© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, everyone, and welcome to the PAA and PAGP First Quarter 2018 Earnings Call. Today's conference is being recorded.
At this time, I would like to turn the conference over to Roy Lamoreaux, Vice President of Investor Relations and Communications. Please go ahead, sir.
Thank you, Yolanda. Good afternoon, and welcome to Plains All American Pipeline's First Quarter 2018 Earnings Conference Call. The slide presentation for today's call can be found within the Investor Relations News & Events section of our website at plainsallamerican.com. During our call, we'll provide forward-looking comments on PAA's outlook. Important factors that could cause actual results to differ materially are included in our latest filings with the SEC.
Today's presentation will also include references to non-GAAP financial measures, such as adjusted EBITDA. A reconciliation of these non-GAAP financial measures to the most comparable GAAP financial measures can be found within the Investor Relations Financial Information section of our website.
We do not intend to cover PAGP's results separately from PAA since PAGP's direct -- results directly correspond to PAA's performance. Instead, we've included schedules in the appendix of our slide presentation that contain PAGP-specific information. Please see PAGP's quarterly and annual filings with the SEC for PAGP's consolidated results.
Today's call will be hosted by Willie Chiang, Executive Vice President and Chief Operating Officer; and Al Swanson, Executive Vice President and Chief Financial Officer. Additionally, Greg Armstrong, Chairman and CEO; Harry Pefanis, President and Chief Commercial Officer; Jeremy Goebel, Senior Group Vice President, Commercial; and several other members of our senior management team are present and available for Q&A portion of today's call.
We have accelerated the timing of this conference call to closely follow the press release we issued this afternoon, reporting our first quarter results. This adjustment is designed to ensure that we have the opportunity to provide a more complete set of information before analysts publish reports. Recognizing it's late in the day, that our Investor Day is scheduled in a few weeks and to be respectful of everyone's time, we have abbreviated our prepared commentary this afternoon.
With that, I will now turn the call over to Willie.
Thanks, Roy. Good afternoon to everyone and thank you for joining our call today. PAA reported total adjusted EBITDA for the first quarter of 2018 of $593 million. As highlighted on Slide 3, these results were slightly ahead of our expectations for the first quarter and we're pleased to make progress towards the continued execution of our strategic plans. In that respect, we remain on target with our leverage reduction plans; our capital program, which underpins our growth for 2018, 2019 and beyond, is progressing as planned; and the fundamentals underpinning our overall business appear to be unfolding largely in line with our expectations, and in the Permian, favorable to our expectations. Furthermore, we reiterated our 2018 adjusted EBITDA guidance and we continue to expect 14% to 15% fee-based adjusted EBITDA growth in 2019. I will now provide some detail on the highlights I just referenced, and then Al will review our financial positioning and our guidance for the balance of the year.
Our fee-based segment adjusted EBITDA for the first quarter, as shown on Slide 4, was $520 million and reflects year-over-year growth in our fee-based segments of approximately $60 million or 13%. When adjusted for asset sales, growth would have been approximately $80 million or 18% year-over-year. As forecasted and assumed in our 2018 guidance, our fee-based EBITDA -- adjusted EBITDA was down approximately $18 million from the fourth quarter, half of that variance is related to asset sales. Additionally, equity earnings from our 50% interest in BridgeTex was down approximately $12 million as compared to fourth quarter of 2017, which was partially offset by a combination of generally onetime and timing-related factors. Industry fundamentals continue to evolve generally as we expected, with the notable exception that production in the Permian is currently exceeding our original expectation. The lower-right panel on Slide 5 shows our 2018 guidance for our Permian Transportation segment tariff volumes, which we expect to grow meaningfully in each of the next 3 quarters due to production increases signaled by our producer customers, and expansions of our intrabasin capacity from our Delaware Basin Wink hub. The recent widening of Permian differentials is a positive indicator for fee-based activity levels on our Permian systems and provides additional visibility for longer-term demand for incremental capacity. Our 2018 guidance incorporated an expectation that Permian takeaway capacity would likely experience constraints in the second half of 2018 and the first half of 2019. This is materializing earlier than expected. Although, we have capacity in our gathering and intrabasin systems, the rapid production growth has substantially filled Permian long-haul pipelines sooner than expected and has created constraints in some of our Delaware Basin intrabasin pipelines. We've been accelerating projects to address these constraints, but long-haul constraints will likely remain until additional takeaway capacity projects, such as our Sunrise loop and extension in Cactus II are complete.
