Good afternoon,
and welcome to the Plains All American Pipeline and Plains GP Holdings 2018 Investor Day. I'm Brett McGill, Director, Investor Relations at Plains. We appreciate those who have joined us here in person as well as those who are joining on the webcast. I'll make a few announcements before we get started with the presentation. Presentation materials that we have printed in the room here today are all posted on the website.
For the benefit of everybody that's participating via webcast, this event is webcast live and a replay will be available for a period of time. Other supplemental information, including management bios are included in that presentation deck. Going to Slide 3, just want to touch on a few important disclosures, specifically the forward looking statements and the non GAAP financial measures that we will be making reference to throughout the presentation. Included in the back of the presentation book are reconciliation of those non GAAP financial measures. Moving to Slide 4, we have a busy day this afternoon.
We have 9 prepared presentations. We'll have 4 Q and A sessions, 2 of which will be moderated. And to summarize, the first half of the presentation content will largely focus on crude oil. We'll have a 30 minute break about midway through the event. And then the balance of the presentation will focus on NGL, social responsibility, a financial overview and some closing remarks.
On the panel Q and A, I'd just like to point out that as we look at feedback from prior events, the Q and A discussion periods tend to be one of the more value pieces of content. So we try to make sure to provide plenty of time for questions to be addressed. The questions that we have identified for the Q and A panel specifically are a combination of feedback through a survey that we sent to registered guests on May 1, as well as frequently asked questions that we receive in our ongoing communications with investors and analysts. There will be a crude oil panel and an NGL panel, and the questions specifically related to those are reflected on the Slides 5564 of your presentation the benefit of everybody on the webcast.
And if you do have
a question and you're participating through the webcast, you're welcome to e mail that question directly to us at investorrelationspaalp.com. In addition to the management presentations that are speaking today, we also have many other members of management here in attendance. So please take the opportunity to interact with the presence that we have here at the event. I'll transition now over to the presentation portion. And in doing so, I'd like to introduce Willie Chang, our Executive Vice President and Chief Operating Officer.
Willie, if you'll please welcome
Good afternoon, everyone. Welcome to the Analyst Day. I want to echo Brett's appreciation for you taking the time to spend with us today and also for all the folks up on the webcast. I'm going to start off with my section here talking about a little bit about the macro views of our company. The theme of today is executing with executing with positive momentum.
And what I'll tell you is, this is a very different position this year than we were last year. It's incredibly exciting for us. It's a lot going on. I think what you'll find is as all the different speakers talk through today in the panels, you'll see that there is a lot of positive momentum behind what we're doing. It's a very exciting time for us.
So I'll cover some macro views, both of the U. S. Globe and particularly around crude oil. I will spend some time on our Permian assets, including our strategy around the Permian. I have a slide that I want to
share on
kind of looking through the cycle. We talk about ourselves as an integrated business model. And we have a slide here that will show the last decade through the cycle. And I think it will help you understand kind of the differentiation that we think we have. And then a little bit around our operating excellence, we've gotten to such a size in the company that preserving the base is absolutely key.
The key points that we're going to be talking about today is really the fundamentals are very strong for the industry. We've got a very strong position, particularly around the Permian base to capitalize on that growth. And I hope you'll see that we've got a lot of execution in everything we talk about. And all this, of course, really drives long term fee based growth for us. I apologize, I got the slide deck here.
Not quite. I need help. There we go. Okay. So many of you have seen this slide before.
I'm sorry about this. Many of you have seen this slide before. This is our footprint. You can see it's across all of North America. The two things I really want to highlight is there's a differentiation between us and others and that we participate in the entire value chain from the wellhead all the way to end markets.
And the integration plus our fee based growth with minimal exposure to the commodity prices really sets us up for a strong fundamental footprint across the U. S. With the growth in the Permian. If I take your attention to the volumes handled, I just want you to look and see a couple of things here. In 2017, we moved 5,200,000 barrels a day of tariff volumes across the system.
And keep your eye on that because certainly a year ago it was significantly less. And as we go forward that number will increase. And we also buy roughly 1,200,000 barrels a day of crude and NGL back on that integrated lease gathering business, purchasing from the lease and putting it into the system. A little bit more on macro. We've seen a lot of improvement on moving towards a balanced market over this past year.
Crude prices have come up. We saw a very large de inventory in the world, roughly 200,000,000 barrels came out of the inventories as shown on the top right, the blue line and are actually approaching 5 year average levels. There's a lot of support around geopolitical events. We got OPEC certainly that seems to be playing a controlling role in the world led by Saudi. If you recall Saudi produces about a third of the world's liquids or crude and has taken about a 60% cut.
Clearly, they want to make sure that the market moves forward properly. There's a number of events that as they happen with the most recent one coming up later in June with OPEC. They've telegraphed that they want to increase some production. I just saw something as we came down today around increasing roughly 1,000,000 barrels a day clearly to control oil prices, temper the prices and keep demand strong. So we see support there.
And then probably the most important thing that we see is continued growth in demand across the world. And what's shown on the lower right is that liquids demand. And you can see other than really the financial crisis in the 2,007, 2008, 2009 period, the world has pretty consistently grown by about 1,500,000 barrels a day. You can see we expect year end 2018 to hit 100,000,000 barrels a day of global demand. And you can see the constant trajectory over the last number of years with the majority of those volumes really going to Asia, really driven by the Asia demand.
Just to put into perspective the world liquids producing capability, the top 10 countries contribute to 70% of the liquids production in the world. And if you look at the U. S, most people don't think about it this way, but when you combine crude oil, you can grind NGLs, condensate, renewables, biofuels and refinery gain. The U. S.
Is actually the largest liquid producer in the world. And on the far left hand side of your screen, you can see the difference in the bars between 20122018 April. Can see the significant growth in the U. S. Liquids production.
And the point I want you to really see on this is that the lower right hand corner, we have the Permian Basin. And of course, you can see the significant growth in the Permian Basin to 4,800,000 barrels a day of that roughly 3,000,000 barrels a day that is crude. So when you think about the U. S. And its role ultimately in the world, we are the marginal or incremental producer that supplies the world.
And again, you can see some of
the numbers there. The U. S. Grew over the last 6 years, 4,000,000 barrels a day in crude and almost 2,000,000 barrels a day of NGLs. We expect the U.
S. To continue its trajectory as far as stable production growth. What we've outlined on this slide here is really 3 phases. You'll recall 2014 really started the downturn of oil prices shown in red. The shaded areas are production growth.
And you can see the amount exported in the dark blue shaded area at
the bottom of the page.
And you can see as the industry as prices fell, U. S. Production fell. And then in late 2015, early 2016, the export ban was lifted. And you can see as you go into the 2nd phase, really 2016 2017, the production or the producer industry really, really optimized, improved efficiency to the point where we really lowered our breakeven costs.
And I think this downturn actually put the U. S. In a much better position for the world as far as the incremental producer. And what you see on the lower shaded area again is the increasing exports in the dark blue and kind of the punch line going forward here is from here on out, we see there's a stable growth of U. S.
Production with a significant piece of that 3,000,000 barrels the next 5 years ultimately going to export markets. A little bit more about the diet of crude and what we're producing. The U. S. Crudes that are being produced are getting lighter and lighter as the shale production continues.
The confluence of that is the U. S. Refining industry, which was really designed for heavy barrels, is slowly starting to reach limits on the light amounts of crude they can run. Shown on the top right just shows from 2015 through now the increase in the different grades of crudes that
are being run. You can see at
the top right, you've got 2 circled areas. That's 40 gravity and 45 gravity and above. The farther right is the lighter, the farther left is heavier. And you can see the growth in these last three years have really been in the 40 to 45 gravity and above increased barrels. And that's because the refiners have been able to accommodate that.
The crudes that we're producing are 40 and above and the average crude gravity for the refineries in the U. S. Is 32, so it's heavier. And also what you can see is obviously there's a mismatch. The lighter barrels ultimately have to go offshore as refiners can't run as much of that.
Now there are some refiners in the U. S. That have spent money on expanding light crude capacities. And as we think about it, those refineries ultimately have to be on the coasts because you're going to want to export product. But absent the refiners that are going to expand, really, there's a pretty finite market for light barrels from the U.
S. Shown on the lower right is really the history over the last 3 decades on API gravity of different crudes that refineries run. And you can see for the 1st 20 years of that, everyone was building cokers and conversion units to run the heavier barrels. And over the last number of years, 7, 8 years, you can see the light barrels starting to come back, hitting the limit. So for us, light barrels is the product that needs to be moved.
And in order to move that, you really have to be able to segregate crude and get it to markets without being co mingled and that of course is what our portfolio is designed to do. This slide illustrates the exports. You can see on the left hand lower side, you can see the number of exports with the blue being PADD III, the Gulf Coast exports. And you can see really before the export ban was lifted, we were averaging about 500,000 barrels a day of exports. As you get into 2016, it started ratcheting up as the export ban was lifted and the export terminal started to get reconfigured for crude exports.
What I really want to draw your attention to is 2017. In 2017, you can see early in the year, we stepped up to just over 1,000,000 barrels a day. And then late in the year with Hurricane Harvey, we really popped up to about 1,500,000 barrels a day of exports. And for the majority of 2018, we've been really averaging close to 2,000,000 barrels a day of exports. And again, most of this is leaving from PADD III and ultimately going to Asia.
So the U. S. Growth is being driven by the Permian. And this slide really helps illustrate where that growth is coming from within the Permian. The Delaware Basin is driving the significant piece of that growth.
You can see on the top left, we have year end estimate of 3,500,000 barrels a day of crude production. And if you go out 5 years and the increase, you can see the Delaware, which is surrounded by the red dots there, is increasing the majority of that 1,700,000 barrels a day or the majority of that increase and 60% of the growth of the Permian over the next 5 years. As I mentioned earlier, the Delaware Basin growth is significantly condensate, so these barrels ultimately have to get to the coasts. As I transition and talking about our Permian asset base, you can see on the lower right, the Delaware Basin is where we have 80% of our acreage dedications within Plains. We've got about 1,400,000 barrels a day of gathering capacity in the Delaware.
We've pre invested a lot of this over the last few years. And what I want to highlight here is 2018 2019, we're going to be adding 1.2,300,000 barrels a day of capacity within the Permian. And it's really highlighted as such. We break our business into gathering, intra basin and long haul takeaway. And you can see we add another 600,000 barrels a day in the Delaware Basin for gathering.
We've got 800,000 barrels a day that we're adding around intra basin to be able to get it to the takeaway points. And then our long haul lines, will have 850,000 barrels of net capacity for us. So this is a big piece of the growth engine that we've had. We've again, we spent CapEx over a multiyear time period to get us to the point where we got a lot of this. We've got the next tranche of capital that we've invested really around Cactus and Sunrise.
That is the majority of these volumes and we're actually starting to look forward to the next wedge beyond that. And really to take it home on the lower left, you can see our tariff volumes within the Permian Basin. On the right hand side, you'll see our guidance for this year, 3,800,000 barrels a day average for the year, and you can see the numbers for the Q1 of 2017 2018. And what I'll tell you is, if it's annualized year over year, the 3.8 is roughly 1,000,000 barrels increase over 2017. And going forward, you'll see similar growth patterns.
So this is the Permian Basin infrastructure. There's 20 plus operators in there, and that's all shown in the light lines. You can see the key aggregation hubs in blue, Orla and Wink, and then we've got the key long haul takeaway hubs in yellow. And what I want to superimpose on this is the Plains asset base. And you can see this is the asset base and the infrastructure that we have around the franchise we've got in the Permian.
Again, it's a fully integrated franchise from gathering, Intravas and all the way to long haul. And you can see it's pretty significantly spread across the basin with an emphasis in the Delaware Basin. This highlights again where the acreage dedications are, is where the growth that we've spent on our CapEx results. And if I expand back a little bit and take this to where all these barrels go, you'll see the Permian on the top left. And what you'll see again here is the 3,000,000 barrels of growth that we expect between now and the next 5 years.
And you can see a lot of the takeaway lines that we are either have constructed or in progress of building. We've got Cactus I, our Eagle Ford JV, our Cactus II project that is in progress. And we also look for additional lines up to Cushing and other markets as we leave the Permian Basin. Corpus Christi is a key hub for us for exports. You can see the growth in the Permian export capacity going up 3x over the last 2016 to 2017 and it really accounts for about 40% of the exports on the U.
S. Gulf Coast. This slide shows you the transportation volumes over time, really the last 6 years of the growth of our transportation segment, shown total growth of transportation along with the dark blue, which is the Permian. And what I would tell you here, we really want to draw your attention to the lower right, which says the last number of years with the investment that we put in the Permian, there really is an inflection on growth in the volumes from the 1st 4 years. And the growth going forward the last couple of years and going forward is going to be the Permian.
And you can see again that 3,800,000 barrels a year in 2018 continuing to grow. The transportation segment is roughly 2 thirds of our 2018 guidance EBITDA and as we go forward, we'll continue to grow. This excludes any contributions from Cactus II or some of the other projects that are not complete yet, which are complete in 2019 and beyond. Harry will talk a lot more about this and I think Al on capital, but the point here is really to reinforce to you that we're spending in the Permian. That's where the growth is.
That's where the opportunities are. You can see the pie chart shows where we're spending our money. We've got the long haul line, Sunrise and Cactus II and a number of complementary Permian projects really to get barrels from our gathering systems intrabasins to the long haul. Recently, we've seen a significant interest on additional capital. We mentioned this in our Q1 earnings call.
We are trying to assess the scope of all that. We do think there's additional projects that need to be considered. And at the Q2 conference call, we'll give you an update on how much we think that will actually include into this year and the impacts on earnings for this year, potentially next year as well as the source of capitals for that. But the key here is all these projects we're talking about here really drive growth and beyond 2019. Now let me step back and kind of look over a 10 year period.
This is really our EBITDA over the last 10 years and it really shows our integrated model and its role as we go through the transition of a cycle. The shaded area in the back is production growth. And what we really saw here is, as you go from left to right, you can see the S and L pieces on the top of it. The dark blue is the fee based. And you can see we started to run into constraints 2012, 2013 2014, and we ended up with significant regional basis differentials that we are able to capture in our supply and logistics segment.
And I always talk about our S and L piece as an enabler of the business. By being in the market, you see it, you capture the arbitrage and it gives you that price signal to invest, which we did, which is really that second group of that second parenthesis there. You take the value that you created from capturing the arb and you can almost think of it as you're using that to contribute into the projects to build the fee based business out. So, you're taking the opportunities, you see it, you invest. Of course, at that point, the arbitrage disappears and you can see when production fell, certainly, our S and L business took a big hit.
But the fee based business continues to grow. And then when you get into the cycle where production comes back, you're really able to capture that operating leverage with the assets you've built. And as you think about this, you can actually question if we're not in this cycle again as the arbitrage opportunities open up again, you see it able to capture the funds and convert it ultimately to fee based growth. So the point on this is S and L enables the fee based growth. Been able to capture that over time, and I think this is a pretty good illustration of how the integrated model does differentiate us.
So as we've grown where our business is over $2,000,000,000 of EBITDA, one of the focus areas we've started to reinforce is really how do we preserve that base, right? We've always focused on optimization, reliability and cost management. But now going forward, it even more critical. We've got more growth that's coming, but we've got to preserve the existing base and even look for opportunities there. And one of the areas that we are really grow our company and run it every single day to grow our company and run it every single day to the point where we're consistent across all 5,000 people across the company.
And it allows us to make sure we're consistent and capture everything we possibly can. So the thinking behind OMS is there's a number of tenants and areas that we focus on and we're always measuring ourselves. It's a continuous improvement process. So the mantra we have is gaps are good. You need to understand what the gaps are to excellence, bridge them and then you ask yourself again, how can we get better?
And over a decade, you continue to improve the business. And one way to think about this is not only is it the base that you're keeping, but you can also capture a lot of opportunities out of the base as you understand it better, which we've certainly been able to do. So this is the key takeaways that we really ask you to think about as we talk today. I'm going to let Greg talk about this at the end, but it's really strong fundamentals again. Our positioning is very, very strong.
And I think you'll see as the rest of the speakers talk that we're really, really focused on execution. So with that, let me ask Jeremy to come up.
Good afternoon. My name is Jeremy Goble, and I'm going to take you through U. S. Crude oil fundamentals, Lower 48 Onshore Fundamentals as well as dig a little bit deeper into the Permian Basin. First, any discussion with fundamentals for us starts with what's our view of supply and how does it impact pipelines and where those barrels go.
And so as we look through this Lower 48 in the current sensitivities. We prepare for the worst and plan for the we plan for the worst and prepare for the best. So in the $50 case, you can see this is roughly a $9,000,000,000 to 10,000,000,000 barrel a day Lower 48 Onshore.
Perfect.
