lot of Canadian diffs, better NGL margins. And yes, the WTI Midland diffs are wider than they were earlier in the year.
Okay. And I wanted to ask about the Red River utilization. What where is that at now out of Cushing?
We don't have an exact number for you, Tom.
140,000 barrels a day, I think, is total volumes. All right.
Good. All right. Thanks a lot.
Not all of that's to our interest though, okay? So that's total volumes on the regular pipe. Valero has part of that interest as well. Okay.
We will now take a question from Michael Blum from Wells Fargo.
Hey, good afternoon. 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 factors 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 to 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 or Chris Chandler can comment on it. When you think about this line, it's speaking a little bit on behalf of ExxonMobil, 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 the 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 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 need of getting it from A to B.
Yes. Willie, this is Chris Chandler. The only thing I would add is, remember, Exxon has refineries on the receiving end that will
be a significant demand pull
for the pipeline. So you have 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.
Thank you. 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.
Thanks,
Willie.
We'll now take a question from Tristan Richardson from SunTrust.
Hey, good evening guys. Just you talked about evaluating projects to expand egress capacity out of Cushing. Is there any of that in the 2018 2019 budget? And if not, just sort of generally the capacity size or options you're reviewing there?
Yes. 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 potentially be developed out of Cushing.
That's helpful. Thanks. And then just sort of the latest update on Capline and after the sort of non binding solicitation that was launched last fall?
It's still a developing process with the owners and 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 lot of work through the project.
Understood. Thank you guys very much.
We'll now take a question from Dennis Coleman from Bank of America Merrill Lynch.
Yes. Good afternoon. Thanks for taking my questions. Just would like to start, if I can, just back on the I guess it's $550,000,000 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?
So there's roughly again, $550,000,000 is new projects. We've got $100,000,000 that's kind of a slight change in scope combination, increased tariffs. We've pulled $100,000,000 from 2019 into 2018. So there are definitely some costs in accelerating some of the projects. But again, everything's around gathering, intra basin and more efficiency around the takeaway out of the Delaware Basin.
Okay.
So it's 550 that are brand new. Okay. And so that diesel projects that are likely to be completed that would roll into that 14% or 15% upside to the fee based EBITDA that we talked about?
Yes. So every project will have a different start up ramp. But yes, these are all projects that are, I'll call, shorter term in nature with the exception of the ExxonMobil project that we talked about that will be multi year.
Okay, okay. Thanks for that. And then on the Sunrise early startup with generators, I gather that will be a it's a 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 a open season process as well.
I see. So those tariffs are set.
Okay. And then shifting not to confuse tariffs and tariffs, but the $40,000,000 tariff that you'll pay on the Cactus pipe, I'm just thinking as you look at ExxonMobil 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 U. S. For that kind of project or a capacity constraint there?
Yes, Dennis, this is Willie. The type of steel that you select for different sized lines can be different. The point we were making, I actually had the opportunity to testify in front of the House Ways and 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 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, the 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 quota or bring any steel into the United States. But if you don't get all 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 build out of the energy industry, which has been so successful over the last number of years.
Yes. 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 product? 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 U. S. And so we went to an outside supplier. Our goal is always to try and 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 of specifications for the ExxonMobil pipeline, we feel like we'll be able to get that domestically and so it shouldn't raise an issue there. 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, no. I was talking about quality of steel. So, for example, we were able to get 75 foot joints basically on the 26 inches that we bought and that could be manufactured in Greece. That eliminates or cuts in probably by 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 issues. So, I didn't want to get into the real details of the engineering specification, but there was a distinct difference between what we could get in a 26 inches 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 in advance.
So a
lot of things that go into the decision.
Sure. Sorry to drag you into the details and I've clearly used up my quarter question. So thanks.
Thanks Dennis.
We'll now take a question from Christine Cho from Barclays.
Hi, everyone. Thanks for all the color today. 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 want to take advantage of the space when it's available.
Is any of the S and S
I'm sorry?
No, 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 for this year is driven by the acceleration of this pipeline being put into service?
Correct.
Okay.
And then, you should we assume that the pipeline with Exxon will be fifty-fifty? Or do you expect to get more partners for this?
So Christine, we haven't 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'll be more partners, more than just Exxon.
Okay. And 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 the pipeline and expanding the capacity on existing pipeline can be done faster, cheaper and better than building a brand new one.
Fair enough. Thanks.
We'll now take a question from Jean Ann Palsbury from Bernstein.
Good evening. You mentioned during your Investor Day that you expected the Corpus Christi 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 two issues here. First of all, our pipe goes into Ingleside and is crossed over to Corpus. So we think coming into Ingleside will be in service faster than the leg back into Corpus.
So that's a
part of
the reason. And then second, yes, 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 pace than the docks.
Okay. That makes sense. And then it seems like you need maybe a slight year on year S and L step up to meet your new CapEx budget and your leverage metrics for next year. I was just wondering if you've 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.
Okay, cool. Thanks a lot.
We'll now take a question from Colton Bean with Tudor, Pickering, Holt and Company.
Afternoon. So 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 ladder. Nothing to do with divestitures. We've just seen a little better performance across several More activity
at a number of the facilities.
More throughput on some of our crude terminals, 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. Okay.
And I guess just to follow-up on some of the commentary around Canadian crude volumes. So you noted the upstream apportionment and then the impact from Wazgana. I think last quarter you 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?
And I mean 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.
Okay. And that's mostly intended to be light oil moving across border?
Yes. So the Western quarter is going to be limited in capacity. It's not going to be a 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.
Okay. And that's all
of us to just
No, go ahead. I didn't mean to interrupt.
No, 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 Refiners 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.
Great. Thanks, guys.