You will note that we chose to leave guidance for 2018 unchanged. Behind the scenes, there are a lot of moving pieces. As an example, increased volumes in the Permian, for the most part, are expected to be offset by decreased volumes in Canada due to apportionment issues. Additionally, the impact of anticipated changes in tariff mix on unit margins are expected to be roughly offset by increased expenses associated with trucking and other system balancing costs we are incurring until our Permian debottleneck activities are completed. Although, these variations are not precise 1:1 offset, when we run the actual and anticipated changes through our 2018 model, on balance, there was not enough of a difference on total volumes or unit margins to cause us to change our full year guidance at this time.
That said, let me front run the likely questions about margin-based upside resulting from currently wide Permian differentials. As we've consistently indicated throughout the last several quarters, our focus has been to position our assets to secure our 2018 plan and, as a result of that, our ability to capture near-term upside from these differentials is somewhat limited over the balance of 2018. Accordingly, we reiterated our $100 million adjusted EBITDA guidance for Supply and Logistics for '18 which, consistent with prior years, is expected to show negative S&L results in the second and third quarter and positive results in the fourth quarter due to the seasonality of NGL sales.
Looking forward, if wide Permian differentials remain for 2019, we would expect to see improved performance from our Supply and Logistics segment in 2019 when compared to 2018.
As for other factors that could impact our Permian production growth forecast, we continue to monitor variables, such as labor and equipment, frac spreads, logistical services for sand and water, gas processing capacity as well as takeaway capacity for NGL and residue gas. Taking these factors into account, we believe Permian production growth remains on track with our expectations for the year, and we look forward to providing a more detailed discussion of these expectations at our Investor Day in early June.
Our capital program also remains on track. We're excited to be moving forward with our recently announced Permian long-haul projects, as reflected on Slide 6, specifically, our Cactus II and our Sunrise phase 1 and phase 2 expansions. We are proceeding as planned with our Cactus II pipeline system that will connect the Delaware Basin with the Corpus Christi-Ingleside area. We have determined to construct the line with the fully expanded capacity of 670,000 barrels a day and expect that line to begin service in the fourth quarter of 2019, with throughput volumes ramping up over a couple of quarters.
The extension and 24-inch loop of our Sunrise system adds approximately 500,000 barrels per day of capacity from Midland to Colorado City and Wichita Falls. This enables us to utilize approximately 120,000 barrels a day of existing available capacity on our Basin pipeline system from Wichita Falls to Cushing. The project is supported by producer commitments as well as the recently negotiated sale of an undivided joint interest of 100,000 barrels a day of capacity in the Sunrise expansion to a subsidiary of Valero.
As a complement to our long-haul projects, we're accelerating the expansion of our terminalling and storage facilities at Wink and adding additional tankage at Midland. We're also constructing additional gathering and intrabasin capacity to connect production located on or near our dedicated acreage to the origination points on both Cactus and Sunrise. Not only are these projects complementary to our long-haul pipelines and the system as a whole, they're supported by long-term commitments of their own. Furthermore, increased production levels are creating additional demand for incremental gathering and intrabasin capacity and, as a result, we are working to accelerate the timing of certain projects, which could bring some more 29 (sic) [ 2019 ] capital forward into 2018, and we're also in active discussions with producers and other potential shippers on a number of other possible additional projects.
Although, we are working to pull some of the projects forward from 2019, we have not formally increased our 2018, 2019 capital program guidance at this time. We expect we'll be in a better position to provide an update on our August call on the CapEx that we are able to pull forward into '18 as well as the impact of additional projects as applicable.
With that, I'll turn the call over to Al.
Thanks, Willie. During my portion of the call, I will provide an update on our capitalization and liquidity and deleveraging objectives. In addition, I will recap our 2018 guidance and preliminary outlook for 2019.
Slide 7 shows a graphical view of how our leverage metrics are progressing with our plan to return to our targeted credit metrics in early 2019. At March 31, PAA had a long-term debt-to-adjusted EBITDA ratio of 4.2x, a total debt-to-adjusted EBITDA ratio of 4.5x and $3.2 billion of committed liquidity. Since the announcement of our deleveraging plan in August of last year, we have reduced debt by $1.3 billion. We expect the balance of our 2018 and 2019 capital program to be principally funded by a combination of retained cash flow and pending or planned asset sales.