In the $60 case, you look more like a 3,000,000 barrel a day of incremental growth. In a $70 case, dollars 3,000,000 beyond that. So we get a little bit nervous around $70 and above as the top could come off of production. So it feels like producers, if that black line is indicated, is roughly where they're spending. So we look towards that $60 case, that constant activity with some growth throughout the year.
That's the case we're looking towards. So when we look for cash flow balances and where activity is, it's kind of solving for that $60 world. Where does the production come from within the Lower 48 onshore? The Permian Basin is the key driver for that. You're going to hear a lot about that today and you're probably exhausted with Permian Basin discussions, but really a focus on Lower 48 Onshore and our business starts there.
And you can see Permian Basin grew 730,000 barrels a day in spite through year end 'seventeen. And we've got it constrained for 'eighteen and 'nineteen and we'll talk about that a little bit more. But it's going to grow from close to 3,000,000 barrels a day at year end 'seventeen to over 6,000,000 barrels a day in this 5 year horizon. The Eagle Ford and Williston are growing from lower levels than they were at peak, but there's a lower underlying decline. They could grow 250,000 to 500,000 barrels a day, respectively.
The STACK, VGA and PRB are we expect to grow as well, but really this theme of production growth is dominated by the Permian Basin. Why do we have that view? 1, it's our fundamental view, our well by well analysis to understand where activity is, what fundamental trends are in each of the different basins. But look at capital allocation, starts there. 55% of Lower 48 Onshore Rigs are in the Permian Basin, oil directed rigs.
The Delaware Basin alone has more rigs than the Eagle Ford, Williston, STACK, DJ and Powder River Basin combined. Then we look relative to peak. And peak in 2014, no other basin has more than 50% other than the STACK, which was just being formed in the Permian Basin. And when you start to think about that, there were 3 50 horizontal rigs in the Permian at peak. Assume that wells the efficiencies now, you could do the same with half that amount of rigs in each of these basins.
So if you look at the other basins below 50%, they're almost as productive now as they were at that time. So if we use that same math in the Permian, you have the equivalent of 175 rigs and now you've got 414. So you almost have 2.4 times of productive capacity in the Permian that you did in 2014. That's why we get excited and why we view it sustainable and why we're putting a lot of long term capital into that basin. So as we step through the Permian Basin fundamentals, we start with where are we in the cycle.
Well, first, if you look at the Permian Basin up to 2,000 and and 7, it was largely dominated by vertical developments. In the you had the Spraberry trend, then you go a little bit deeper and then it's the Wolfberry trend vertical developments. The Wolfcamp and the Bone Spring vertical development. And all of a sudden you started, if I have a 5000 foot vertical column, what if I go horizontally 5000 to 10000 feet? You started in the Southern Midland Basin, then Northern Midland Basin, then parts of the Southern Delaware Basin, then Northern Delaware Basin, and then you continued over this 10 period 10 year period to extend the aerial area that you're going in each of those places.
So the areal extent is expanded. The perimeters have largely been found. Now it's how do I optimize recoveries in each of the zones that we've kind of optimized. So completion design is advancing and really understanding how do I optimally develop the resource and get the most leases, is it's now 10, 20 well pads, each operator has their own way of doing it. But planes all throughout this period has to adjust our business model to keep up with it.
It's not 5 to 20 acre spacing, get a truck, move a vertical well towards Midland. It's now connect gathering systems to central facilities with a few wells, horizontal wells coming into it. You go from 150 barrel a day IPs to 1,000 barrel
a day IPs. Now you
could be 20,000 to 30,000 barrel a day IPs and you need 1 year planning with the producer to understand where he's going to be because trucks won't do it. So, our entire business model is adjusting to this. You've got step changes in production as opposed to linear changes. So it's been an exciting time with planes and they've been the whole group and team commercial team has adjusted to this and it's been exciting to go through. As we look forward, we've got all these efficiency gains, hasn't shown up in rig You're now almost on par with the Williston, which geologically is closer from a depth and pressure standpoint.
So, you're starting to get towards there. We wouldn't expect to get towards the Eagle Ford and DJ with current technologies. The DJ, you can drill 3 wells in a month of rig, Eagle Ford 2, But the Permian Basin, 1.2, 1.3, as we talked about before, 1 rig was doing roughly 0.67 wells a month. Now you're at 1.2. That's where we get 2 times as many wells.
Question is,
are those wells as good?
Well, we look at the next page and you say, yes, the wells are materially better, when we look across the core counties in the Delaware Basin, Lee, Ward, Reeves, all the way through Culberson, you've got 12 month queues, which is a much better proxy for IP than 24 hour or 30 day, exceeding 120,000 to 150,000 barrels. When you start to think about that in a simple multiplier 4 to 6 times to an EUR, you've got 500,000 to 700,000 barrel oil wells at the median across 7 counties. When we look at 7 or 8 counties, when you go to the Midland Basin, same story for the core 6 counties. So, we're seeing even as you increase the density, we're starting to see more continuous better results, statistically significant results. Now we're going to continue to monitor this as density gets tighter and tighter, but so far it's very encouraging.
We've got more rigs working in the Permian. The rigs can drill more wells and productivity of the wells is better. So will that result in increased production in the basin? Well, so far, the real constraint has been completions. You have 4 24 wells rigs drilling close to 4 50 to 500 wells a month, but you're only completing 300 to 3 25 wells a month.
So you've seen your drilled the question is when does that gap start to narrow? Well, without any additional rig add completion adds and no other constraints, we would expect to see that this year. But what we're seeing we're not going to see that because of constraints, we'll talk about in a minute, but we are seeing producers indicate that completion counts are growing. They're growing close to 30% year over year, which is going to yield steeper and steeper production increases as we'll show
in our forecast. So we're
going to go from 200 completions a month in January of 2017 to 300 in December and we think you'll get pretty quickly to 3 50 a month and you'd well exceed that if we had takeaway capacity from the basin. So what will drive the incremental growth? Where will incremental rigs come from? Well, the exciting thing for us is we work heavily with the integrators and we think they're just to get into this manufacturing mode. So the next wave of incremental growth above and beyond the independents, we expect to come from the integrated.
Just in the when is the last time you've seen Chevron or Exxon talk about a U. S. Shale play? That's very prominent now in their strategy. They're building the infrastructure.
They're making the investments to grow over 600,000 BOE per day over the next two and a half years alone. So when we look at this, we're excited about all earlier. Well, in the Permian Basin, the Central Basin platform is roughly earlier. Well, in the Permian Basin, the Central Basin platform is roughly 500,000 barrels a day and we expect that to stay fairly constant. The Midland Basin, you could see 450,000 barrels a day of growth this year and becoming close in that constant activity case or unconstrained case, you're going to see close to 2,500,000 barrels a day in the Midland Basin.
The Delaware Basin could grow by 50% this year, roughly 700,000 barrels a day and it could become 3,500,000 barrels a day and a lot of that's driven by there's 100 additional horizontal rigs working there relative to the Midland Basin. So when we look at the Plains asset, as Willie alluded to, we're heavily levered to the Delaware Basin. And what's interesting about
the quality, one question
is, well, what is the
That's roughly That's roughly consistent quality. It's slightly lighter in the Southern Delaware Southern Midland Basin and slightly heavier in the north. But for all intents and purposes, it's in that 40 to 40 API range. Central Basin platform has some of the medium sour, but if we look at the Delaware, it looks like a box of crayons. And what is that?
Well, as you get closer and deeper, the Central Basin platform, it's largely WTI. As you get shallower and you go up dip in the basin, you start to get more and more condensate to the west, becomes more of a gas condensate reservoir.
So there's
variability as you go east to west. And the question is, what do you do with that? Well, historically, it's all gone into the common stream WTI. But going forward, if you go from 400,000 barrels a day of tons a production to over 1,400,000 barrels a day, it's got to find a new home and you've got to develop new markets. Harry will talk about this in his section, but Plains has been shipping neat condensate from the Delaware Basin since April a year ago, finding markets in homes.
And the interesting thing is because we've planned our system, we planned our commercial contract to allow for segregation, we've planned our specs on our downstream pipes that we're building and select common carriers that we've got the mouse trap already set up to do this. And there's some very unique quality attributes of the Delaware Basin barrel. It's low resid content, it's got low metals, it's got low sulfur, which could be good for refineries as we get to these lower and lower emission standards. So, Plains has got the commitments and the mousetrap to capture these as well as get them in the end market in a neat manner. So when we roll all this up, what is our view of Permian production?
Well, we have the same view here of the $50, $60 $70 case and you see the Permian can grow at all. It's just a matter of how much cash flow gets reinvested. But the issue here is that there is a constraint in 2018 2019 and it's largely driven by crude old takeaways as well as labor. And so if you see that constraint, so in an unconstrained environment, you'd be completing 5.30 wells a month, but we're not. We're completing 300 to 350 and we really don't get outside that 350 to 3.75 range this year because we have to constrain production.
So the question is, well, how did you constrain it? Was it arbitrary? Well, what we did was we said, look, this is our view of local refining demand and all the expansions we can do and the times that they're going to get done on the existing pipeline network and the new pipelines that are coming online. We added 150,000 barrels a day for rail and for trucking capacity. Completions a month.
The constrained completions to keep production within that 150 of takeaway is what that black line is. And that's what our expectation, our business plan is based upon. So we talked about those constraints. So when you start to think about it labor, it's trucks, it's services. There's a lot of people out there that are looking and willing to pay for it.
So, the services are spread thin and it's a thinner labor pool. So, it's hard to ramp completions. It's hard even if there were an enormous amount of trucks and it was operationally feasible to move them to the Gulf Coast, you don't have enough drivers to do that. That's another reason we have to constrain that view of crude oil production for this year and next year. Frac spreads, there's the labor component in addition to do you have enough horsepower to complete 5 35 wells a month?
And the answer is no at this time, but we expect it to grow and be there later. We think logistics last mile logistics at times becomes a problem in certain areas, but it's not pervasive across the basin. We think gas processing side, there's plenty of capital chasing those opportunities and we think that will not become a bottleneck. So we really think the primary, other than labor, is going to be takeaway capacity, specifically on the crude oil side and to a lesser extent on the gas side. On the gas side, you start to think, well, will the Mexican demand be there?
Will there be the connectivity on the other end to pull the gas through? But you also start to worry about does that lead to basis problems? Well, the problem the driver in the Permian Basin is crude oil, not gas. And so when we start to think about that, what will happen, capital allocation away from the gassier areas and you'll shut in the largely gas wells. So, we think the gas part will balance because the real driver is crude oil.
We'll finish with a more detailed look at how we constrain production and what that impact is. You still have substantial growth this year from close to 3,000,000 barrels a day to 3,500,000 barrels a day. But you could be over 4,000,000 barrels a day in an unconstrained environment. So we're conservatively estimating that. Could you exceed it?
Possibly, but that would lead to very wide differentials. In addition, you look at year end 2019, that could be well north of 4,500,000 barrels a day, but we have to getting to 4,000,000 barrels a day. So what that's going to do is incentivize, try to bring projects forward, try to do everything you can to accommodate this. But there's a real opportunity here. And if the rig count stays the way it is and you're building DUCs at 175 to 200 a month, that gives us more and more confidence in the tail end of this forecast that you're getting to over 6,000,000 barrels a day because while you're the opportunity in the production won't be there in the near term, you're still growing at 500,000 barrels a day.
It gives you some really low cost productive capacity to come on and bring in the tail end. So you'll notice how the gas narrows as we get further out on the curve. So we expect tightness through at least 2018 2019 and potentially into 2020 depending upon the timing of projects, which is an opportunity for our S and L business. And at the same time,
we are aligned with a lot
of the larger producers have firm takeaway. So hopefully, the guys that don't get shut out are the ones that have capacity to get out and those are the ones we're tied to. So we think in this our business mix and what we're planning for, we should be successful in this environment. With that, I'll turn it over to Harry.
I'll turn it
over to Luke, sorry.
Okay. I'll give you a
brief update on what's going on in Canada for
the crude oil.
Really, this outlook looks historically let's look at last year. So, last year, I spoke about oil sands development. And at that time, there was about 5 to 6 major projects that were slated to come on stream over the next 12 months. In total, these projects added about 450,000 barrels a day of mostly heavy crude oil production that we were expecting to come to market. So, fast forward 12 months to where we're at today.
The situation is relatively simple sorry, is relatively similar. A fewer complete and production started to ramp. So, so far, of these projects, we've seen about 150,000 barrels a day come to market. That's what you've seen so far in 2018. There's about 70,000 barrels a day that was delayed due to economic reasons.
And so that leaves about 250,000 barrels a day that we expect still to come to market over the next 12 months. Now, our outlook beyond 2018 and the next 12 months is somewhat more tempered in the oil sands, primarily because a lot of these projects take a long time to kind of come to fruition. And the FIDs that a lot of companies were previously expecting to make over the last year were kind of delayed due to commodity reasons. So, our outlook is still for about 300,000 barrels a day of oil sands development beyond this kind of next 12 month stage, which is still healthy, but obviously the focus is going to be for the next 12 months. On the non oil sands side, we continue to expect to see a bit of growth.
Currently, we're producing just over 1,000,000 barrels a day of conventional light, heavy and condensate. We expect about another 200,000 barrels a day to come over the next 4 years. That's primarily going to be in the form of light oil and condensate, and that's due to an increase in drilling from a lot of producers onto the gas side of things. So, rolled up, if you look at this total forecast that we have, over the next four and a half years, we expect about 700,000 barrels a a day of production growth, and that's going to end us up at about 4,700,000 barrels
a day by
the end of our forecast period. So, the question then becomes, how are you going to move all of this production out of Canada? And that's been a lot of the discussion points so far in the last couple of years. If you look at this chart here, we overlay our supply outlook, which is the black line, which is also inclusive of all of your diluent requirements that you need to move the heavy crude on pipe against what we estimate is your takeaway capacity for the country so far. So, the key here is where the black line is above your area charts.
You obviously need additional takeaway solutions besides what's currently available by pipe. And so far, in 2018, what we've seen is rail has made up the bulk of that delta. So, currently, our rail movements out of Canada is about 180,000 barrels a day. The interesting point there is that now that's about the same level of rail movements that you've seen from the 2014 peak. So, in our estimates, as you move forward through 2018 2019, with the lack of additional real takeaway capacity coming on stream from pipelines, the question is really whether or not crude by rail make up the
delta. So, if we look at
kind of the shortfall a little bit closer, 2019, 2018, 'nineteen and 'twenty are really the areas where we see a serious crude by rail window appearing and a need for additional the 1,000 barrel a day range in each of those years. If you take an average over the year, which is what the chart below shows, 2018 2020, we estimate about 300,000 barrels a day required to move by other solutions other than what's currently available by pipe. And that's compared to what we're currently moving or have ever moved on rail at 180,000 barrels a day. So the question obviously becomes, how can we make up this delta? And will crude by rail really be able to make up the window?
And through our discussions with a lot of rail movers and facility owners, the nameplate capacity in Canada is anywhere in the 800 to 1,000,000 barrel a day range for crude by rail facilities. The downside to that is there's some significant congestion
on the
rails due to other commodity movements. There's facility constraints. There's labor constraints at a lot of the existing facilities. So, through our aggregated outlook, we pin the actual capacity somewhere in the 3 100,000 barrel a day range. So, the key there is that you're just barely making that through 2018 2020.
The key question is whether or not that can actually, through 2019, can actually move that much crude. The other side of the equation is these outlooks are premised on a lot of our additional capacity and takeaway solutions coming to market on time. Line 3 is the nearest term solution to those. And that's still 1.5 years away. That outlook has already been pushed out about 12 months.
And there's some other solutions that are scheduled to come on stream, which would make this forecast work. But the question is whether or not that those delays continue to happen. If that's the case, it opens the window for additional optimization opportunities as well as some other smaller pipeline movements to out of the country. And I think Harry is going to speak to that next.
At this point, we're going to go ahead and open up our first audience Q and A. I'm going to ask Willie, Harry, Jeremy and Luke to come back up to the stage. Roy Lamoreaux is going to field the inbound questions and zipping them up accordingly.
If you
do have a question, please raise your hand. We have up accordingly.
If you
do have a question, please raise your hand. We have microphones that will be passed about. And if you're on the webcast and want to submit an e mail question, you can do so at investorrelationscaalt dotcom.
Got a question from Brian Zahran from Mizuho.
Thanks, everyone. I guess looking at pipeline constraints, can you walk through a little bit
in more detail how you
expect 650,000 barrels a day of production growth between the end of 2018 2019 to get to market? How much rail trucking are you assuming? How do you think about refinery turnarounds in West Texas also constraining the system?
We can't hear very well. So the question was how are you going to get, call it, the production growth to come to market and how much of that is going to be basically take away by truck and by rail?
