Morning. My name is Emily, and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation First Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
Thank you. Scott Burrows, Senior Vice President and Chief Financial Officer, you may begin your conference.
Thank you, Emily. Good morning, everyone, and welcome to Pembina's conference call and webcast to review highlights from the Q1 of 2019. I'm Scott Burrows, Pembina's Senior Vice President and Chief Financial Officer. On the call with me today are Mick Dilger, Pembina's President and Chief Executive Officer Jason Boone, Senior Vice President and Chief Operating Officer, Pipelines Jarrett Sprott, Senior Vice President and Chief Operating Officer, Facilities and Stu Taylor, Senior Vice President, Marketing and New Ventures and Corporate Development Officer. Before we start, I'd like to remind you that some of comments made today may be forward looking in nature and are based on Pembina's current expectations, estimates, judgments and projections.
Forward looking statements we may express or imply today are subject to risks and uncertainties, which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non GAAP measures. To learn more about these forward looking statements and non GAAP measures, please see the company's various financial reports, which are available at pembina.com and on both SEDAR and EDGAR. In Q1 of 2019, Pembina once again delivered strong financial and operational results, including record quarterly results for adjusted EBITDA and adjusted cash flow from operating activities, while continuing to announce new major projects supporting the ongoing growth of our business. Pembina reported record quarterly adjusted EBITDA of $773,000,000 representing a 12% increase over the same period in 2018.
Quarterly results were driven by strong year over year increases in the Pipeline and Facilities division as a result of new assets being placed into service, including most recently the Phase 4 and Phase 5 piece pipeline expansions higher utilization on existing assets, including Veresen Midstream and our Redwater fractionation complex. Within the marketing business, the quarter was positively impacted by higher NGL sales volumes, the adoption of IFRS 16 and a realized gain on commodity related derivatives, offset by slightly lower margins per barrel. Adjusted cash flow from operating activities increased by 9% to $578,000,000 in the Q1 of 2019 compared to the same period in 2018, primarily due to an increase in operating results, higher distributions from equity accounted investees and the adoption of IFRS 16, partially offset by increases in current tax expense and interest paid. As previously mentioned, effective January 1 this year, Pembina adopted the IFRS 16 accounting standard, which affects the accounting for leases. For the quarter, the adoption of IFRS 16 contributed to $15,000,000 positive impact to both adjusted EBITDA and cash flow from operating activities.
The impact to earnings during the quarter was 1,000,000 dollars On a full year basis, IFRS 16 is expected to increase adjusted EBITDA by approximately $60,000,000 cash flow from operating activities by approximately 55,000,000 and reduced earnings by approximately $5,000,000 Based on the expected full year impact of IFRS 16, Pembina is revising both the low and the high end of 2019 adjusted EBITDA guidance range by $50,000,000 to $2,850,000,000 to $3,050,000,000 the continued strength of our business and financial position, we are also pleased to announce that our Board of Directors approved a 5.3% increase to our monthly common share dividend, resulting in a monthly dividend of $0.20 per share, up from $0.19 per share. The increase will be effective for shareholders of record on May 24 and paid on June 14. This is the 8th consecutive year we've increased our dividend. Now I will turn things over to Mick for an update on key growth projects.
Thanks, Scott. Good morning, everyone. It's been an excellent start to the year, great quarterly results, significant project announcements, strong share price performance and excellent safety and reliability despite record cold temperatures. In fact, many of our assets set throughput records in the month of February during the cold. This quarter we are pleased to announce another expansion of Peace Pipeline Phase 8 which will accommodate incremental customer demand in the Montney area by debottlenecking constraints, accessing downstream capacity and providing ethane plus and propane plus segregation on the system from Gordondale to market.
Phase 8 is yet another example of the advantages our strategic footprint provides, namely the ability to provide staged expansions that deliver timely and reliable transportation service solutions for our customers. The most notable achievement however during the quarter was dollars dollars 2,500,000,000 net Pembina 550,000 tonne per annum integrated propane dehydrogenation plant and polypropylene upgrading facility we call PDHPP facility. Facility is the largest step taken to date by PEMMA in executing its strategy to secure global markets for our customers' hydrocarbons and provides another exciting platform for future growth. Also last week the Government of Canada announced a Strategic Innovation Fund will provide federal government funding in the amount of $45,000,000 to support this project. Support from all levels of government has been instrumental in ensuring this project success.