During the first quarter, we received proceeds from asset sales of $83 million. Subsequent to quarter end, we received an additional $255 million from asset sales, and we expect to receive an additional $68 million of payments with the passage of time and completion of performance conditions. We continue to advance efforts with respect to a number of additional transactions, and believe we'll be successful in achieving and potentially exceeding our asset sales target for 2018. On that basis, we expect total debt to remain at or near current levels with variations primarily associated with the timing of asset sales, capital expenditures and margin variations associated with our hedge positions. However, should our sales efforts exceed our targeted levels, any excess proceeds would be used to further reduce debt or fund incremental expansion opportunities. Assuming generally flat expected debt levels, the critical element of achieving our deleveraging objectives is delivering the expected ramp in our fee-based adjusted EBITDA through the combination of increased utilization on existing assets and project completions. As Willie discussed, the continuation of constructive industry fundamentals and positive momentum for our fee-based businesses position us well -- position us to reiterate our 2018 adjusted EBITDA guidance of plus or minus $2.3 billion and reinforces our 2019 preliminary fee-based growth forecast of 14% to 15% over our 2018 fee-based guidance. Our second and third quarters are typically seasonally low quarters, but I would point out that our implied adjusted EBITDA guidance for the second quarter of 2018 is relatively flat with the second quarter of 2017. This is the result of 3 largely offsetting factors: first, projected strong year-over-year growth in the Transportation segment, net of transportation-related asset sales; second, asset sales in the Facilities segment; and third, lower projected contributions from the S&L segment in the 2018 quarter. The lower forecast S&L results are driven by crude oil activity, primarily related to contango-related benefits in last year's second quarter that are not forecasted in the current year period. As Willie discussed, we are not forecasting meaningful benefit from the wide Permian differentials in 2018. However, if we are able to capture some incremental upside to our annual S&L guidance, we would use the benefit in a similar manner as incremental asset sales to further reduce debt or fund incremental expansion projects.
With that, I'll turn the call back over to Willie.
Thanks, Al. As discussed today and shown on Slide 8, we're pleased to have made meaningful progress towards each of our 2018 goals, which should position us well for continued growth in 2019 and beyond. Highlights of today's call are shown on Slide 9. We appreciate your continued interest and investment, and we look forward to meeting personally with many of you at our Investor Day early next month.
With that, I'll turn it over to Roy for a few quick comments before we open the call to questions.
Thanks, Willie. We have included our typical earnings update and some additional reference materials in the appendix of today's presentation. [Operator Instructions] Additionally, Brett and I plan to be available this evening and tomorrow morning to address additional questions you may have.
Yolanda, we're now ready to open the call for questions.
[Operator Instructions] Our first question will come from Jeremy Tonet with JPMorgan.
Just wanted to start off with Transportation facilities, looking forward into 2Q here. I was wondering if you might be able to help us a little bit with regards to asset sales and kind of what the impact is quarter-over-quarter here, just so we can kind of calibrate our models a bit for the fee-based side of the business?
Yes, I mean, clearly, we've sold some incremental assets early in the second quarter. That's an impact as well as are basically seeing very significant growth in the Permian Basin. So as I commented in the prepared remarks, we expect to see meaningful growth in the Permian and Facilities segment quarter-over-quarter; the Facilities segment being actually slightly down principally as a result of asset sales.
Jeremy, if you look at the asset sales that we've done to date, you can probably triangulate back to kind of what the order of magnitude is. And I think the point really taken here is if you think about the Permian Transportation business, it's clearly the strong growth engine for the company.
Great. I guess, picking up on that in the Permian, in your S&L outlook for 2Q, it sounds like you're not really baking in anything there despite diffs that have gotten really wide at this point. Am I correct in understanding that? And then just as far as crude by rail, do you see opportunities at McCamey given the bottlenecks as you've described them there?
I'll take that, and maybe Harry will have something to add. If you think about our S&L impacts in the second quarter, it's the traditional NGL seasonality piece of it. I would -- consistent with our comments in the prepared section, the short-term opportunities on the spreads between differentials, we are not going to be able to catch short term. And then on your question on crude rail capabilities out of the Permian, we've got a -- we've got a rail facility in McCamey and are working to put that in service. But I think if you look at overall rail capabilities out of the Permian, they're going to be fairly limited. Harry, do you want to add anything to that?
I mean, the only thing I would add is our guidance at the beginning of the year sort of -- our view on what we though differentials would do in total. So I think, probably the way to characterize it is nothing meaningful over what was originally included in our guidance. And then secondly, as Willie said, we're certainly trying to position ourselves to take advantage of the McCamey rail terminal as the differentials get widened out.
We'll go next to Shneur Gershuni with UBS.
Maybe starting off with a big-picture question. Given the strong spreads that we're seeing in the Permian right now, is there a thought process around trying to resell some of the S&L capacity into longer-term contracts in a scenario where S&L retains the shipping history, kind of essentially trading price for term. Is that in the thought process in terms of going forward?