We'll now take a question from Keith Stanley with Wolfe Research.
Hi, good evening. 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 $9,000,000,000 so no incremental debt funding. Just how do you bridge the gap on the incremental CapEx? And then also any update on other asset sales?
Just is $700,000,000 still the target? Or could you do more there?
Yes. On our comments, I mean, clearly, we believe that the increased capital is going to be funded by 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. There will be some potential mismatches between quarters, but we feel very comfortable with our funding plan.
Okay. So it still assumes $700,000,000 for the asset sales though?
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 and the new projects, Cactus II coming on a little sooner, is putting upward pressure on this and kind of the message is you guys are going to update that in the quarter or are there offsets elsewhere to the contribution from some of the new projects?
I think it's fair to say that and somebody asked the question earlier, I mean, we're adding a lot of capital, 650,000,000 dollars but there's a time lag between the time you incur the capital and you get the full run up. 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 raised our fee based for 2018. We're still holding to a 15% to 14% to 15% uplift in 2019.
And most of that's really coming from a combination of incremental run rate of just carrying through the volume uplift that we experienced in 2018 through all of 2019 plus the added contribution from 12 months of Sunrise, Cactus coming off 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 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.
Got it. Thank you.
We'll now take our next question from Patrick Wang from Baird.
Hey, good afternoon, everyone. Thanks for taking my question. 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 pull 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 where 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. And so we're just building a lot of DUCs. So if you 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, 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 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, so far, we don't want infrastructure to be the gating item on building production volumes out of the Permian. And so, therefore, by pulling this stuff forward, we've given the producers a chance to get the market, certainly those that are on our system, where we've got guaranteed takeaway capacity and how we can give them intra basin 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 today.
Okay. That's very helpful color. Thank you very much.
We'll now take a question from Chris Sighinolfi with Jefferies.
Hey, good afternoon, guys. Willie, one quick clarification question, if I could. I appreciate your answer to Jeremy in regard to how Sunrise comes up earlier with the aid of generators, etcetera. 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?
Yes, 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 at capacity 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. And you would but you would expect to have regular way power under the time profile you were guiding before by 1Q for example?
Yes, correct.
Okay, great. And 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 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?
Yes, 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 kind of in what we call the priority the good area as far as connectivity and 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 of 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, the 1st 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, yeah, 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 and Cushing's in our tanks.
Okay. And Greg, does that I mean, if you're running at low levels there it's more difficult to move as a result, does that sort of raise the cost on activities within the hub? Do you follow me?
Well, I don't know that it raises the operating cost so much. It just makes the operating complications and the coordination become super critical. And there's a chance for 3rd parties to not be able to make their deliveries. Part of 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 a 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 cost, but it raises the complications and can cause some market aberrations and that creates opportunity if you're able to capitalize on it.
Yes. I think as Blake touched on earlier, ratability is really the key there because if you get behind early in the month and you're all 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. Well, if
I could 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 costs increase that stem directly from the tariff, the federal tariff on the steel. Is there an opportunity to pass that through? Or do you and the partners need that cost?
That's the owners' costs.
Okay, great. Thank you guys very much for the time this evening.
Thank you.
We'll now take a question from Danilo Juvani with BMO Capital.
Thank you for fitting me in. I just had one quick follow-up question regarding funding. You mentioned no equity will be needed going forward here, but the possibility for preps, what would trigger the need to issue prefs?
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 then come to fruition etcetera that would be a fallback. That's fairly consistent with how we've thought of it for say the last year. It is a tool that is still there. There's been several done recently, but we don't expect to need to.
Okay. And so some assets in the Permian recently becoming available for sale. What are your thoughts on maybe M and A versus organic growth going forward?
Well, we always look at M and 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 and L EBITDA guidance for the balance of the year. You increased the guidance by $75,000,000 Should we think of 3Q now as less negative? I think you're guiding to a negative number. Or should we think of 4Q being much more stronger than what you initially expected?
Well, 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.
Okay. That's it for me. Thank you for taking my questions.
Yes. 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 and then if there are others in the queue, feel free to get on with Brad or me afterwards, and we can walk through your questions. But we'll take one more analyst question.
And we'll take our final question from Becca Solowill from U. S. Capital Advisors.
Phew, under the wire. In the facility segment, the guidance implies that the second half would be down about $20,000,000 to $25,000,000 versus the first half. Is there is that conservatism or is there something else going on?
No. I mean the first quarter was really strong, Becca, relative to, say, the 2nd quarter. And so now I mean, there's some chatter between quarters. But if you look at it relative to 2nd quarter, it's just real pretty much in line just slightly down. Just minorly.
There was an asset sale that closed during this year. So that is a little bit of it. Okay.
Thank you. And then the next question is and final go ahead, Willie.
I was also going to say that there is some noise between quarters around timing of operating costs and so that impacts it as well. Yes.
I think that the average for 3Q and 4Q, if you average them, is probably $2,000,000 within $2,000,000 of the 2nd quarter number.
That's what I get. And then the last question is on so you're incurring higher expense to get Cactus II online earlier by putting these generators online, 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?
Sunrise, you're talking about? It's Sunrise, Becca.
Yes, Sunrise.
You said CAC, but it's Sunrise.
Thank you.
Yes, I think it's a little bit of all of the above.
Okay. I mean, 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 our
Inter basin.
Inter
basin system. So again, the value chain comes into play. And I assure you on a consolidated basis, it makes sense to incur that incremental cost.
Super. Thank you, guys.
Thanks, Becca.
At this time, I think we're going to close-up the call. Thank you all for joining. We really appreciate it and look forward to keeping you updated as we go forward over the coming months.
And once again, that does conclude today's conference. We thank you all for your participation. You may now disconnect.