So thanks so much for joining us here today. My name is Cameron Goldade. I'm the Vice President of Capital Markets with Pembina. I really want to thank everyone for attending. I know it's a busy time, but we really do think we're going to have a lot of interesting new information for you.
It's a very exciting time at our company, and there should be lots to talk about here today. So want to take a moment and just alert you in the unlikely event of an evacuation. Please use the stairwells located across the ballroom foyer and proceed to the muster point, which is located in front of Union Station on Front Street. If there is a need to evacuate, the evacuation alarm will sound in fast tones, 2 short or 1 long. So the agenda for today will be a formal presentation, which will go through roughly 11:15 followed by a short Q and A period.
We'll be taking a short break halfway through and we'll have lunch served around 11:30. So please stick around. We've got lots of representatives from the company and we'd love to speak with all of you. I want to introduce the presenters today. First, Mick Dillinger, Pembina's President and CEO.
And in the crowd, if you can please put up your
hand or stand up as I call your name. Scott Burrows, Senior Vice President and Chief Financial Officer Dew Taylor, Senior Vice President, Marketing and New Ventures and Corporate Development Officer Jarrett Sprott, Senior Vice President, Chief Operating Officer, Facilities Jason Buhn, Senior Vice President and Chief Operating Officer, Pipelines Kevin Jagger, Senior Manager, Business Development, who is a key member of our polypropylene facility project. We also have Randy Finley in attendance, Pembina's Chairman Brad Colesmith, the VP NGL Services at Pembina Scott Arnold, the Manager of Investor Relations with Pembina our IR team of Chelsea Hoye and Riley Hicks And a special thanks goes out to Becky Disher, who is also here today. She's the one who makes all the details for an event like this work. So as I said, I encourage you to speak to all of the reps in the crowd when we have a chance.
And with that, I'll kick it off.
Good morning, everyone. You guys hear me okay in the back? Outside, is it okay? Great. Well, welcome.
I guess we might have an evacuation if Trans Mountain or Kinder Morgan announces whatever they're going to do, we have a pretty good idea what that is, but keep you up to date as things unfold. Exciting program today. My piece is really going to be talking about how we got here and the reasons we are planning to do some slightly different things in the future. The guys who are presenting are going to talk more about the projects, but I'm going to talk more about how our strategy developed over time and where we think it's going to go next. As you know, we're we've got some predictive information in the deck, and we believe it will happen.
But these days it seems to matter more what from tweets on China than what's really going in terms of fundamentals. So it's our best guess at what will happen, but it certainly isn't a promise. Lots of non GAAP measures in here. I think we'd all agree that's the way we communicate now is with non GAAP measures, not with GAAP measures. So notice there.
Our presenters, Cam's already introduced, so I won't go through that. Our agenda, I'm going to take the front end, as I said, and Jason will go through pipeline, Sarah will go through facilities, 2 marketing and new ventures with our special guest star, Kevin, who is luckily not in London or Kuwait this week and able to address you on what's going on with our petrochemical joint venture. Scott will take you through our financial health and then I'll close it up. So a lot can happen in a year. It was only a year ago, and we'd since then announced roughly $10,000,000,000 acquisition of Veresen, and it's working out very well.
And I'll touch on that throughout. We had a great year, record EBITDA, record EBITDA per share. Things look even better into 2018. We did conclude the bulk of our capital program, the $6,000,000,000 to $7,000,000,000 capital program we've been working on since 2014, 2015. We had a great Q1.
Things look robust for the balance of the year. Another 1,000,000,000 projects going into service in 2018. Capital markets have been very kind to us. Picked up almost $2,000,000,000 of debt and equity over the year, most of the time well oversubscribed. A lot of solid base hits kind of coming through the year last year, the Phase 6, recently announced Phase 6, Duvernay, Prince Rupert Terminal, I was out there, Earthworks are progressing, North Central Liquids Hub, that was a project
in our midstream
and then further development of Empress with a new fractionation facility announced there. We announced that we are taking over commercial operatorship of Alliance Pipeline, perfect, and also out there in an open season. We'll talk more about that later. On the petrochemical side, we knew it would be kind of a quiet year this year. We're doing what we said we'd do.
We're getting the appropriate precision of our cost estimate before we progress that project. I'll leave it to Kevin to talk through that, but we are headed towards an FID, I think, late this year at the latest early next year, I believe. And we had a great year in terms of shareholder return. If you measure it on a 1 year or 3 year basis, we were the top in the sector. And this year, we're up there as well, maybe not the top so far, but we got a little bit of running room still in terms of time to get into that top spot.
This is my favorite slide in the deck comparing 2018 to 2,008, so a 10 year period. And price of oil in the good old days was about $100 and now we're about 2 thirds that price. But look at the gas price, what happens when your customer has all the gas they need in the U. S. And so we're struggling as a basin in terms of gas prices.
And we'll talk about what we plan to do about that, how we turn that in from a negative into hopefully a positive. Liquids production, dramatic ramp up, reflecting the value of liquids. Gas, not surprisingly pretty flat. There's no price signal in the market to drive gas production up. But switching to Pembina specific, we're sneaking up on a triple of our BOEs moved, processed over that time period.
Adjusted EBITDA sneaking up on 10 times as large. EBITDA per share, well, 2.5 times roughly what we were 10 years ago. That's really the main event. What are you doing per share? It's not absolute growth, it's what are you doing per share.
Dividends per share, $2.24 versus $1.49 But over the same period, going from pretty much 100% payout ratio down, I think we're roughly around we're churning a lot more cash inside reinvesting a lot more cash inside the company. Scott will talk about that, but we're in that elusive self funding model now after
a lot of hard work.
Enterprise value, a 10 banger. And employees, I predict by 2019, we'll be strong. Real change over that time. And I was thinking last night, what would it look like if we could do that kind of change 10 years from now? So this is kind of there's a bunch of journeys here we're going to go through.
This one is about how we developed our asset base over time. I got another journey on how we developed our service offering over time. And then Garrett and Jason are going to go through kind of how their businesses developed over time, and it's really quite a story. So some landmarks here, Western North America started with the geology, of course. And first, there was the Cardium and the Deep Basin and oil sands, and that's really what Pembina was trying to do was to get crude oil and condensate largely a day from producing wells to Edmonton where Enbridge would take it to the customers.
So more recently, we've had the shale revolution, and that's really the part where Pembina got lucky. We've done a lot of good things, smart things, I think, over the years, but we also got lucky with the shale revolution. Of course, when the shales happened, our infrastructure was in the right place. Everything got supersized, literally kind of a 10:one ratio for the average productivity of a gas well or an oil well, and our infrastructure was in the right place. So the monster, of course, is the Montney, over 100 years of reserve life left.
So our assets are well positioned for that. And then what's emerging, the Duvernay. I think the Duvernay keeps getting better and better and better and very excited about what's possible there, Williston and now some exposure down to the Rockies through the Veresen acquisition. So it all started with the Drayton Valley system that I just put up there. That's really the call was called Pembina originally.
And then the other conventional assets. So what's on the screen now really is the original Pembina back when I joined after 50 years, they built a world class hydrocarbon liquids gathering system. Position of strength of franchise that we could vertically integrate around. So that vertical integration started in around 2000. First, we got into oil sands.
Jason will show you that it was conventional and then 5 years were spent building out the oil sands because as you saw, we had $100 oil and oil sands couldn't do it fast enough.
So a lot of our growth for a while
was adding to the conventional business an oil sands. And then we added the Cut Bank complex, our inaugural purchase of Cut Bank from Talisman, a $300,000,000 a day gas plant. And that really launched us into the upstream vertical integration, processing gas. And we like the processing business, but the main reason we got into it was because we had spare capacity on the pipeline. So how do we fill the spare capacity?
Figured out the best way to do it was to get into processing, increase the liquids recovery in the field to use up spare capacity on our pipeline, and we are in fact our own largest customer now. You add up all of our processing, all the liquids we put on our system, we're our own largest processing. So that was the skill part that we undertook. And then in 2012, we added Providence, a world class fractionation Complex, Younger, Empress, about 2.5 Bcf a day of processing, and that really added the second leg to the stool. Like we had crude oil and condensate.
We were had a nice franchise there. And then when we added provident, we added the NGL franchise. So that was kind of part 2. And we added the Vantage asset. That was really our first significant U.
S. Piece, really ethane gathering. And then, of course, last year, we added Vericin, and Vericin was our diversification into now. So that was the 3rd leg to the stool. Crude oil condensate, which is really our conventional business unit.
And then providence, the NGL piece Vericin, the gas piece. So now no matter what comes out of the ground in the Duvernay or the Montney, we can deal with it. Gas, C2 plus C3 plus crude, condensate, no matter what it is, we can deal with it. And we're going to show you some interesting ideas on how we push those services further down the value chain. And of course, down at the bottom, let's not forget the Ruby pipeline.
It's a 42 inches gas pipeline. Like it's a world class asset. It terminates at Malin, as does TransCanada's GTN. And so at Malin, we're connected to 2 world class resource bases. And if we are successful with Jordan Cove, we'll build a pipe from Malin to Jordan Cove, and we will enter the LNG business.
And that's a very exciting development. Stu will talk more about that. So what's been our key to success over that 10 year period? It's always about location. It's about geology.
We've got some slides I'll show you later that our geology hunts. It hunts even in poor prices. Our ability to perform Pembina's ability to perform has not been dependent on commodity prices. It's been steady, steady eddy through all cycles, and we are building a model I'll talk about a little later that should make it even more steady through the different cycles as commodity prices go through. Integration, a huge factor in our success, that one stop shop in the Pembina store.
Call our company a store now. We buy processing, transportation, storage, fractionation, marketing, hopefully LNG, hopefully petrochemicals. Some customers that we're meeting, particularly the international customers, they kind of want to buy everything. They want to buy they want to turn their natural gas into polypropylene, get their gas on both. So the Pembina store is getting more shelf space.
Commercial creativity, we believe we'll be one of the first, if not the first company to do fee for service petrochemicals, not entirely fee for service, but at least half. So we'll figure that out. Critical mass of feedstocks, that's another thing that really differentiates our company is we have 75,000 barrels a day of propane. Nobody else has that. It allows you to backstop polypropylene plants for 40 years.
To have critical mass of feedstock, you can assert yourself downstream value chain. We've been doing that consistently. The technology, that was the luck part I talked about with producers learning how to fracture shales and get hydrocarbons out of shales. We were in the right place and the right time. The credit I will take for that was we captured our market share or even improved our market share through that piece of explosive growth.
So there was some skill involved with capturing those volumes through our systems. Our family culture focused on all stakeholders. I'm going to conclude today talking about the 4 stakeholders, why it's important for a company to pay attention to all the stakeholders, employees, customers, communities and states focused on shareholders. You have to deliver. It takes a decade to gain trust, and it takes a minute to lose it.
So you have to deliver consistently. And among those things we deliver well are our capital program. We've been on time, we're ahead on timing on our projects by and large and by and large under budget. So our guys and gals have learned how to build stuff. Really proud of that.
So let's take it back to what's the purpose of our company, and it really is fourfold. Heard earlier versions of this, but it's really that the customers choose us first for reliable value added service. So in the store, customer gets to decide what they want to buy. We want them to choose us first, and they are. We have had terrific returns in our sector.
Our share price hasn't done what we wanted, but we've done everything that needs to be done to see our dividends continue to grow up, and hopefully, the share price continues to go up. Kind of an overhang, we believe, on the sector right now. Hopefully, that will be alleviated. Employees say we're the employer of choice. We consistently have 100 people apply for every job that we have at Pembina.
It's a great place to work, but we're not done. We're going to do an engagement survey later this year, keep trying to get better at going full and really have them engaged. Communities, U. S. Is having a net positive impact.
So you put a hydrocarbon facility near somebody, I think we can all agree that's not a net positive impact. But if you do all the other things well, Unity, then perhaps you can get people to say, I'm pretty glad Pembina's in my view. I'm glad for the tax base. I'm glad for the jobs. They run a safe operation.
They keep me up to date, and they give back to the community. We think that's the appropriate stance. We believe we're meeting that standard, so it's a high standard. The new thing is that we think we have a role to play connecting the WCSB and the Rockies to the 2 global markets. Really, that's most of what I'm going to talk about through my section is what is Pembina's role to get WCSB, Rockies Hydrocarbon, to the rest of the world, and the evidence is that we should be trying to do that is compelling.
Now we're not going to take any new risks in doing that. You'll see it's a very intuitive next step for us. We are going to be true to our guardrails as we always are. What we do has to fit into our guardrails. We're not going to fit our guardrails into where we want to go.
It's the other way around. So if petrochemicals doesn't fit into our guardrails, we're not going to do it. It's just that simple. LNG doesn't fit into our guardrails, we're not going to do it. So the guardrails come first, and that's really what guides our strategy.
So our strategy, preserve value, that's no different. Diversify, we're diversifying. Talked about 3 commodities. I talked about new basins. We're have greater U.
S. Exposure through Vericin. We're up to about 20% U. S. Off margin, diversifying across services.
And as we vertically integrate and get international customers, we're also going to keep diversifying the customer base. The growth, we got lots of slides on that. I won't belabor that, but we're growing steadily, rationally. We never feel pressure to grow. We grow when the opportunities are right.
And if a time ever came when there's no apparent growth, it's not a problem just to make money. It's okay just to make money. We don't feel that we have to grow. We have those opportunities, and we've been lucky enough to have them. But we if there's nothing out there, we're not going to grow.
Our former Chairman said sometimes you actually make more money when you just read the news rather than making a bad deal. That's our mantra. We'll grow when sensible opportunities are out there. The new part about our strategy is looking beyond Alberta, looking to where the commodity prices in the world are the highest, where worldwide demand will be, getting our hydrocarbon. You'll see throughout the morning that, that's not a scary thing.