Yes, I'm not sure I want to sort of publicly say, what our strategies are with respect to our S&L business. But I think when you look at what we've tried to do all along with our capacity is we've tried to look at it as a long-term asset and structure the arrangements as long-term commitments, not as really spot commitments.
Okay. Fair enough. And then with respect to asset sales, I was wondering -- kind of a 2-part question here. One, are there any incremental asset sales that you're going to be potentially looking at? There was some discussion in the marketplace about BridgeTex. And then also with respect to the assets that you sold specifically in Transportation, do you have kind of a bridge in terms of the EBITDA impact from 4Q to 1Q?
The 4Q to 1Q, I believe, for Transportation was in our slides, I think, it was $12 million.
That was the year-over-year impact. It was $9 million on...
$9 million, I'm sorry...
That was both...
That was both fee-based...
$4.5 million, $4.5 million.
There you go. I was thinking year-over-year. So $9 million impact total between both segments 4Q to 1Q.
It was $20 million 1Q to 1Q.
And Shneur, on the other asset sales, we've come out publically on our LA terminals system, which is in process right now, but we really probably don't want to talk about additional asset sales at this point, just for the obvious reasons.
Okay, that makes perfect sense. And then finally, have you had any discussions with the agencies recently with respect to their outlooks? Is there any discussion about potentially an improving outlook from either S&P or Moody's at this stage?
Well, no, we haven't. We have ongoing dialogue with them. Clearly, Moody's today has stable outlook. They had moved us to Ba1. So with S&P and Fitch, we have had ongoing dialogue with them, but no update on timing. We aren't complete with our leverage plans. So you won't expect to see a change in outlook until we basically complete that plan.
We'll take our next question from Tristan Richardson with SunTrust.
Just Willie, real quick one, if you could touch on something in your prepared comments about accelerating projects into 2018. Can you talk about where maybe some of the low-hanging fruit lies, whether that be intrabasin or long-haul? And just given tight labor market and sort of everything tight in West Texas, how the mechanics of accelerating a project might work?
Sure. Let me talk about long-haul first. We -- both those -- all the projects we have had been in motion for some time. So we've been working to try to accelerate that. I would say that's still work in progress on the long haul. I wouldn't -- it's very difficult to get something like that moving quickly. The other pieces that I was really referring to on accelerating some capital, we've always had in our budget additional tankage at Midland and at Wink. And what we've done is because of the increasing volumes and interests in quality and additional operational tanks needed, we have moved some of those projects and accelerated it into this year. And we've been able to do that. And then everything else, we've been -- we've got some small -- smaller projects that really help us debottleneck the entire system that we have really pushed to move forward. And again, those aren't large dollar impacts as far as capital, but they are large dollar impacts by accelerating a debottlenecking of a system. And a good example of that is we have a pump expansion project at our Wink hub, that will add 220,000 barrels a day capacity on the existing system. The pipelines are adequate -- have adequate capacity and it's a matter of sizing at the pumps. And we've been able to pull that up into later this month.
That's helpful. And then just last for me, kind of a higher level -- as production has materialized maybe ahead of your expectations as you alluded to, when you look out at second half of '19 with Cactus II and some of your peers with projects under construction, do you see the current slate of announced projects currently as adequate to address sort of the growth you guys expect longer term?
Tristan, that's a tough question to address. I probably would defer some of this discussion to the Investor Day presentation, where we'll have a more robust analysis of takeaway capacity in projects that are announced. What I will tell you is these projects are complicated and whether -- even as people have announced them, I think there are still a lot of movement out there on timing on some of these projects. So I think we'll give you a better assessment on Investor Day, but know there's still a lot of moving parts around it.
We'll take our next question from Michael Blum with Wells Fargo.
Wonder if you can just provide maybe a little more detail in terms of -- you mentioned in the prepared remarks working on a few debottlenecking projects. Can you just discuss more kind of what that is and potentially what does that mean in terms of freeing up any incremental capacity?
Sure, Michael. The project I just talked about is a good example of that. And the way I would think about this is long-haul debottlenecking is very difficult. And as I said in the prepared remarks, you really have to wait for the significant additional capacity to come on with projects. The debottlenecking we're talking about is really around intrabasin and getting the gathering systems connected into the key hubs and the capability of being able to move all the barrels that we gather through the intrabasin system into the long haul. So the Wink expansion is a good one. We also have a project that we're working on right now from Wink to McCamey, which is south. That will be part of the Cactus II project. But by completing it earlier, it allows us to move barrels further along the chain. And then we've got a lot of projects around -- in the Delaware Basin that just allow us to move barrels to the key hubs, still limited by the takeaway points in the key hubs.