It is important to note how much is indeed possible when industry and all levels of government and First Nations work together as was the case for this project. Since our FID announcement, we've also begun the process of obtaining engineering, procurement and construction bids, started site clearing activities, made long lead equipment orders and continued building out the CKPC team. We continue to pursue additional fee for service agreements and project reaching our minimum goal of 50% by year end. With the approval of our PDHPP and Phase 8, we currently have approximately $5,500,000,000 of secured projects that will diversify and strengthen our business, extend our value chain and ultimately enhance our customer service offering. As we discussed over the past year, a key component of Pembina's strategy involves securing access to global markets for hydrocarbon resources in the basins where we operate.
The execution of that strategy includes our Prince Rupert LPG export terminal, the PDHPP as well as Jordan Cove. We continue to progress Jordan Cove regulatory processes and we're pleased to receive the draft environmental impact statement from FERC. This is an important development which provides a constructive framework for approval of the project. We believe the conditions outlined in the statement are achievable. We continue to look forward to a final FERC decision in January of 2020.
As outlined with our release yesterday, Pembina has approved an incremental 50,000,000 of Jordan Cove Investments for 2019 to support remaining regulatory and permitting work streams, however, limiting the FID capital on non permit related activities. Given the anticipated regulatory timeline, we expect non permitting activities to resume in early 20 20. Suspending non permit related activities will affect the construction schedule and First Gas is now expected to be delayed up to 1 year from the previously anticipated date of 2024. Also as previously disclosed, we have executed non binding off take agreements with customers in excess of planned design capacity of 7,500,000 tonne per annum. However, discussions with the same off takers continued despite the delay.
The company intends to seek partners for both the pipeline and liquefaction facility to reduce its net ownership interest to between 40% 60% in order to right size the project to match our corporate investment and spending profile objectives. We look forward to providing more details on all our projects at the upcoming Investor Day which will be held on Tuesday, May 14 at the Omni King Edward Hotel in Toronto. For those unable to attend in person, you will be able to follow along via webcast and the details are available on our website. Before we wrap things up, I'd also like to remind all of you that our AGM Annual General Meeting will be held today at 2 pm Mountain Time, 4 pm Eastern Time. The AGM will be webcast and the details for the webcast can also be found on our website.
I'd once again like to thank all of our stakeholders for their continuing and enthusiastic support. 2019 is off to a great start and we look forward to the rest of the year. With that, we'll wrap things up. Operator, please go ahead and open up the line for questions.
Your first question comes from line of Jeremy Tonet with JPMorgan. Your line
is open. Hi, good morning.
Good morning.
Just want to start with Jordan Cove here and kind of changing the dynamics of the spend, does that impact, I guess, your pursuit or your conversations with potential partners in the project or any thoughts you can provide there?
Not really, Fermi. I mean, we're we just can't absorb the whole project. We love it. We'd love to be able to absorb it, but we want to stay within our cash flow spend and so also to manage our risk profile. So getting down to around 50% seems right.
The overall timing of that, it's ongoing. The timing of that will likely occur after we have the permits, not necessarily, but probably.
That's helpful. Thanks. And just wanted to touch base with the lower NGL prices that we've seen. How has that impacted at all, I guess, to your conversations with potential customers regarding your PDHPP facility in contracting there?
Jeremy, it's Stu Taylor. No, not at all. We continue to progress the PDHPP project. We're working on our engineering bid process at this point in time. As far as customer conversations, the customers remain enthused with the opportunity to access that new market.
We're continuing to have conversations of bringing propane through that facility and accessing the PP markets as opposed to our more traditional markets.
Got you. I just didn't know if the lower propane prices kind of incentivize more people to get more constructive on the project. So that was kind of the question there. And then as far as marketing margins are update us there update us there as far as the pricing and differential, how that's tracking versus your expectations when you put out guidance before?
Yes, Jeremy, it's Scott here. I'd say, I mean, let's remind everyone just before we get into that question that about half of that marketing margins comes from the crude oil side and half comes from the NGL side. I'd say that the crude oil side is in line, if not slightly better than what we expected when we set the budget. From the NGL side, certainly margins are have come down from the time that we set budget. That being said, we have layered in hedges to protect approximately 25% of our frac spread business.
So when you take all that into account, obviously, we were comfortable in revising our guidance range.
That makes sense. That's helpful. I'll stop there. Thanks.