Yes. This is Jeremy. From our vantage point, I think we articulated how we feel about it. It's not going to all come
to market. You're going to
probably need to slow down activity because you could have the potential for shut ins in the scenario where we talked about because it's not feasible. The Permian Basin is not set up like the Williston to pipe into rail facilities and move unit trains out. It's just not set up that way. So you can't expect 4,000 to 600,000 barrels a day of rail to move. So kind of estimated, John will talk about this some more in detail, but in the neighborhood of 100,000 to 120,000 barrels a day of rail capacity and then the balance being trucked for a total capacity of probably 150,000 barrels a day to get out by non pipeline or local refining demand.
Your question on turnarounds, the refineries will be heavily incented to continue to run. So in those these periods, we've historically seen deferrals of maintenance and other things, but can only last for so long. So that would just make the problem worse to the extent you have extended shutdowns.
I might just add to that. I think when you look
at the rail takeaway capacity, the 100,000 to 125,000 barrels a day is what we think the load capacity is, but there are other logistical strength constraints. So you
might actually see the rail and
truck somewhere between 100, 150 in total is our sort of view today.
Yes. One other thing that's very difficult to do, but we're certainly focused on, and as you think about projects that are in process, anything we can do to accelerate that, we're pursuing as many of those opportunities as we can. Nothing to announce on that, but that's big focus for
us. Great.
Other questions? Hi. David Amis with Heikkinen.
Can you talk about any potential
constraints that you're seeing already or foresee in the future from
the intra basin perspective from
the Delaware interior long haul transportation? Not just you, but the industry is low.
Sure. Crane and Wink are currently prorated, but Plains is adding capacity this month and next month, increasing to the tune of 40% our capacity out of the wing. So we're going to have material increases in that area. Crane, we bring on capacity in the July timeframe. And
then a lot of this we're going to cover later on. Yes. Okay. Sure. Yes.
If we could maybe limit our questions to the or focus the questions on the fundamentals, it probably makes sense just because Harry is going to go through a lot of the movements that we're making and the expansion that we're making to our system. I'm not trying to cut off the questions, but just want to make sure we don't just run that completely. And I am going to go ahead and repeat all the questions. Just for whatever reason, the setup of this room is such that if you're on this panel, you can't actually hear. And we've tried to resolve that from last year.
But even with speakers, it hasn't fully happened. So I'm going to try to repeat your question. So keep it simple for me.
Is that better?
Yes. Go ahead.
I just want to focus on Willie's slide, Slide 18, Slide 19.
Slide 18 and Slide 19, Willie. Let me grab the
book. So just to start off, I think you were trying to make a point that S and L effectively base and kind of how you see that going forward? How much more can we grow fee based based on the dislocation in the ARPS today?
So the question was really on how we use the S and L business to kind of grow our fee based business and how it kind of helps our fee based growth?
I think it's Shneur or is it your question? Yes. Okay. I'll try to answer it. If it's not the question, start waving.
Your question is really around how do we translate supply and logistics to fee based?
Exactly. You sort of said
it like you mean it like it was a business development.
Right. Okay. So remember, so we've got a whole team that's out on the ground buying crude. My argument would be, if we weren't in that segment, okay, we wouldn't see the price signals as quickly and we certainly wouldn't participate in them. So, I think by being in the market and understanding the fundamentals better and talking with the producers, it allows us to move quicker on sanctioning pipelines than perhaps others would and it gives us 1st mover advantage.
And again, once you're what you're doing is you're taking the price signal, building a pipe, converting what you're going to capture now as an arbitrage into a steady fee based growth over a long period of time. Does that make sense?
That does. And I have a
quick follow-up. On the following slide, you talked about OMS.
I was wondering if you can talk about what the goal of this program is? Is it about cost savings over the long run? Is it more about optimization of your business? How do we measure the progress of that?
So how do you measure the progress of OMS? Is it cost savings or is it something else?
What's your objective?
Optimization. So obviously, hopefully, we it results in less injuries, less releases, impacts to community. Those are the ones that you can measure very easily, right? Those are the lagging metrics. Hopefully, we're also seeing improvements on sufficiency.
We can do things with less. We're more consistent, so we don't have as much rework. So you can accomplish more with less there. And again, the other one is consistency across the system, whether it be reliability programs, integrity programs. It just makes sure that we're on the same playing field across the company.
So we don't have one area that may not be inspecting something as much as another area. And it drives consistency across the company and just eliminates one off incidents and rework around what we do.
Ethan, I think you're next. Ethan Belkmann from Baird. Where is the ceiling on rig productivity? And do you have any changes in rig productivity in your forecast for these three scenarios? So kind of sealing rig productivity, yes.
Sure.
I think we alluded to the fact
that sorry about that.
You're starting to see diminishing returns in some of the basins as you get to really low levels, right? You can see the DJ's are the most efficient because it's a shallower reservoir and they're
just in manufacturing mode. And in the Eagle Ford, you're starting to see that as well.
Ultimate development ultimately, it will remain to be seen what the ultimate development plan is for each of the producers as to how they develop these 10, some it's 4, some it's 8, some it's 10, some it's 20 well pads. And so can you see a step change through that as you get multiple rigs on one location drilling horizontal rigs and horizontal wells and not having all the mobe and the moatons? Yes, you could. We don't know exactly what that is. We don't forecast that or improve well performance.
It's just not the way we've historically done things. We'd rather miss to the low side than be overly aggressive. And so is it possible? Yes. Are we forecasting it?
No. But we think it certainly would make sense as you get to more efficient development that you could have a step change, but you're going to start to get to practical limitations with current technology. So, I don't think we're going to go from the same way we went from 44 to 25 or you're going to go from 25 to 1? No. But could you see something inside of 25 days in the Delaware Basin shore?
Is that number close to the Williston at 19? 19? Maybe. But that's just kind of how we would think about it, but we don't forecast any of that.
Okay. Jeremy Tonet.
Jeremy Tonet, JPMorgan. Jeremy, just wanted to touch base on your outlook with Permian there. And it looks like it's kind of a smooth trajectory, but I imagine it's going to be kind of jagged over time depending on how things shape up there. Just wondering how
We think it's you have the it's really going to be dictated by when pipeline capacity comes on. I think that's where you can start to see step changes. Could you see completions accelerate to fill up when new pipeline capacity comes online. So as differentials come in, producers are incentivized to do that. So you can take some of the jaggedness out by this 3,000 and growing drilled and uncompleted well inventory, right?
Because if you think about that today, we have 3,000 wells there. You're completing 300 to 350 wells a month. You almost have 10 months of inventory. That's growing at 150 to 200 a month. So you could see 4,000 drilled and uncompleted wells in the not too distant future, which when the pricing signal and differentials get there, you can start to see production come on and fill that capacity as it comes in.
So the jaggedness will likely come from the timing of projects, but we think that having that shock absorber, which is quick turn completions of drilled and uncompleted wells, can start to fill it as the pricing signals get
there. Great. And Luke, looking at Canada, just curious if the need for takeaway is greater than rail and that booster wire basis, when did that start to slow down production? What level of basis impacts that? And how does that impact the planes business and I guess your forecast?
Yes. So we did kind of see that earlier this year when there were a couple of SEGI projects that decided to slow up their production basis. That was when you saw WCS dips in the kind of 30 plus range with a $60 crude price. So I mean right around there is where you would expect to see some impact. Out of the gate, you'd probably expect to see more on the conventional side than the oil sands side.
Those projects typically, once they tend to start up, they like to keep going. There's a lot of ramp up and ramp down associated with that and cost and such operational struggles if you do ramp them down. So you have to have not only a current price but an outlook that is going to
stay that way in order to see that as an impact. Over the
longer term, as these projects ramp up, that's a good question. What happens if your production continues to exceed your takeaway capacity? I think rail propensity to take up some of that slack, but I think you're going to need some additional pipeline optimization projects to take that up.
Okay. I think we've got well, we have one right here and then we'll go to you back.
Hi, Matt Smith from Stephens. With drag reducing agents, is basically all that can be done, already be done? Or how much does that factor into potential capacity additions through 2019?
Basically, the benefit of drag reducing agents or DRA through kind of 2019.
I'll take that. So we use drag reducing agent on the majority of our pipelines now, right? Not only does it debottleneck, but it's a power saving. So we've got DRA as part of the solution today. So I would say going forward, DRA, I don't think is an incremental solution for additional takeaway capacity.
Harry, could you speak to maybe DRA for do we have a sense for others' lines or just for ours?
I'd be shocked if everyone wasn't using DRA to the maximum extent possible.
Okay. Yes, Becca?
Becca Follow-up with U. S. Capital. Back to Brian's question, you're going to have to do this in part. So your forecast is 1.2 Let's say Let's say rail is 120, fueling at 1.1, let's say we've already filled up a couple of incremental, but we've probably got 900,000 barrels a day of incremental supply that's to be evacuated out of the basin.
Every pipe is full, what is it move on?
So the question was really if you back out rail and trucks and then you look at, call it, over 1,000,000 barrels a day of production that needs to clear back out the trucks and rail and you get to almost 1,000,000 barrels a day over the next year and a half or so that needs to clear the basin, how does that get out?
I think Harry is going to answer that in his section when he talks about the projects we have coming next.
Yes. Well, hold on. We will address it. But at the end of the day, as you saw from Jeremy's chart, it doesn't look like everything can clear. Over the next 12 to 18 months, you have that kind of volume ramp.
And
in fact, maybe to answer that question
a little further and also address Shneur's, back on OMS, it's making our system repeatable. So if we can be more reliable, less downtime, we can serve our customers better by producing or shipping more. So as I think about, for example, one of the long haul takeaway lines, right? Everything that we do on it, whether it be maintenance, whether it be inspection, if we can avoid a one day outage, you save 10,000 barrels a day over a month. So that's another big piece where OMS and
optimizing reliability efforts really pay out because now we
are very constrained. Reliability efforts really pay out because now we are very constrained. The system has to run at its capacity consistently every single day and OMS is a big piece of that.
Clearly, that's not going to get you 1,000,000 barrels a day, right? But every little bit helps and all that. And I think many of the producers or many of the pipeline companies are trying to do that, right? They're trying to just eke out a little bit every day a little bit more. Yes, Michael Blum.
Michael Blum, Wells Fargo. You said earlier that you thought the constraint would be, I guess, to Becca's expand a little bit about how you why you think natural gas won't become a limiting factor? And to the extent you have any views on what the Texas Railroad Commission may or may not do in terms of the flaring
So I can't speak from the regulatory side. But if you just think about it, they're drilling the wells primarily because it's an oil reservoir for oil production. So if the price of natural gas was 0, they would continue to complete wells. So the question is, how do they resolve that? How do they temper gas production?
And so there's a few ways. You can slow down your drilling in the gassier prone areas and concentrate on the wells that are 80% to 90% oil. A lot of the producers do have multiple places to allocate capital. You can effectively force the shut in of the heavier gas producing wells. So the system will balance and create space for the oil production.
So we use you're right. There could be an issue with gas. But if it's not the driving factor from an economic standpoint, we think gas will balance and crude will still push as much as it can to fill the pipes and whatever remaining way is out.
Great. I think that probably concludes this part of the session. We'll from this part, I think that we'll hear from Harry. And I'm going to go ahead and smooth these tables forward before you get going, Harry, so that we can our next panel will maybe
Thanks, Roy. I'm going to walk through our assets sort of from Canada all the way south and I'm going to spend my talking a little bit about some of the opportunities we see and we'll talk about some of the constraint points along the systems as well. So I'm going to start with this map that we've used in a lot of presentations. We used it earlier. It's our footprint in North America.
I want to highlight just a couple of things in this map. First of all, as you can see, we have a presence an asset presence in all the major oil producing regions in North America. Secondly, we have a very integrated system. We can actually take crude in to our system in Northwest Alberta, move it all the way down into Cushing and even into some of the takeaway pipelines that we own out of Cushing. One point that's maybe not as obvious on the map is if you look at the terminals that we own, we have terminals in almost all of the major liquid trading hubs in North America.
And then lastly, I'll just touch on our NGL footprint just a little bit. Our NGL assets are comprised 2 components. 1, our supply based assets are concentrated in Western Alberta or in Western Canada and Alberta where the supply exists. And then our distribution assets are basically in niche markets in North America. So we take sort of our lower cost supply and try and find niche markets for those in North America.
Like I said, I'm going to start in Canada and walk down. There's a lot of information on these slides. I'm not going to really try and read all the slides or convey all the information on the slides. I'm really going to try and describe the assets and talk a little more about the opportunity set. So if you start with Northwest Alberta, that pipeline extending from Northwest Alberta down to Edmonton is our Rainbow Pipeline system.
That's a pipeline system that gathers light crude from Northwest Alberta and also has the ability to source heavy crude from the Wabasco, Seal Lake and Peace River areas. All that comes into Edmonton. A little further east, we have 2 heavy pipeline systems, the Manitou pipeline and the South SaaS pipeline. Manitou moves Lloydminster type heavy crude and the Fort SaaS I mean, the South SaaS system moves a Fostertank crude. Both those pipelines are feeder systems into the Enbridge pipeline system.
And then back West, again, we have our rangeland pipeline system. That's a light crude oil pipeline system. It has the flexibility to move crude north and or south into the our U. S. Pipeline infrastructure.
So from a growth perspective, what we're looking at is we see a developing play along the rangeland pipeline of light crude. And our view is we think we can take that crude into rangeland and move it south into the U. S. On a cross border pipe there. And then the other growth area from our perspective is kind of in between the Canadian border and the South SaaS pipeline system.
There's quite a bit of conventional activity in that area and we think we're going to have the opportunity to bring pipe crude into our Wascana pipeline system, into our Bakken North system and really reverse the flow, move that back into North Dakota and access some of the takeaway capacity out of North Dakota. So to put it in perspective, there's 2 cross border crossing pipelines. When you look at, like Luca mentioned earlier, 700 barrels a day of incremental growth in Canada over the next 4 or 5 years, we sort of think 50,000 to 100,000 barrels of that is at a capacity that can move on our system into the U. S. Move down into the Rocky Mountain area, we're going to start kind of in Northwest Montana, that's our Western Corridor pipeline system.
It's actually comprised of 3 pipelines. It's a joint venture with Phillips 66. It sources crude from our Canadian pipes across border and it also can source Powder River crude into a station at Casper. So we take Canadian and Powder River Basin crude, move it to local refineries. For the most part, crude that isn't absorbed locally moves into the currency market where it can be where there are takeaway pipelines, including our Cheyenne pipeline that connects down into our DJ Basin pipes.
In the DJ Basin, we have interest in 2 joint venture pipeline systems. The White Cliffs system is a partnership where we have about 35%, 36% interest And Saddlehorn, we have a 40% interest in that pipe. Both those pipes move DJ Basin crude into the Cushing hub. Today, we've got a lot of underutilized capacity sitting in the DJ. And what we think occurs over time is, well, first all, White Cliffs recently or Semcrude recently announced that they're going to take 1 of the White Cliffs lines and put it into NGL service.
And then secondly, if you look at our volume growth expectations out of the DJ, we could easily see 200000 or 300000 barrels a day of incremental DJ production over the next few years. So we think that incremental production fills up the existing pipe capacity. So we think we see a clear path to filling up big pipeline capacity out of the DJ. We move into our system in Oklahoma. This is an area where we've had a footprint for a number of years.
I sort of look at our pipelines in 2 components. We have our supply based pipelines that can access crude from Kansas, from the Mississippi line, from the Anadarko Basin, STACK, Merge, SCOOP, all that can go into our existing pipes. There's capacity to handle some of the growth too and all that crude moves into Cushing. Out of Cushing, we have 3 takeaway pipes: our Midway pipeline system, our Diamond pipeline system in Memphis, our Red River pipeline system into Longview. And all three of those pipelines have some sort of joint venture arrangement with local refiners.
So they all have existing capacity where we can put more crude in and there are some expansion opportunities with respect to all three of those pipes. Before I leave the Mid Continent, I'll talk just a little bit about our Cushing terminal. And really the short answer here on Cushing is, it's the largest facility in Cushing, 25,000,000 barrels. It has the most connectivity in Cushing. We have 23 direct connections.
If you include indirect connections, we have over 30 indirect connections or over 30 connections. And then we just move a lot of crude to our terminal in Cushing. In the Q1, we moved about 1,500,000 barrels a day. And to put that in perspective, we estimate total flows through Cushing were in the 2,200,000 to 2,300,000 barrel a day range. So the unique aspect of our facility is it was designed the start as a hub facility, handle high volumes of crude, multiple grades, receive and deliver at the same time.