I think, Michael, it's also -- yes, Michael, it's probably also fair to say that it's not necessarily, in some cases, going to increase the volumes that we move. It's going to decrease the expense of moving those volumes. Right now, we're having to truck around some of the bottlenecks. Obviously, trucking is not very cost effective, but if we can move it off the trucks earlier, you're going to get the efficiency of the pipeline. And then there are some areas, as Willie mentioned, where we'll actually gain the ability to move barrels farther along that pipeline system, which gets us to other distribution networks.
[Operator Instructions] We'll go next to Vikram Bagri with Citi.
My first question is on Permian volume growth in 1Q versus 4Q of '17. Can you quantify the impact of weather in 1Q? I see the volumes are up only modestly. And if you can share what you're seeing in terms of volumes in April versus average in 1Q of '18?
Well, January was definitely impacted by volumes. Earlier in the month, there were weather outages that impacted power, not only to our facilities, but also to producer facilities. We saw a little bit of that same event in February. I'm not sure that we calibrated what that's done to the whole basin though.
I would say, I think, fourth quarter volumes probably had some benefit from the inventories that built due to the Hurricane Harvey and not seeing the volumes move to the Gulf Coast.
And then 20,000 barrels a day was probably on BridgeTex. It was down about 20,000 net to our share, Vikram, on BridgeTex in the first quarter.
Okay, got it. And big picture question, you mentioned that rail capacity is limited in the basin and trucking is not efficient. And there are different sizes of trucks also, smaller and larger, and there are multiple views out there that you'll probably run out of larger trucks and moving barrels on smaller trucks is going to be a little more costly. I was wondering if you can share your view on how the industry solves this excess supply, crude supply over takeaway capacity issue in the basin? How much of that could be on rails? How much of that could be on trucks? And where might you capture most upside in that scenario?
On trucks, Vikram, I mean, the standard truck -- I'm not sure what size trucks everyone has. The only ones we know about, they have 180 barrels of capacity. And so you take 180 barrels per truckload. 100 trucks, that's 18,000 barrels a day. So it's going to help move some of the product, but I'm not so sure there is enough -- if you look at the volume forecast into 4Q and 1Q, I don't think it's going to be solved with trucks. Rail, there are a handful small rail facilities in place. We could probably do 10,000 or 15,000 at our rail facility. You've got logistical issues with the short lines in those areas as well. So I think, rail's going to help debottleneck some of it as well. It's hard to imagine that rail and trucking can totally debottleneck what production is going to do in the latter half of this year.
And quite frankly, that's why you see the spreads kind of in that low double-digit range right now, kind of reflecting the incremental cost of being able to move barrels out.
Our next question will come from Jean Ann Salisbury with Bernstein.
I had a related question on how fast could you ramp up trucking long-haul out of the Permian and would you expect to make high margins per barrel at these differentials? Or does it all go out in costs?
It mostly goes out in costs.
And Jean Ann, Greg mentioned this. We are, in some cases, doing long-haul truck runs to get around some of these debottlenecks. But to Harry's point, the costs really offset any margin you get. But you are able to move the barrel further down the value chain.
That makes sense. And then on Cactus II at 585,000, is that including DRAs, everything? Or could you go higher once it's on?
You mean 670,000?
Yes. So Cactus II, we've said 585,000 in the past with the capability to go to 670,000. We're actually -- we're ready to go to 670,000 -- we'll be ready to go to 670,000 as we complete this first phase.
Okay. And the 670,000, is that with DRAs and everything? That's the sort of true max?
Yes.
Our next question will come from Ross Payne with Wells Fargo Securities.
I guess my biggest question is, are you seeing much of an impact on storage rates given the lack of contango across your numerous storage assets?
I mean, at Cushing, our rates have been stable. Most of -- if you look at our major locations, Cushing, St. James, Midland, Patoka, those are all areas where there's a lot of operational requirements. We've seen very stable rates. We're probably seeing record throughput at our Cushing facility. So we're not seeing upwards or downward pressure on our rates at our major locations.
I think Harry's point is a lot of our storage, we would call it operational storage and our customers are refineries. So they're not using it to store barrels to try to capture from a contango standpoint. And so when you think about people that use the tank in that fashion, whether it's backwardated or contango, they still want the tanks and we've been seeing strong demand on it.
Okay. And also, on the rail side, I know you guys have a significant amount of rail cars available. Is it more about finding locomotives to pull it and/or space on the rail to get it down the rail, that's preventing some of the movements that you might have had a couple of years ago, when S&L was doing considerably better?
