Good 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 speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you would like to withdraw your question, please press the pound key. 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 first quarter 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 Wiun, Senior Vice President and Chief Operating Officer, Pipelines, Jaret Sprott, Senior Vice President and Chief Operating Officer, Facilities, and Stuart Taylor, Senior Vice President, Marketing and New Ventures and Corporate Development Officer. Before we start, I'd like to remind you that some of the 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. The first quarter 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 CAD 773 million, 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 IV and Phase V Peace 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 CAD 578 million in the first quarter 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 1st of this year, Pembina adopted the IFRS 16 accounting standard, which affects the accounting for leases. For the quarter, the adoption of IFRS 16 contributed a CAD 15 million positive impact to both adjusted EBITDA and cash flow from operating activities. The impact to earnings during the quarter was CAD 1 million.
On a full-year basis, IFRS 16 is expected to increase adjusted EBITDA by approximately CAD 60 million, cash flow from operating activities by approximately CAD 55 million, and reduce earnings by approximately CAD 5 million. Based on the expected full-year impact of IFRS 16, Pembina is revising both the low and the high end of its 2019 adjusted EBITDA guidance range by CAD 50 million to CAD 2.85 billion-CAD 3.05 billion. With 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 CAD 0.20 per share, up from CAD 0.19 per share. The increase will be effective for shareholders of record on May 24th and paid on June 14th. This is the eighth consecutive year we've increased our dividend.
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 VIII, which will accommodate incremental customer demand in the Montney area by debottlenecking constraints, accessing downstream capacity, and providing ethane+ and propane+ segregation on the system from Gordondale to market. Phase VIII 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 our announcement that Pembina, along with our partner, PIC of Kuwait, reached a positive final investment decision to construct a CAD 4.5 billion, CAD 2.5 billion net to Pembina, 550,000 tonne per annum integrated propane dehydrogenation plant and polypropylene upgrading facility we call PDHPP facility. Sanctioning of the PDHPP facility is the largest step taken to date by Pembina in executing its strategy to secure global markets for our customers' hydrocarbons and provides another exciting platform for future growth. Last week, the government of Canada announced that Strategic Innovation Fund will provide federal government funding in the amount of CAD 45 million to support this project. Support from all levels of government has been instrumental in ensuring this project's 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 have 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 PDH PP and Phase VIII, we currently have approximately CAD 5.5 billion of secured projects that will diversify and strengthen our business, extend our value chain, and ultimately enhance our customer service offerings. 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 PDH PP, as well as Jordan Cove. We continue to progress Jordan Cove regulatory processes. 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 CAD 50 million of Jordan Cove investments for 2019 to support remaining regulatory and permitting work streams, however, limiting the FID capital investment on non-permit related activities. Given the anticipated regulatory timeline, we expect non-permitting activities to resume in early 2020.
Suspending non-permit related activities will affect the construction schedule. First gas is now expected to be delayed up to one year from the previously anticipated date of 2024. As previously disclosed, we have executed non-binding offtake agreements with customers in excess of planned design capacity of 7.5 million tons per annum. Discussions with these same offtakers continue 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% and 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 14th at the Omni King Edward Hotel in Toronto.
For those unable to attend in person, you will be able to follow along via webcast. 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 2:00 P.M. Mountain Time, 4:00 P.M. Eastern Time. The AGM will be webcast. 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. 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.
At this time, I would like to remind everyone, in order to ask a question, please press star followed by the number one on your telephone keypad. Your first question comes from the line of Jeremy Tonet with J.P. Morgan. Your line is open.
Hi, good morning.
Morning.
Just want to start with Jordan Cove here, kind of changing the dynamics of the spend, does that impact, I guess, your pursuit or your conversations with potential partners in the project? Any thoughts you can provide there?
Not really, Jeremy. We just can't absorb the whole project. We love it. We'd love to be able to absorb it, we want to stay within our cash flow spend, also to manage our risk profile. 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. Just wanted to touch base with the lower NGL prices that we've seen. Has that impacted at all, I guess, to your conversations with potential customers regarding your PDH PP facility in contracting there?