It's entirely intuitive. It's not risky. Just a natural evolution for our company. So here's kind of the story on our on the Pembina store and how it evolved. Of course, with a blank sheet of paper, there was production and consumption and Pembina evolved to fill a need.
And that initial need was pipeline. So back in 2004, 'five when I joined, it was a pipeline company, and we were pretty good at our craft. My predecessors did a great job in building a world class hydrocarbon liquids gathering system, and we use that position of strength to vertically integrate. We started in 'five with marketing. So we started to market around our crude oil franchise sustainably.
We added terminals to get more product on the pipe. We started to arbitrage commodities, store commodities. We had a lot of storage in our system. We never used it. We only used it as operational storage in case of emergencies for batching, but we had a lot of storage.
So, we started to monetize that storage. It was pretty intuitive, very low risk, very high margin business. We started that in 'five. And then in 'nine, we got into processing. And as I mentioned earlier, we got into processing to fill spare capacity on our pipeline.
And And processing was a great business in its own right, and it was the business many of the now officers had been in, and so it wasn't scary to us at all. But we were very successful increasing the cash flow from our pipelines because essentially had no incremental cost of transporting those liquids. So at this point, we were processing, we could take NGLs, we could take the Condi through our crude pipes. And then in 2012, we added the NGL second leg to the stool, as I mentioned. So now we could look further downstream and make sure that if we process gas, took out liquids, transported, that there'd be enough capacity for all those NGLs.
And we realized actually early that the shale revolution was happening and that, in fact, the Fort Saskatchewan fractionation complex would not have enough capacity. That's what led us to Providence because we realized that we couldn't keep building processing and pipe without somewhere for these NGLs to go. So we acquired Provident and we ended up building 2 new fractionators. Really changed fractionation, which was a completely commodity exposed business. Well, people forget it was just like petrochemicals, it's now completely commodity exposed.
There was no fee for service fractionation. Now that's mainly how fractionation works in Alberta on a fee for service. 2%. We changed the way that business was done in Western Canada. And of course, we added rail and trucking and marketing continues to serve us very well.
And then last year, we added the gas piece, gas. And so now we could take whatever came out of the ground at the gas plant, whether it be NGLs, condensate, crude, natural gas, and we could provide services. So it only stands to reason that we would take the next step in the value chain. We would take the propane that we produce out of the back end of our fractionators, roughly 70,000 barrels a day right now. As we have enough product, we can build a propane export terminal, direct us to propane there and hopefully get our producers much higher, more favorable netbacks.
Turning propane into polypropylene, a massive value add for producers and for the province. Not going to be risky or scary. We'll fit it into our guardrails. And we weren't really thinking a lot about LNG, but we got a world class opportunity through the Veresen acquisition to look at Jordan Cove, and we like Jordan Cove. There's only 2 kinds of West Coast projects, the hard ones and the ones you don't know anything about yet.
And Jordan Cove will be hard, but we think we can get it done, and it's now down the fairway of our strategy. We like LNG enough that even if Jordan Cove didn't work, we would still why this keeps flashing forward, We would still pursue LNG with fundamental next step in our evolution. And then partial upgrading, we're looking at partially upgrading crude streams. So here's why. A bunch of slides coming up that support that strategic look at the price of AECO, sub $2 probably sub $1 today.
I understood last week AECO was 0. And price of gas in Tokyo is around $10 So it's worth 10x as much in Tokyo as it is. And that arb, we think that arb is going to remain large, maybe not this large, but it will remain large for some time to come. So that backdrop lends itself to LNG development. Propane, not quite as dramatic of a backdrop.
Propane is about US0.60 dollars a gallon. Last year, it was US0.30 dollars But in Korea, at are we going to do about this thing flashing forward? $0.36 a gallon premium, so a real great ARP, and that's really what our Prince Rupert terminal is about. Of course, crude oil, dollars 10 premium and much higher for WCS. This just regular crude in Canada.
So those arbs are one of the reasons we want to get these products offshore. You add them all up on a revenue basis, it's about $20,000,000,000 a year that Canada is foregoing in revenue, dollars 15,000,000,000 of which is associated with crude and projects like Kinder Morgan. And so that's a lot of money. That's actually I was presenting this yesterday, sorry and earlier in the week in Edmonton, and that's enough so that every Albertan wouldn't have to pay tax or everybody in Ontario wouldn't have to. So it's a lot of dough.
Go look back at your T4, think about what you would have done with all that money. But people don't get how much money that is, what it means, what it could mean to us, and we are leaving that on terrible. We're going to do our part to try to fix that and hopefully some of our other sector companies will help with the crude oil piece. So what other reason do we have to go international? Well, just look at North American hydrocarbon demand, pretty much flat.
Crude demand, we expect, will be flat. Gas demand will continue to go up with LNG exports and with coal to gas conversion. Europe is actually declining, and all the growth is in India and China and North America. Canada wants to keep growing. I mean, we've got a nice fairway 3 to 5 years out, but in absence of polypropylene and Prince Rupert and LNG, it's going to be harder to grow.
We think those things are going to happen. We're fans of Shell. We're fans of AltaGas. Whoever can clear the basin, we're rooting for them because that's going to be good for our Canadian economy, our Alberta economy, good for producers and good for us. We're going to work very hard.
We are working very hard to do our part there. We think we can lead parts of that on the NGL demand side, gas demand side, and we hope our sector partners can lead it on the oil side because we have some of the best geology on the planet, arguably the best gas reserve in the world. We have a lot of natural advantages to seek international customers. I talked about the next natural step in the value chain. It's very intuitive.
You kind of think of Pembina over a 20 year period. We've been making these steps the whole way along. This is just the next step. We have access to fantastic geology. We have critical mass of products.
So when we announce Prince Rupert, we know it's going to be full because we have the product already. Commercial creativity, we think we can crack the nut on service petrochemicals. We don't know we're not saying we want to be 100% fee for service because we actually like the margin, capture some of the margin, not a lot, we'll fit it into the guardrails. Our on time, on budget record attracts partners, and we know what we don't know. So in petrochemicals, we didn't go it alone.
We got a world leader that had built a number of polypropylene plants at worldwide marketing expense. We didn't go it alone because we didn't have the knowledge. Just like in 2012, we didn't know fractionation, but we bought a company 5 years. So it really is about it starts with having the right knowledge, and we're always very careful. Our board is extremely careful that we have the right people on board before we make a major step.
And you'll see, Sue is going to put up the location advance slide for Jordan Cove. It's astonishing location, lower transportation costs to places like Tokyo. Our new corporate structure, clearly aligned with the value chain extension. Operations and services equally balanced in importance. Pipelines, all our pipelines are under Jason.
We have a center of excellence in pipeline. We have a center of excellence in gas processing, storage and fractionation. We're world class in these areas and getting better. And we used to do our new ventures kind of inside the pipeline and processing business unit, and it just got to be so prominent, so important to us, particularly in light of this new strategy that we moved Stu over to deal solely with new ventures. It's a lot of fun,
a lot of work.
I think we knew what we were getting into with the international push, but it doesn't leave a lot of time travel. On the service side, all the money stuff is Scott, doing a great job, and we broke the rest of the services up between services to our internal customers, to our businesses, call that corporate services. And Paul, who used to be our COO of Pipelines, he's now running that service component. So he knows what the businesses really need, knows what the service groups have to perform. And Harry deals with all things external, external affairs, First Nation, regulatory, legal, things that are outward facing.
So that's how we're organized. We're organized for the new strategy. With this structure, we'll have running room for a long period of time. Some foundational stuff. What gives us so much confidence?
I'm going to spend a few minutes talking about that. Look at our how our business is now contracted. I mean, we are proud of how we looked in 2015, but only about 44% of our EBITDA came from kind of long term take or pay contracts. And now in 2018, we expect that's going to be more like 60%, 65%. The red is fee for service, but short term shorter duration, that's dropped by quite a big margin.
But most notably, the 23% that used to be commodity exposed EBITDA is now down to 15%. We're making a lot of money in that business right now, but it's still only 15% of our EBITDA that's commodity. So we like the eightytwenty split. We don't want to get that number to 100% service. We like some commodity exposure, so our shareholders can participate with us as we get our commodities to the rest of the world.
Again, the 10 year contrast here. So on your left, what was going on in 'eight. So you saw a lot of drilling kind of west south of Calgary, 'eight, dry gas drilling really. Now you look at 2018, dry gas, not where it's at. It's all about liquids right now.
But in both cases, a lot of drilling right under our pipe, but huge bias towards liquids these days. The average well, you can see on the right hand side, the evolution of condensate production over a time period starting in 2013, more and more and more liquids. Jared will show you that our average gas processing plant now is half of the cost is associated with liquids and only half the cost is gas, used to be all gas. Now half the cost of building a new gas plant is handling all those liquids. You can see on the left, the percentage of liquids rich wells into the oil window.
It's the whole story, whereas the dry gas window is just closing. A lot of the gas plants that are existing in Alberta were built for dry gas, so they're just not usable for the kinds of wells produced and drilling. Profitability, you see the Duvernay rich gas, kind of this is lay netback. So how much money is left over after costs and how much money is left over after costs. And so we're seeing modest return.
You can see Alberta dry gas. There's not that much money left over after you drill a dry gas well. There's a lot of money left over if you're in Montney or in the Duvernay, and that's the story. That's really what's in behind the ramp up that the folks are going to show you later. And really, the play economics are really quite good at 60 US70 US70 US is classic.
US60 US80 dollars and we pay our costs in Canadian dollars. Like look at the Montney, CACWA, you actually don't need a positive gas price to fill that because it's all about condensate itself. So these are North American plays. And so on the gas side, half or slightly more than half are the kinds of the plays we capture to our assets. Story on oil, it is a little more favorable in the U.
S. Than
the U.
S, but still a whole bunch of very economic oil plays underneath our pipe. And we're seeing the Cardium start to revive at $60 plus oil. Even Swan Hills is starting to revive. So we expect the oil to continue to be developed. This is what I was talking about earlier, kind of looking on the right at Pembina's cash flow per share through commodity cycle.
So you can see it's kind of steady Eddie, growing our cash flow per share, whether the price of oil was $140 or it was $30 We're steady eddy through the whole piece. We think that's going to continue. We think simply said, we're just going to keep doing what we've been doing for years. Something subtle that people don't realize, I'll spend a minute on is, if we extend the value chain, we are actually going to get much more diverse. So how is that going to happen?
So imagine a scenario where we have good prices. Good prices, our gas pipelines are going to fill or be expanded NGL, same story fractionation will do well crude oil condensate will do well in good prices. But what about bad prices? Maybe you're not going to have as many for signing up for pipeline capacity and bad pricing. But in bad pricing, all of our value chain extensions actually do better.
If propane price is low, we make way more money in polypropylene to the extent we're taking the commodity risk or our producers do, those are the ones who pay us a fee. LNG, if gas prices are low locally and high internationally, there's a bigger prize. Propane exports are like that too. So we're actually building a business that can parts of which can make more money in low commodities. That's really how we got to another way we got pointed to our enhancement.
I think we'll be one of the few companies that are in the energy sector that can grow a part of their business, like the petrochemical complex or the export business, prices are low. So we can drive growth both in a high commodity price environment but also a low commodity. That's another compelling reason we're going down the path that we are going down. Current projects, about $2,000,000,000 underway. We categorize these now as base hits kind of $150,000,000 to $250,000,000 was only 10 years ago that $250,000,000 was our whole capital program for the year and now we just Duvernay, you're going to see more Duvernay, Prince Rupert, ethane storage, Empress fractionator and then, of course, the usual suspects of $200,000,000 to $500,000,000 pipeline expansion, which we really see no light for that.
It's just those are going to keep happening, particularly with robust crude and condi prices right now. And as we look out the $2,000,000,000 I talked about, another $3,500,000,000 stuff we're working on, we've heard Alliance expansion, and we've got additional pieces we announced and we're always already working on the next one. Duvernay development, we think one of those is going to come in a couple of years. Can't promise that because we don't control the cadence of development in the Duvernay, Chevron's cadence, but I think that's going to continue to happen, processing facilities, laterals and connections. We're always building new laterals and expand.
Another $3,500,000,000 stuff work. We're at various stages of developing paper. And you kind of to use a reserve analogy, our secured is our proved, our uncommitted is our probable and our value chain are possible. Now I think we're pretty close to putting a petrochemical piece in probable, not possible. And I would submit that, that $10,000,000,000 is really a very low number compared to if possible or current.
We talked about on time, on budget. There's all the projects. I'll let you look through that. We've safely built stuff on time, on budget, and the assets did what they were supposed to do. Veresen Synergies, a question we get asked a lot.
We actually moved everybody from Veresen to Pembina the 1st week we closed. So everyone had a desk, a computer, a nametag and what they needed to do 2 days after close. And we finished the systems integration. We'd spent a decade building world class systems. So we brought them on to SAP, brought them on to our preventative maintenance systems, brought them into our IT because we have world class systems.
So bolting another company, even though it was a $10,000,000,000 transaction, we did that in 3 months. And then you observed in Q1, we revamped our accounting entirely to the divisional segments I talked about. We did that in the one. Lots of times it takes that company, Vericel, was 40% of our size, and lots of times you see that takes 2 or 3 years. From a business perspective, we recontracted eggs already.
Owner operator model at Alliance and Aux Sable is being implemented, has been announced, commercial and physical operatorship of those assets, respectively. Open season, announced North Central Liquids Hub. So all the things that were in our base and development cases that we foreshadowed, they're all working out as expected, often better than expected. And our cost synergies are right on track. Some come from tax savings, some come from financing savings.