In Canada, it is definitely power, okay? In the U.S., if you look at the Permian, it's really the logistics. None of these facilities are really geared to move crude in, in rail -- large volumes of -- out of the Permian. They were mostly transload facilities, smaller facilities. Some of them have been converted to sand use right now. So there is -- I think, it's the logistics around those rail loading facilities in the Permian that probably prevents a lot of movements.
If you think about the Williston, it is pipe in, rail out. This is truck in, rail out with -- and it's not unit trains, it's manifest. So it's materially different scale.
Our next question comes from Christine Cho with Barclays.
I wanted to start with cost. In the Transportation segment, your purchases and related costs have been ticking higher. And I think we saw it last quarter, but it was driven by a onetime payment. It's a bit high again this quarter at $46 million after being at a plus or minus run rate of $25 million for the past several years. Can you remind us what else is in here besides trucking cost, and is that primarily what's driving it? And is this a good run rate to go forward?
I do think it'll shift with our business mix, and there are some other purchases that are included in there. It isn't only the trucking. As far as the run rate, I would look at it as kind of a net margin versus looking at the components separately.
Yes, Christine, clearly, when you pump facilities at the higher rates, it's less efficient; so you end up spending more on the last barrel that you pump. So I can't give you an accurate number on what the run rate would be. But at higher rates, you will spend more on drag-reducing agent and in power costs for pumps. But I can't give you the number on a run rate comparison.
Yes, what I'll also add, as we bring on some of this incremental capacity, we're able to load balance. We'll be able to pump the same volume, but at a lower cost of utility. And then, clearly, as -- if volumes go up and as Willie mentioned, your costs are going to go up as you move up the pump curve. So a part of this is just simply when you say stable, I mean, as we pump more volume, we're going to have more variable cost. And that's what's happening, our volumes are going up to record levels.
And some of this is where the segment is purchasing barrels as well. So it may be something that we would need to circle up with you off-line.
Okay. And then can you talk about the year over increase in facilities, EBITDA per barrel from $0.47 to $0.50? Was this asset sales? And just generally because your guidance is a bit lower than this, at $0.44, should we assume that there's going to be degradation in this per unit number as we move through the year? Or anything you're expecting there would be helpful.
I don't have that at the tip of my fingers. But we do see business mix asset sales do impact that; timing of operating expenses can as well. And so I do think on a quarter-to-quarter basis, you do see some fluctuations in that number.
Some of it might be the FX too.
Yes. And there's -- FX can impact it as well as just over shortened terminals. There's a number of things that can cause that to fluctuate up and down over periods of time. Capacity, where we see higher throughputs through terminals that -- what's in our volume denominator for the segment measure is capacity, not throughput. So there's a number of things that cause noise in that, Christine.
We'll move next to Becca Followill with U.S. Capital Advisors.
Can you walk me through again, why you don't see any impact from the wide basis differentials in '18, especially, given that you guys saw this coming?
Well, we see impact, okay? Part of it was embedded in our guidance to start with. I think Willie mentioned it earlier, the production increases, certainly, have been greater than we had anticipated. So while we thought that you would see some tightness in the market, our view was probably the late fourth quarter -- within the fourth quarter, and it's really accelerated to the prior month. So while we thought you see a tightening market, it has occurred faster than we thought. And I mean, we do have some of the benefit embedded into our guidance, which is a lot of it was anticipated.
But on the Supply and Logistics side, did you hedge out some of the basis so that you don't benefit in '18, but you do benefit in '19?
So Becca, maybe I'll try to translate it here a little bit. I made a comment in that we positioned our assets to secure, plan and build the future growth. So when you think about that, there was an amount that we hedged. We won't disclose what it was, but we've got additional -- and again, if you don't think the volumes are going to materialize until later, you might hedge more sooner, right, to lock in decent margins. And using the blend and extend concept, you're able to use some of this capacity to lock in longer-deal projects. So when you look at those 2, that kind of addresses what's happened in the near term. Again, all in service for locking in the 2018 plan and building fee-based growth for 2019-plus.
We'll hear next from David Amoss with Heikkinen Energy.
Just thinking about the kind of broader network here. And you've announced a number of projects, the basin expansion to Wichita Falls being, I think, one that gets you a certain distance. But just curious to hear your commentary on any potential needs that you see for further expansion from Wichita Falls to Cushing.