Jeremy, it's Stuart Taylor. No, not at all. We continue to progress the PDH PP 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. That was the question there. Then as far as marketing margins are concerned in this current commodity price environment, could you just update us there as far as the pricing and differential, how that's tracking versus your expectations when you put out guidance before?
Yeah, Jeremy, it's Scott here. I'd say, let's remind everyone just before we get into that question, that about half of that marketing margin 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 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. 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 one-year delay, what sort of additional cost beyond carrying the capital for an 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, 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. The only thing we're really dealing with there is inflation. The way I think about it is, we're whatever inflation is greater on the total capital cost.
Okay, thank you. I'm just wondering if you could provide some context around the CAD 33 million settlement that we saw in marketing. What periods was that related to? Can you just remind us the context?
Yeah, 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. That lawsuit is essentially the culmination of many years. 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. Just another operational question. Your conventional volumes were down in the first quarter versus the fourth quarter of last year. Can you just comment on what was driving that? Is that something that's supposed to reverse or temporary? Is that contributing also, I believe your take or pay deferrals were up as well.
I can talk to the volume specifically. Q4 typically is a very 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 first 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. 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 the three-day outage that impacted our HVP capacity. That was a planned outage, so that impacted capacity. Through the quarter, we have seen consistent weekly gains in volumes as we've gone through the quarter.
We do see things trending up, right along with what we would've 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. There is a bit of a 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, Pickering, 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?
Phase IX, the activity is really in the West Montney area, close to the B.C. border and into B.C., and utilizing a lot of our NEBC assets. Discussions there 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. We are seeing positive momentum there, and I think things are going well commercially there. I think what it really does is allows us again, to move volumes from the far west end of Peace Pipeline through the Phase VII and Phase VIII expansions all the way down into the Edmonton area.
Yeah, that's great. Thanks for the color, maybe just one last one. The hedging realized gain flip 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? Also, if you can give us an update just on where hedging stands right now.
Yeah. Overall, there was a lot of hedging noise in the quarter. We obviously had a big unrealized loss that came off of a big unrealized gain in Q4, 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, 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 CAD 19 million positive variance from realized hedging in the quarter. About half that was from our NGL side of the business, 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. Where you're hedged at 25% now, which prices are that? Is that a Q4 run rates or maybe just some thought process there?
We've layered them in throughout Q1, it would be a combination of where the strip was throughout Q1.
Okay, great. Thanks.
Your next question comes from the line of Robert Hope with Scotiabank. Your line is open. Please go ahead.
Good morning, everyone. Most of my questions have been answered, 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?
Yeah. Butane is the commodity that's not being well addressed on the propane side with our terminal, a third-party terminal. We have a couple of PDHs going up. Propane's got some running room and our focus is shifting to butane. There's no reason any of these West Coast terminals can't export butane. They're not currently envisioned that way or set up this way, they certainly could. It becomes a matter of which commodity makes you more money exporting. That said, we continue to look at opportunities for butane because it's getting crushed. Go ahead.
Rob, Jaret here. Oh, pardon me.
Go ahead.
I was just going to say, Rob, we're also looking at butane upgrading, which we would rail down to refining customers.
All right. That's helpful. 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 Canada into the Marcellus area? Are you looking in that neighborhood as well?
We always try to take an approach where we leverage our value chain and we've crept south. We have now ethane egress from the Williston Basin, the Bakken, and we're working with our partners on creating additional methane egress out of the Bakken. That's a logical place, but we've been looking there for some time. The greatest probability of us expanding is always around our existing asset base, because 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.
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. We're seeing strong throughput through both American, Younger, and obviously the Redwater Fractionation Complex. 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 year?
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.
Yeah, I was looking for sort of a characterization or quantification of the positive impact on price.