And Sam and Scott and their team are really getting after the financing. Very exciting. We lend our balance sheet to the Verison assets if possible. And then the cost reduction targets are well within hand. So we have a little bit more precision in our guidance that we announced this morning.
We're going to increase the lower end of our guidance by $100,000,000 There are the reasons. We've hedged our marketing businesses somewhat, and we see strong production. And we're not quite ready to move up the upper end, but things keep tracking as they are. It's the upward mobility in that guidance. This is what we're comfortable with.
And here's the longer term picture, kind of in 2014 and 2015 having a $1,000,000,000 EBITDA dollars 2.75 a share of EBITDA to where we're guiding now, kind of $5.25 to 5.50 So a double in EBITDA per share, that's as I said, that's the main tripling almost a tripling of our absolute share. But again, growing EBITDA isn't that hard. Growing EBITDA per share is really that's the number. So with that, I think Jason's going to come up and take you through some more details on our pipeline division and then I think Garrett's next on
facilities.
Thanks, Nick. Good morning, everyone.
So
the first slide today, I guess, really when we look at this, this is kind of sort of puts in a picture what the reorganization of the pipeline division really looks like. And the way to think of the sort of the index there that shows conventional transmission and oil sands pipelines is think of everything west of Edmonton that's really crude oil or NGLs, it's really effectively our conventional crude oil and NGL gathering system. Everything north of Edmonton is effectively our heavy oil and oil sands gathering systems and then everything that's not crude oil or liquids is our transmission business unit, moves either natural gas or spec ethane products in the case of the AGG system. As we go through the presentation for the pipeline division, we'll really focus a lot on the piece expansions and clients expansion. I guess it's key to understand that there are several other assets that are seeing opportunities emerging as we go along.
If you look to the southern part of the pipeline system, Mick talked about the origin of Pembina and the Pembina system. It sits on top of good geology. And now with the crude oil prices being the way that they are, we're starting to see some volumes emerging there. So with the Cardium, it's now cost effective to produce those barrels and then the Eastern Duvernay as the oil play starts to open up there in the east side of the Drayton Valley system and Bonney Glen system there that's also ready to take some of that volume. I think the other thing that's really key and Mick mentioned it earlier in his presentation is that no matter where you find product in the WCSB, Pembina can take it away on their pipeline system.
So if you find gas, if you find liquids, if you find crude oil or condensate, we've got a pipeline system that's there to transport it to market. So, this slide really does kind of reinforce the ability of Pembina to grow regardless of the cycles, the price environment that we're looking at. So if you look at the far left side, we started with just the Drayton Valley and the P systems. And then from that, we built our oil sands network. So from 2,001 effectively through 2011, we basically doubled the size of the capacity that we have on our systems through oil sands growth.
And then in 2013, with the new technology and the horizontal drills, we started to see the Peace Pipeline system start to take shape. And we really started in 2013, the build out of the Peace Pipeline system. We launched the open season on Phase 3 and we really understood what the producers were developing out in the areas of the Montney and the Duvernay and got ahead of that curve. It really, I think, and then as we moved along, obviously, in 2014, we acquired the Vantage system and expanded it. And then beyond that, in 2017, we acquired the Vericin pipelines, which included the AIGS pipeline system, Ruby Alliance.
And of course, you can see that we continue to expand Peace and we're looking to continue to expand Alliance as well. So really what this chart is showing you is that our assets sit on top of premium geology and regardless of quantity prices or timing or cycles, we're able to continue to expand and grow. So from a performance perspective, financially speaking, obviously, 2017 was a record year for Pembina. It was a combination of all of our expansions coming into service on piece and starting to see those volumes materialize as well as the Veresen acquisition that we completed in the 4th quarter. So when you compare the Q1 of 2017 to the Q1 of 2018, obviously, you're seeing the effects of the expansions now being in service and the Veresen acquisition.
When you look at the revenue volume chart, you see about 800,000 barrels of growth year over year quarterly and really about 600,000 of that growth is related to the Veresen acquisition. And similarly, on the operating margin, you see more than a doubling of the operating margin and about $200,000,000 of that growth is associated with the acquisition of Veresen. So this is really what's driving activity in the basin and really driving the growth of our pipeline system. So when you look at what we did in 2013 when we launched the Open Season, it was really driven by the demand for condensate needs up in the oil sands area to be able to support the development of that commodity. And what this chart is really showing you, the blue line is the demand for condensate and the gray bars are the production of condensate in the basin.
And so you can see in about 2,008 that there started to be a gap between what was being produced and what was being consumed. And so that gap really started to drive the demand for condensate. And you can see that there's that gap continues into the current environment in 2018. What that really is, is the amount of condensate that's being imported from the U. S.
To be able to support the oil sands. So I think what you can take away from this is that there's still a lot of running room for condensate growth on our assets and in the basin. And I think that as our conventional production of condensate grows, potentially you can see the pricing of the imported condensate not being competitive with the conventional production and you can start to see some of that production is actually ramping off as the production in
the base starts to increase.
This is just a focus specifically on the conventional pipeline systems. This is there is the revision to the conventional pipeline systems where the Vantage and the Swan Hills systems are no longer in these numbers. Those have been moved to the transmission business unit and the oil sands business unit, respectively. What you can see in 2013, that's when we launched the open season on these pipeline. Volumes were starting to materialize there and we were looking at our expansion.
As you kind of follow the chart to the right, you can see in Q122 of 2017, we kind of flat lined on volume and that flatlining is really that we had filled our pipeline system to capacity prior to bringing the expansion into service. So in Q3 'seventeen, you see the Phase 3 pipelines came into service and you see a significant jump in the amount of product that we're moving on our systems. So as we sort of went through the process of launching the open season, we were able to determine how much condensate crude oil and NGL egress we were going to need and started putting a plan together to expand our pipeline system. So this chart or this graphic shows you will kind of walk you through step by step our expansion of our pipeline systems. And I think really the key to focus on here is the first bullet says there's 1,100,000 barrels of Edmonton area market delivery.
That's post Phase 4 expansion. So currently, we're at about 900,000 barrels a day. And when we went through and we ran our open season, we really looked at what could happen and we got in contact with all of the producers in the basin and started to really get a good solid understanding of what's possible. And so when we went out and built Phase 3, if you recall, we originally announced 1 pipeline, there was 2 pipelines. And so effectively, we kind of predicted what the potential market for all of these volumes could be.
So we built a 24 inches 16 inches pipeline that could be powered up into Edmonton. So, you can think of everything the Fox Creek is the catcher's mitt for everything that's being developed in the basin.
So,
after we launched the open season, obviously, our pipelines began to fill and we saw a need to expand the pipeline system. So the first phase of expansion of our pipeline was the Phase 4 pump stations, which were added to the 24 inches pipeline and really take our delivery capacity from the 900 1,000 barrels a day I mentioned to 1,100,000 barrels a day that's listed here. And really from Phase 4 on and from West of Fox Creek, really what we're doing is debottlenecking the system. So we have significant capacity coming out of Fox Creek and really we're trying to find the most optimal way to get the production into Fox Creek so that we can serve as customers' needs. So the first phase of that was phase 5, which was a 20 inches pipeline that got built out to Latour, some pumps and some tanks out at Latour and then another pump station out near Le Colas.
And effectively, what that does is unlocks capacity quickly on our pipeline system west of Fox Creek, so that we can move to market relatively quickly.
And then, of
course, more recently, we've Phase 6 expansion. Where we keep pushing our capacity further to the west, so it can access the capacity that we already have in place east of Fox Creek. And so ultimately, we can continue to expand the system. If you look west of Taylor, we built the NEBC gathering system. We built that system with the expectation that LNG could potentially go forward on the West Coast.
So we built a 12 inches pipeline that could be powered up and you can see that there's opportunities to continue to power up the system all the way down to Fox Creek. And then from Fox Creek to Edmonton, we can add about 5 pump stations on each pipeline system to bring the ultimate capacity to at least 1,300,000 barrels a day. Currently, today, you can see we have about 835,000 barrels a day at capacity. So, we still have lots of running room, about 500,000 barrels of oil adds to the pipeline system before we have to look at other options. I think what's not shown necessarily on this slide is you can see it on the slide, there's numerous gathering assets that bring the product to the pipeline and so that most of our pipeline power ups and expansions are along the corridor, but we spent roughly $500,000,000 tying in a lot of this production to our pipeline system.
So the replication of what we have here isn't as simply as drawing a line on the map and trying to find 1 or 2 producers to tie it in. We have roughly 100 connections on pipeline and 100 of 1,000,000 of dollars of assets through some of the most difficult terrain that really brings this product onto the pipeline. So it's a very difficult system to replicate and that's pretty consistent with all of our pipeline systems. They have a significant gathering network that's really tough to replicate and it's usually in the most difficult terrain to
expand in. So this is a
little more detail on specifically what Phase 4 and 5 are. Phase 4 is the 2 pump stations that I mentioned on the 24 inches pipeline. They add about 180,000 barrels a day of capacity. It will be brought into service in the Q4 of 2019. Similarly, on Phase 5, it's 90 kilometer 20 inches pipeline between Latour and Fox, and it's progressing well.
And so effectively, both of these projects come into place in unison in the 4th quarter and will drive EBITDA growth in 2019. I think the other thing to take away from this is these are projects that we consistently do. So we're doing the same types of projects over and over. So they're sort of becoming they're not quite cookie cutter, but we're getting pretty confident at doing these projects and we're able to bring them on time, on budget and do them quite confidently. So the Phase 6 pipeline expansion is really pushing further west on the pipeline system deeper into the Montney.
It supports the Duvernay and Deep Basin plays as well. It's a $280,000,000 expansion. The centerpiece of that is really the 20 inches pipeline that will go from Capla to Latour and then a number of associated pump stations. And so currently, we're developing the FEED study, so engineering and design and procuring long lead equipment to have that in service. We expect the in service date for that to be roughly early 2020.
So similarly to Peace, when we ran the open season for Peace Pipeline, we saw that there was going to be a problem when you got to the other end of the pipeline system. And really the problem was that there was more condensate coming in than the space for condensate to go out. And so when we looked at that situation, we realized there needed to be an alternative. And so we started looking at how do you get condensate into Edmonton and realized that that's probably the most difficult place that you could possibly build pipeline infrastructure into with all of the infrastructure that's already in place, trying to work around that. So it would be very costly in time.
So we quickly realized that the right place for condensate north of Edmonton, where it can access all the same pipeline systems that currently are accessed from the Enbridge CRW pool. So we went north of Edmonton and put that system into place. And so you can see that effectively, a couple of years ago, Kompina really wasn't moving any condensates or any of its own terminals. And then we started to piece together what CDH would become. And over about a year, we've effectively grown from 0 to about 160,000 barrels of condensate that we're moving through CDH.
That's more than half of the condensate production that we move on our system today. So we've quickly taken the lead in condensate movements off our system. And then I think the other thing, when you look at all of the connectivity that you get out of the CDH terminal, there's lots of running room. There's literally 100 and 100 of 1000 of barrels of excess capacity for condensate coming out of this terminal. So as we continue to expand Keyes, the CDH terminal will continue to be there for condensate takeaway to deliver to all of those systems.
So transmission systems, and this is really a focus on the Alliance Pipeline system. So if you go back prior to 2015, Alliance was really a cost service pipeline system. It's a traditional flow through operating costs, operating capital. And in 20 15, they launched what they call the new service offering, which was really a fixed fee service offering. And so I think that when you see the alliance, the blue line is the alliance volume and the red line is the differential.
The gray bars are the price of AECO. You can see that Alliance was originally constructed to move about 1.5 Bcf of production out of the Q1. And you can see through its history, it's basically always been full. Even when AECO prices were high, that pipeline was full. And as AECO prices started to come down, the pipeline stayed full.
But what's really interesting is what happened in 2015 after service offering. Alliance with their fixed toll model was a very attractive service offering from a customer's perspective, because they knew what their tolls were going to be going forward. And then you started to see a spread between the Ayco and the Chicago prices, which started to drive the demand for that service. So you can see that the volume started to grow and the new model really forced Alliance to start to think about their asset differently and look at optimization opportunities. So they've taken a pipeline that was designed to move about 1.5 Bcf a day and they've actually been able to drive that up safely to over 1.7 Bcf a day.
So it really has been a success story since they launched the new service offering and it's driven the demand for that pipeline service. So the demand obviously is continuing to grow for gas egress out of Alberta. And so Alliance has an opportunity to expand its system to be able to support that growth. So we launched a binding open season on that's going to close here in the next few days. Really, the open or the expansion of the Alliance Pipeline system is really just a series of compressor stations.
There's no pipeline involved in this. So and there's 13 compressor stations, 6 of them in Canada, 7 of them in the United States, and all of those are on land that was already acquired by Alliance when originally constructed this. So they built their original pump stations and they acquired the midpoint all the way down the pipeline system to be able to add those pump stations to be able to power up the system. So those 13 pump stations will add about 400,000,000 cubic feet a day of capacity. We started the regulatory and environmental assessment along those pump stations and we're progressing the engineering development of that pipeline.
We're expecting we'll close the open season here in the few days. We'll go through and do an assessment process on what the nominations look like. And then as we kind of progress through that and finding negotiation with our customers, hopefully in the Q4 of 2018.
So this
is an illustration of the net backs to our customers. So the net back is after all costs have been taken off, including transportation costs to the customers. And when you look at the chart, you can see that Alliance is very competitive. It's the blue bars and the expansion is the red bar. And so you can see that on the left side of the graph, the netbacks on the Alliance Pipeline system are the best if you come from zone 1 and zone 2 and go directly to Chicago.