Your next question comes from the line of Linda Ezergailis with TD Securities. Your line is open. Please go ahead.
Thank you. Just to follow-up on Jeremy's question about Jordan Cove. If there is up to a 1 year delay, what sort of additional costs beyond carrying the capital for additional year might we see in the project? And when do you think you'll be in a position to provide an updated cost estimate?
Well, Linda, I mean the amount we spend is the same over the same number of years. So we're really only talking about inflation. The PV from start date is the same whether we start now
or a
year later. So the only thing we're really dealing with there is inflation. So the way I think about it is whatever inflation is greater on the total capital cost.
Okay. Thank you. And I'm just wondering if you could provide some context around the $33,000,000 settlement that we saw in marketing. Is that something that what periods was that related to? And can you just remind us the context?
Yes, Linda, I'm not going to get into the specifics of it, just due to confidentiality, but essentially it has to do with some disagreements over capacity over the last several years. So that lawsuit is essentially the culmination of many years. So on an ongoing basis, it is a net positive to Pembina, but it's not material in the grand scheme of things.
Okay. Thank you. And just another operational question. Your conventional volumes were down in the Q1 versus the Q4 of last year. Can you just comment on what was driving that?
Is that something that's supposed to reverse or temporary? And is that contributing also, I believe your take or pay deferrals were up as well?
So I can talk to the volume specifically. Q4 typically is a very strong, strong production period. Typically producers try to exit the year with very high exit volumes. So you usually see December come in extremely strong. You tend to see a leveling off in the 1st couple of months.
February was extremely cold in Alberta. So there were some challenges on some of the producer sides in terms of being able to drill and connect wells and things like that. So we did see a bit of an impact there. We also had a short outage that was scheduled in the quarter. I think it was a 3 day outage that impacted our HVP capacity.
That was a planned outage. So that impacted capacity. But through the quarter, we have seen consistent weekly gains and volumes as we've gone through the quarter. So we do see things trending right along with what we would have expected at this
stage. I'd also just add in that typically Q1 is where we see the most amount of deferrals as it relates to IFRS 15, whereas Q4 and Q3 is where you'd expect to recognize the most. So there is a bit of disconnect there from IFRS 15 as well, Linda.
Okay. Thank you. Thanks for the context.
Your next question comes from the line of Matthew Taylor with Tudor, Holt. Your line is open. Please go ahead.
Hey, guys. Thanks for taking my question here. Can you just give us an update and notice any comments on Phase IX, where discussions are at and maybe just how it's progressed through the year?
So Phase IX is really it's sort of the activity is really in the sort of West Montney area close to the BC border and into BC and utilizing a lot of our NEDC assets. So discussions that are progressing well there. We have a number of customers that we're advancing discussions on. I'm not quite ready to say exactly when we expect to officially announce that project to go, but we are seeing positive momentum there. And I think things are going well commercially there.
And I think what it really does is it allows us again to move volumes from the Far West and the Peace pipeline through the Phase 7 and Phase 8 expansions all the way down into the Edmonton
area. Yes, that's great. Thanks for the color. And then maybe just one last one. The hedging realized gain flipped from a loss year over year.
Can you just give us some sense of thought process on implementing a hedging program? Or how should we think about how you're hedging through the remainder of 2019? And then also if you can give us an update just on where hedging stands right now?
Yes. So overall, there was a lot of hedging noise in the quarter. We obviously had a big unrealized loss that came off a big unrealized gain in Q4. And really that was a bunch of the positions that in Q4 of last year as you saw a bunch of the prices collapse, we obviously had a big gain at the end of the year. A lot of that is all unrealized.
And of course, as prices have stabilized throughout the year, that has flipped from an unrealized gain to an unrealized loss. On the realized side, we had roughly a $19,000,000 positive variance from realized hedging in the quarter. About half that was from our NGL side of the business and about half that was crude oil on some storage positions we had. On an ongoing basis for the rest of the year, we are currently at about 25% hedged for the remainder of the year on the NGL frac spread, And we continue to layer in incremental hedges with a goal of getting to 50% of 2020 by the end of the year.
That's great. Thanks. And then where you're hedged at 25% now? Is that which prices are that? Is that kind of a Q4 run rate or maybe
just some thought process there?
We've layered them in throughout Q1. So it would be kind of a combination of where the strip was throughout Q1.
Okay, great. Thanks.
Your next question comes from the line of Rob Hope with Scotiabank. Your line is open. Please go ahead.