This wasn't this was a facility that was designed to be used operationally, not designed as a contango storage facility. Now moving to the Permian and really I'm going to divide the Permian in 2 parts. I'm going to start with the first part just sort of explain our asset base. I'll circle back in a few minutes and talk about the opportunity set out of the Permian as well. But when we look at our Permian, as Jeremy showed earlier, we're very bullish on the Permian.
There's significant growth potential. We could add 3,000,000, 3,500,000 barrels a day over the next 4 to 5 years out of this area. So our system is broken down, at least from our perspective, into 3 buckets. We have our gathering assets, which are in red and as was previously mentioned, it's heavily concentrated in the Delaware Basin. We have about 2,000,000 barrels a day of capacity in our gathering systems and today we move about 1,000,000 barrels a day to those assets.
Our inter basin systems are highlighted in blue and those are the pipelines that move crude from our gathering systems to regional hubs or to takeaway pipes, including third parties, not just our own one. So again, we have about 2,000,000 barrels a day capacity in our Intra Basin pipes and we have about 1,500,000 barrels a day on those pipes today. And then our takeaway pipes are in green. We have takeaway we have interest in takeaway pipes at Cushing, Houston and Corpus Christi. In total, our net share of takeaway capacity is about 1,000,000 barrels a day.
3rd quarter, those volumes on those pipes were a little over 850,000 barrels a day. So we have a little bit of capacity in those pipes today. Now like I said, I'll circle back to the opportunities in just a second, but let me just touch on the rest of our system. The last component is our South Texas, our Eagle Ford system. We have got gathering assets on the west end of the Eagle Ford and then kind of in the Karnes area.
Those gathering systems feed into our mainline system. The mainline is a joint venture with Enterprise fifty-fifty ownership. The mainline sources crude from both locally picked gathered South Texas production as well as Permian production from the Cactus pipeline. That crudes can be moved to Houston via connection at Lissy or down into Corpus Christi area. We've got connections with all but one of the refiners in Corpus Christi and several dock facilities in Corpus as well and really including our own dock, which will go in service a little later this year.
It's targeted to be in service in September and we'll have about 200,000 barrels a day of export capacity at that dock. The growth in this area could come from 2 ways. 1, we see some meaningful growth out of the Permian, we think I mean, out of the Eagle Ford, we think we can see another 4000 or 500,000 barrels a day of growth over time. That mainline system has existing capacity and it can be expanded. We could also see more Permian crude into this pipeline too.
So we see a path to having our Eagle Ford JV pipeline at capacity as well over time, okay? So I'm going to circle back to the Permian. I'm going to start kind of our near term focus, our strategy is really into 3 buckets here again. Really, we want to continue to expand our footprint and our gathering footprint in the Delaware Basin. And really what our objective here is to get our gathering systems out to production to meet flush production.
All these gathering projects are supported by either acreage dedications, facility commitments or minimum volume commitments. We also want to make sure that we can timely debottleneck our inter basin pipeline system so that we can handle the growth that we're forecasting from our gathering pipes. So that's both capacity into Wink is where we're concentrating and then out of Wink to Midland and to McKamey. And then lastly, we want to make sure that our takeaway projects are placed into service on time, okay? We've got 2 major projects, our Sunrise project that adds 500,000 barrels a day of capacity from Midland to Wichita Falls.
But the reality of the situation here is that Wichita Falls, we think takeaway capacity out of Wichita Falls is about 220,000 barrels a day. So when we factor this into our model, we only use 200,000 220,000 barrels a day of additional takeaway capacity. And our Cactus III pipeline system, by the way, that will be in service right the 1st of the year. Our Cactus II pipeline system adds 670,000 barrels a day of capacity. We're targeting initially in service October of 'nineteen.
So that will be serviced into the Ingleside area. Full service is expected to be achieved in around April of 2020 and that's the leg back into Corpus Christi. So partial utilization beginning in the Q4, full utilization Q1 2020. And believe you, we're fully aware of sort of the value proposition of putting these assets into service on a quicker time frame, accelerating the in service base. Willy pointed to that earlier.
We are highly motivated to do so. What I've shared here is sort of our current time line of what we're forecasting these lines to be in service. So we also want to touch on the fact, I think it was actually part of the questions earlier, is we've done a pretty significant ramp in volume forecast in 2018. We're forecasting over 1,000,000 barrels a day of growth out of the Permian Basin on our systems. And what I wanted to show here is if you just look at Q1 average to April volumes, you can see we're on track.
We've already added 450,000 barrels a day to our systems as of today. So we think we're on track to meet our volume forecast. And if we could talk a little bit about that later, but you'll see we've added VIAAM in April in all three categories: our gathering systems, our inner basin pipes and our takeaway pipes. Becca, this might be a little bit of what you were asking earlier. On an unconstrained basis, we see a lot more volume potential than what we think the logistics will handle, okay?
The red line indicates the pipeline takeaway capacity that we see coming into service between now and the end of 2019. And when you look at it, we're forecasting about 1,100,000 barrels of capacity coming into service, okay, 900 of those from our assets. We think other pipelines optimize, debottleneck, add some pump capacity, etcetera. So we don't have any other pipeline coming into service before the end of 2019 except for R2. The rest of it is just debottlenecking optimization of existing pipes.
We think there could be somewhere in the neighborhood of 100,000 to 150,000 barrels a day of truck and rail capacity that can be added to this. But the rest of this production growth, we think, is going to be constrained and you actually will not be able to achieve it on a constrained basis. Talk a little bit about the debottlenecking efforts that we have in progress right now. I'm going to start kind of chronologically. So the first project we had that comes in service occurs in June.
We had 200,000 barrels a day of capacity from Wink to Midland. And this is all debottlenecking really the Delaware Basin. In the Q3, we have 2 projects coming into service. We'll add 50,000 barrels a day on the ADDvantage pipeline system. That's a joint venture system with Noble.
We have 50% of that. That adds capacity into Crane. And we've got a pipeline expansion project from Crane to Macambie that has 135,000 barrels a day of capacity. In the Q4, we'll have a 26 inches line from Wink to Macambie in service that will help create additional debottlenecking for Wink. That's actually going to be the feeder's pipe for Cactus II.
It's just going to be in service much
older than Cactus II will
be in service. And then lastly, Q1 of next II will be in service. And then lastly, Q1 of next year, we've got a new pipeline system that's going to help keep up on some of the growth in the gathering systems and the kind of the state line El Mar area. That will be a 500,000 barrel a day pipeline from El Mar into Wink. And then here's kind of a high level shot of our takeaway pipes.
Again, it's got the existing pipes, basin to Cushing, BridgeTex to Houston and Cactus into the Corpus Christi area, the two projects that I just mentioned, the Sunrise Extension and then the Cactus II pipeline system, you can see Sunrise and Cactus II. They're both follow right away of existing pipes. So we're highly confident that we can get these pipelines in service and the time line we forecasted. Looking forward, whether it's sort of the next generation of projects on our horizon, we've got a couple of projects that we think are pretty efficient, low cost relative to other projects, alternatives to add capacity coming out of the Permian Basin. The first one we'll refer to is Cactus III.
So we have plenty of infrastructure being designed to take crude into the McKamey and Crane areas. And as I mentioned earlier, our Eagle Ford JV pipeline system has available capacity and expansion capacity out of Gardendale. So if we can just fill the gap between McKamey and Gardendale, we can add several 100,000 barrels a day of pipeline capacity out of the Permian Basin. And then I mentioned earlier, our Sunrise extension adds 500,000 barrels a day capacity, but there's only a couple of 100,000 barrels a day takeaway out of Wichita Falls. So the logical logic there is either an extension to Cushing or possibly even extension sort of east into our Red River system to go down into the Longview markets and markets east of Longview.
So that's sort of the next projects that we see on horizon from our perspective with respect to debottlenecking the Permian Basin. So we'll take some time for a panel discussion on the Permian. I'm going to ask John Keffer and Sam Brown and Jeremy and Tyler to join me up here on the Permian and Canadian logistics.
Hey, Brett, I'm going to or somebody that has a mic, can you do a sound test for us, please? I want to see if the panelists can hear.
Yes. Can you
hear me? Can you guys hear Al there?
Tess, can you hear me? Okay. We'll
see. We're asking questions from Mike.
We've been to a number of conferences lately and we've heard repeated questions, almost the same ones, time and time again. And I thought it might be helpful for us to recap some of those. We've also gotten questions from that we pulled in advance, and as Brett mentioned. And so what we've done is
we've tried to recap those, and
we thought it would be more efficient just
to hit those right off the bat.
And then clearly, we hope that we get time for more audience questions. To the extent that we're not able to hit those, then we'll have time during the breaks. We're going to have a 30 minute break right after this, so you can grab folks. We also have the reception and we have the game as well. So anyway, I thought I might just see on the first three questions.
I'm not going to necessarily read these to you guys. They're up on the screen. So the first three or four questions, I think those, Sam, I think were you going to address those? We're going to
tag team them.
Oh, you're going to tag team between you and Harry. Okay, sounds great.
So on the first question, takeaway capacity and how we can achieve our volume growth. In the slides that we showed you, we've been able to achieve so far, Q1 to Q2 being on target. And when you think about achieving the rest of that volume growth, I'll point out a couple of factors that we took into consideration in our forecast. So first of all, some of this is production that's currently on truck and it's going to go on gathering systems during the balance of the year and would also move on our inter basin pipes. There's also some of our gathering pipes that that volume is moving to 3rd party inter basin pipes and will shift over to our system as we continue to deep bottom that point to Midland.
And then the balance of the volume comes from growth. So the obvious question is capacity limited all the time in, how do our assets attract that much volume? And what we've tried to do is look at we look at the growth, who the shippers are, do those shippers have takeaway capacity, assess the capacity that those shippers have, and that's what we factored to our guidance. So again, it's a forecast. There's always risk when you forecast in the future.
But we think we have a reasonable basis to support our forecasted growth for the balance of the year.
I might add that there's multiple touch points on many of those. So as you think about gathering, intra basin and long haul, then the same barrel of production can have multiple touches as well. Okay, great. Far as how do we benefit from integrated system and then how do we segregate various qualities? Sam, are you going to hit that?
Yes. So I think it's obvious that we do benefit from an integrated pipeline system. And we benefit because our assets are complementary to each other. And it allows us to offer our producers the optimal transportation solutions. And we do this in a number of ways.
The first way is we offer them ratable flow assurance, which is really important these days, from the receipt points that we have to the market hubs, and we basically touch all the market hubs in the basin. And then by doing this, we give our important now than ever. In addition to that, we give them dependability. We have ample pipe capacity. We have ample horsepower.
But more than anything, we have ample storage. And because we have ample storage, we're able to adjust to weather events, production ramps and any downstream interruptions in connectivity that we may have. And so we describe our storage as kind of a buffer that allows us to keep producers flowing and ultimately keep the markets sourced in a ratable basis so they can run their units in their refineries. From a segregation standpoint, this is something that we kind of showed up on our radar about 5 years ago when we saw the Delaware Basin start to evolve. Historically, the basin has been 2 fungible grades of crude, WTI and WTS.
But as the Delaware Basin started to get developed, we started to realize that there would be varying qualities of crude oil like Jeremy touched on earlier. And long term, this could cause a problem because markets look for consistency in what they want to run-in their plants. And what you try to do is match up crude quality with markets.
So we put a lot of
foresight forethought, and we spent the last year last 5 years designing, building and developing an infrastructure platform that can segregate crude oil from the wellhead to the market all the way to the dock. And like Jeremy said, we've been doing this for a year from the Western Delaware Basin all the way to Corpus Christi. And we do it in a number of ways, but mainly we do it through dedicated assets. We have dedicated gathering systems that dedicate these qualities accrued to a, what I call, a small regional hub. And then from these regional hubs, we have segregated tankage that moves it in our pipes to all the export pipe hubs that leave the basin.
And so we're really just starting this development of moving crude in the basin. And over the next 5 years, you'll really see this become more and more important. And it takes time to develop this infrastructure.
Thank you. Cactus III,
are we pursuing Cactus III or an expansion to Cushing?
Yes, I'll take that question. I think we're going to this is all a result of the system that Sam and the Plains team have built, having the integrated solution from wellhead to market, having liquidity at all the market hubs. We become a natural partner or originator of any of the takeaway pipelines. So it's what that's what's allowed us to put Cactus II and Sunrise, the first two greenfield projects in service before any of the competitors. And we'll continue to look at opportunities, but we're not going to build just to build.
We're looking for what's the right solution the market needs. As Harry mentioned, Sunrise at Wichita Falls becomes an option play. We have additional capacity we can bring to market. It's a question of where is that needed. So, we'll evaluate, is that Cushing?
Is that Longview? Is that the Red River pipeline? Is it which ways do we need to bring barrels and what commercial opportunities do we see? So we have some options out of there to commercialize additional capacity for substantially smaller capital costs than the competitors. With Cactus III, we have unique ability to use origination facilities that we have on the McKamey side.
We have the ability to use excess capacity on the Eagle Ford JV or additional third party connecting carriers at Gardendale. So we'll have a lower cost option to bring additional barrels to Corpus from the Permian if the market dictates it. And it may be a matter of time. We may go out and see what's available at this point, see if that's where capacity needs to go. But longer term, we have that ability to bring that capacity to market in a lower cost solution.
In addition, because of the system we have, the liquidity we have, the access to numerous grades, we may look at other opportunities with other partners to other locations. So we're just going to keep our options open and look what the market dictates and that's where we'll put our capital as the best opportunity for Plains.
Great. Thank you. We've got a lot of differentials questions. I'm kind of surprised maybe that's I know there's a pent up demand for those questions in the audience. So Harry, can you describe why differentials widened faster than maybe we expected and what exposure we have to wide differentials?
Sure. So we'll take a crack at it. And listen, lots of things drive differentials. It's really hard to for anyone to grasp all the different factors that are impacting the differentials. But I thought what I'd do is maybe just start with our view at the beginning of the year.
We came into this year with the expectation that you would have more MVCs and volume coming into the year with some new pipeline capacity coming into service. But that by sort of August, maybe September, production start to fill up the pipes, you could be in a constrained situation by August or September of the year. So with that view, we actually hedge a fair amount of our exposure to the differentials between for 2018, making sure that we had the differential necessary to move product online, maintain shipwreck history and clear our commitments out of the Permian Basin. Why did the differentials widen out quicker? A couple of thoughts on what drove it.
But I think some of the contributing factors started earlier this year. Some of it was from an extended turnaround. The Fort Worth refinery had a 30 to 45 day schedule turnaround. I think that turnaround lasted probably 45 days longer. So what happened was a lot of crude went into inventory that was expected to be running at a refinery during the 1st part of the year.
So inventories built up, built up a lot of those inventories built up on the western end of the Permian Basin and the Delaware Basin. So that caused congestion and bottleneck issues coming out of the Delaware. Our thought is some of that congestion may have influenced the differentials in that March to April, May timeframe. Additionally, once the refinery went back into service, now that inventory has to clear. So that inventory filled pipeline capacity that we didn't think would be filled early in the year.
And now production kicks in. So we probably missed sort of the window when we thought production would start to fill up the pipes by a month or 2. But that's what we're seeing today is inventories cleared, filled up the pipes. As inventories have come to normal levels, the increase in production is starting to fill the pipe. So from an exposure standpoint, a lot of ours has been hedged away for 2018.
We think we have some meaningful upside in 2019 if we continue to see these types of differentials.
Thank you. Impact of gas takeaway, I think we've covered that. As far as how much volume we can take out truck and rail, we've heard that as well. Will Permian Basin crude oil takeaway capacity get overbuilt?
Yes. So from our vantage point, you've got ratable production growth and you've got step changes in capacity. So we just exited a year of 2.5 year period of overbuilds and now you're in roughly a 2 to 2.5 year period of not enough capacity. Our view is all the announced pipeline projects based on our production profile will be full. And so that's why we're working on the next wave.
But will you be in a period of overcapacity after these? Sure, for a period of time, but you'll grow through that. So we're planning on the next phase. We think because of all the reasons we talked about, more efficient rigs, better recoveries per well, advantage resource base that the Permian pipeline and the Permian Basin as a whole is a place for long term investments. And yes, you will have periods of overbills and periods of tightening differentials, but our intent is to stay ahead of it as much as we can and work with our producer customers to give them the flow assurance and that market access that they demand.
Competition in the basin and our exposure to margin pressures or recontracting risk given that there may be periods of kind of pipeline oversupply?
Yes. So, we've got,
I think, 3 main thoughts around competition going forward. As we've talked about, we've built a very large aggregation and distribution platform in the Permian Basin. And going forward, there will be a lot of upstream and midstream capital allocated to the basin and we think we've positioned ourselves well to participate in that capital allocation. Secondly, we've got an integrated pipeline system and we think an integrated system will be more competitive over time. It allows us to be uniquely positioned to adjust to changes in the marketplace and continue to offer solutions to our customers.