Then as you sort of move down the system, you can actually get on to 3rd party pipeline systems in Chicago and get to Dawn, which is a competitive offering with TransCanada. And then as we do the expansion, there were some concerns about the toll on the expansion. But when you look at the expansion comparatively to the TransCanada offering, it's very consistent. So, it's not
a good question to answer
to what TransCanada just came out with, with their LTFP announcement. So effectively, they have a route that they can get you to Chicago as well. It's effectively the same price. But the big difference between Alliance and TransCanada is that Alliance is roughly 99 actually 99 and I think everybody in the room has heard about some of the challenges on the TransCanada system with their expansion, which is that producers have been facing some reliability concerns there. And so the reliability is a really important factor for Alliance every day all the time.
And then of course, the fixed tools on the Alliance system are also very attractive there. You sign a deal for 15 years, you know what your tools is, unlike a regulated pipeline system for all the costs. So the outlook for the pipeline division, I think what's not been talked about a lot here is I think the I think that we do see some opportunities outside of Peace and Alliance for some growth in the Cardium and the East Duvernay. I think there's some opportunity there. Also not we haven't really talked about it, Mick touched on it, but the Ruby pipeline system, obviously, if the Jordan Cove project proceeds, that will provide a lot of support to the Ruby pipeline system.
But the underlying value of that asset is a preferred share dividend. So, we're secure for a number of years on that asset. But assuming Jordan Cove goes ahead, there's going to be a lot of demand from the Rockies Basin to be able to move gas on the Ruby's pipeline. Back to sort of the conventional assets, we're seeing the growth of production on those assets. It's exactly in line with what we expected.
We're filling up as we move along and we continue to expand. We can stay ahead of the volume with our expansion to go along and expand the Peace Pipeline system. On the oil sand side, the higher commodity price, the higher crude price is obviously positive for that pipeline system. We have a lot of opportunity to be able to go and add pump stations, do some optimization on both of our Alliance and sorry, our AOSPEL and our Horizon Pipeline systems to be able to move more of the volume on those systems. Those are synthetic crude systems.
So they're actually premium valued product compared to
their SynBid
or deal debt product that gets moved on the other pipeline systems that are operated by 3rd parties. So we see positive momentum in those as well, which supports the underlying fundamental economics of those assets. And then of course, the CDH system, we continue to expect to see as we develop piece, see more volume come through that system, we'll be able to see
more products delivered to market. With that, I'll turn it over to
Thanks, Jason. Good job. I recognize everyone really wants to hear Stu Taylor talk about New Ventures and Jordan Cove, but Jason and I feel that our base businesses are still very important. So I'm going to walk you through about 15 minutes of the Facilities division with a little bit of a video. So, here's a map of the Facilities division, very similar to our pipeline.
You can see the pipeline network there in gray. But the facilities division now with our announcement of our Prince Rupert terminal, it expands all the way from Prince Rupert, British Columbia all the way down into Sarnia, Ontario, where we have a storage facility and partial ownership fractionation, Aux Sable down in the Chicago area and then facilities littered all across basically all the continent. Keeps us fairly busy with respect to travel. This slide here, very similar to the pipelines division. You see it's a common theme.
We continue to grow in all of these areas, but what I wanted to talk about was the diversification that's associated with that growth, very similar to how Mick talked about we diversified and grew our company. If you look at the left portion, Cut Bank Complex 2,009 and then the expansion, that was Deep Basin Cretaceous Wheat Gas Processing. That's what that was. Then we grew into Empress and Younger. That is basically mainline or field extraction.
So that's just reprocessing gas that's already sales quality. We've diversified that portion. Stutter and Complex, once again, that's just reprocessing gas, extracting liquids to fill our pipe and fill our frac. Then you move into West Haven. West Haven was our 1st raw to sales gas processing facility that takes raw gas right from the wellhead and goes to full deep cut and that is a combination of Deep Basin Resource plus Montney Resource.
That was our first entry into the Montney formation. Deep is an extraction facility. That's our first entry into the Bakken formation. Kakwa River acquisition, that was our first entry into the liquids rich Caco River Montney that Mick showed on the left hand side. They basically need no gas price in order to have some fantastic economics.
Then you move into the Duvernay. Duvernay 1 is our first entry into sweet processing. I should mention that Cackle River is our 1st sour facility entry into that processing scheme. Then we go into the Duvernay, that's extremely exciting, right? That is Uber liquids rich, that's an entry there, Barrison Midstream, now we're into Northeast BC, sweet and sour, liquids rich Montney and then Aux Sable obviously is the terminus of the Alliance pipeline and then Duvernay II.
So it looks like we've just been growing our base gas processing business, but in behind that when
you peel a layer off
the onion, we are extremely well diversified through geology, different types of processing and different liquid schemes that gives us obviously a lot of flexibility. I should mention that every one of these facilities is physically connected to the pipeline division.
Now a little bit
on the condensate stabilization, this is something that we haven't really been talking about overly a lot. But one of the things that fundamentally had changed when we moved into these liquid rich plays is we saw an opportunity not only to generate revenue from our gas processing business, but also we've turned a lot of our field condensate stabilization into fee for service or cost to service model where we're spending a lot of capital and earning a return. So what you're looking at is the gas services, basically 2,009 to 2015. That was 17,000 barrels of condensate stabilization associated with about 1.6 Bcf of field processing. That condensate stabilization would be within the plant gate and that would be built into the fee that we would charge someone to process their gas.
Tacko River acquisition, you can see that was only 250,000,000 a day of gas processing with roughly 24,000 barrels a day of stabilization. Then you move into Duvernay 1, that's a 75,000,000 a day facility, net to Pembina, 100,000,000 gross, 12,000 barrels a day. And that facility is actually a it's 37 kilometers away from the gas plant. That's extracting the liquids from the gas stream in order and then sending the gas to the Duvernay 1 facility. Now we're getting this was kind of when we thought to ourselves, hey, this is a business line we could get into.
We could start building these types of field stabilization, etcetera and start charging a separate fee in order to accommodate the requirements of our customers. Same old story, Verusen Midstream, the height and steep rock facilities, you've got a massive amount of gas processing only at 10,000 barrels a day of stabilization. Then you move into the North Central Liquids Hub that has a separate fee, generating revenue, extracting liquids, allowing that gas to go to Saturn and Sunrise. And then Duvernay 2, you can see how the step change in Chevron's performance has been. It was 100,000,000 a day gas plant with 12,000 barrels of stabilization.
Now we're building another 100,000,000 a day gas plant with 30,000 barrels a day of stabilization. So the liquid yield on the play is continuing to get better as they learn from their peers in Canada, changes in technology and what they're learning from their counterparts in the Permian. Fractionation, very similar story. We're continuing to grow and there's diversification obviously here too. The first four, RFS I, we've got exposure in Sarnia, RFS II and RFS III in the Redwater area.
Auroch Sable is obviously in the terminus of the Alliance Pipeline and then the Empress. So that's at our Empress extraction facility. You can see we're starting to diversify also our fractionation portfolio. And one of the key Brad, when he took over the NGL service business unit and we built RFS II and RFS III, those are very, very key pieces of infrastructure. Not only do we generate fee for service and we have long term take or pays there, those are absolutely critical and able to supply SKU's business with long term propane supply and the propane export supply.
You need this infrastructure in place in order to Jason's built the pipes, we've built the fracs, we've expanded the storage, we've expanded our rail to not only handle all of our own products, but also Northwest Refinery. So, in behind this, there's a lot of diversification going on as well, which is extremely key and positive. Similarly, I just mentioned hydrocarbon storage required not only on the front end of your fractionation. When Jason's pipeline sends all the product to the complex, all of that mix goes into the ground. We ratably pull that mix out of the ground, run it through the fractionator And then on the back end, you require spec products caverns.
So your C2 cavern, which would go to Nova and those Dow and then your C3 plus cavern, which would be railed across North America and ultimately go into our polypropylene facility. You can see everything there, merchant underground storage capacity, that's all would be obviously underground salt caverns. And then over into the right hand side, that is our above ground storage capacity on the heavier crudes. Jason just talked about CDH and those types of things and that's that infrastructure. So, significant growth required to meet all of our needs that Mick talked about in the future.
A little bit of an update, revenue volumes, very similar to the pipeline division quarter over quarter sorry, Q1 2017, Q1 2018, 20% growth and operating margin obviously growing in accordance with that. Probably the big highlight in 2017 notwithstanding the record volumes and the operating margin would be commissioning of a significant amount of new iron in 2017. The Duvernay 1 facility was brought on with Chevron bringing in product that had a significant that was brought on a couple of months early. That significantly helped that business unit within Chevron meet their 2017 goals and objectives. That was extremely positive.
And Encana, who built and commissioned the Bearson Midstream assets, the tower facility, the Saturn and the Sunrise facility, those were also ahead of schedule and under budget. So that's very significant, not only from their ability to ramp up with respect to Barisan Midstream, but also all of those liquids go through our pipeline and go through our fractionators. So even when third parties and or our subs companies are accelerating these projects, that is a significant net benefit to Pembina. In 2018, Q1 has been looked great and things continue to look very positive, which I'll talk about here in
a little bit. Now, I
want to talk about kind of some of the projects that we have ongoing and give an update on that, but some of the key partnerships and relationships that we have that we think that are very key to our not only our success to date, but also our ongoing success in the future. On the left hand side there, you see a very complicated working interest partnership diagram, but Verusen Midstream is probably everyone's well aware of Pembina and KKR. We have a fantastic relationship with KKR. Working with them is actually extremely fun. That's Verusen Midstream.
And Verusen Midstream serves the Cut Bank Ridge Partnership, which is Mitsubishi, who is a partner in LNG Canada and Encana. So, that is basically all of Encana's Northeast BC Montney resource that's dedicated to our partnership with KKR, Veracy Midstream for 30 years, right. Over on the right hand side is the production, the throughput that Encana and Mitsubishi has been putting through the facilities. And I'll just point everyone's attention to Q4 2017 as you can see that's when the new facilities that Verus or pardon me, Encana brought on where you can see a significant ramp up in volumes and through those facilities. Up to 2018, we're almost at a BCF of raw gas going through those facilities.
And once again, all the associated liquids roll through Pembina's entire value chain. The other major, I think, relationship, partnership that we have is obviously with Chevron and Coupek in the Duvernay. We announced that deal, I think it was probably about February of last year. That's a 20 year area of dedication to Pembina for all infrastructure for Chevron's molecules in the Duvernay. We had built Duvernay 1 and built the Wassix hub, which is basically a stabilizer and separation facility.
And then we announced the Duvernay II, which is 100,000,000 a day facility, 30,000 barrels a day of stabilization and 300,000,000 a day of inlet separation and all of the other infrastructure required. So, when all that water condensate and gas shows up at the facility that we can separate that. You should note that all the land on this map, all of Chevron's land, this is just public land and you can also see Shell's land in there. They are also a partner in the Duvernay 1 facility and we process all of their Duvernay gas to date. So an extremely positive, if you look back, we've got Northeast BC Montney, which has some of the best geology and best metrics today.
Within Canada and Mitsubishi, we have 30 years relationship there. We have a 20 year relationship here and the Kakwa River Montney that Mick spoke about before, we have a 20 year relationship with 7 generations there. So we're well positioned long term to continue to grow in those areas. Now a little bit on the projects. This is just a picture of the North Central liquid sub that Encana is currently building.
This is anticipated to be on stream in Q4 2018. What this essentially is, is a great big stabilizer and a great big separator, separating the gas, the condensate and the water. The gas will go to the Saturn and Sunrise gas plants, which Baresons Midstream owns and all of the condensate will get stabilized at this facility and end up on Peace Pipeline and go to CBA. Our versatile ethane storage cavern, this is a 100% project that Pembina inherited through the Veresen acquisition. This is about 1,000,000 barrels of ethane storage that is contracted with Nova.
This project is going extremely well. This is under Brad's watch. So Brad's here today if you have any questions with respect to that. About $190,000,000 of costs and anticipated to come on in Q4 as well. Our Empress fractionation, this is, as I mentioned, a 30,000 barrel a day fractionator at our Empress facility.
Typically, all of the Empress volumes when they're extracted, they head up to Enbridge's line and they make their way all the way down to Sarnia. With everything that's changing in Western Canada, we're building a C3 export terminal, AltaGas. There's a couple of polypropylene PDHs. We potentially see that there might be a fundamental shift in the value of C3. It might shift from maybe Eastern Canada to Western Canada, but we also want that flexibility.
And so this fractionator will allow us to be able to frac those products at Empress, will be connected to CP Rail and then that will actually leave more volumes up at the Redwater area. Currently, a lot of the volumes that come out of Redwater because there's nowhere else for them to go, there's no PP facility in that neighborhood, we rail all those volumes, let's say, to Chicago or into the States, etcetera. We could actually rail these volumes in there, which is a lot closer. Empress is closer to the into those markets and keep those barrels at Redwater. So, we're just giving ourselves a lot of flexibility.
So, this is also an exciting project under Brad's watch. Our Prince Rupert export terminal, I'll focus everyone's attention over to the graph on the graphic on the left hand side. You can see Redwater, it's the red fractionator and Prince Rupert Terminus. Basically CN, you can put a train on to the main line and it can make its way all the way right to Prince Rupert, following obviously the goods and services that get imported into Canada. That's the route I don't know how it will go.
And I guess some key items with respect to the project. We've got about 80 people on-site right now. We're just kind of cleaning up the site doing remediation that's ongoing. Site already has a sheltered birth. I'm going to show a little bit of a video.
It's got some cool music, so bear with me when you see that. But it's going extremely well. This is going to supply our customers who show up at Redwater and increased flexibility in order to get to where the markets where people were paying a lot more for the product, as Mick showed, than we're paying for that we're receiving here in Western Canada. Here's a little bit of an illustration. Stu is going to talk about this with respect to Jordan Cove and LNG.