Good morning, everyone. Most of my questions have been answered, but just want to take a look at some longer term opportunities on the butane side. Is there potential that on the West Coast you could look to export more or are there some more Alberta centric solutions that you're looking at?
Yes, we're look I mean butane is kind of the commodity that's not being well addressed. And on the propane side with our terminal, a third party terminal, we have a couple of PDHs going up. So butane has got some or propane has got some running room and our focus is shifting to butane. There's no reason any of these terminals, West Coast terminals can't export butane. They're not currently envisioned that way or set up this way, but they certainly could.
And so then it becomes a matter of which commodity makes you more money exporting. So but that said, we continue to look at opportunities for butane because it's getting crushed.
Go ahead. And Rob, we're Jeremy here. Pardon me. Go ahead. I was just going to say, Rob, we're also looking at butane upgrading for which we would rail down to refining customers.
All right. That's helpful. And then maybe more broadly speaking, if you're looking at opportunities outside of Alberta, what geographies do you think makes the most sense to you, whether it's layering on something in the Bakken with your existing assets in the region or your Eastern leverage our value chain and
we've we leverage our value chain and we've crept south. We have now ethane egress from the Wilson base in the Bakken and we're working with our partners on creating additional methane egress out of the Bakken. So that's a logical place. But we've been looking there for some time. But the greatest probability of us expanding is always around our existing asset base.
That's our position of strength and knowledge.
Thank you. I'll hop back in the queue.
Your next question comes from the line of Robert Catellier with CIBC Capital. Your line is open. Please go ahead.
Hi, good morning. Scott, you gave some comments about where you stand on marketing vis a vis guidance with respect to pricing, margins and hedging. Can you make a comment where the volumes are lining up vis a vis your expectations?
Volumes are stronger than expected. We've seen really good throughput build at the Redwater complex which also led to some of the stronger results in the facilities division. So we're seeing strong throughput through both Empress, Younger and obviously the Redwater fractionation complex. So volumes are trending slightly higher than what we had forecast.
Okay. It leads to another question. What have you seen on frac fees in the facilities segment year over year for the new NGL marketing here?
I would say with the low AECO pricing and still fairly solid NGL pricing, as Scott mentioned, we're seeing high utilization of our extraction facilities, which is leading to overall frac demand and prices are going up.
I was looking for sort of a characterization or quantification of the positive impact on price?
It's a slow trend upwards, Rob. And these are not most of our deals as you know are long term deals and so it's kind of a macro look at how much capacity is left in the fort. But it got quite soft and we were darn glad we had 100% take or pays over the last number of years and we started about 2 thirds utilized and we're going up quite a bit and it's just supply demand. I'd say it's getting it's starting to approach rates at which we did RFS 2 at kind of more normal rates that we projected at the time of construction.
Okay. That's helpful. I just want a little bit more understanding what's going on with Jordan Cove. Really, I guess my question is, has anything really changed on the permitting side to get you to stop the non permitting expense? Or is it just really a capital management issue?
You have to take up your permitting spending by 50 mills. You just wanted to limit the total spending in 2019 or is there a change in your perception of the permitting risk?
Rob, it's Stu. No, I mean I think there's always been a risk. The risk hasn't changed for us. And I think as we move forward, we have greater understanding and we're working closely with all the regulators on progressing that permitting exercise. It was a case of in order to maintain our projected in service day we had to ramp up the capital.
And so from a capital spend perspective we thought it prudent to manage that a bit more appropriately and time it with the permitting. We've talked to our off takers and they understand that timing as well and the ability to continue conversations they're excited about. But again, our prudent management of capital spend, nothing has changed from a risk perspective.
Okay. Thank you for a number of questions. But one last one here. I did want to clarify your opening remarks, Mick, on PDH contracting. I think I understood you expected to have the 50% that you wanted contract that you expected that to be done by the end of the year on the PDH?
Yes, that's what we're hoping to accomplish. And once you FID something that the phone starts ringing, so we've got a lot of inbounds. So I mean, forward looking information comment, but I think we're going to get there.
Okay. Then maybe just an update on where you stand with EPC part of the process?
We're in the middle of our RFP packages. Those have gone out. We're receiving abundant and detailed questions which is a positive sign that the EPC contractors are well within the data books that we have provided. So we are anticipating to get our responses as scheduled and be making our decision in the timeframe that we have laid out in the October timeframe.