And then finally, we think we've done a good job in matching up both acreage and throughput commitments with our larger capital projects so that we've got tenor around both capital invested at the wellhead all the way to the dock. So those three things combined, we think, put us in a great position
quiet here. Can you talk maybe a little bit about our dock export capacity? And then while you're maybe you can transition into just the Cushing question, which is we've got a lot of questions really about is Cushing still relevant? What are the rates at Cushing? Do we see a lot of competition?
Our pipeline is going to get constrained out. There's a lot of questions that weaved in there about dock capacity and then Cushing.
All right. With dock capacity, Harry mentioned earlier the Corpus Christi dock that should be finished late this year. That will give us 200,000 barrels a day
of capacity.
At our St. James facility, we're expanding that dock. That should give us an additional 200,000 barrels a day, bringing us up to about 400,000 barrels a day at St. James. And lastly, we do have a terminal in Mobile, Alabama.
That capacity is about 150,000 barrels a day, although most of that is taken up with long term contract deliveries in or imports. There is some minimal export capacity there. We're going to see some coming up. So all in all, we have just a little bit over 600,000 barrels a day of export capacity
with the new by the end of the year. Got
it. Good. Thank you.
With regard to Cushing, it's a question that we've talked about several times in this presentation. The bottom line is pushing is still relevant, but I'll tell you why.
If you look at
the financial structure and what's going on, the CME consistently sees record setting volumes in open interest. And that's there's no exception this year. It continues to grow. There have been efforts to move the benchmark in other places in the United States. In spite of those efforts, the benchmark
is still cushy. Physically, we're seeing you can
go back to Harry's slide, I think it's 46 that talks about the volumes. If you look at that, volumes continue to ramp up. We also see substantial need for batching and segregation capabilities and we're providing those. So Cushing is extremely relevant. With regard to how we're positioned, I some most of you may remember a slide Greg had that comes to mind.
He had the Tier 1, Tier 2, Tier 3. We're in the central portion of the hub itself, which gives us the ability to have all the connectivity that was on Harry's slide. You look at that and then we're constantly looking at ways to improve connectivity, improve efficiency and capacity out. And a good example of that is we just finished a project where we've increased our capacity to deliver into the Ozark pipeline system, which just recently expanded.
And we're always looking at
those opportunities. Over 30 grades of crude today. If you take all of that and combine it, it gives our customers all the flexibility and all the optionality that they could want, which sets us ahead of our peers. The last question was what?
I think this one might be more of a
hairy question on we've actually recently gotten some questions on pipeline constraints out of Cushing, whether there would be constraints on pipelines leaving Cushing.
Yes, that's a great question. I mean, if you look at just the volume forecast that Germany's team has put together, if you look at DJ that can move into Cushing, STACK that can move into Cushing, Permian Basin that can move into Cushing. I mean, you could see 6,000,000, 700,000 barrels a day of crude pointed that way. Not all of it's going to go to Cushing, but it's conceptually a lot of crude can move to Cushing. So when we think about what's the restriction on takeaway capacity, today, as John just pointed out, Ozark has just completed 100,000 barrel a day expansion.
Looking forward in the near future, we look at the existing lines, we think the BP lines of Chicago has existing capacity. We know our three lines coming out have existing capacity. So we would place existing capacity today at about 200,000 to 225,000 tons a day that could be handled incremental volumes in. Looking forward, just at our own pipes, okay, we've got expansion capacity of capacity of about 250,000 barrels a day out
of cushion. That's not going
to happen overnight, but if you give it sort of a 12 to 18 month window, certainly quicker than the production rates that we see. So in total, you probably have pretty easily 400000 to 500000 barrels a day. There's some big pipes leaking Cushing going south. The differentials are there and the demand is there. I'm sure there's optimizations within those pipes.
We're just not close enough with those pipes to understand what type of optionality or flexibility. But I think there's certainly room to handle additional volume over the next 12 to 24 months out of patient.
Great. I'm going to skip ahead and Tyler, you've been awfully quiet. So with regard to Canada, I mean, how can you grow your Canadian crude oil footprint?
That's interesting, if everyone can hear me. The Canadian business really over the last decade has been primarily driven by heavy oil sector. Plains All American through its sub PMC really hasn't played that much directly in the heavy oil space. Now what's interesting from a fundamentals point of view is it's been tougher and tougher to get heavy crude out of Canada given pipeline constraints. A lot of the producer shift has gone towards some of the light oil areas.
And it's really quite nice that some of our light oil pipes and most of our light oil assets are right in the areas that have become quite popular with producers. So I'll start kind of from the north to south. I think if you refer back to Slide 43 just to kind of orient yourself.
If you take a look
at our rainbow system, surprisingly enough, up in that northern part of Alberta, now this is the one heavy play we've got. There's becoming a new sort of heavy window that's opened up near Nipissie that we're seeing that's quite interesting. Even though it's a heavy crude, it's a lot lower in acid and a lot lower in sulfur than some of the mined or SAGD heavies. We're seeing quite a bit of appetite for the market for that type of crude. So seeing some producers wanting to tie into Rainbow, which connects down into Edmonton and ultimately through Enbridge to the Cushing or the Gulf.
The other interesting plays, if you look sort of mid province around Edmonton and just to the of Edmonton, there's 2 interesting plays, both the Montney and the Duvernay. Those are sort of light oil and or C5 or condensate plays. We're seeing a lot more interest in those areas as well. I think we've talked about it in this fundamental slide where you'll see condensate in that area increase by a couple 1,000 barrels a day over a very short time period here. Both condensate and light oil in those areas are sort of those producing zones are right on top of both our rangeland and coed pipeline systems, both of which have spare capacity, so we can easily bring on producer barrels without spending that much capital.
Then when you move over to Saskatchewan, so move one province to the east just above North Dakota, just interesting whether it's the Shaunavon, whether it's the Saskatchewan Bakken or the Viking areas, we've got 2 major assets in Saskatchewan, the Saskatchewan pipeline, which is almost at capacity, so right for an expansion. And the Lascana pipeline, which is a North South pipeline between North Dakota and Regina. Again, pipelines right
on top of areas where producers
are drilling. So we're looking at several right on top of areas where producers are drilling. So we're looking at several projects to tie in more producers. Now you link that in with Harry's slide talking about a couple of cross border opportunities. We've got a couple of cross border projects and ideas on the go at the moment.
Western Quarter rangeland, we've got producers that are now actively tying in and looking for egress to go south and avoid the whole Enbridge apportionment issue. And same thing along Wascana, right along that border of North Dakota where the North Dakota Bakken is becoming quite prolific, we've got producer interest in terms of reversing our Wascana pipeline and taking light crude again down south into Trenton into our terminal down in North Dakota, again trying to get away from the Enbridge pinch points. So that's really conventional pipes. The one interesting bit I think about Canada that a lot of folks have missed is the low condensate growth. So if you
do take a look
at the Montney and the East Duvernay, you got 200,000 to 300,000 barrels a day of growth, which is just sort of west of Edmonton, kind of halfway up The condensate there is really interesting. It's a heavier condensate. So we're trying to figure out whether it's condensate or whether it's crude or yes is the answer to both of those questions. But we've got capacity to if it's condensate, coming in, But we've got capacity to, if it's condensate, come in our COIAD system into Edmonton together into our fractionation facility or if it's crude, we are looking at projects in terms of maybe new pipeline builds from the Montney into that Edmonton area for crude to come into Edmonton. So lots and lots of growth there.
The unintended consequence to all of that area is really the condensator crudes getting produced from a really liquids rich gas. That gas otherwise wouldn't be produced. I mean, AECO gas, I think yesterday was trading negative below 0. That gas would never get produced if it wasn't for that condensate trading WTI at the moment. So we're going to see fee for service on pipe, fee for service on truck.
Then the unintended consequence of more liquids coming into Edmonton is we'll see more fee for service around our frac plant in the Fort Saskatchewan area. So beginning to be a real fee for service story for us in that sort of changing economic and fundamental environment.
Thank you.
We had one more question that we've received a lot of feedback from investors on or questions about and that's kind of the FERC income tax allowance. Can you provide an update Harry on that and potential impact to planes?
Sure. I think the short answer is nobody knows what's going to happen with this. But just thinking about what the potential impact is, what's the range of possibilities? If you look at our FERC Form 6, our tax component is about 14% of our total cost of service. I think that's consistent with some of the work.
I think actually Becca did some work that showed that the average industry was about 15%. So if you start with that as a premise and you knock out 15%, the simple math is that would be a 3% reduction in the FERC PPIFG adjuster when the adjusters review it again. So that review would be in 2020 effective in 20 21. And then if you take into consideration that you're also going to eliminate deferred taxes and it has an impact on your asset base, your original cost. That reduces that 3%.
It's going to differ for every company. I think Magellan did an analysis where their actual impact was down to about 1%. But it will be different for every company, but it will reduce that 3% reduction. From our perspective, less than 50 percent of our tariff based revenue is tied to the FERC index. So that will reduce it again.
And then none of our facilities revenue is tied to it. So it starts
to get to be
a pretty small impact. When you look at the actual calculation, again, it's hard to tell what's going to happen. I mean FERC has used the middle 50 cost changes for the middle 50 percent of filers, cost changes for the middle 80% of the filers. They've used Page 600. They've used Page 700.
So there's a lot of variables involved. If you look at using the middle 5th year and middle 80 and then look at what's the composite of that? How many of those filers are corporations to Adventures versus MLPs? So honestly, there's a scenario where it could be 0, okay? If you use page 607, page 7 100, it might be 0.
If you get a number of filers that
are in that middle
of 50 or middle 80 that are C Corps or joint ventures, it'll mitigate it.
So today, the way the rules are, it doesn't matter whether
you're a taxpaying entity or not. The same adjuster applies to everything. Of course, that could change too. So very long winded answer of saying, not sure what it's going to be, but somewhere probably between 0% 2% of the
FERC base revenues.
And that would be kind of just foregone potential tariff increases. Is that right? Yes. In July of 2021. Brett, can you give us an update?
Are we at a breakpoint? Or should we entertain a question or 2?
We're at a breakpoint right now. We'll stay on schedule. I think we'll go through our 30 minute break at this
I'm going
to let everybody take their seats. We're going to go ahead and get started again.
Our next speaker is going
to be Luc Maggio, who's going to give us an update on our fundamentals around NGL.
That will be followed by Harry Pefanis.
Okay. So I'll start this section again kind of talking to give
you a brief overview of
what's happened over the last year in Canada as far as NGLs. So last year, when I spoke about the NGL growth in Western Canada, I primarily spoke about how we expected it to continue and that was going to be fueled a lot by the Montney development that we've seen, both in Alberta and in BC. This growth was primarily expected to continue, namely for two reasons. The first, liquids yields in this area for the gas production have been higher than what we've seen in a lot of other areas in Western Canada. And that's been buoying a lot of the producers' netbacks and fueling their drill bit activity.
The second reason is because gas production from the wells have been much more prolific here than other areas. And in addition to that, delineation has helped these producers find better spots for exploitation. And that's improved their F and D costs and full cycle economics. So you've seen a higher degree of concentration in this area. So as we kind of fast forward to today, the message really is unchanged from last year.
Over the last 12 months, what we've seen is an increase of about 12% from the total base C3 plus production, that's about 80,000 barrels a day. And over the last 4 years, just the Montney in the Alberta side alone has added over a Bcf a day of gas. So, like I said before, the reasons for that was higher liquids yields and better gas production. And really what we've seen over the last 6 months, in particular, you'll see in the graph there a big step up in the liquids production is a lot of additional field extraction that's come on stream, namely in the BC region that's helped producers unlock some trapped gas and as well as a higher rig count in the Northwest Alberta areas, primarily Grand Prairie has unlocked a lot of gas as well. So, over the next 5 years, we expect this trend to continue.
I don't typically forecast a lot of the big step ups like we've seen in this last 6 months. Typically, I'll forecast more of a steady state growth. But despite that, we're expecting another 150,000 barrels a day of production or a 30% increase from where we're at right now. And a lot of that is largely going to be, again, concentrated in the BC and the Alberta areas of the Montney. And a lot of that growth is going to be linked to additional gas egress, which I'll take a minute to explain in the coming slides.
So, if we view in on the Grand Prairie area, in particular, the graph on the left hand side you'll see has shown an increase in your rig count over the last two years. We've gone from a low of 22 rigs on average for the year in 2016 to today, we're upwards of 40 1 rigs in the area. So today, what we're looking at is north of 25% of all of Canadian rigs are focused just in this one small area of the Montney. And that's, like I said, a double over what we've seen in 2016. This area alone generates now 3.5 Bcf a day of natural gas and 160,000 barrels a day of your C3 plus That's 25% of your total basin production.
And that's in addition to the B. C. Area and other areas of the Alberta BC. So, if you look on the graph on the left, you'll see what I've been talking about. As far as fundamentals for the Grand Prairie region, the new generation wells that producers are drilling, namely over the 20 sixteen-twenty 17 timeframe, have gotten more than a 30% boost in their production rates.
A lot of that has been driven by higher frac stages, longer laterals. And primarily, one of the biggest developments recently that we've seen in the area is a move to pad drilling in the area. So, a lot of producers historically where they were delineating with 1 or 2 horizontals, now they're running pads anywhere between 6 to upwards of 12 wells per pad. And you're seeing these advancements come on and improve the production out of the area. So, our forecast for this area, keep your well results about the same and your current rig count flat for the forecast a day of C3 plus in condensate.
To put that in perspective, against that, a day of C3 plus in condensate. To put that in perspective, against our total Western Canadian forecast, that's about 2 thirds of our total growth for the region. So, if we look at kind of what all this means for Western Canada, one of the maybe underlying points that are forgotten about is how does all this gas kind of move to market? The reality is a lot of this growth is translated to exports that we haven't seen in a long time out of Western Canada. Our current supply of gas is 15.5 Bcf a day.
That's levels that have been higher than what we've seen in some time. So, what we've seen are 4 main projects that have come to light that are going to expand the egress for gas out of the area, help the long term growth rates of a lot of these plays. And you can see them. So Enbridge, Alliance and you've got your TCPL West and TCPL East Gates. Those are each each and every one of those are planning expansions for a total of about 2.5 Bcf a day of takeaway out of Western Canada.
So, if you look at our supply demand balance, which is in the upper right corner there, you see that we've got an increase in supply of about 2 point 7 Bcf a day. Like I said, 2 Bcf a day of that is attributable to the Grand Prairie area. And you've got a modest growth in demand of about 0.9 Bcf a day. So what that means is you require another 1.8 Bcf a day of exports out of the area over the next 5 years. Of the 4 projects I mentioned before, there's only about 0.7 Bcf a day that's going to be non Cochrane or Empress related expansion.
So that means that based on what we're seeing, we're expecting the bulk of those exports to come out of both East Gate and West Gate sources. And Harry is going to come and talk about
our opportunities related to that. Thanks, Luke. We don't spend a lot of time at these usually talking about our NGL assets and I get to feeling that probably we leave everyone with a feeling that it's a black box, our NGL business. So I really wanted to step back, take a high level view of the NGL business and try and break it down into kind of a more simple format of how we look at it, okay? So, I'm going to break it down into 3 components.
This is a map of our NGL presence in Canada. And when you think about our business, we start out on the Western Port part of Canada with our coed system. So that's the red pipeline system that originates at Cochrane and ends up in the Edmonton Fort Sask area. So we gather, say, 65,000, 70000 barrels a day on that pipeline system. It all goes into our infrastructure at Fort SaaS and it feeds our fractionator at Fort SaaS.
That is all fee for service business. Producers pay the transportation rate, they pay a frac fee and they can take the products back in kind at the tailgate of the fractionator. They can also we can also take title to those assets that apply at Fort Sask as well. So that component of the business is all fee based. If I move down into the Empress area, we have interest in several straddle plants at Empress and the TransCanada pipeline system, Eastgate that Luke just mentioned, all that gas goes through the Eastgate, flows through Empress.
And at Empress, our straddle plants can extract C2 and then C3 plus C2 all goes to local pet chems on a cost of service basis. We have the ability or the opportunity to extract the liquid. So we have low cost gas, probably some of the lowest cost gas in North America. We can extract the liquids and take advantage of the liquids to gas spread and move those use our assets to move those liquids into higher valued markets. So at inference, we also have the capacity to we have some fractionation capacity there.
So our fractionator can create spec products, C3 and C4, and those spec products move on what we refer to as our PPTC pipeline system. It originates at Empress and goes to Fort White. So there's local distribution of those and we can also access rail takeaway off of that pipeline system. The raw mix that isn't fractionated at Empress goes into goes up to corroborate, goes into the Enbridge system, gets shipped east to Sarnia. At Sarnia, we have a fractionator and we fractionate those that raw mix there.