But if you can get any product to the West Coast, it's obviously very close to get it to into some Asian markets, comparatively to the other areas that are supplying Asian markets today. So West Coast to Northeast Asia, 12 days from Prince Rupert. If you look at the Gulf Coast, where primarily all the propane is coming out of today, it has to go through the Panama Canal in year about 28 days. So a significant advantage if we can get our product onto Tidewater, we can add a lot of value not only to Pembina, but also to our customers. LPG export, so your top graph is just showing the Far East C3 import demand go forward and the Far East imports and U.
S. Imports. Key takeaways on this is demand for propane is increasing in the Central and South America and the Asia. That's just ongoing. Demand has not been overly increasing in Edmonton, for example.
There's a 36% premium to the netback in Far East Asia versus Edmonton today. So, we get our product onto the water, we feel that we'll be able to provide our customers that extreme flexibility in increasing value for them. Now, I'm going to show you a little bit of a video with respect to the Prince Rupert terminal. I'll caution you, it doesn't look like this today. It's going to look like this 2020.
It. And bye. Okay.
Almost feel like you need to clap after that. Pat, I promise you when we go out there, we'll play that music for you. Just a couple of comments on that. Obviously, you see how those pipelines need to go over the rail lines, that CN's main rail line going to the port, hauling grain, etcetera. Our relationship CN moves all of our product today.
We've been we have a great relationship with them for years years. So that's going extremely well. And all of the major equipment, you see those big spheres, you don't build those overnight. All of that steel has been ordered and that's all in process of being completed today. And as I mentioned, we're just doing a lot of the work to see those rocks that's pretty sharp walls.
That's not like that today. So we have to do some blasting and stuff and that's basically what we're doing today. So project's going extremely well and the dock's in place today, so we're really looking forward to getting that project on stream. And in summary, so just kind of 4 takeaways with respect to the Facilities division is, one, revenue volumes and physical volumes continue to grow. That's obviously a good sign when you're in the fee for service business.
Our customers continue to drive down their supply costs. They continue to increase their 100 and day IPs, their ultimate recovery of reserves, they can do that. They continue to drive down their capital and just the overall productivity and the timelines with respect to how they're doing their work is improving through technology and cross border learnings from other plays. We continue to diversify the facilities portfolio. I talked about that in some detail.
It's not just as it seems. We're just adding more processing or adding more fractionation. There's actually strategic merit and there's differences in between each one of them. So that continues to grow. We're getting into sour processing and field stabilization, right.
And roughly 50%, 46% of our total field processing in January 1, 2016, 100 percent of our field processing was Deep Basin Cretaceous Sweet Gas on the dryer side. Now 50% is Duvernay and Montney, right. And that's primarily those 2 long term relationships that I mentioned. Well, 3 really, when you include the 7th gen, we've got our customers with Kufepec and Chevron, Mitsubishi and Encana and 7th gen, which we're extremely proud of working with those customers and we have great relationships on their really long term deals. So with that, I think everyone, Keanu is going to say a couple of words and then we're going to have a break.
A couple of words that I'm
going to say is we're going to take a 10 minute break. So tight turn. We'll be back at 10:15. So please grab a coffee, take a quick break, and we'll see you again
soon. And and
We're going to
get going again in about 2 minutes. So everybody find a seat, fill up your coffee and we'll get going real quick.
Me
Okay, everyone. If I could ask everyone to take their seats. We're going
to get underway right away with Stu Taylor.
Good morning, everyone. I'm going
to take a brief minute just to let you know we're going to talk a bit about our marketing group. We're going to talk a bit about the LNG opportunity, the Jordan Cove LNG opportunity. And then Kevin Jager is going to get up and speak to our PDHPP opportunity in the 4 Saskatchewan area. We took the opportunity upon the reorganization for our marketing company, marketing groups to essentially combine them all in one group. On the Marketing Adventures team, we pulled the crude oil midstream group and combined it with our NGL marketing teams and created the marketing group.
Move forward, I have one number in the whole slide actually to talk about, but our marketing group is expected to contribute 15% of Pembina's operating margin in 2018. Marketing plays a key role in the utilization of Pembina's infrastructure assets, which Jared and Jason have described, both through the marketing aspect itself, but the forward sale of those products for our customers. Our day to day market participation and gain market intelligence improves Pembina's understanding of customer needs. Marketing agreement is active in the short term on a day to day basis, but is also very active looking at long term trends, imbalances and helps Pembina look at new opportunities for infrastructure that need to access new markets. Marketing activity enhances customer netbacks and encourages further development of the basin's resources, thereby benefiting Pembina's infrastructure businesses.
Marketing combines Pembina's infrastructure and marketing launch to capture value in a range of commodity pricing environments. Marketing uses services on a fee basis through a variety of the Pembina's infrastructure, both the facilities and the pipeline division, brings a perspective of value for that capacity beyond the fees and engages in a range of commercial activities, including marketing for others, storage, accessing downstream markets via pipeline, truck and rail options and optimization opportunities. The activity provides insights into commodity markets short and long term. Marketing sets up its businesses driven by a proprietary perspective on where the commodities are most needed in the current cycle, 1 month to 1 year, but also on a forward looking basis where the commodities will be needed next beyond the next 2 year horizon. The Edmonton terminal, the Canadian diluent hub, Watson Island Propane Export Terminal, the PDHPP facilities are examples of infrastructure where opportunities were identified and led from this marketing perspective.
On this slide, we've captured some of the highlights. And I think it's quite surprising to what is the volume of products that our marketing group does and will on a daily basis. Marketing is a significant participant in the market for Western Canadian Sedimentary production. On a barrel oil equivalent basis, we handle in excess of 500,000 BOE per day. We service markets across North America with international destinations in the not too distant future.
Some of the highlights, again, we actually contracted supply of natural gas 1.9 Bcf a day, and that is behind our Taylor assets and through our Empress facility. We had 145,000 barrels a day of NGL transactions, 145,000 barrels a day of crude oil and condensate transactions. We marketing shipped 20,000 railcars in 2017, 60% of our LPG sales were transported by rail, 11% by truck and 29% by pipeline or inventory transfer. LPG product was railed to over 3 20 different locations across North America. Themeda's fleet of rail tank cars is expected to reach 2,800 by the end of 2018 and marketing transported 41,000 barrels per day of product.
And again, 60% of our products handled by rail requiring a massive logistics coordination and rail fleet management, which again, we believe to be a core competency for the marketing group. There are many factors that drive Pembina's marketing margin. Our margin can be reflective of what's happening in the prop markets. There can and has been variability over time as you would expect when seeing these graphs. On this slide, we've highlighted a few of these contributing factors.
What jumps off the page is the graphs in the graphs is the volatility. And first to the left, oil differentials tightened. First of all, we're wide before the price collapse in 2014, some wide differentials, which leads to opportunity. Price collapse in 2014, some wide differentials which leads to opportunity. The tightening following that oil price collapse through 2017 led to some challenges as far as the differential basis in the marketing group.
But we've seen that widen again in late 2018 and are seeing increased revenues generated through those oil differential pricing. On the propane inventory slide, the graph in the middle, new U. S. Exporting capability has pushed C3 inventories to near the bottom of the 5 year range with 2018 levels below 2017. And we expect to see solid pricing for C3 in the short and medium term.
We are excited about that. The pricing should improve with the shortness that is available and that greatly enhances the value of our fractionation business. Finally, the frac spray itself, which is shown, there's no question that the frac spread margins are driven by many factors, including the level of propane in inventory, which has swung wildly over the past 5 years, but particularly the egress challenge for natural gas volumes associated with the shale developments. Again, low gas price and improving LPG pricing is driving a lot of our margin in marketing group. Having a strong working knowledge of the fundamentals is a core competency for Pembina to stay on top, what is happening and how commodity markets are evolving.
Brief outlook for the marketing business. Pembina's base business, as Jared and Jason have described, is continuing to grow and the marketing business will grow along with that and will grow with the increase in Western Canadian Sedimentary Basin production. Our marketing business, we see near term challenges for natural gas, which will support strong fractionation business. LPG supply growth is strong, but growth in exports will support healthy netbacks. Tightening of crude inventories has led to stronger pricing offset by regional Canadian challenges to get that product to market with stagnant pipeline egress, maybe that's solved this morning.
And marketing can participate with our base business to invest in infrastructure and develop a merchant role around those assets. Marketing will continue to use its marketing knowledge to identify the next constraint point or imbalance between supply and demand and working with new ventures to find new long term market solutions. I'm going to jump into the Jordan Cove presentation, a brief background on what the project is exactly. Again, our Jordan Cove opportunity, which we inherited through the acquisition of Veresen, is an LNG export opportunity located in Coos Bay, Oregon. It's on a site, a 240 Acre site on the northuspid of Coos Bay.
It's a liquefaction and export facility for LNG with a capacity of about 7.8 1,000,000 metric tons per annum. Our plan or design is 5 separate liquefaction trains, each 1,500,000 metric tons. The incremental 0.3 is just due to ambient air temperature. 2 full containment LNG storage facilities of 320,000 gas treating facilities and marine facilities. To locate where you're at, behind the 2 large tanks are the 5 trains towards the top of the page.
And again, we like that technology and that design for the redundancy and the reliability. We can do maintenance on any one of the trains at any point in time. We can bring additional volumes in to utilize that. As we go to look at Phase 2, once we get past Phase 1 of this project, we look at Phase 2, the site is already prepared and is ready for an expansion, essentially doubled in size. Access to over 25 Bcf a day of gas supply from Western Canada and the Rockies makes a critical point in LNG from a low cost gas supply basis.
And there's significant benefit for this project in Southern Oregon. It will create over 6,000 jobs at peak construction, over 8,500 indirect jobs, spin off from the project and 1500 permanent jobs. Will generate $60,000,000 per year in average property tax revenue for Southern Oregon itself. And for anyone who's been to Southern Oregon, it is a place that they're anxiously awaiting for this project. The tax base that will be created will go a long ways in support of schools and buses for those schools and the areas in general economic benefit.
This is probably the graph that has the most context for us and why we like the Jordan Cove project in particular. This is total LNG demand. It's expected to almost double by 2,030. With current global demand of around 300,000,000 metric tons per annum and the blue, that's the gray. The blue actually is accounting for almost over 100,000,000 metric tonnes of new capacity to be added between essentially now and 2025.
And as you see, the demand curve in that 2024 time frame starts to dramatically outpace the supply of LNG. And by 2,030, it's almost doubled to nearly 600,000,000 metric tons per annum. And by 2,040, the projection is 700,000,000 metric tons. So lots of running room. The timing of the demand, Jordan Cove was possibly a bit before its time previously, but right now with our in service our expected in service date, we're very much matched up to when that demand starts to exceed the supply basis.
Most of the growth is expected to be in Asia, where LNG imports will be on the rise due to constraints in domestic supply. Chinese imports in Q1 2018 have increased by over 50% year over year. We are actively in conversations with Chinese off takers. Japan, Korea, Taiwan imports are projected to be flat to declining. However, 50% of Japan's existing contracts expire between 2019 2025.
They are looking for diversification from their historic supplies. Recent elections in Korea signaling a phase out of nuclear and coal gas fire generation brings in a strong new offtaker for the project. And North America's abundant gas supply with the cheap shipping costs makes Jordan Cove a very attractive opportunity. This is an LNG supply shipping day graph. Jared showed one that had for our LPG product.
But basically Jordan Cove to Asia, along with the abundant low cost gas supply, one of the significant costs for any LNG project is shipping. And as you can see, our round trip is estimated to be 25 days, Jordan Cove to Japan and back at a cost of essentially $1 for our shipping cost. If you have to go through the Panama Canal and the challenges of the Panama Canal have been well documented, your cost essentially doubles to nearly $2 And again, if you can't get through the Panama Canal and you are forced to go around Africa as an example to get to the same markets, your cost essentially triples up into the $3 range. In conversations with some off takers who have secured capacity on the Gulf Coast, 3 of their 4 cargoes actually end up going around Africa at this point in time, just due to congestion, limitations of LNG ships through the Panama Obviously, you have to be cost competitive in this business. There's many people looking at this opportunity.
The market will allocate incremental LNG demand by the cost of supply and the lowest cost producer will win. Jordan Cove and Canada's West Coast have the shortest shipping distance to Asia, I already mentioned, allowing the projects to compete with Brownfield Gulf Coast project. This is the graph represents our interpretation of IHS data and incorporates all the costs, including shipping. As you can see in the cost stack, Jordan Cove competes very favorably with North America and global LNG projects. Jordan Cove has a slightly higher fixed cost due to its location from a build perspective, but benefits from the abundant gas supply.
And just as a point, the gas supply that we're assuming in here is we're actually assuming a $3 Henry Hub U. S. And a $2 AECO price U. S. As well.
So with AECO trading, as it is seeing in these days, our costs actually dropped dramatically as well from
delivered for
base. As a new project for Pembina and Mick spoke about on time and on budget, we're doing everything we can to actively manage the project risk. Pembina is committed to growing the business while maintaining its financial guardrails. We're actively managing these risks using lump sum turnkey EPC contracts, experienced LNG EPC contractors and Tem and his major project team has recently taken over the Pacific Gas Connector pipeline, the team that essentially built our Phase 3 pipeline on time and on budget. We're continuing to discuss selling down our interest in the project while maintaining control, and we'll utilize a conservative capitalization plan by financing at the project level.