Fantastic. Thank you.
Your next question comes from the line of Andrew Kuske with Credit Suisse. Your line is open. Please go ahead.
Thank you. Good morning. I'll probably start with a nitpicky one first and it's just on the Phase 6 East expansion and that's the only project you've got that says it's trending a little bit over budget. Just what's the dynamic that's happening there?
Yes. So this is Jason, Andrew. I guess, when we went into that area, it's a very difficult territory to construct in. Probably the if you could pick the most difficult spot on our pipeline systems to actually put pipe into service that would be it. And so there's a bit of a confluence of things going on there right now.
It's actually very active in the pipeline business. And so a number of processors are building, gathering pipelines and things like that behind their plants. So we're seeing rates for pipeline construction actually going up and that's a combination of that and very difficult terrain is what's really driving the cost there. We're putting into place some procurement strategies that we're pretty confident we'll manage that risk going forward on 7, 8 and beyond. But this one we're expecting to come in a bit above budget.
Okay. That's helpful. And then maybe just a bigger broader question, and it's really on the theme of the quality of the condensates coming out of the basin versus what gets comes into the province from the U. S. Are you seeing any kind of degradation or just quality of condensate or the productivity of the condensate coming out of wells?
And then just really the end users preference for local condensate versus the imported condensate?
I think the condensate that gets produced in the basin is higher. It's definitely higher density condensate across the basin. Historically, all the condensate that came on to our pipelines came out of the back end of a gas plant. And so it was basically almost spec condensate and now what you're seeing is condensate being produced out of the ground essentially. So it's similar to a very, very light crude.
It comes out of the process a little bit differently. So the density is higher than what gets imported on the American, Cochin and Southern Lights pipelines. That said, I think the market is adjusting to the condensate quality and there's a very active conversation about looking at the
Alberta. Yes. And as it relates to what does that all mean? When you're diluting bitumen, you need less light barrels and heavy barrels. And so to get the same result you got to buy more heavy barrels than imported barrels.
And so it's just a matter of cost and the market has to adjust to the impact of that.
I guess maybe you kind of preempted my next question with the I guess what's in it for you as you get to handle more stuff at the end of the day?
Well, I mean we get to handle what Mother Nature created. So what's keeping the industry healthy here right now is condensate production that's driving much of the piece expansion. And the way I think about it is thank goodness we found the one product we need up here, the one product we were importing. So it's giving the basin and Pembina a lot of running room that we're slowly but surely displacing imports and there's been some talk that Southern Lights will reverse at the right time and that just gives us another 150,000 to 200,000 barrels a day of running room on piece. As we know, local production always wins because it's advantaged by transportation.
This is the one place in North America where everybody wants to bring their condensate. So we have the transportation advantage instead of the disadvantage we have with our gas and crude oil. So I think condensate is going to remain healthy. And as I said, thank goodness we're finding the product we were importing.
Okay. That's great. Thank you.
Your next question comes from the line of Robert Kwan with RBC Capital Markets. Your line is open.
Great. Thank you. Just for Veresen Midstream stopping the pick, I'm just wondering is that because you're seeing a bunch of upside on the horizon? Or can you just give some color? And also if you can quantify what the cash flow impact is to you due to the change?
Yes, Robert, it's Scott here. I mean that was obviously a structure that we inherited from Verusen. In my understanding, the original intent of that structure really was to protect Veresen's dividend. If you recall, they had a pretty high payout ratio and they needed that cash flow as they built out those assets. So I think from just to start off, that was not something we would have ever put in place.
It was really we inherited it. Secondly, specifically, that was a right that came due within the contract. So that was the earliest that we could exercise that right. And quite frankly, we're positive on the Montney. We like Encana as a counterparty and we like the potential within that asset base.
So we did we wanted to stop the dilution. So what it means from a cash flow perspective was effectively, we were receiving a disproportionate amount of dividends from that asset base compared to our equity ownership. So we were getting roughly 55% of the dividends despite owning 45%. So on a go forward basis, now it will be simply the cash available for distribution will get 45% and our partners will get 55%. So we'll have a minor impact when you look at the historical distribution profile.
Got it. Okay.
If I
can come back to the discussion we were just having and really how that works into your thoughts on Phase IX versus competing projects. I guess just overall though, do you see Phase IX versus the others as an either or situation? Do you see the chances of both or and even if you can talk about the chances of none, as you kind of look at what your customers are doing, the part around the Conde just getting heavier, some of the other projects have talked about the ability to deal with off spec products. I'm just wondering how do you kind of position that? Do you work on changing the spec or do you look at changing the scope to even think about putting excess line in the ground?