And there, we take the raw mix and sell locally to demand centers there or move out of the Sarnia. So, in that component of it, we're taking sort of the location differential of lower cost liquids value on the West East arbitrage on that. It's a location difference. So those are 2 of the 3 components of our business. The third component is we buy NGLs from 3rd parties at large plants in the Bakken or in the Marcellus or the Utica.
So we'll source spec product there. We take advantage of the storage facilities we have in North America as well as the distribution assets we have in niche markets. So there we're playing a combination of seasonal difference, summer versus winter spread and location difference, lower cost supply sources to higher cost higher value demand centers. So when you think about our business, that's sort
of it. Fee for business,
fee for store fee for service business out of the Fort Sask area. We have gas liquids, frac spread out of the Empress area and then seasonal and location differentials by using our storage and our logistical assets. So a short
3 or 4 minute
high level summary of our NGL business. So I think what we'll do is I'll invite Tyler and Luke and Jason up We really have a little bit of a question and answer. We've got some prepared questions and then we'll take questions from the audience as well.
So with as much discussion as we've had about the Permian, frequently we get questions from investors that just say, well, is the NGL assets, are they core to Plains anyway? And so it seems like maybe a rhetorical question, but I figured we might as well lead with it since we get a lot of those questions. So Harry, were you going to address that?
Yes. Let me address that one first. So if you think about it, about a year, 1.5 years ago, we sat back and looked at all of our assets, okay? In the timeframe,
we were trying to make sure that
Go ahead. I think you're on. I think you're on, Harry. I just want to make sure that this Okay. Yes.
We want to make sure we had our could achieve our credit metrics We looked at all of our assets, took a hard look at all of them. And really what we concluded was that the NGL assets were strategic. They were complementary to our existing business, although not like entirely like the crude oil business. There are a lot of attributes with it. There is a lot of fixed fee business with it and we felt like we had incremental upside within our asset base.
So we felt like those were core assets and really the only assets that came out of that review out of Canada. We had a little gas plant in the Steelman area and another little pipeline that we felt like were non core would be available for sale.
Why are the NGL earnings in the S and L segment volatile? And what changes have you made in relation to the challenges that were experienced last
year? Great question. When you talk about NGL earnings, I'm really going to talk about 3 factors in terms of volatility. I'm going to talk about sort of financialspricing element is number 1, talk about the physical market, number 2, and then just talk about customer contracts, which I think may
have come up as a topic last year.
If you think about the NGLs business, particularly on the pricing side, our big exposure, particularly from our straddle plants, is we end up buying or sort of straddling natural gas, process that natural gas and produce a spec product like propane or butane. And you think about we take Aecogas in the West, manufacture that up a little bit, we send all that product out to an Eastern market for further processing our sales and then sell propane into, for example, the U. S. Northeast or the U. S.
Southeast. You just think about the several 1,000 miles that that spans and the different kind of market sort of fundamentals and changes that happen. So, you get a lot of price variability in that thing that we call the frac spreads. So, buying the natural gas, just traveling natural gas, tend to move up, maybe not always in lockstep,
but they tend to move up or
down with WTI. So as the price of WTI goes up, typically propane and butane tend to move up, maybe not always in lockstep, but they tend to move up or down with WTI. Weather is a big impact. So weather in East versus weather in the West can cause some dislocations. Just supply and demand, what is the supply and demand for butane at a refinery for any given time.
Then the big sort of evener that we saw last year was exports. So exports materialize in quite a big way and we're seeing export clear some of the cheaper barrels in the market, whether it's off the West Coast in the U.
S. Or East Coast U. S.
Now what we're trying to do to sort of reduce that volatility is we've got a very formal hedge program that we I won't call formal, we've got more structured hedge program that we've put in So, on a daily basis, our traders have a look at supply demand fundamentals, weather, shifts in our market and our product and they'll hedge off certain elements of that. On a weekly basis, we get together as a senior executive team, including Harry, and we kind of talk through sort of what does the week look like, what does next month look like, what does the season look like. And we make sure from a strategic point of view that we're really trying to smooth out some of that volatility and variability in that sort of price dislocation between gas in the West and products in the East. So, a lot of exposure, but we do manage it very, very actively and manage it on a very, very fine basis. On the physical side, you get a lot of volatility introduced.
I don't really talk about propane, that's kind of 70% of the liquids that we sell. If you think about propane, we can't predict the weather. Lots of folks try to predict the weather, but the weather doesn't necessarily follow nice even quarters and it really, really doesn't like to follow year end cycles. So, you tend to see a bit of volatility in our earnings either across the quarter where we might Harry may forecast some earnings and let that get released as a forecast earnings. We might sometimes miss a little bit on the quarter or by the year because weather didn't behave and demand didn't behave.
So, you see an occasion where it's colder in December, but we had forecasted a colder January. We'll pull some of those January sales forward into December and it will distort
our earnings a little bit.
Now we do do a little bit of hedging around that, but that's just volatility in our business that just doesn't go away. We manage it through our physical sales and through our physical assets, but you will see from time to time, quarter to quarter, over year end some of that volatility. The other bit around physical is demand, never really happens in nice hedgeable hubs. So you can hedge propane or butane at Bellevue in the Gulf Coast or more Midwest at Conway. But if you think about all the propane and butane demand across North America, it doesn't happen really nice and tight around those 2 hedging areas.
It often happens 100 or 1000 of miles away from those hedging areas. So, there's not really a liquid instrument available to kind of hedge away that volatility. So that's where
we think we've got a little bit of an
edge over most of our competitors. We have so many assets, whether it's on the producing side or on the distribution side between our storage, our pipelines, our trucks, our terminals that when we see dislocations in the market, we play kind of a goal seek game every day to find the premium markets to sell into and we've got the assets to come back us up to be able
to do that. So sort of take
we take advantage of market opportunity and sort of reduce the volatility at the same time, the closing arbitrage is very quickly on a physical basis. And then in the very last part, I think we you may have talked last point in the carry or last year on customer contracts. We're spending an awful lot of time with customers started this year and we're evolving, really taking away a lot of the optionality that was embedded in customer contracts that we as an industry gave out to customers. So we weren't unlike our competitors. We gave a lot of flexibility to our customers in terms of lifting flexibility around timeframes, volumetrically.
We're starting to take that back and actually charge customers for some of that optionality in the contract or limit the customer's ability to stack liftings early in the year or stack liftings later in the year, we're forcing customers to to chop up their liftings much more ratably as we go over time. And it allows us to better match up our hedges with those lifting schedules. So to do those things and we're making sort of tweaks every day to those. We started halfway through last season. You'll see that volatility in our earnings reduced because of some of those
just inventory valuation, the inventories are valued at our weighted average cost. And so over the winter cycle, you know how much you're going to capture, but that could float with which contracts that inventory is drawn against. So in addition to sort of the timing between Q1 or Q4, the inventory gets priced against the same the average cost gets priced against various lifting contracts.
So the changes what changes have occurred in the NGL business recently?
I'll handle that one.
I think the changes are really driven by supply, changes in supply and changes in demand. I think everyone in the room is pretty familiar with, from a North American standpoint, how much NGL production has grown over the past years and is expected to continue to grow. Luke talked about the Montney, we see forecast coming out
of the
Permian growth there. And then we've referred to it several times, the rapid extended and rapid growth of exports, primarily of propane, but of butane as well off of out of North America. And that really drives the change, but kind of embedded in that change and Harry talked about regional basis differentials with new markets, export markets and growing petrochemical use in the Gulf Coast and the U. S, it's really smooth the market out a little bit away from the seasonal and heating demands that Tyler talked about. So, we're seeing more volume, steadier markets, but also less volatility in seasonal and regional basis differentials.
And that's kind of a structural change in our industry. With our asset base, we really like our the flexibility we have in distribution, both geographically a wide geographic scope, west to east and our storage and terminalling presence throughout the U. S. And then, we do a lot of rail logistics and that gives us a lot of flexibility on where to point products. And that's really with changes in the market, it's given us an opportunity to evaluate whether we continue to use our storage for a regional or a seasonal basis opportunity that we see or we've got the flexibility and the geographic presence to divert to an export market either directly or indirectly through displacement.
And in Western Canada, particularly with Fort Saskatchewan imprint, we're well positioned for to be ready to meet growing petrochemical demand if and when that happens. And I can jump right into the next question because it's really tied. It's just where's the growth in the NGL business. Specifically, with our PMC business, it's really tied around what Luke and Harry were talking about. We see strong fundamentals for further volume growth and we've got a great footprint for increasing Montney production volumes coming into Western Canada.
We've got a great footprint for increased gas order flows to make more liquids out of that. And our 4th Saskatchewan asset, which I've gone into a lot more detail here in other years, is a really great footprint. It's full value chain from gathering mix to storing mix to fractionating it, storing products, terminaling and distributing products, both at Fort Saskatchewan and at Empress. It's a full value chain service we can provide. And we're well positioned for serving expanding Western Canadian exports off the West Coast.
There's 2 PDH projects that have been announced or talked about in Western Canada. So we see growing markets, we see growing supply and the assets are right in the middle of it, ready to really grow the fee based business that we were talking about.
Great. Thank you. And then as you talk to customers, how do you describe your the asset positioning and the system capabilities?
Yes. When we describe it to our customers, we're really changing up our business model from what we've done in the past. Jason touched on the fact that for our customers, if you think about on the producer side, we provide everything from gathering rate of the wellhead via trucks, we tie folks in laterals into, for example, our co ed system. We take that product right through pipelines, frac that product out in Edmonton. And typically, what we've done in the past is we would give our customers either a netback price at Edmonton, a bit more of a I'll call it a black box for lack of a better word, it just wasn't all split out in terms of the pieces, but we would give our customers as an Edmonton netback or if they chose to want some sort of eastern netback, we offer that out to customers as well.
But really forced a customer from wellhead right through one of those two options in our system and said, thank you, that's kind of it. It's become quite a bit more competitive in Alberta, particularly for those services. And we think that what we've done is really a bit of a breakaway
from the pack. It actually allows us, I think, to
earn a little bit more rent. We're giving customers now a choice, which is really quite a different thing for customers in Alberta, given we've got so few competitors that provide the same services we do in Alberta. You can choose to tie into our pipe or truck to our pipe or not. You can choose to ship on coed or not. When you hit Fort Saskatchewan, you can choose to frac with us or not.
After you frac with us, you can choose to either take your products in kind and go market them yourselves or we'll provide you a bid for them. But if you take them yourselves, then we'll offer a storage service and a rail service or not. And it's really giving the customers a choice and producers really have felt trapped over the years. I think they're really quite warming up to our offering where we can really chop up our business into pieces and provide customers more of a McDonald's menu board of choices. Now in that, I mean, you think, A, all great for customers, not great for planes, but along that, we are embedding a fee for service element to every one of those pieces.
And for customers to be able to pick and choose the pieces that they want, we're finding that they're actually paying premiums for those pieces. So I think in the end, some of those fee for service pieces and rents are going to be worth more than what we used to do as sort of a whole value chain in the past. On the demand side, I'd say what we offer out to customers is we've got a lot of our own proprietary production that comes out of Western Canada. A lot of it gets shipped as raw mix to Eastern Canada and fracked out into spec products. So we end up with spec products in the West, spec products in the East.
And we've got a distribution system really that takes all that product and pushes it down into the U. S. Into distribution terminals. We also engage in a tremendous amount of 3rd party buys and sells. So, from a demand perspective, we can offer our customer East or West exposure in terms of where would you like to buy your product.
We've got 22 different distribution terminals in the U. S. That we can supply at any given time. 6,000 railcars we can move product on. We've got pipeline space.
We've got storage. We've got all the bits and pieces that we can offer to customers. I think a very good solution in terms of moving a wet barrel to a market that the customer wants, particularly premium markets, where I think others don't go that far down the value chain. It's just something that we can offer out as optionality. And again, we're doing that now and moving a lot more fee for service for each of those individual chunks.
Would it be appropriate to what I'm hearing you say, and this is not something that I prepared, it's more just as I'm hearing you talk about this, it's more of a just flexibility on both sides, right? Flexibility on the supply side, flexibility on the demand side and being able to kind of tailor what it is that they want and where they want it. Side and being able to kind of tailor what it is that they want and where they want
it. Yes. I'd say that's fair, Roy. I think what's really changed what used to be a more North American trap market without exports really, I'd say, hamstrung both the producers and the consumers in terms of where do you put your product to get fracked versus where do you buy your product I think with exports, it's really become a much more global market. We're having to compete on that basis.
So we know we as industry no longer have trap players on either side. It's an open or free competing market and we're very happy to go compete on each
of those individual pieces and we've got the flexibility in
the asset footprint, east and west, north and south, up and down from wellhead to end use that we feel very comfortable covering all those spots.
I want to make sure that we have some time for Q and A from the audience to the extent that there is Q and A. So if you have a question, please raise your hand.
Jeremy Smith, Jason Morgan. So just touching on growth in the Montney and you've seen some good growth already in Peace Expand multiple times to take advantage of that situation. I'm just wondering what would you guys do kind of differently going forward to capture more of that growth against BPO's fully integrated value chain? Integrate that?
You're correct.
The Montney growth so far has been captured by Peace. We, in the past, have been out trying to develop another project. We still see some potential opportunities there. There's some other entities that have been out in the market trying to develop a project. And it is from a new asset investment standpoint, a long pipeline build, it is difficult to compete with existing infrastructure.
But we think with our presence at Fort Saskatchewan, we are tied into Peace. We take volumes off of there today. We are hopeful we can develop something from an asset growth standpoint to extend our value chain that way. But regardless of that, that growing production will benefit our assets, whether it's trucked in, whether it's railed in. Our high prairie fractionators, a small one we don't talk about right up in the Montney.
It's built up. Growing more production and piece expansions just bring more mix and more products into the Fort Saskatchewan area and we've got a great position there and a great footprint. We can expand there. We can provide all the surface value chain services we've been talking about to folks regardless if we're the ones or there's a 3rd party or it's more a piece bringing those barrels in.
Other questions?
I know everybody is just dying to hear about social responsibility, so we may move on. Okay. Thank you, guys. Appreciate it. As they're moving down, I might point out, we didn't really this is maybe a subliminal message up here with the crude oil samples on the table.
As you have time, it's something rather organic to look at oil in a Mason jar. There's something that just I don't know, it's very freeing to the spirit, I think. So, anyways, we do have just some samples up here. All these came from West Texas. And so, it just gives you a sense visually for the difference between the various grades of crude oil that we're handling.
And you can see the kind of almost, I don't know, maybe Gatorade looking pink over there, very, very different from this kind of flying green color that you might have. So anyway, just I mean trying to segregate that and keep it separate so that the refiners can get exactly what they want, clearly a big priority for us. Okay. So switching gears on the social responsibility side. There's been a fair amount of discussion of this topic in the broader capital markets among the banks.
We term the ESG or ESRM lots of different acronyms for it. And ultimately, we it's been
a focus of ours for
a number of years, but we haven't talked a whole lot about it. And so we thought it might
make sense to just take
a few minutes and talk about what the way we think about social responsibility of planes, how we manage our business, how we think about our business when it comes to these matters. So ultimately, as I think about what are investors really thinking about when they talk about ESG or social responsibility? And as I think about it, it's or bankers or even our communities, it seems as though they're trying to assess the soul of the company, right? You can look at the income statement and balance sheet and statement of cash flows to understand the financials of the business. And you can clearly talk about the fundamentals of the business, but what is the soul of the company, right?
How is the company run? How do we make decisions? How do we interact with our stakeholders? And what are
the core values of the company? And how
do we think about those core values? Ultimately, it's important for all of the senior management of our company to embrace and to move forward the core values of our business. And as we think about those, that's really what our social responsibility effort is all about. 1st, it's safety. We want to make sure everybody goes home safe at night, that we minimize our footprint environmentally and that we mitigate accidents and we reduce risk.
Ethics and integrity, it's really about doing the right thing. We're going
to obey the law.
We're going to act at the highest levels of integrity, honesty and ethics in everything that we do. We embrace accountability to all of our stakeholders and we're very active on this. As and then respect and fairness, it's really about treating each other and our stakeholders in a fair and honorable way.
As we look at kind
of the other elements of our social responsibility, it's really focused on continuous improvement. Willie talked about our operations management system in a very disciplined way in the way that we execute our business. And it's really identifying social responsibility are subsumed within our operations management system. And it's really something that we track. It's something we measure and that we execute upon.
This ensures that we have executive level oversight over the softer matters that you might say. And it really ensures that we're striving to do the right thing in all areas of our business. It's a mantra that we embrace. It's something that we talk about. And we actually have stories and of folklore within the company regarding doing the right thing.