Let me take that one, and I'm sure Harry or even Greg can jump in. We've always talked about our system as being very flexible. So when you see in our pipeline maps, you'll see we've got multiple lines in segments, all the way up. And right now we've taken the capacity from Midland to Colorado City to Wichita Falls, which leaves the last segment from Wichita Falls to Cushing open. So we've always had the capability, that would be a phase 3, to be able to loop that line down the road if there were interest in bringing additional barrels to Cushing. So as we think forward, we're always looking at how we can further debottleneck our system. Currently, we've got enough commercial support to go up to Wichita Falls. And as we continue to work our magic, hopefully, get some people interested in being able to take more barrels out of the Permian up there. And again, it's a cheaper expansion than building a complete pipeline from the Permian, all the way up to end markets.
Any thought about what that might cost to loop that line?
This is Greg. I think the answer -- we got a lot of thoughts about it. Effectively, we've been leapfrogging up. So we've leapfrogged from Midland to Colorado City, Colorado City to Wichita Falls. At Wichita Falls, we tie into 120,000 barrels a day of excess capacity on basin. And so we've got the ability to move up all the way to Cushing. Now we'll have excess capacity that gets us to Wichita Falls. And so the extension from that final leg, and there's a couple of different routes that we would be looking at, can be supported with a -- much lesser incremental volume than you might otherwise expect. We've certainly been in discussions with producers and potential shippers about that. And I think, ultimately, part of the benefit of that would be what I call hurricane insurance. It used to, we had a big concentration of oil production offshore that was always at risk. We basically moved that risk onshore now because if a hurricane comes into the Gulf Coast, you could actually see barrels back up into the Permian Basin, simply because something happened on the coast. And we're certainly providing a discussion, if you will, with producers about an exit valve to Cushing that would allow you to keep producing, albeit perhaps at lesser margins than you could've gotten if you could've gotten to the Gulf Coast. But it doesn't do you any good to go to the Gulf Coast if you can't get on a boat. So I basically dodged your question, but I can tell you that we've got a lot of work in progress.
David, I can assure you that the pieces we're talking about are a lot cheaper than other options of running lines all the way back to the origin.
Our next question will come from Ethan Bellamy with Baird.
You've been better at forecasting crude oil prices than a lot of the folks on Wall Street, including me. Greg, what do you see for crude prices in 2019?
I wouldn't bet against them. I mean, obviously, demand is very strong and the economy, not only here in the U.S. but worldwide, has been going -- where we've got areas of the world that aren't able to hold up their end of the projected forecasts, such as Venezuela. I mean, we're sitting on a potential, but it doesn't take much in a geopolitical unrest to cause prices to spike fairly meaningfully. But the real good news is somewhere around $60 a barrel, we can supply all the world needs as long as everybody stays online. So we feel pretty positive, generally speaking. I think we're going to see $80 before we see $40.
I hope so. With respect to industry consolidation, do you anticipate any of that to actually happen or are we just going to see more related party transactions?
So I'm not sure if that's a softball or one that's high inside of my chin. I think you may recall, I predicted 7 out of the last 2 periods of consolidation. And so I think the answer is it should happen. Will it happen? There's a lot of other variables in there that has nothing to do with logic, and so I'll still say it should happen.
Our next question will come from Vikram Bagri with Citi.
I saw in one of the slides, you mentioned that you're seeing increased demand for gathering. Could you comment on what you're seeing in terms of gathering margin, if you're seeing improvements in margin there as well?
We're seeing slight improvement in margin, but we're also seeing higher costs. So like Willie said earlier, when you take all that into consideration, it wasn't meaningful enough to revise any of the guidance that we had out there.
Vikram, just kind of a broader comment. What you're seeing is you're seeing a development of an area that really hadn't had any development before, right? Much of this is in areas that people don't even inhabit. So what you've got now is you've got a lot of brute force efforts to get barrels to market. So I would expect, as we go forward, a lot of this will start smoothing out. And as we said in our comments earlier, we are spending quite a bit on trucking costs, not optimized, but just getting the barrels to market. As the capital projects start following that, you'll get a little bit more efficiency, of course, offset by the demand of continued growth.
Our next question comes from Tom Abrams with Morgan Stanley.
Could you elaborate a little bit more on what's going on in Canada with the apportionment, is it just crude takeaway, gas processing, rail capacity? What's going on there?
Well, what's happening is the mainlines exporting crude out of Canada are at capacity. So when they apportion the pipelines, they go back to the producers and producers have to cut their production; either cut their production or try and get it on rail. What we've seen is not a whole lot of volume is able to move to rail because of the constraints out of Canada, and to us, it looks like you're seeing some volumes actually shut in, completions curtailed, production curtailed. So -- and we're seeing it on some of our feeder pipes, our pipes feed the main export pipelines out of Canada.
Not to mention our trucking activity around the gathering systems are lower.
So we have a couple cross-border pipelines that we practically are trying -- to try to bring more volume on those.
