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, Ana. 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 and 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's 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 three, 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 a 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, up 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…

Thanks, Willie. During my portion of the call, I'll 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 sale. 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 Facilities 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 Facilities segment decreased by approximately $14 million due to a combination of non-routine 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…

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 our call up for questions.

Thanks, Willie. We've included some additional reference materials in the appendix of today's presentation. As we enter the Q&A session, we ask that you please limit yourself to one question and one follow-up question 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 Magill and I plan to be available this evening and tomorrow morning to address additional questions. Ana, we're now ready to open the call for questions.

Thank you. And 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 II expansion and a 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?

I would characterize the $650 million as $550 million were predominantly all Permian projects. The $550 million 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 million barrels – $100 million, excuse me, 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, and nor is the looping of the line from Wichita Falls to Cushing. Those are some of the projects that we continue to develop.

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 on to your system, or is it cost related and are these the temporary issues that you talked about that'll 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 $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 second quarter, but we expected actually slightly above. And we haven't had seen anything that would cause us to change the outlook for the year.

And one final confirmation, 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?

Yes, we don't view that we needed 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 the need to do that.

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

Congratulations on the strong quarter here. 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 good portion of capacity was hedged, it seemed, like in the past. And so what's changed that gives you the 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 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. S&L is really a combination of couple 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 little 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 thought – when we came into this year, we thought by the end of the year, you 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, up 14% to 15% on that new number.

And just want to go back to Sunrise. 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 while there's 500,000 bpd into Wichita Falls, it seems like there's only a further 220,000 bpd egress thereafter out of the basin, and so the 280,000 bpd 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 of difficulty on Sunrise. So, we're building this section, and there's really two 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've always said January 1st, we've been pleased we've been able to get a little bit of 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'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 fourth quarter.

And so on the capacity issues, kind of reiterating what we said in our 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 nearer-term basis, the 220,000 bpd is 120,000 bpd 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. 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.

So from the end there, I mean, above the 220,000 bpd, 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 other way to really maximize -- take advantage of that 280,000 bpd.

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 think 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 could [indiscernible] saying it's not an easy job.

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

Couple questions, one in the Transportation 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, with Canada?

Yes.

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 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 a 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 a changing market.

I wanted to ask also in the S&L, as you think about your guidance evolving during the year, what precisely is changing? Is 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 dips, little better margins on the NGL, 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 must be the dips then widening?

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

And then wanted to ask about the Red River utilization. Where's that at now out of Cushing?

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

140,000 barrels a day, I think, is total volumes.

We will 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 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 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 to sponsor 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 in a very cost-effective pipe with certainty of mitigating 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, yeah, the production feeding the pipe, the refinery is taking the production at the receiving end, and a large pipe that brings a lot of economies of scale.

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.

Yeah, none of it's in the plans for next year. Sunrise I mean, not Sunrise, Red River is probably about 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.

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. There's a lot of interest on the owners to have an alternative movement on the Capline system. But there are three owners, and it does take a lot to work through the project.

We'll now take a question from Dennis Coleman from Bank of America Merrill Lynch.

Just would 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. 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 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, intra-basin, and more efficiency around the takeaway out of the Delaware Basin.

So it's 550 million that are brand new. Okay. And so 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 startup 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'll be multiyear.

And then on the Sunrise, early startup with generators, I gather that will be -- it's 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 a open season process as well. So those tariffs are set.

And 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 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 toward a capacity constraint there?

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 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, 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.

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 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.

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-inch 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 had to do. And when you talk about issues with respect to Integrity Management and Corrosion Management but 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-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 U.S.

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 lot of things that go into the decision.

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

I just wanted 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 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&L...

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

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.

And then 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've 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 will be more partners, more than just Exxon.

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 the reversal of the 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 Christi export capacity to leg 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 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 as it crosses 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, there's 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.

And 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'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 would 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 statements 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.