And I'll give an example of that here in a moment. But ultimately, it's important for not us just to do the right thing for you but for you to know that we're doing the right thing. And I think
that part that we're probably have been
a little bit more, just by nature, modest on. I know Greg has frequently said that a whale only gets harpooned when it comes up to blow. And so we've really been we've been perhaps reserved on really speaking out about the things that we do from a social responsibility perspective. Numerous examples of elements that we do. I'll give a few of them in this presentation today.
But ultimately, we want to make sure that the focus of ours lately on the social responsibility side has really just been more disclosure and ensuring that investors have access to the information so that they can make their own kind of determination. We've made some updates to our website to with additional social disclosure. So that's on there. You can go and take a look. Up in Canada, we actually do a full stakeholder report and so that's available as well.
We're also participating in the ACI work group on social responsible disclosure and so making sure that as an industry, what can we do to try to expand the disclosure around social responsibility, particularly with respect to banks and some of the heat that they took around some of the project finance projects that have really brought that into the spotlight in the industry. We've also implemented just an example, we've implemented a 1st responder grant program within our social responsibility sphere. That's actually managed through my team. We particularly on we have a corporate program. We also have a 1st responder grant program that goes into the communities in which we operate as well as new pipelines as they come forward.
If we have a major new pipeline project, we may put in a 1st responder grant program. In certain cases, the 1st responders may be a volunteer fire department that's along the right of way. Even a modest donation to that fire department for either materials or training sometimes can have the impact of doubling their annual budget. So, it can be pretty meaningful impact. And it has the dual benefit of assisting the community and also ensuring that we have response readiness.
Another example of doing the right thing was just recently back last year, we had a we were notified of oil in Little Beaver Creek in North Dakota. This was near our Baker to Marmot pipeline. Before confirming who's responsible for release, we cut down our pipeline operations in the area, responded to the effective area and really implemented our emergency response plan. It was identified that this was not a Plains asset. And although it wasn't a Plains release, we recognized the potential for environmental impact and just acted as though it was ours or just responded nonetheless.
We had the assets. We had the people, so we could mitigate the environmental impact of this. And so we boomed off a 14 mile section of Little Beaver Creek. We stopped the oil migration prior to reaching the Missouri River. And many of the responding employees, I think it came actually over the weekend and on their time off to make sure that we were adequately staffed.
And this was a story that's talking about kind of the folklore of ensuring that we're doing the right thing that we shared throughout the company, placed it on our intranet. And just an example of trying to ensure that we are responsive in the communities in which we operate. Another one that we have talked about fairly widely within our organization is really even with our employees during periods of hurricane or inclement weather, There's been a massive outreach of both supplies, resources as well as labor going out with the floods. We had set up release stations for employees to come receive needed supplies. We actually had work groups that went out and locked out homes.
And then there's actually an employee assistance fund that will get funds to employees very quickly to ensure that their needs are met even before insurance monies kick in. And so just a few examples of the way that we approach social responsibility.
With that, I believe that I
will turn it over to Al.
During my section of the presentation, I'm going to review our financial strategy, touch on our guidance, also talk about some financial considerations for 2019 beyond and then also just give an update on PAGP's tax attributes. This first slide on our financial strategy is fairly consistent really since inception of the partnership. Probably the most material modification has been on how we execute it, I'll touch on that in a minute. We think it's been a key part of the success of the business strategy and our ability to grow over the years, again, really dating since inception. We focus on funding our growth capital with at least 55 percent equity or retained cash flow or more of late proceeds from asset sales.
We target a credit profile that is commensurate with investment grade for a midstream entity. We are very much focused on achieving and maintaining mid to high BBB credit ratings, a significant focus on maintaining prudent amounts of liquidity as well as managing our risk associated with interest rates and refinancing risk of debt maturity profile. I mentioned kind of the one tweak in how we executed and it's really the first sub bullet on the first point. Recently, we've taken a focus on attempting to minimize the amount of reliance we have on the equity markets, a focus on trying to fund the equity component of our capital programs on the current program as well as on what we think will be a more routine sustainable level with retained cash flow instead. So again, really a fairly important change and I'll touch on that on a couple of slides here in the future as well.
Deleveraging plan, we announced it last summer. We've made very good progress to date on this plan. We're not done, so there's clearly more work that we need to do, but we are very pleased with where we're at. When you look at the kind of the graph and the bar chart, shows total debt and then the lines show leverage metrics against that. Since we announced the plan in June 30, dollars 1,300,000,000 reduction in debt.
If you back up to year end 2016, it's actually a $2,000,000,000 decrease in total debt. The line shows substantial progress in our leverage metrics. Again, we're not done. We've got more work to do, but we're very pleased with where we're at and we are very much committed completing it. Asset sales are a key part of this.
This year's target was $700,000,000 We have roughly about $400,000,000 either closed or under contract. We're very pleased with where we're at. We are focused on if we can increase and actually sell more assets than that against this target, we will look to use the proceeds again to either reduce debt or to fund additional capital that I'll touch on in a minute. Our view is that debt will remain roughly flat from here over the next 3, 4, 5 quarters as we complete the plan. There will be some quarterly fluctuations in it.
But really the leverage metric will come in line with the cash flow growth that we expect. You heard a lot today about that growth. We've provided what I call preliminary shadow guidance next year of 14% to 15% growth in 2019 over 2018 from our fee based segments. That is the driver that will reduce this leverage metric and complete deleveraging plan as well as provide significant financial flexibility as we look at 2019 beyond. And again, I'll touch on that in a minute as well.
Liquidity, one of the pieces of the financial strategy, we've been very focused on that for a long period of time. I've used this chart for a number of years. The red line shows kind of the range of committed liquidity throughout the year and the horizontal line shows the average. At March 31, we had 3 $200,000,000 of liquidity. One of the things several years back is we did put into place a $1,000,000,000 3.64 day credit facility, kind of right on the onset of the downturn of the sector.
We have made a decision not to renew that in August. We're going to run with a little less liquidity. We feel very comfortable with that. We expect to still maintain very prudent levels of liquidity as we go ahead. Senior note maturity profile, in essence, another tenet of it, the fixed floating mix as well as the refinancing risk, key parts of how we look at our financial structure.
We do not expect to access the debt markets asset sales. Our next maturity, the bar shows 2019, it's not till December. So the profile looks great. Of $9,000,000,000 12 year average maturity, 100% fixed, 4.5% rate. And the little call out box on the top just kind of shows how it's migrated over time.
As we've grown the company, debt has grown, but we've extended maturity and reduced the average coupon significantly over that period of time. Clearly, a function of the interest rate environment that we've been in. Again, but that's part of why we want to maintain a high fixed component with attractive rates on our senior notes. Shift gears a little bit to our guidance. This is a similar format that I've used for a few years.
The top graph really shows 5 years of historical actual segment EBITDA and then also 2018 guidance on top of it. And really the takeaway, and I think Willie touched on this a little bit earlier, significant growth in the fee based segments, headwinds against S and L and obviously kind of offsetting some of that growth, fee based percent, 60% up to about 95%. The bottom graph really show the volume and the unit margin that supports the top part of the graph. Clearly, the dark blue, the transportation segment has been the driver and it will continue to be the driver for us in the near term. Over this period of time, segment EBITDA from the transportation segment in This goes through 'eighteen.
We expect that segment and the Permian underneath it is really the driver for the 14% to 15% as well, the primary driver of it as we look at our shadow guidance for 2019. Facility segment, a little flattish over this period of time. The last several years, less capital going into it and we've also sold a disproportionate amount of assets for that segment. And you all know the story on S and L, headwinds there, competition, fewer arbitrage opportunities against it.
Harry touched on it, I think,
a little bit in the panel discussion as well. But clearly, in our May earnings call, we left S and L guidance for 2018 flat at the plus or minus $100,000,000 explained it as we've taken positions with our assets and our business to really protect plan, which limits upside in the near term. We also commented that 2019 had meaningful more upside than wide. So clearly, 2019, we would build the capture more if they stay wide. Now while we have limited our upside in 'eighteen, and I think Harry touched on it.
Rest assured, we are actively looking to try to capture any benefit we can out of the Permian spreads, be it later in 'eighteen and carrying into 'nineteen. But I would note, if we are successful with that, again, it will be kind of like excess asset sales proceeds. It will reduce debt or fund capital. So again, rest assured, we're trying to capture as much as we can. Some key metrics relative to our 2018 guidance at more of an entity level, adjusted EBITDA up 10% based on our guidance, DCF up 25%.
We are starting to pay cash distributions on the preferred and clearly the Series B were issued late last year. So you can see significant increase there. But DCF available to our common unitholders, which is a metric we'll probably be more focused on going forward, up 13%. DCF per common unit, now that will be a metric we look at very much internally and you'll hear us talk about it more externally. The $2.03 that's our guidance, up 12% from last year.
Clearly, we reset the distribution. You could see the reduction there. But probably one of the more important takeaways is the retained cash flow and the common unit coverage, dollars 600,000,000 of retained cash flow versus not quite covering last year. And that's really a segue into my next slide. When we look at 2019 beyond, we believe we're going to complete our deleveraging plans in the first part of 2019.
We're forecasting and modeling significant EBITDA growth, as I talked about. The 14% to 15% preliminary shadow guidance, that's a little over $300,000,000 of growth. Dollars 500,000,000 of growth, if you look back to kind of this meeting a year ago, we provided, I think, in some pie charts here, a fee based operating leverage illustration and reference $650,000,000 of potential over time. Dollars 500,000,000 represents a decent part of that. Clearly, there's been more capital adds, that type of thing.
We've also had more asset sales. But as far as the capture embedded in our system, we're very pleased with the progress we've made against that illustrative assumption we showed you last year. Clearly, the Permian is probably progressing quicker and some of the other basins a little slower, but the bottom line of it is they're also growing as well. So we feel good about our ability to capture it. But this $300,000,000 of growth that we're forecasting over 2018, when you combine that with $600,000,000 of kind of excess DCF in 'nineteen, we think provides very significant financial flexibility as we look at 2019.
And as we think about it, clearly, again, that is before any of the S and L upside that we may be able to capture next year. So as we look at it and we get this question a lot, we think it's too early to try to communicate any specific actions we would articulate that we would do once we get the deleveraging plan complete. Rest assured, we're very much focused in the near term on completing and executing against the plan to actually deliver the EBITDA growth that we're talking about and get our leverage metrics in line. But I would say there are 3 considerations we could share. And clearly, the first one I touched on when I talked about the financial strategy.
We will be focused on reducing our reliance on the equity markets going forward, again, to fund routine CapEx. We think that's healthy. We think that's a good change. Not only we're not the only ones. I think a lot of the MLP sector is thinking about that.
That will translate into higher coverage by default than probably historic as well as less equity dilution, we think that will benefit again that all important DCF per common unit metric I mentioned on
the prior slide.
Even when the deleveraging plan is complete early next year, we are very much focused on getting our credit ratings back to mid to high BBB. We will manage our leverage and our capital structure with that important objective in mind. And then finally, the 3rd consideration and these aren't separate, they will all be balanced, but the distribution reduction we did was done to also partly facilitate deleveraging. The reduction was larger than what we needed to just reestablish coverage. And what I'm describing in this financial flexibility, we will it will allow us for distribution growth when we get the financial metrics in line.
But again, it will be balanced with the 2 points above, having running the company in a healthy way as well as eliminating the routine equity issuance that we've historically done. Capital program, I think Willie and Harry touched on this a little bit. The 2 year program was just under $2,000,000,000 very Permian centric. We are, as we talked about on our May earnings call, focused a little bit on trying to accelerate. We are looking at incremental projects that aren't in these numbers.
And so but too early to make any changes to it now. I think we'll provide an update on our August earnings call. If we are successful in increasing the program, again, the laundry list of things we're looking at, additional asset sales, non convertible preferred, private equity arrangements potentially or retain cash flow and again this excess potential excess S and L profit. We do not want to or expect to use common equity to fund what we would expect the capital program to be over this time. Cost of capital, this format is similar to what we've used for several years, but there's really one change.
We used to base it off of a distribution level as a starter. You can see here the DCF per common unit, that's really our starter. $2.03 Illustratively, we've used 20% growth, $2.44 results in 10.7 percent equity cost, 5 year excuse me, 10 year fixed rate senior notes for the debt component weighted and it's a hair over 8%. Clearly, it fluctuates every day. We aren't in the market trying to raise equity to fund growth projects, but this is the barometer of which we use to scrutinize and approve capital expenditures.
Historically, we've targeted and articulated a meaningful return above our cost of capital. That generally has meant 300 to 500 basis points. So 8% cost of capital would mean we would at least be targeting minimum returns of 11% to 13% on an unlevered basis. Clearly, risk assessment is a big part of reviewing any potential investment. And clearly, we would like more than 13%.
But again, really the subtle change here is the shift from distribution to a DCF metric. Just a quick update on PAGP. PAGP's sole asset is indirect ownership of PAA common units. We still get some degree of confusion in some people about exactly how this structure works. PAGP indirectly owns 157,000,000 PA common units.
It has 150 7,000,000 Class A shares outstanding, effectively a one to 1 link. This is a corporate way to own a PA common unit in effect. It is treated as a corporation for tax. If you own it, you get a 10.99 and not a K-one. And it has what we think is very positive and unique tax attributes that have meaningful amount of tenure to them as the sub bullets indicate.
This entity, we do not expect will pay corporate income tax for more than 10 years and we expect that it will be more than 8 years before the distributions will be treated as dividend income versus a return of capital. Final slide before turning it over to Greg. Again, hopefully, I've conveyed this, but we are very much committed to our financial strategy and completing the deleveraging plan. We see the growth of our assets and cap structure and credit metrics to where they need to be as we continue to try to retain and maintain debt at kind of currently flat levels. And we think as we complete that over the next 3, 4, 5 quarters that ultimately we'll have significant financial flexibility for the company again, which again actually increases our operating and commercial flexibility as well.
And with that, I will turn it over to Greg.
Good afternoon to everybody. And we're in the home stretch. I've got just a few slides and then we'll open it up for one more Q and A session. So what I thought I'd do is take a look at kind of looking back at where we've been and more importantly perhaps looking forward to where we're going, it's a very exciting future. Turns out 2018 marks the 20th year for Plains as a public entity and actually about the 25th year since we actually had the inception of actually forming a pure kind of crude oil midstream entity to take public as an MLP.
During that time period, when we went public in 1998, we had an enterprise value of around $800,000,000 a little bit less than that. Currently, it's around $30,000,000,000 If you were an percent ROI. Unfortunately, last 4 years have been pretty tough. And so if you invested during that time period, you haven't made nearly as good a return. In fact, it has been negative.
That time period has been very difficult on the industry in general and PA specifically because of low oil prices and increased competition primarily. In response to that, we took a number of steps that really started in 20 16 and culminated really in 2017 with the change in focusing on deleverage and raising the coverage. During that time period, we've eliminated the IDRs. We've shifted to a fee based focus. We've addressed the financial leverage and the distribution coverage.
And we've continued to strengthen the organization, both in terms of succession planning and also adding and recruiting new talent to develop it for the next 20 years plus. And we've improved our long term positioning in all the key basins, marketing hubs and demand centers. I'm proud to say that throughout the down cycle, we have invested in the future and we've steadily increased our fee based cash flow and maintained strong cash flow profitability. I've been in the business for almost 38 years and I've seen a number of down cycles where companies went from high profitability and high liquidity to low profitability or no profitability and sometimes running into financial strain. So through the last 4 years, even though we haven't grown as much as certainly we intended to grow, our EBITDA has remained within a range of 2 point $1,000,000,000 to $2,200,000,000 in net income as opposed to a loss of roughly $900,000,000 to $1,300,000,000 And importantly, during that time period, we've continued to execute on the business plan and we expect to generate very attractive growth in adjusted EBITDA, net income and DCF per unit.
And that will be driven primarily by the fee based activities with S and L adding additional upside, not so much in 2018, but certainly in the late part of that and into 2019. We've continued to improve and will continue to improve on the leverage profile and the distribution coverage. And as Al just emphasized, we're really focused in on growing from internal fund sources to be able not to be reliant on accessing the common equity markets. So we minimize dilution, we maximize growth of DCF per unit and that will be the common theme that you'll hear going forward. This is a slide that Willie mentioned the last part of his presentation, just really reiterating kind of what we think the key takeaways are from today.
It's very solid industry fundamentals volumetrically with Permian being a major driver of that outlook. Plains has very strong asset positioning with the premier Permian franchise and it's really our core growth asset that we see going forward. And then again, we'll focus in on the execution the deleveraging plan, the capital program, the many commercial opportunities that we see and as Willie mentioned, operational excellence. So we're focused in on basically reinforcing your confidence in us through prudent management, consistent transparency and staying true to our core values and we characterize 2018 as a year of execution. As the very last boxes, we very much sincerely appreciate your continued investment and support.