That's really -- the resolution, then, of that is those export pipes, essentially?
Yes.
Our next question will come from John Terril with Terril & Company.
Can you guys just give a little macro conversation about current competition and what you see as future competition, particularly, in the Permian?
I would say it's intense and it's intense.
And there are low barriers to entry.
Supported by low-cost dollars.
Do you think you have a natural advantage over some of this competition because of your gathering routes?
Yes, sure, John. We've talked a lot about our integrated value chain, right, and the benefits of it. So when you think about people that ought to be able to capitalize on this, it's people like ourselves that have built and spent 20-plus years building a system out there that has got pipelines, tanks, hubs, infrastructure. We should be the most competitive. Unfortunately, as we bid against other projects, there are people that are willing to do things for a lot cheaper than we are and, in some cases, ultimately end up either just building it or winning the deal.
I think one thing to add there is we don't have to participate in all portions of it. We're uniquely positioned and we touch every part of the basin so that we have different competitors in different parts. We can play transportation and long-haul role. We can play the long-haul role from the hubs. We can play the gathering, transportation and long-haul. So the header system was created. I think -- and the optionality associated with it allows us to be effectively anything to anyone within the basin, and we get to pick the customers we want to align with longer term. So I think that's what's created the biggest advantages for us.
John, this is Greg. I'd also comment that -- and kind of playing off Willie's comment about the value chain. At the very top of the market when oil was over $100 a barrel, the conversations with producers and potential shippers was how fast. And how much never even entered into the equation. At the very bottom of the market when oil was $29 a barrel, the only question was how much because margins had been pinched so much. We're now in a sweet spot right now, where I think people are saying how certain. And the most important thing is my barrel moves when I produce it and I get it to a good market. It doesn't have to be the absolute cheapest price and it doesn't have to be in always the best market, although, certainly that's our goal. And so some of these things that we're doing right now, for example, we're trucking, and as Harry and Willie mentioned, we may not be making much in terms of incremental value to us right now by moving that barrel around these bottlenecks. What we're doing is providing service to a customer that says, we told you we would move your barrel and it will, and it's a long-term relationship. As Willie mentioned, there are, in many areas for these one-off kind of projects, very low entry barriers, but ultimately, at the end of the day, it's about the certainty of providing -- moving that barrel from the wellhead to the best market on a routine basis. And so I do think we have competitive advantages over time. But on a transactional nature, a given project, if somebody wants to come in and ignore risk and some of the uncertainties, they may build [ something ] for what we think they may realize a 5% return. But they, with their spreadsheets, say it's going to be a 12%. Once it's built, we have to compete against it. Long-term, those assets should be rationalized into the system and that's where, I think, competitive advantages come in. So this is more of a marathon than it is a sprint. And long term, I think we're going to be able to see and take advantage of our competitive advantages, so to speak. But in the short term, if somebody wants to come in with a big billfold and buy their way into the system, they can certainly do it.
John, our calling card is quality, reliability and access to markets. The difficulty is when you -- it's hard to put dollars on that on a sheet of paper unless you actually see the benefits of it.
Our next question will come from Jeremy Tonet with JPMorgan.
Just want to touch on a comment I think you put out there as far as some of your pipes that cross the Canadian-U.S. border here. What's precluding you guys from reversing Wascana and making that into kind of a Canadian export solution there? Crossing the border is an increasingly difficult task these days, it seems like that's a valuable asset.
Yes, Jeremy, we're looking at our cross-border pipelines and seeing if we can't maximize the utility of those pipes. I mean, we don't have anything today that's far enough along or concrete enough to say we've got a project. But it's certainly one of the component -- one of the things we're looking at in Canada. It's pretty hard.
Yes, I think, Jeremy, what Harry's saying is, is you can see short-term [ arb ] opportunities, but they come and go. And the solution to a wide spread is people put pipe in the ground then spread goes away. So it's fair to say that we're looking at trying to back some of these opportunities up with commitments that allow us to, as an MLP should, have sustainable fee-based cash flow. So I would say, it's -- you always think it can happen faster than it otherwise takes, but the reality is I think we're always thinking long term.
That makes sense. Tenor is always better. It just seems you guys have a very strong hand to play since the only thing worse than Permian spreads are Canadian spreads.
Well, today, Permian barrel looks like it's almost priced like a Canadian barrel.
I think we'll go ahead and close off, Yolanda. If there is anybody else that had questions, they can follow up with us afterwards. Thank you.
Certainly, and gentleman, any additional or closing comments before I end the call?
I think that's it. Thank you all for joining.
Again, thank you, everyone, for joining today's conference. That will conclude the event. You may disconnect at this time.