Robert, this is Jason. So I guess in terms of well, I'll start with the spec question first because that's the easiest. The market is actually looking at the spec. Right now, there's a funny deadband in the specification between crude and condensate. And it really doesn't make sense when in Alberta, the majority of the growth product is a product that in some regards doesn't get classified as anything.
So the whole industry is actually looking at modifying the spec and there's active discussion to get rid of what we refer to as gray zone condensate. Pembina does have the ability to manage that gray zone condensate for our customers and we actively do that today. So at the moment, there's no condensate being turned away because it doesn't need any specifications on our pipeline at the moment. Virtually all of it is still on spec as they drill new zones, some of it is sort of getting higher density or lower density. And some of the areas in the Montney are actually looking more like crude than condensate.
So I think we're okay there. So in terms of your question regarding expansion, we do have a lot more running room on our pipeline now than we have in the past. I think we've caught up on a capacity basis. We be able to be able to access the new zones where the production is coming from. But downstream of that, we have the capacity to move the product.
So we're really debottlenecking our gathering systems to bring this product in. So and then taking it all the way to the end with your question about is there enough room for multiple projects. I would say, when we look at the map at the moment, it seems like we're in discussions with all the customers and we have capacity to move all the demand that seems to be there at the moment. So it is a question that we think about fairly frequently whether there is enough capacity for all the projects that are being proposed out there right now. But we feel confident that we can move all the volume that needs to be moved at the moment and we're actively discussing with pretty much every customer across the basin.
Okay. Thanks. If I can just finish up with a quick one here on the scope changes for Duvernay 2 and 3. Is the increased spending with those scope changes was recoverable within the contract?
Yes, Robert.
It's Jared here. Yes, they are.
That's right. Thank you.
Your next question comes from the line of Patrick Kelly with Nation Bank Financial. Your line is open. Please go ahead.
Yes. Hey, guys. Just to confirm here on Verus and Midstream that you're not exercising the option to top up your ownership to 50%, you're going to stay at 45%? And if so, your thoughts around that decision?
Yes, we can confirm we're not exercising the option. We're happy with that investment. The partnership is aligned and solid. We get all the liquids out of that area. It's growing.
We did the height project in there. And we just don't feel any need to buy it all or buy part of it at this time.
Okay, fair enough. And then just given the cost savings that we saw in the quarter and recently, could you update us on whether or not you're at full speed here with respect to the expected synergies from the Veresen acquisition, just given the move to the owner operator model there?
Yes. I'm going to actually talk a bit about that this afternoon at the AGM. Let me just zoom out. I mean, we would characterize the Verastin acquisition. We kind of had if you think about good, very good and outstanding, we are good trending towards very good quickly.
I think if we can get an Alliance Open Season done, then that becomes a very good acquisition. If we get Jordan Cove done on top of that, then we're into outstanding. So we're I think it's highly probable that in a year, you asked me that question, I'll say it was a very good acquisition. Perhaps in a year, we'll be able to say it was just outstanding. So that's synergies, everything is on track so far.
Alliance open season is maybe a year late, but maybe we've come up with some better ideas in that year and it will be better than we first envisioned it.
Okay, great. And then lastly, just back to the discussion around some of the cost pressures within Phase 6. Maybe you can comment on the change in government here and whether or not you see that as somewhat as a positive tailwind here for your construction costs going forward as it relates to the regulatory environment?
I don't think it's I think it's way too early to try to connect the construction costs. I mean, it feels good, no doubt. Alberta being open for business, we all long for 2014, no doubt about it. But there's got to be a lot of things have got to happen in fact to I think really start to positively impact the basin. And I think the tangible things that are happening that are very good are increasing propane markets, the LNG plants on the West Coast, Enbridge taking ground on their pipeline expansion, Things like that I think are going to be the real catalyst.
I mean we are just delighted that Shell took FID on their project and Chevron is certainly making noises about a second project. And those are going to be the real difference makers. It would be great if all levels of government, as I said in the script here, could work together because it was just awesome that we had First Nation, municipal, provincial and federal support for our EP project. It just shows what's possible. We're going to invest 1,000,000,000 of dollars and put 100 of people to work and pay monster taxes and the fullness of time to support our country.