With that, we can then open up to the last Q and A.
Okay. I promise no real canned questions so far, except for one. I mean, there's a violate on the one. We've had some questions on kind of the recent tariffs by the administration and potential quotas, so tariffs on steel imports and potential quotas. And I'm just curious on the potential impact to Permian production growth from this development.
So I got this question yesterday as well at an EIA conference in DC. I think everybody's kind of focused in all that production is rising much faster than we're able to keep up with and take away build a takeaway capacity. I think Jeremy touched base earlier, it's kind of like a sawtooth where production rises and fills up excess capacity and then you add the next pipeline which creates more excess capacity. So we're right now in that place where we're approaching full capacity. There's 2 pipeline projects that are coming up.
Ours, the Sunrise project that extends, I think it will start here January 1st is the target date and then Cactus II. The Sunrise project steel has already been ordered and being delivered. On the Cactus II. We shared that we basically ordered from a European mill that makes the type of steel that we need to meet our customers' needs. The quotas we think would be unjust simply because we shouldn't be penalized for basically buying foreign what we can't buy domestically.
Just seems bizarre to have to pay a tariff.
Or the tariffs, you mean the tariffs.
The tariffs,
I'm sorry. The quotas standpoint of it is to be unworkable, because quite candidly, if they impose a limitation on the steel order that we have and only 80% of it's able to be brought into the US. If you think about it, 80% of the pipeline really doesn't do us any good. It's kind of like only 80% of a bridge. It's kind of pretty to look at, but you can't get across it.
And the theory on the quotas right now, and I don't want to take the analogies too far, is like going into a shoe store and tell them you got a size 12 foot and said, but all we're selling is size 8.5 shoes, buy 2 of them. And so we think that hopefully we've applied for the exemptions. We've got the steel on order. We think the tariffs would be unjust, but we could tolerate the quotas would just be unworkable. And if it were successful, if you can imagine, if we're that far ahead of the group and we can't get the steel in, the mills can't make
a lot of what's in the U.
S. What we need for the Permian. So it would just basically extend and delay the growth ramp. So we think it will actually be worked out because it's common sense.
Okay. Thank you.
Shneur? Hi. Shneur with UBS. Just I was wondering if we can talk about CapEx or the potential projects, for example, CAC3 and also the Wichita Falls extension. It sort of seems like there are shorter routes.
Just wondering if you can give us kind of a zip code of what we should be thinking about of what the CapEx could be if those projects FID? And then secondly, how long it would take to put them
into service once you FID that? Yes. Why don't I take a stab at that, Shneur? When you think about those projects, I wouldn't think of them as large mega projects, right? And then when you factor on top of that likely a desire to do that with someone, really makes the project pretty bite sized as far as going forward.
As far as time line on most projects, Harry, what would you say to once you FID a project?
Yes, those are projects that are probably 18 month projects from the time they be approved. You don't have the right of air permitting challenges that you have with some of the other pipes. And maybe to put it a little bit in the perspective, I think if you want Wichita Falls to Cushing, it'd be under $400,000,000 Cactus would probably be $500,000,000 range. So those are these kind of estimates, okay? They're not prime tuned yet, but certainly a fraction of the cost of a new build coming out of Permian to Cushing or to the Gulf Coast.
One of the comments
I might add, just like on Cactus III with the amount Perry talked about, obviously we'll be tying into a pipeline that we own 50% of. So we had a 50% partner, we cut that number in half. So very manageable capital, but very significant incremental upside opportunities.
And much of the capital requirement would likely come after kind of the deleveraging event if that were to
you'd spread the cost over a couple of years, typical S curve on a construction project.
And one follow-up, you've been funding a lot of your CapEx for the last year and a half with asset sales. How many non strategic assets are left to be sold as we start thinking about 2019 2020 or if we kind of hit the end of the non core strategic assets?
I would just probably point out at the right price strategic turns into non strategic. So I think it depends on the market. One of the things that is clear out there, there's a significant amount of capital looking to be put to work in asset sales and
I think it's very similar to it. So the other thing is we sold assets that may be considered strategic, but they've been fully valued or we bought joint venture partner in that adds even more value to the assets. So they haven't all been sort of non strategic assets. We've got one question over here. Thanks, Chris.
When you think about the
So, Eve,
do you mind giving us your name?
We all know you, but the webcast folks don't.
When you think about the opportunities set ahead of you, do you see any additional sort of mega projects? Or is it fair to say that the global CapEx will be of this pro rata we're bringing for the foreseeable future so that it is really a manageable type of number.
Certainly, our expectation
will be in the
manageable piece for what we see now.
I think one of the things, I mean, there may be larger projects, of which we would have a portion of it. I think one of the things that we're seeing right now is that having joint venture partners, I think we'd all rather build everything 100% ourselves. But as a practical matter, if somebody comes to us and says, I'm willing to support or underwrite a project, but I want to be able to buy a meaningful percentage of it, and it puts us ahead of the pack and gets a reasonable
return and lowers our risk. And so the very
return and lowers our risk. And so the very process of that can take a couple of $1,000,000,000 project and turn it into a bite sized project with a very attractive rate of return and yet let us leverage off what I think we're very, very good at, which is building big projects and delivering it on time and on budget.
Jeremy Hinman, JPMorgan. Just trying to reconcile a few things in the guidance together. You guys talked about 3.8 1,000,000 volumes of Permian, yet you're already at 3.7 in April. What makes you think you only averaged 3.8 for the year? And then the other side of that, in the 2Q, it looks almost like transportation might be going down just because it's such a big step down from Q1 to Q2.
I was just wondering if you could help me reconcile these different items.
I can take a shot. Clearly, we put the 3.7 for April, which it's June. So we know what the number is. We've closed the books for April.
We put
that in there to hopefully communicate that the growth is coming. It's here. We're seeing it. Clearly, the average 3.8% for the year, we need the back end of the year to be above 3.8 because the Q1 was below. Again, we're pretty comfortable with our numbers.
We balance the export pipes. We look at that. And so we think we got a good start on 3.7 with April. And again, the one point that maybe people didn't catch since we don't provide quarterly segment guidance on an EBITDA base. But we did, when we provided guidance in early May, talked about that the Permian volumes would see meaningful growth each of the next three quarters.
Maybe that got lost as to how some folks have interpreted that. But no, it's we fully expected in May and in our original plan to see growth each quarter.
I might just Jeremy, I think if I heard your question right, what made us think it wouldn't be more than 3.8.
If you think about
it, we were 3.3 or 3.2.50, okay, in the Q1. Let's say we were 3.7%, 3.7%, you got to be above 3.8% to exit the year. So I think the answer is the exit rate by default has to be meaningfully above 3.8%, okay? It's just a question of how you run the average. But we start off with the Q1, which had some weather impacts.
It had some of the production ramp really hadn't started as much as it has now. And so by default, you're going to basically exit the year at meaningfully above 3.8%.
And don't forget, the Q1 had the arbitrage wasn't open for a good portion in the Q1. So barrels weren't incented to flow on long haul lines.
Just the Q2 guide, it kind of appears low relative to the Q1, appreciating that there's seasonality there. But is transportation EBITDA stepping down quarter over quarter there?
Is there higher O and
M or are we reading too much into this?
No, the transportation when we step in there, it's seasonality of the aggregate EBITDA ramp. So we'll end up with I think last year we had negative EBITDA in S and L in the second quarter and also the Q3. So that's going to basically offset some of the growth that's in there on the transportation side. But the fee based, I think, is pretty steady on a
up into the right throughout the year.
With the exception, there's asset sales that we'll have in there that could affect primarily facilities.
Yes, you get some quarterly flux on operating expenses, but the transportation segment adjusted EBITDA generally follows volumes.
There is also noise with operating expense. We'd also talked about this on the S and L side that there was some benefit to contango in last year's Q2 that we're not getting the benefit of this year's Q2. So that's some impact on S and L as well.
And then just philosophically thinking about S and L here, you derisked some of your guide this year when you saw spreads at a rate that made sense. When you look at the rest of your ethanol exposure over the balance of 'eighteen, whatever's left there and as you look into 'nineteen, how do you think about taking risk off the table, locking in some of those margins? How do you go through that trade off in your mind?
I'll take a shot at that.
Everything we've been trying to do is
to build the fee based growth, right? So when we think about and we've been trying to deemphasize S and L because it's a difficult stream to quantify and the stability of the earnings stream in S and L is very different. So if we look at a project and we say we can use our differentiated capabilities to help anchor a longer term fee based growth project, we'll do that all day long.
Yeah. I think Tyler touched on it earlier when he talked about our frac spread exposure. I mean, we're continuously looking at our exposure, looking at opportunities to reduce the risk in our business. But sometimes there's also risk if you hedge too much, right? So it's a balancing act and it's a combination of what our fundamental views are and the risk opportunity that we have the opportunity we have to take risk off the table.
I think it's fair to say, though, that if there's a $100 bill laying on the ground and we can pick it up, we're going to pick it up. I mean, that's kind of goes without saying. Any other questions? Just mind that you're standing in the way of drinks with all your
questions.
Going back to your Permian debottlenecking slide, you've got a lot on here and appreciate the initial disclosure. Does that get you through all of the long haul projects that you've already announced in terms of being able to get your barrels from one side of the basin to the other? Or is there more to come in 2019 in particular in terms of debottlenecking the Plains and Systems in the basin?
I think we walked through everything that we have on the table for 2018 2019 to debottleneck the inter basin systems. Was that your question?
That gets you through Cactus and Sunrise and then when you think about Cactus III and Sunrise II, do you need more debottlenecking? No. Okay. Thank you.
Thanks. Keith Stanley with Wealth Research.
The aspiration to get to mid to high BBB
on credit ratings, does that align with the 3.5x to 4x leverage target? Or would you require incremental debt reduction for the agencies to put you to that level?
The target we have is commensurate with that. The question will be how much that's a long term metric. So the question becomes is how much short term debt do you have? What happens with our preferreds? But no, we it is commensurate with it.
Again, we intend to operate with over time to achieve those ratings. Again, the preferred part of our preferred structure is convertible. We'll see what happens with that. Clearly, we've tightened down the short term debt component. But clearly, the growth in cash flow that we're seeing will ultimately bring our leverage down and we intend to operate in those in that band or near the bottom of the band depending on to have some operating flexibility in it.
Getting to mid or high won't happen overnight, we expect. But that's the direction we want to go.
Yes. I might just add, you asked the question, does it require more debt reduction? Effectively, I think what Al touched on earlier is that we'll get to those credit metrics simply by holding debt relatively constant and having the EBITDA growth as these projects come on. And when we put our deleveraging plan in place in basically the August of last year, we targeted early to mid-twenty 19 as the point where the combination of debt reduction through the asset sales and the growth in the EBITDA from the fee based part of it that we felt very comfortable with because it's primarily contracted enough to us to execute on the construction side would allow us to get there. So I think what rating
agency then takes action. But I think
the fact is that we're rating agency then takes action. But I think the fact is that we're defining it based upon the fee based part of it. And as I think everybody in this room knows right now, there's incremental upside opportunities through S and L, through our asset base that we're could help either reduce debt or fund incremental fee based cash flow, which would then further improve our position. So we're going to be knocking on their door or these guys are going to be knocking on their door in the middle of next year. I think let them know we got to where we said we'll go to and we're hopefully we'll overshoot that.
I mean the whole goal is to reinforce the confidence from everybody in this room and on the Internet that we're going to under promise, over deliver type approach and that includes not only on operations but on basically financial management.
Chris? Chris Sighinolfi with Jefferies.
I just had a calibration question maybe for the 14% to 15% fee based EBITDA growth next year. Just given that several of those projects that will drive that are not wholly owned by plants, but you do have a majority position in them, Sunrise and Cactus.
Are we including 100% of
the EBITDA in those projects to drive CECLIFIs or is
it just the net interest?
Net. Okay. And then with Cactus too then, how do you what is the ownership you're assuming in that? Because I know it can be worked down to, I think, 65%. Is that what you're assuming?
Yes. We've assumed 65% ownership. It what you would expect, but it is in there at the 65%.
Great. Thanks.
I have a question actually that was submitted online. It was from Doug Christopher from D. A. Davidson. He says, any chance Line 901 will ever return to service?
Well, we have a permit filed to replace Line 9 0 1 and we're advancing the permitting process. So it's certainly our goal to replace 901 and provide service again.
We have a willing customer and we have a willing builder. We just need a willing California.
Understood. Vikram, I think we have a question here.
A couple of questions on Cactus. Vikram Badri from Citi Research. You bring 1st wave of Cactus to online in October. How much volume will Cactus move then? And will there be a step change in volumes in April of 2020?
How will the volumes ramp up on Cactus? The second question I had was that it was sort of it seems like if there was a delay in bringing the pipeline online at least based on my assumptions. Was it driven by tariffs? I heard some rumors about construction being difficult around Corpus Christi area. And do you foresee all the other peers facing similar issues and delays in infrastructure coming online next year?
Yes. So can I take that? Cactus II originally, I think the original comments from us was that it was a Q3 in service date, but it was always late Q3 September timeframe. So Q3 is such a wide July to September 30 is a pretty wide band given the constraints. And just giving sort of the normal permit and right of way environment, we felt like it was more appropriate to have a in service date of October 1 rather than a wider timeframe of Q3.
So to the extent it was pushed back in sort of our model, it was only pushed back a matter of weeks. As far as volume is concerned, it will be able to move the whole 600 and 70,000 barrels a day. The issue is going to be takeaway capacity since we won't be since some of the markets are in Corpus Christi. So I think a reasonable assumption is going to be 300,000 to 400,000 barrels a day would be able to move to markets into the Ingleside complex. It's going to be a function of the ability of the docks and infrastructure at Ingleside to take the volume.
There are 2 legs, right? One goes to Ingleside. The other one goes to the Corpus Christi ship channel. So there's a delay in that. The lengthier one is the Corpus Christi ship channel really around permitting, which we're currently working.
But that's the 2 different legs that are
going on.
I think it's fair to say whether it's us or anybody else, the more complicated lays of the pipeline are when you get into the highly populated areas. And the ability for us to get from McKamey to Gardendale with Cactus II is going to be much quicker than it is to get to that last leg. I think your question was how would others be impacted by it.
I think the rules are
the same for them as they are for us. And for some of those, it will be a build of first impression. We built 2 20 inches lines from Gardendale to Corpus Christi or the Ingleside area. So in some cases, we'll be twinning very closely what we've already done.
Realizing, we want to honor kind of the time line of the meeting. We'll run a little bit over. We'll probably have room for one more question. So Vikram, if you can hold yours unless there's somebody else that okay. You get last 4, Victor.
Did you have something else or were you done?
On Sunrise 3 expansion, is it a factor of Keystone XL getting built and Capline getting reversed and you expand Diamond Pipeline? You mentioned you have capacity on some of your pipelines to move more barrels out of Cushing. Is that a function of Capline reversal ultimately or there is a way to build that, expand the Sunrise pipeline without CapEx getting reversed? Those CapEx getting reversed, I'm sorry.
The Sunrise extension 3 or Sunrise extension? Yes, so they are kind of independent decisions. But the ability to say expand a Diamond pipeline, you would need an outlook like Capline to fully capitalize on a diamond expansion. There's incremental capacity that could be utilized, but to fully develop it, you need something like a cap line reversal.
I think the gap is to me and we've got a partner on that, but I mean the gap between the end of Diamond and Capline is
10 or 15 miles? That's 35 miles, but our partner has some existing lines in that corridor. So that might be a utility.
Yes. Flow used to go the other way, right?
And I think Jeremy touched base. I mean, the market will help us figure out what people are willing to pay for. And I think it's not only the economics that Jeremy mentioned, but the time. I mean, for example, Cactus III, I think would be a much more expeditious lay to Gardendale to tie into that excess capacity than a brand new line would be at this stage even if we started at the same time we should finish much earlier. And then the same thing is true on Diamond, let's say, the Capline or whether it's Wichita Falls not to Cushing, but maybe to Red River.
So again, just shorter lays known territories, etcetera. So the benefit of having a very large integrated value chain systems is in this type of environment we're probably well ahead of somebody that's trying to build a greenfield project when we're building what's truly a brownfield project.
I think it's fair willy, wouldn't you say? Yes.
Before we shut it down, sorry about that, really as everyone here knows, this will be Greg's last Investor Day as CEO of PAA. And Willie, Al and I on behalf of the entire organization, PAA organization, we'd like to thank Greg for his leadership over the last 25 years That's his SPAA. He's really set the tone at the top. He's been an unbelievable leader through both the peaks and the valleys of this business. So if you guys would join us for just a minute and thank Greg for 25 years of leadership with PAA.
You very much, everybody. Thank you for coming. Those on the webcast, appreciate you joining.