We are again, we're sitting at this point in time, we're 100% working interest on the facility. Our off takers are interested in equity. There are others who are interested in equity, but our plan is to maintain a majority interest in the facility on a go forward basis. Gas egress supports Pembina's based business. The more gas we can get out of Western Canada, delivering a higher netback for that gas molecule will drive additional plants, additional pipes and additional fractionation facilities in Western Canada as well as the Rockies.
And LNG, again, I think we're in the boat and I think everyone agrees LNG is a global transition fuel. We are seeing the process. We looked at this opportunity when we acquired DuraSyn and why does it make sense. The strengths, Asian buyers and governments want a West Coast LNG supply source, price competitive with the Gulf of Mexico, brownfield LNG delivered to Asia. It's right sized for the market at 7,000,000 tons.
It's a capital expense. And again, the first phase of our expansion will fit well, and it's fitting well with our off takers as well. We have long term gas supply. We have abundant gas supply coming out of Western Canada, Rockies. We are connected to 2 significant gas pipelines, one of which we are 50% owner in the Ruby pipeline, which has spare capacity, and we're working with TransCanada to access gas through its system and GTN into our Jordan Cove facility.
We believe there's a structural and sustainable feedstock advantage. The ability, as Jared has described, and the efficiency of the producers to drill wells, largely driven off condensate economics, There'll be abundant gas supply at a low cost. And it has strong support in the state and from the community itself. How can Pembina help Jordan Cove? Again, we have a proven track record of successfully building projects on time and on budget.
We've got a demonstrated history of relationship building across stakeholder groups, including tribes, landowners, communities and regulators. We have a robust balance sheet, low cost of capital supports our project financing, and we have strong relationships with the customer base. A lot of our customers up stream are multinationals. They are looking to get their gas reserves delivered into their own countries, and we can facilitate that. And as Mick described, we provide the entire Pembina store for these people from processing pipelines, fractionation, ultimately gas delivery and LNG.
I will say just as a closing, we are continuing to await our FERC certificate. It is a bit delayed, though it is being worked on. We don't have a schedule at this point in time. We are awaiting the FERC draft schedule to be released, but it is a bit delayed. But we are our knowledge at this point in time is that it is being worked on as fast as any of the other LNG opportunities, and we expect it in the very near future, but probably pushed us back a little bit from a timing perspective, and we'll keep on top of that.
I'll turn it over to Kevin. Oh, there it is. There's our key milestones. Thank you.
Thanks, Stu.
I'm Kevin Jagger. And in addition to my role in the petrochemicals group working for Stuart at Pembina, I also have the role as commercial manager for Canada Kuwait Petrochemical Corporation or CKPC. So I'll talk a little bit more about that, but from that context, reporting to joint owners. I'm going to walk you through an update of our project and the progress made on the PDHPP project. The project's a world scale, a fully integrated propane dehydrogenation and polypropylene production complex.
It's located immediately adjacent to the Redwater complex, just northeast of Edmonton on industrial lands owned by Pam and I. In 2016, we acquired 2,200 acres of land to facilitate downstream development. Just as Jared laid out, significant infrastructure built upstream that's now put us in a position and that capture of stable and significant scalable feedstocks. We looked at acquiring land to facilitate this development, and this project will use just under 20% of that available land. CKPC is a fifty-fifty joint venture.
Our partner is Petrochemical Industries Company or PIC, a wholly owned subsidiary of state owned Kuwait Petroleum Corporation. And you've heard us refer to Kufpec a number of times. We have a 20 year partnership in our gas services business. Kufpec and PIC are sister companies. They're both 100% owned by KPC.
The facility will consume 23,000 barrels a day of spec propane and produce 550,000 tonnes of polypropylene. So to put a little context to those numbers, the propane is about 10% of WCSB production and the PP production is roughly 6% to 7% of North American demand of polypropylene. The expected capital cost, again, this number is on a fully integrated basis. So the PDH, the PP processing units proper as well as what we call the outside battery limits, which includes the central utilities block, including the cogen, rail, off sites associated connectivity, an all in number is C4 $1,000,000,000 Getting to what is polypropylene. Whether you know it or not, as Canadians, we interact with polypropylene each and every day.
It is a key material that enables modern life. From our cars to our Canadian banknotes to the lid on your Starbucks cup this morning, it's actually the very carpet we're standing on right now. All of that is produced with polypropylene. There's a number of desirable attributes that make PP a desired resin and a top material. From its heat resistance, that allows it to comprise car components that it can actually go under the hood.
Its durability and toughness make it great for multi use durable goods in your household. But perhaps probably its most notable attribute and something that it's seen continued market share capture is due to its recyclability. Many regional and macro factors kind of drive the strategic rationale of an Alberta PDHPP, and it also kind of helps to frame why now, why this opportunity now. And it really lies in the convergence of 3 commodity trends: 1, Alberta propane 2, North American propylene and 3, North American polypropylene. And I'm actually going to work from the bottom of the slide up.
And I think what that helps to do is change the opportunity around and specifically how we frame propane. Instead of propane being the question, we have all this propane, what do we do with it? I think when you look at the opportunity that's created in polypropylene, propane is in fact the answer, not the question. So between 2,005 today and again, I'm at the bottom at the polypropylene side, between 2,005 today, 8 North American polypropylene plants closed. That includes 1 in Quebec and 1 in Ontario, while only during that same timeframe, only 1 greenfield plant opened.
So 8 closed and one opened. Over the same timeframe, PP demand continued to rise, driving up North American demand by over 1,000,000 metric tonnes per year. Combined with the production lost and the growth in demand, that created a 2,000,000 ton a year shortfall that led to imports of polypropylene coming into North America for the first time ever in 2016, and we as Canadians are now 100% reliant on imported polypropylene. So why did these plants closed? A couple of them were too small to compete anymore, a couple using outdated technology, but the primary factor across the portfolio was lack of access to available feedstock.
And in this case, when we're talking about polypropylene, we're talking about propylene feedstock. So now we kind of go to the middle of the page and look at propylene. Traditionally, propylene is produced as a byproduct. It's not created intended. It's a byproduct of another process.
Nearly 90% of propylene production in North America comes from 2 sources: 1, refineries and 2, crackers. In refineries, propylene is a byproduct of gasoline production. With higher fuel efficiency standards and the proliferation of electric vehicles, we are seeing a trend of declining gasoline demand and associated gasoline production, which takes with it propylene production. In crackers, propylene is a byproduct of ethylene production. With the shale gas revolution that we've talked about at today's session as well as Investor Days in the past, the associated low cost gas has led crackers, most notably Nova in Sarnia to retool.
And they've retooled from consuming crude based feedstock, I. E. Naphtha to gas based feedstock, namely ethane. When a cracker switches from naphtha sorry, when a cracker is consuming naphtha, 12% of the product at the back of that facility is propylene. That 12% off the back of a cracker drops to 2% when that cracker starts consuming ethane instead of naphtha.
Again, a major source of propylene that's being impacted by the market dynamics of another product, leaving polypropylene producers having stranded access to the propylene sources that they relied on the back of refineries and crackers. That has now led to the advent of what we're referring to in what's been called on purpose propylene. So propylene not produced as a byproduct, but it intended to be produced on purpose. In North America, North American PP producers and certainly when it comes to any new production must have a secure supply of propylene. And in order to produce on purpose with our geology here that leads you to consuming propane to produce propylene via PDH.
So now that takes you to the top of the graph, Alberta propane, the answer to the opportunity created in polypropylene. With improvements in drilling technologies, we've seen the boom in natural gas liquids. We've seen the fracs come online. And again, the other dynamic is Jared walking through not only this excess propane that came, but a shortfall in condensate. So we had a mass oversupply of propane and then at the exact same time, a structural shift in market access occurred in 2014 when the Kinder Morgan Cochin pipeline reversed service.
Instead of taking propane out by pipeline, it now brings condensate in, leaving every molecule of spec propane in Alberta now has to leave the province by rail. The pricing impact of this was pretty immediate and pretty dramatic. Absolutely nothing has changed with how Alberta propane is priced. Alberta propane is priced on a cost a transportation cost differential to getting to the robust larger U. S.
Trading hubs. In this case, what's on the graph is Mont Belvieu, Texas. When spec propane is moved by pipeline, the price differential reflects pipeline costs or pipeline tolls. So prior to the Cushing Reversal, about $0.11 a gallon. That widens by about 2.5 times the moment that pipeline is cut off for propane service and instead you have to load a railcar and send it all over North America to find a market.
Now looking at WCSB propane production in a little bit more detail, Western Canada is forecasted to produce 200000 to 300000 barrels a day of propane. The red column is effectively local demand. The gray column is Eastern Canadian demand. And again, we've talked about it at the West East trade. This is Alberta product that gets shipped on Enbridge mainline and eventually fracked at Sarnia and sold into the Eastern market.
We've touched on the Empress frac that we have, that's putting pressure on that gray bar that perhaps some of that volume instead will stay in Alberta. But collectively, that's about 100,000 barrels a day. Even accounting for both PDHs, that leaves well over 100,000 barrels a day of Alberta propane that still needs to be loaded on a railcar and exported out of the province. So is there room for 2 Alberta PDHPPs? As you can imagine, this is a question we get asked quite often.
And to save you all the suspense, yes, we do believe there is room for 2 and in fact, we believe there's room for more. Just on the left hand side talking about PP a little bit further, global PP demand continues to rise. Traditional applications see demand driven by population growth as well as the world's largest populations, notably China and India, demanding the types and quality of products that we as North Americans have enjoyed for years. Additionally, in addition to kind of base growth among existing PP applications, PP continues to see growth driven by new applications, again using electric vehicles and higher fuel efficiency standards as an example. That has led to a continued drive in innovation of lightweighting vehicles.
In order for the vehicles to get, A, more efficient and, B, carry the additional weight of the battery, These cars need to continue to get lighter, which means PP continues to capture market share from materials such as aluminum and steel. With strength in PP demand, the focus is on feedstock. We've already walked through how Alberta is positioned from a feedstock perspective, but the Alberta advantage is starting to go beyond purely low cost feedstock. We have a supportive government, a favorable labor market, significant existing infrastructure and investments that have already been made, location advantages to the major U. S.
Markets. Again, the vast majority of Alberta hydrocarbons typically have to find a home in Texas. Now we're talking about a product that needs to find a home in Chicago, in New York, in Southern Ontario. So again, that takes the Alberta advantage beyond just a discount at the front end of the plant, but instead a sustainable advantage over our global peers. Now a lot of you would have seen this graph before.
It's really just showing the delta in value between propane and polypropylene. On a purely economic basis, the uptick is 5 to 7 times, but there are a number of other compelling value drivers or considerations between these two lines. One is reduced rail traffic. Right now, we load and rail the red line, the propane. Every one railcar of polypropylene that moves in North America is roughly the equivalent of 2 propane cars that we won't have to ship.
We can ship 1 PP car instead. Lower relative rail costs. We move a propane molecule that in many cases, we've sometimes had to pay 50% to 100% of the value of that product in rail costs. Now we're shipping product where the rail costs are roughly 10% of the value of the product we're moving. Global market access, you've heard us touch on this a number of times.
There's some infrastructure impediments for propane to reach and achieve global pricing. If we were producing PP now, we could sell into the global market today through existing channels that are well established in Vancouver, Prince Rupert as well as the Pacific Northwest of the U. S. And finally, kind of from a Canadian perspective on national trade, we export 85% of the lower red line and import 100% of the higher value blue line. This project will help to flip that trade around and preserve significant value within Canadian borders.
Now to talk a little bit about CKPC. CKPC truly represents an organization where 1 +1 equals 3. Pembina brings the strength of a local partner, feedstock access and security, while PIC brings international petrochemical experience and established marketing channels. Pembina's expertise is at the front of the complex, the ICs is at the back and in the middle is CKPC. Cognizant of our corporate guardrails, we continue to pursue fee for service opportunities and we've actually not only seen a strong interest, but a steep uptick in the learning curve of WCSB producers with respect to this opportunity.
We'll talk to you a little bit about our joint approach to risk in a few slides. But since day 1, our strategy and again, Mick alluded to it earlier of our Board's request to go out and find a partner and we took the challenge on and went all over the world to find a partner. And we secured an aligned partner where we each brought complementary, not necessarily competitive strengths to the partnership positioning CKPC for long term success. Aside from counting among the world's largest petrochemical companies as its existing JV partners, CIC has experience in Alberta, existing investments in PDH and PP production plants and global marketing channels, which already include PP in addition to other products. Staying on marketing, CIC's strategic direction, as you can see on this graph, red represents polypropylene, blue, dark blue is polyethylene.
So from a polymer perspective, strong presence certainly in the Middle East as well as Europe and Asia, but noticeably absent from North America is BIC's polymer presence. The green assets there are ethylene glycol assets, which in fact they have 3 operating assets in Alberta. And we kind of joke that we went around the world to find a partner and found one that had operating assets on the other side of the North Saskatchewan River. So we for PIC, their direction was to penetrate North America. After extensive review, that entry point was Alberta and their access point into Alberta was through Pembina.
For Pembina, we desire to reach global markets and our entry point is through PIC's existing, vast and expanding global marketing channels. It truly is a great fit. So what PIC offers right now is PET production in Germany, polyethylene in Kuwait, ethylene glycol in Texas and Alberta and polypropylene in Kuwait, and they just turned on a new plant a month ago in Vietnam. And they leverage the same technology that we'll be employing in Alberta. PIC has strong existing relationships, and what this allows CKPC to do is enter the market before we turn our plant on.
When we commence operations, PIC will be marketing over 2,000,000 metric tons of polypropylene worldwide. Part of our alignment with PIC as a partner was our consistent approach to managing project execution, operating and business risks. On the construction side, we see a favorable market, have a very accessible site in a county we're extremely familiar building in, leveraging commercially proven technologies and also pursuing lump sum EPC contracting. With respect to operations, we're drawing on 3 deep pools of expertise. The partners' existing experience aggressive local and global recruitment of experienced petrochemical operators and bringing them into the CKPC fold and continuous engagement with the technology licensers leveraging lessons learned from around the world.