So that's what's possible and I hope we can get there.
And maybe Patrick, this is Jason. I'll just zoom way back down on your comment. You were asking specifically about Phase 6 and regulatory and cost structures. The regulators are independent of the government. The previous government was also quite supportive of the industry and Pembina in general.
But the regulators have been going through in Alberta, particularly the AER has been very active in trying to help us streamline processes for getting pipeline and project approval. So we're seeing very positive momentum on the regulatory front within Alberta specifically.
Your next question comes from the line of Jeremy Tonet with JPMorgan. Your line is open. Please go ahead.
Hi. Thanks for letting me have another go here. Just want to circle back on Alliance as you talked about just a moment ago. And if you could provide a bit more color and remind us where you are with what the expansion could look like? And I think you might have mentioned some creative things that you might be able to do.
Any other thoughts you could share on timeline of when we could see an open season? Would this just be a post Bakken expansion? Anything you could provide there?
Jeremy, maybe come to the Investor Day, more to say about that because our thoughts are I mean, we believe and we never faltered on that asset having great utility and we will unearth that utility. The timing and configuration of that is well underway and we're having sample discussions with certain customers to prove our hypothesis. And trust me, I'm whipping the guys to get this open season announced and out. But we just need a little bit more time. But I think in the next couple of weeks we'll have more to say about it at Investor Day, but just not ready with our partner to say that today.
Got you. Makes sense. Don't want to give away all the goodies ahead of Analyst Day. Just a smaller question, I guess, as far as the FX position that you guys have in the sensitivity. If you could remind us how much is hedged for this year in USD and relative to your earnings there and what that looks like for 2020 as well?
Jeremy, it's Scott. Yes, it's Scott. From an FX perspective, we do not hedge our U. S. Dollar revenue streams from an FX perspective.
All of our FX hedges are solely related to when we lock in frac spreads that are priced in U. S. Dollars. So from a let's just pick an example vantage that's in U. S.
Dollars, we do not hedge that revenue stream. But our overall sensitivity to the EBITDA stream from FX, again, I believe we'll have updated sensitivities in the Analyst Day presentation. But overall, U. S. Dollar EBITDA is roughly 30% to
35%. Got you. That's helpful. I'll stop there. Thanks.
Your next question comes from the line of Ben Pham with BMO. Your line is open. Please go ahead.
Thanks. Good morning. I just wanted to touch on you announced some of the Chevron gas treating facility and some of the Duvernay plants you've been sanctioning in the last couple of years? And maybe just a quick catch up on since you've announced the Chevron 20 year agreement, just how that's tracking to your expectations? And is it above or below or in line?
And is it still in the $1,000,000,000 figure going forward in terms of opportunities?
Hi, Ben. It's Jared here. I would say that it's the development has happened quicker than we had anticipated when we initially took this idea to the Board. And that's primarily due to the stronger condensate gas ratios that our customers have seen that's requiring more condensate processing and gas processing than we had anticipated earlier on. So obviously a very positive result.
Okay. Thanks, Ryan. And then the other question I was curious about is, how do you guys think about the how peers the competitive dynamics are going to be when you think about your value chain and offering? You got private equity firms buying gas processing plants. You have some of your peers trying to fight for the condensate molecule and you got this huge logistics network that's kind of a lot of guys trying to move product down to the U.
S. And more just maybe just to comment on just how you think about that and how do you respond to it? Do you need to look at new markets as hedged? Do you need to reconfigure?
It's really the same as it's always been. I mean people have been trying to bypass us for what 7 years now, 8 years. So we've had private equity come, we've had private equity go and we just march along and we keep raising our dividend. We have more growth now. In fact, I would say our capital allocation exercise is more difficult than it's ever been.
We spend way more time talking about what we no longer can do because of funding constraints what run around trying to get enough business. So we really are extremely busy and we're high grading opportunities and quite comfortable with our position.
All right. Thanks, Mike. Thanks, Jack.
We have no further
It's just Scott Burrows here. I just wanted to clarify one comment. Our overall EBITDA exposed to U. S. Dollars is roughly 20% to 25%, just to clarify.
And we have no further questions at this time. I will now turn the call back to Mick Dilger for final comments.
Well, thanks everybody for your interest
and support and look forward to people either being at Investor Day or the AGM. We're excited for both. See you soon.
This concludes today's conference. You may now disconnect. Have a great day.