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 latter, nothing to do with divestitures. We've just seen a little better performance across...

Activity...

Yes.

At a number of the facilities.

More input through 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...

And I guess just a follow-up on some of the commentary on Canadian crude volumes. So you noted the upstream apportionment and then the impact from Wascana. And 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?

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.

And that's mostly intended to be light oil moving across border?

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

And that's...

And then Colton...

Mostly just in…

No. 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.

Well, we're connected all the way to Cushing 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.

Appreciate it.

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 that to stay flat at about 9 billion, so no incremental debt funding. Just how do you bridge the GAAP on the incremental CapEx? And then also any update on other asset sales? Just is $700 million 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 principally by retained cash flow in our asset sales program. Clearly, some of the margin money that we've posted will come back to us over the next two, three quarters. And there will be some potential mismatches between quarters, but we feel very comfortable that they're our funding plan.

So it still assumes $700 million 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.

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 out 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 that, and somebody asked a 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 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 14% to 15% uplift in 2019. And most of that's really coming from a combination of incremental -- the 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 at 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.

Yes, 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 Wang from Baird.

Just a quick one from 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 -- in given areas I should say, where somebody's laid down a rig but they've 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's 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, 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, it's 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. And so therefore by pulling this stuff forward, we've given the producer the chance to get the markets. Certainly, those that are on our system where we've got guaranteed takeaway capacity and now we can give intra-basin transportation efficiency and just makes all the sense in the world to accelerate.

Patrick, just another data point, we typically have been kind of at a completion crude 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.

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

Willie, one clarification question if I could. I appreciate your answer to Jeremy in regard to how Sunrise comes up earlier with the aid of generators, et cetera. 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.

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 a capacity if you have regular power. So clearly, will probably start up slower and ramp up but we'll have to see how things go on the generators.

But you would expect to have regular way power under the time profile you were guiding before by 1Q?

Yes. Correct.

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 held itself in your position there. But we have seen a consistent draining of regional stocks in the weeks since the Investor Day. I realize that we've seen similar 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?

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, 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 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 three 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, yes, 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 in our tanks.

And Greg, 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? 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 becomes supercritical.

Yes.

And there's a chance for third parties to not be able to make their deliveries part of it again where 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 cost, but it raises the complications. And it can cause some market aberrations and that creates opportunity if you're able to capitalize on it.

Yes. I think Willie touched on earlier, ratability is really the key there because if you get behind early in the month and you're low on inventory, 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 hopeful, guys. I really appreciate it. Willie, I know I'm over my limit but if I could ask a clarification question to something you said earlier. Sorry if I missed it. But the Cactus cost increase, it's 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 [indiscernible]. What would trigger the need to issue [indiscernible]?

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, et cetera, that would be a fallback. That's fairly consistent with how we've thought of it for, say, the last year. Is it the tool that is still there? There's been several done recently, but we don't expect the need to.

And so 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 differ 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.

Last question from me, has to do with S&L. EBITDA guidance for the balance of the year, you increased the guidance by $75 million. Should we think of 3Q now as less negative? But 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.

Hey. 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 Brett 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 Followill from U.S. Capital Advisors.

Under the wire. In the Facilities segment, the guidance implies that the second half would be down about $20 billion to $25 billion 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 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 just we're pretty much in line, just slightly down.

And asset sales.

Just minorly. There was an asset sale that closed during this year. So that is a little bit of it.

And then the next question 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, it's probably $2 million -- within $2 million of second quarter number.

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...

It's Sunrise, Becca.

Yes, Sunrise…

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

I mean, we've got a lot of customers on our systems that do takeaway capacity, so it does help. When you think about pulling through volumes, it does help our gathering business as well.

I mean, the more we can move on takeaway, the more we can move on our gathering and our...

Intra-basin.

...intra-basin 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...

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.

And once again, that does conclude today's conference and we thank you all for your participation. You may now disconnect.