It's a slow trend upwards, Rob. 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. It got quite soft, and we were darn glad we had 100% acre pays over the last number of years. We started about two-thirds utilized, and we're going up quite a bit, and it's just supply-demand. I'd say it's starting to approach rates at which we did RFS II at, more normal rates that we projected at the time of construction.
That's helpful. I just want a little bit more understanding of what's going on with Jordan Cove. 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 CAD 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. I think, there's always been a risk. The risk hasn't changed for us, I think as we've moved 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 date, we had to ramp up the capital. 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, they understand that timing as well and the ability to continue conversations they're excited about. Again, our prudent management of capital spend, nothing has changed from a risk perspective.
Okay. Thank you for the number of questions, 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 contracted, you expected that to be done by the end of the year on the PDH?
Yeah. That's what we're hoping to accomplish. Once you FID something, the phone starts ringing. We've got a lot of inbounds. A forward-looking information comment, I think we're going to get there.
Okay, maybe just an update on where you stand with the 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. We're anticipating to get our responses as scheduled, be making our decision in the timeframe that we've 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. It's just on the Phase VI Peace Pipeline expansion. That's the only project you've got that says it's trending a little bit over budget. What's the dynamic that's happening there?
This is Jason Wiun. Andrew Kuske, when we went into that area, it's a very difficult territory to construct in. Probably, if you could pick the most difficult spot on our pipeline systems to actually put pipe into service, that would be it. There's a bit of a confluence of things going on there right now. It's actually very active in the pipeline business. A number of processors are building gathering pipelines and things like that behind their plants. We're seeing rates for pipeline construction actually going up. 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 will manage that risk going forward on 7, 8, and beyond. This one, we're expecting to come in a bit above budget.
Okay. That's helpful. Maybe just a bigger, broader question. It's really on the theme of the quality of the condensate that's coming out of the basin versus what comes into the province from the U.S. Are you seeing any kind of degradation of just quality of condensate or the productivity of the condensate coming out of wells? Really the end user's preference for local condensate versus the imported condensate.
I think the condensate that gets produced in the basin is definitely higher density condensate across the basin. Historically, all the condensate that came onto our pipelines came out of the back end of a gas plant. It was basically almost spec condensate. Now what you're seeing is condensate being produced out of the ground, essentially. It's similar to a very light crude. It comes out of the process a little bit differently. The density is higher than what gets imported on the American, Cochin and Southern Lights Pipeline. That said, I think, the market is adjusting to the condensate quality. There's a very active conversation about looking at the specifications that Stream has managed at and trying to adjust those to match more consistently with what's actually produced in Alberta.
As it relates to what does that all mean, when you're diluting bitumen, you need less light barrels than heavy barrels. To get the same result, you got to buy more heavy barrels than imported barrels. It's just a matter of cost, and the market has to adjust to the impact of that.
Maybe you kind of preempted my next question with the, I guess what's in it for you is you get to handle more stuff at the end of the day.
Well, we get to handle what Mother Nature created. What's keeping the industry healthy here right now is condensate production that's driving much of the Peace expansion. The way I think about it is, thank goodness we found the one product we need up here, the one product we were importing. It's giving the basin and Pembina a lot of running room that we're slowly but surely displacing imports. There's been some talk that Southern Lights will reverse at the right time, and that just gives us another 150,000-200,000 barrels a day of running room on Peace. Because 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. We have the transportation advantage instead of the disadvantage we have with our gas and crude oil.
I think condensate's going to remain healthy. As I said, thank goodness we're finding the product we were importing.
Yeah, 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 PIC, I'm just wondering, is that because you're seeing a bunch of upside on the horizon? Can you just give some color, and also if you can quantify what the cash flow impact is to you, due to the change?
Yeah, Robert, it's Scott here. That was obviously a structure that we inherited from Veresen. In my understanding of 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. I think from, just to start off, that was not something we would've ever put in place. It was really we inherited it. Secondly, specifically, that was a right that came due within the contract. That was the earliest that we could exercise that right. Quite frankly, we're positive on the Montney. We like Encana as a counterparty. We like the potential within that asset base. We wanted to stop the dilution.