Finally, given the size of this project, again, we touched on it earlier, we elected to partner to share risk and leverage experience. We continue to pursue fee for service and have secured support from multiple levels of government, including the $300,000,000 royalty credit from Alberta Energy. This April, our relationship with PIC officially passed the 3 year mark. Over that time, we've hit some significant milestones. We secured the land, we've been awarded the royalty credits, we selected our technologies and we've kicked off FEED.
Momentum continues to build and with over 200 FTEs from CKBC and our contractors currently engaged on the project, we're positioned well to conclude FEED in Q4 this year and then seek FID from
our partners.
To summarize this slide, in short, the more we advance this project, the more we love it. Stable long term feedstock supply, leveraging billions of upstream and downstream connectivity investments already made, ability to access global markets, reduce rail congestion and associated rail costs, and then align support across our stakeholder group and most notably our partner PIC who along with their sister company Kufpec have developed extremely strong ties across our entire organization and they have positioned us to develop, execute not only on this project, but future projects to come. Thank you very much. I'll ask Scott to come up to speak about our financial position.
Good morning, everyone. My name is Scott Peroz, Pembina's Chief Financial Officer, and I'm here today to talk about Pembina's enviable financial position. And really today, I'm covering 2 main topics, 1 being Pembina's financial guardrails second, our funding plan on a go forward basis. So in terms of our financial guardrails, this is a slide you've seen many times for us from us. And just to remind everybody what our financial guardrails are.
They're essentially the deal that we have with our Board and our shareholders when we think about how to approach strategy. With all the new ventures that Stu is currently investigating, not only LNG, PDHPP and other opportunities, they continue to serve us well as we think about new strategies. When we get down to the individual investments, we of course have our 10 to 12 investment criteria we consider for individual investments. But as a global strategy, these guardrails are really how we approach it. As you can see from the page, we're in a strong position on each one of these, and we're going to go through each one of these in details.
Other than the first one, maintain 80% fee based contribution as Mick had already addressed that slide. But I did want to make 2 points on that guardrail before I move on. One, you'll see that in the past that number was historically around 87%. So it's come down marginally. But what I would point out is the fee for service and take or pay has actually increased.
It's just that our marketing business has increased a slightly higher pace. So we're actually making more money overall. So it is a good news story. Secondly, when you actually look at the numbers, 77% to 85% is still a very positive outcome. But when you drill down and look at the absolute EBITDA that actually an increase of take or pay or fee for service EBITDA from 7 it's actually an increase of take or pay or fee for service EBITDA from $750,000,000 to $2,250,000,000 today.
So over a $1,500,000,000 increase or a 200% increase in fee based revenue. Looking at our 2nd financial guardrail to target a payout ratio from our fee for service business of less than 100%. This was quite a journey that we've been on when we set these guardrails. If you look at 2015 2016, we were approximately 130%. So again, that's paying out all of our dividends, all of our corporate costs that includes our G and A or interest on all our debt.
We still relied on a significant portion of the commodity business. In 2017, we almost got there with 105 percent payout ratio. And as we move forward to 2018, we're currently forecasting again a fee for service payout ratio of 85%. Again, one thing that we always like to point out on this slide, because there's variations of this graph and other people's investor decks, We've allocated no G and A, we've allocated no interest, anything to our marketing business. This truly is the fact that our marketing business could go to 0 and our dividend is safe.
I would also point out that this graph includes distributions from our joint ventures. So again, along that same lines, it's after all corporate costs within our joint ventures, including debt amortization as a couple of our joint ventures also have pretty significant debt amortization as well. And so when you look at 2018, we're now in a position where our dividend only relies on our take or pay and half of our fee for service business. So very solid foundation to the dividend payout. Moving on to our 3rd guardrail, which is to maintain at least 80% of investment or split grade ratings.
You can see from the chart here, when you look at our investment grade and split rating, we're over 80%. It's about 83% overall. What I always like to point out is the pie chart on the bottom, because I think generally speaking people assume that all of our non investment grade and our split rated is just pure junior E and P. And what you can see from that graph overall is that over half of our non investment grade and split rated is chemical companies. So as you know, one of our largest customers is Nova Chemicals, very solid counterparty, but they are split rated, so they do not fall in upper bucket.
We also have deals with other midstream companies, as well as a lot of retail propane deals, which just given the size of those companies, they can't have an investment grade rating. Now we do other things to protect ourselves such as LCs or prepays. So the point is that overall, we only have about 12% of our exposure, 12% to 15% of our exposure to junior oil and gas. Another point to point out is, as you think about the cycle that we've come through, we've talked really a lot today about Pembina's ability to make it through the cycle. Our producers have been extremely resilient as well and Pembina's benefited.
When you think about 2015, 'sixteen and even into 'seventeen the commodity price we faced, Pembina had no material bad debts. So just a remarkable outcome given the cycle that we've come through. And part of that is just the diversity of customers. As I pointed out, not only do we have over 200 customers, Pierre pointed out we're diversified across geological plays. We're diversified across geographic regions.
It's a subtle benefit of the Veresen transaction. Veresen brought a lot of counterparties to the Pembina name that we just didn't have before. So again, diversity across the credits exposure. 4th, Guardrail maintained strong BBB credit ratings. As you know, Pembina has taken a conservative approach to its balance sheet.
Our credit metrics as we stand today are all forecast to be within our target ranges that we set out a year ago. In fact, they've all trended in a positive direction since we did set them. And we think that we manage our balance sheet in a way that is appropriate. And given the numerous factors that we face, when you think about what a strong BBB metric affords us, it allows us flexibilities for increase in the capital program. It allows for protection against downturn in commodity prices.
And lastly, it protects against changing rating agency goalposts. We've seen that happen in the past. So when you're in the high end, those ranges come down, we're well protected. So we've designed the capital program to fit within that financing strategy. When you look on the right hand side, you can also see that Pembina continues to maintain one of the most conservative balance sheets in the sector.
Moving on from our guardrails and to talk about a little bit about our financing history, our approach to the balance sheet and how we see the business on a go forward basis. You can see on the top left pie chart, if you look at the debt and consider half of the press debt as well, we funded our business basically 48.5 percent debt and 51.5 percent equity from 2012 to 2017, which is consistent with our stated goal of fifty-fifty debt equity over the long term. And we think that this positions us well on a go forward basis. The chart on the bottom left is really an illustration of our estimated capital program for 2018. So where we stand today, the equity portion of our capital program will be funded solely with internally generated equity.
So I apologize to all the bankers in the room that are hoping we're going to raise equity. That's not going to happen in 2018. We're self funded. In addition to the capital program, we also have CAD2.2 billion of room on our credit facility and currently have approximately CAD300 1,000,000 of cash on the balance sheet. When we think about the program on a go forward basis, we're confident that we have a self funded model for the equity portion of our capital program.
Moving on, what this graph really tries to illustrate is our approach to how we manage the balance sheet through large builds. And if I take you back pre this graph in 2010, 2011, we are facing a similar situation where Pembina was just starting to grow. We actually had the high end of that range, more in the middle of the chart and the dip was below the downgrade threshold. And really coming out of a conversation with the rating agencies that we said, well, yes, the dip is below the downgrade threshold, but we promise we're going to get back once all the projects come online. And really what they said to us was, we've seen this movie before.
Everybody does that. Everybody says they're going to get back and then they continue to grow or things don't go as they expect or capital increases and you never really get back. And it was good advice. We took it back. We ran some scenarios and we thought about the capital program and all the opportunities that were ahead of us.
And so what we approached this was, we're going to go with our strong BBB credit rating, which means we start always at the high end of the range, which is really close to what we consider the upgrade thresholds. What that allows us to do is we build the projects, get to about the middle where you've spent majority of the capital, but you don't have the cash flow yet and it really strains the metrics. But we keep that bottom end above where the downgrade threshold is, so that when the projects come on, we're always above it and we
don't face that risk of
cost overruns or increased capital and we stay below that threshold. So the graph there really illustrates our journey that we were on from 2013 to 2018 and how we manage the balance sheet through that very, very heavy capital program before we started to receive the cash. I think this is important for people to understand because as we go forward with both the CKPC project and potentially the Jordan Cove project, we could face this same general curve again. But the point being is we're trying to leave you with the confidence is that we start high and maintain it through the cycle.
The other thing that it's
led us to is significant cash flow generation after dividends. As Mick pointed out, from the time of 2,006 to 2011, 2010, Pembina really didn't have a significant growth program. So it had no requirement to retain cash. So essentially, we were running at about 100% cash flow payout ratio. As we moved into 2010, 2011, we started to retain incremental cash flow as the capital program grew.
Of course, in 2012, we acquired Providence, so we took on a little bit more commodity exposure. So again, a little bit more conservative with the payout ratio. As we moved into 2013, 2014, we set our corporate guardrails. So again, a governing factor in terms of how we think about the business and how we think about our payout ratio. Of course, 2017 2018, we've seen a material uptick in our cash flow generation, both from the acquisition of Arison, but also the majority of our growth program came online in early middle of 2017, which has led to if I look at this graph, we're using 2018, that's really a trailing 12 months, about $650,000,000 of cash flow after dividends.
We would, of course, expect that to be higher for a full year 2018 as the projects continue to ramp up. We have a full year of Veresen versus just 6 months within those numbers. But point being is now not only have we grown the payout sorry, have we grown the cash flow per share, but with a lower payout ratio, there's very significant cash flow generation, which gives us confidence in the ability to say that we're self funded on the equity side of our business. Just a subtle point and something that's new to Pembina shareholders is through the acquisition of Veresen, we of course acquired pretty significant joint ventures. And with those joint ventures, they have debt that's amortizing at the joint venture level.
So for Pembina, we pick up the distributions and those distributions are after all the corporate costs and after the debt amortization, we pick up those distributions in our adjusted cash flow per share. But what I'd point out is on the slide below between 2018 2021, I mean this graph continues on, but we just cut it off at 2021. There's roughly $600,000,000 to $700,000,000 of debt that continues to amortize at the joint venture level. And on the right hand side, what we did was quantify it on a per share basis. Now the right hand side doesn't include the Ruby debt amortization because, of course, we have the preferred interest.
But just alone on the Alliance and Verus and Midstream, the amortization is roughly $0.20 an adjusted share. So moving forward, again, a question we get a lot is, can we finance Jordan Cove and can we finance the PDHPP together. And similar to Kevin's answer, the answer is yes. And really what we've tried to do is highlight the projects here. And when you think about the overall equity check, they are quite large.
But what you have to realize is that that spending is generally over a 3 to 5 year timeframe. So when we model it out, it works out to somewhere in the neighborhood of $600,000,000 to $800,000,000 a year of equity requirements. And I think as I pointed out in the previous page, where we're going with our cash flow per share growth and where we're going with the payout ratio, we believe that we have the equity, the internally generated equity to fund both Jordan Cove and CKPC. Now I will point out on this page, the illustrative Jordan Cove financing assumes a 60% hold or a 40% sell down. As Stu pointed out, that is our objective when it comes to Jordan Cove.
So I spent a lot of time discussing how we're going to fund the equity portion of our capital program. We, of course, do rely on the debt capital markets as well. And consistent with past, given the underlying asset base and contracts that Pembina continues to sign, we will continue to pursue long dated maturities and a debt profile that helps to mitigate interest rate risk and refinancing exposure. We also look at our maturity schedule on the bottom. As you think about kind of Pembina today going out to 2023, the timeframe as we're adding on CKPC and Jordan Cove, we actually have a very, very manageable debt maturity profile.
So from where we sit today, we feel confident about our ability on the debt capital market side in addition to the internally generated equity. And so lastly, as a check, we're up here singing our praises, but what we thought we would do is just look at where we stack up versus our peers. And when we look at this slide, really what we're trying to highlight is obviously we have the lowest payout ratio in the sector for 2018. We're one of a small group of companies that have not had their credit rating changed since 2015. And we're only one of 2 companies that currently do not employ a dividend reinvestment program.
So for us, this was evidence that our financial strategy is working. With that, I'll pass it over to Mick to wrap it up.
Bringing it back together, most of the presentation obviously is about shareholders. That's the purpose of the session today. But I do want to just emphasize that we really do feel business for all of our stakeholders. I actually spend an equal amount of my time with each stakeholder, with customers, 18 field tours a year, meeting with employees, meeting with communities, I've gone through these, so I'm not going to go through them again. But I'm going to talk a little bit about customers, a bit about employees, a bit about community closing.
So why do people buy things in the Pembina store? Let's use a pipeline example. So on our pipelines, we can take any product that comes out of the ground, whether it's C2 plus C3 plus crude, condensate, natural gas. And wouldn't you rather just get your services all from 1 company? And if you do and you do get processing and pipe and fractionation and marketing and maybe someday propane exports or polypropylene LNG, you get discounts.
If you were our Board of Directors and you saw our economics, we actually discount every step in order to make adequate returns for the benefit of customers. And so we are able to give discounts for multiple service commitments. We also give volume discounts. And as Jason outlined, our build and you can imagine that the build between Fox Creek and the Mayo where we only have to power up the lines is very accretive to us and our intent is to share that upside with customers. So as we kind of position and we see demand continuing to grow for those ultimate expansions, we intend to wrap additional discounts and opportunities in whatever open season or next offering we plan for our customers to so they can share in what we've created.
We align commitments across the value chain. So let's just say you had your processing with Tiara and your pipe service with Pembina and Dow or Plains was doing your fractionation. If Plains is out, if Plains is down, you're still paying Pembina and you're still paying Keyera. When we wrap our services as a bundle, if we're down at the frac, which Brad assures me will never happen, You don't pay for the pipe, you don't pay for the pipe, that's a big deal. We allow people a step up, right?
So if you're exploring in
a new area and you don't really know how your wells are going to work out, let's use a simple example. Are going to drill a bunch of wells and you are really confident you are going to get 10,000 barrels a day. But depending on how many wells you drill and risk having capacity you don't need. We give people 10 with an option to go to 20. That's worth a lot.
That's game changing for customers. We give them priority access to expansions. We have a lot of storage, as Jared showed, on our systems, both on our pipeline systems and at the delivery point on our systems to create buffer, so people can continue to produce even if there's outages wherever they might be in the value chain. The exciting things that Stew is working on, we are going to expose our customers to the upside potential of international pricing. So value chain, the bundled offering to customers will get even more exciting and more accretive.
Talked a lot about shareholders. This is our recent 10 year graph. So red is kind of Pembina to total return. Blue is the energy infrastructure total return. So we're outperforming our peers on average by over 2 to 1.
You put $100 into Pembina in 2,008, you now have $380 That feels pretty good. Employees, we're being recognized by others as being a top employer, many years running in Alberta and more recently nationally as a top 100 employer. I mentioned earlier, I think we'll hit 2,000 strong in 2019 at the rate of growth that we have. We're one of the safest companies out there. Recordable injury rate compared to our peers well under half.
We do, as you can see on our driving, it's gotten a little bit away from us, some fender benders, but we don't take that lightly. We know that fender benders turn into worse things if we don't get on top of them. So that's a top priority for Jared and Jason and you in their businesses. Communities, we invested about $4,000,000 We invested $1,000,000 actually last week, major donation. In addition, another $2,500,000 from staff, so the $4,000,000 is Pembina.
Our staff is another $2,500,000 We think that number will grow to $10,000,000 by 2019 based on keeping our reinvestment into communities aligned with our ability to generate
returns for shareholders. So it's
something we're very proud of. We take it very seriously. We use the same care and attention to managing investments into the community that we do with our business investments. We have full time people that make these choices and monitor them. We're very, very proud of what we're able to do in the community.
And as I said earlier, we want to leave communities with a net positive impact of dealing. So in closing, what do we offer? We offer diverse integrated assets capturing long life world class hydrocarbon reserves. That diversity continues to improve across 3 commodities now. In the future, with value chain extension, we will have international customers, not supply push customers that will open our customer base even well beyond what Scott articulated.
We're going to grow. We're going to grow our traditional businesses. We think we can grow our traditional businesses between $1,000,000,000 $2,000,000,000 a year and layered on top of that our value chain opportunity. So we kind of have a 2 pronged approach, traditional and doing more of the molecules we have, which are our value chain opportunity, but we're going to grow them within the guardrails. Those guardrails Scott put up, we're going to adhere to them.
We will remain over 80% fee for service, have the credit worthiness, all those things Scott talked about, whether it's petrochemicals or LNG or other businesses, you never have to ask yourself, hey, I heard Pembina is doing something new. I wonder if the guardrails are we'll take care of those first. Large scale value extension projects, organic self funding model, Scott talked about. Raising the dividend, we're raising the dividend at 6% annually. We think there's scope at certain times to double that up in a year.
We saw that last year. Don't know if it will happen this year, if there's a catalyst to do that. But clearly, our payout ratio is getting very, very low and we have the ability already to self fund. There's certainly hope for our Board to consider increasing the dividend here. Balance sheet is very strong, terrific relationships with the rating agencies and that broad stakeholder commitment, because you can't have these kinds of results if your employees aren't engaged, you can't have them, customers aren't solid and aligned and you can't have them when communities don't want you to invest.
So we're focused on all of that. We want to be the leader in energy infrastructure. I think we're closing in on that objective and if we can keep doing what we have been doing, I think people would call us that. With that, I think we are done, Cam.
Thanks, everyone. We've got time now for a few questions. If you look at the back of the room, Chelsea Hoy and Riley Hicks have microphones on them. So if you have a question, please put up your hand, they'll come over. If I could ask you to state your name and who you're with, advance your question, and we'll go from there.
Have time for a few questions before we break for lunch. SKU Credit Suisse. Nick, in some of the past Investor Days, you've talked a lot about just the M and A opportunities and how successful you've been at doing those transactions. And now you're in a situation where you've got a lot of balance sheet liquidity, got great opportunities ahead of you. So if you just give us some color on the build versus buy decision that you face right now, in particular with the sector derating in the U.
S?
Well, acquisitions are lumpy. You have to buy things when they're on sale and you can't really answer the question of what are you going to do next year, you're going to build or you're going to buy, because maybe something good is for sale, maybe it isn't. The traditional businesses, you see the base hits. It's just going to keep chugging along and we're getting very, very good at greenfield and brownfield. And clearly, that's our focus.
I mean, those are the most accretive. You do brownfields at 4 to 6 times EBITDA, greenfields, 6 to 8, maybe 8 to 10 depending. And the acquisitions are more expensive, but they have to represent a new platform. We are always focused on per share metrics and is something is it accretive, that's check mark 1. But check mark 2 is, is it strategic?
So does it make the rest of your business worth more? And if we can't say yes to the second part, we're usually not interested. So there's a lot some decent quality stuff out there, but is it strategic to us? Does it make the rest of our business more valuable? And that's the question.
There are certainly asset bases we watch very carefully. I get asked a lot about U. S. MLPs with a differential and multiple. Certainly, we're learning more about the U.
S. It wouldn't be surprising if I said we're going to start looking more at the Rockies and Williston because have egress out of those. So we'll look at that, but we in terms of the U. S, we just don't see the kinds of contractual underpinning that we like. It's just a fundamentally different model that doesn't fit our value chain So we can take some more risk with that kind of stuff, but not at times.
We look at everything though. We're very well banked and we do look hard at everything.
Maybe just as a follow-up, so then really stays close to home with the current asset base, you see a lot of runway with the existing assets in place to extend to go into petchem in a new model business model as opposed to stepping out into a new Yes.
I mean, if you looked at the thrust adjacent slide is, as we're importing 250,000 barrels a day of condensate that if it's grown locally, it will displace imports just like Marcellus gas has displaced Canadian gas, local product always wins. So just in the near term, that will happen. We don't even need oil sands to grow and it's still growing. So call it 200000 to 300000 barrels a day of imports, that's many 1,000,000,000 of dollars of investment for our company without even increasing overall on its 8 demand. So we've got lots of running room.
As Jared said, the Duvernay, every time we look, they knock another 10 drilling days off a Duvernay well and do it for 90% of the cost. They did it only a couple of quarters ago. So they're getting better and better. And if you follow Shell and Chevron, they're talking about the Duvernay is like their number 1 or number 2 area in Canada would tell you the same thing as the Montney. So very prolific reserves.
So we have running room even without incremental pipeline egress, but if we get egress or Jordan Cove works or Shell LNG works, it's going to get really I think we're good without it. We're great with it.
Scotiabank. Maybe turning the attention to, I guess, to the larger projects, maybe first with the PDH and PP. As we look forward through the rest of the year and into Q4, just want to get a sense of what you think the key gates and roadblocks are in front of a potential sanctioning of the PDH and PEP projects, because presentations that were given today largely seems as just get engineering in hand, get an agreement in hand, and you have all the parts there right now?
Yes. I think you could sense from Kevin's presentation things are on track and not a lot of fear in his voice about getting to FID this year. I think that will happen. The milestones, you'll recall, we're going to get our Class III here in June and provided that is that cost is about what we expect. We're going to keep motoring along.
No reason to believe it won't. And then our Class II precision is what we need to turnkey a number of the pieces. So, if you think about that project in 3 pieces, the propylene plant, the polypropylene plant and everything else, cogen, rail, yada, yada, yada. We think about it that way and the cogen rail stuff, we do that every day. So, we don't need to get lump sum bids for that, because it's tough Pembina knows how to do.
I think the evidence is there. The other two modules, we're going to get lump sum bids for. Again, we know what we know, we don't we know what we don't know. We don't know how to build those things. So, we're going to write the insurance policy check and get lump sum bids that cost more, but we're going to know what those things cost and you need a Class II precision to get that kind of bid.
And we have every reason to believe that bidders are out there, particularly given the slowdown in oil sands upgrading and other projects like that. And that liberates a world class top tier labor force that Alberta hasn't So, there's the 3 thirds. So, that's the cost side taken care of. We have no concerns whatsoever about supply, because it's only a third of our supply, little less. And we have absolutely no concerns, because we have a world class marketer who's going to step into those shoes and they already will have the distribution channels to guarantee that we will be able to sell.
So, the only thing that's missing is getting it half fee for service. And if you actually do the math on our guardrails, even if we did our whole half without fee for service, I think the 85 maybe goes to 82 or 83. I mean, it's not material, we could do it. We just choose not to, because we want to demonstrate that we can do this business with fee based customers, so that when we announce our next foray into petrochemicals, the market has the confidence that, that can be done. If we never wanted to do anything else, we wouldn't worry or need to worry about fee for service, but we want to include that component, because we want to grow in the sector.
And the only way to grow in the sector within our guardrails is to have at least half fee for service. We actually believe we'd make more money without fee for service, that is our hypothesis, but it doesn't fit our guardrails and we have to stay within our guardrails to enjoy the multiple that we have. We're not
going to put Thank you.
Rob Catellier, CIBC. I just wanted to dig down a little bit in your comments about giving your customers exposure to international pricing. I'll start with the LNG first and then move to the liquids. So on LNG, here we are at another Investor Day and still we don't have any Canadian projects
that have reached
the FID stage. So I'd like your opinion on what has to happen to move any of these projects to FID. Related to that, what are the opportunities
in Penmena's appetite to make direct investments in LNG projects other than Jordan Cove while you're developing that project? Well, what we're hearing, what we're evidencing is that Shell will go forward. So, I hope by next Investor Day, we'll have 2 projects with egress from the WCSB. And if you consider Stu's cost stack and you consider the real price of Ayco, which is half of what he had up there, actually less, it's about a third, The evidence is compelling that buyers want to connect to WCSB and our hypothesis on the Rockies Rockies is it will be trading like AECO within a couple of years too, because it's getting backed out by the Marcellus. And so Rockies prices, we think are going to reflect transportation adjusted AECO.
So, we're going to have 2 basins that are the most compelling gas basins from a price perspective on the planet. LNG buyers that we talk to, they know that. So I would say, Jordan Cove, which I know obviously a lot better than Dallas project, it's all about permitting. When will FERC give us the schedule? We don't know when that is.
We are also developing a new way to think about LNG with typically, it's been all demand pull, the Japanese and other buyers, Chinese, Korean, they buy the product FOB or in Western Canada. But we have a lot of international customers now with tremendous geology captured gas geology in Western Canada. They want to get it out. That's why they invested. They invested with the promise of LNG.
So in absence of LNG, they've made arguably not great investments with LNG. They were profits. So we're getting a lot of supply push interest from high credits, medium credits, low credits and we're trying to see how that sleeps through the project as well. So with the backdrop obviously of Tokyo gas prices going from, I don't know, dollars 5, dollars 6 to $10, dollars 11 that's created a lot of hype. Again, it's always surprising to me to see how badly the world misses in forecast, whether it was $140 oil going to $30 like how could the whole world be that wrong.
And LNG, I mean, when I met the Veresen guys, I think the price of gas was like $6 in Tokyo and then goes to $12 like 6 months later. So again, the whole world is so wrong, but we look a lot like we're going to be way under exposed. There's going to be a great shortness in LNG. And I you think about if the world wants to meet its climate goals, the only way to do it is to use gas to displace coal. That's the only way we're going to get there.
It's never going to happen on renewables, too slow, too expensive that will come, but I think that's kind of a something we'll see a number of decades out, but the only way to do it is with gas and people in India and China that have a real climate issues, real pollution issues, they're at the front of the line. So, when they look at Jordan Cove, it's the spot. So, it's really just a regulatory. And the other thing I get encouraged about is like with all the trade deficit this year in the U. S, I think those are really easy ways to switch trade imbalances.
Again, pretty optimistic about what it can become if we can get
approvals. And West Coast projects are hard to get approved.
So a similar question on the liquid side. You have a lot going on to help your customers potentially with natural develop a long haul oil pipeline to the U. S, but let me develop a long haul oil pipeline to the U. S, but some of your peer group has made some investment in related assets in the U. S.
So is the value proposition for Pembina doing that strong enough and are there enough strategic benefits to look at that as well?
Oil egress specifically, sure. I mean, we have 3 commodities. We love to have international market for all of them. It stands to reason. I mean, it's no different than NGL and gas.
We just we're just too far behind right now. But if it's clearly in strategy, we'd love to do it. We just haven't found a good way to do that yet. Maybe that'll come. Certainly, if we're exporting 2 out of those 3 hydrocarbon types, oil could possibly happen, but we're focused right now on gas and shale.
I don't know if oil will ever shale itself. Yes, they have. Well, I mean, our fees are based on our total cost, including income taxes. So clearly, it would help us compared to other non U. S.
Locations, whether it be Canada or Australia or other places. Our business makes more money with the the new U. S. Tax rules, including Jordan Cove, we'll be more competitive.
Sorry, everyone. We're going to have
to cut the Q and A off there. We've got a brief break. I know there's some 1 on ones scheduled. They start at noon. So if you've got a 1 on 1, they'll be on the floor below on the mezzanine level at the rooms listed in there.
I want to sincerely thank you today and those who joined by webcast for your time and for listening to our story. We're so excited about it and I hope that came through and we look forward to chatting with you all and continued engagement. So thank you very much for your time today.