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. We were getting roughly 55% of the dividends despite owning 45%. On a go-forward basis, now it will be simply the cash available for distribution, we'll get 45%, our partners will get 55%. We'll have a minor impact when you look at the historical distribution profile.
Got it. Okay. If I can come back to the Condi 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 look at what your customers are doing. The part around the Condi 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 position that? Do you work on changing the spec, or do you look at changing the scope to even think about putting a fifth line in the ground?
Robert, this is Jason. I guess in terms of 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. 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. At the moment, there's no condensate being turned away because it doesn't meet 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. I think we're okay there. 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. A lot of the expansion that we're doing is 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. We're really de-bottlenecking our gathering systems to bring this product in. 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. 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. 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.
Got it. Okay, thanks. If I can just finish up with a quick one here on the scope changes for Duvernay II and III. Is the increased spending with those scope changes recoverable within the contract?
Yes, Robert, Jaret here. Yes, they are.
That's great. Thank you.
Your next question comes from the line of Patrick Kenny with National Bank Financial. Your line is open. Please go ahead.
Yeah. Hey, guys. Just to confirm here on Veresen Midstream, that you're not exercising the option to top up your ownership to 50%, you're going to stay at 45%? If so, your thoughts around that decision.
Yeah, 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 Hythe project in there. We just don't feel any need to buy it all or buy part of it at this time.
Okay, fair enough. 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?
I'm going to actually talk a bit about that this afternoon at the AGM. Let me just zoom out. We would characterize the Veresen acquisition, 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. I think it's highly probable that in a year, you ask 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. Synergies, everything's 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'll be better than we first envisioned it.
Great. Lastly, just back to the discussion around some of the cost pressures within Phase VI. 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 think it's way too early to try to connect the construction costs. It feels good, no doubt. Alberta being open for business, we all longed for 2014, no doubt about it. A lot of things have got to happen, in fact, to, I think, really start to positively impact the basin. 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. We are just delighted that Shell took FID on their project, and Chevron is certainly making noises about a second project. 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 PDH PP project. It just shows what's possible. We're going to invest billions of dollars and put hundreds of people to work and pay monster taxes in the fullness of time to support our country. That's what's possible, and I hope we can get there. Maybe Patrick, this is Jason, I'll just zoom way back down on your comment. You were asking specifically about Phase VI 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.
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. We're seeing very positive momentum on the regulatory front within Alberta, specifically.
All right. That's great. Thanks, Mick. Thanks, Stu.
Thanks, Jaret.
Welcome.
Your next question comes from the line of Jeremy Tonet with J.P. Morgan. Your line is open. Please go ahead.
Hi. Thanks for letting me have another go here. Just wanted to circle back on Alliance, as you talked about just a moment ago. If you could provide a bit more color and remind us where you are with what the expansion could look like. 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. We'll have more to say about that because we believe, and we've 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. Trust me, I'm whipping the guys to get this open season announced and out. We just need a little bit more time. I think, in the next couple of weeks, we'll have more to say about it at Investor Day. 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 just 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-
How long we can expect to hedge?
Yeah. It's Scott here. From an FX perspective, we do not hedge our US 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 US dollars. Let's just take an example, Vantage, that's in US dollars. We do not hedge that revenue stream. Our overall sensitivity to the EBITDA stream from FX, again, I believe we'll have updated sensitivities in the Analyst Day presentation. Overall, US dollar EBITDA is roughly 30%-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. Just wanted to touch on, you announced some of the Chevron gas treating facility and some of the Duvernay plants you've been sanctioning the last couple of years. Maybe just a quick catch-up on, since you've announced the Chevron 20-year agreement, just how that's tracking to your expectations. Is it above or below or in line, and is it still in the billion-dollar figure going forward in terms of opportunities?
Hi, Ben. It's Jaret here. I would say that the development has happened quicker than we had anticipated when we initially took this idea to the board. 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. Obviously, a very positive result.
Okay. Thanks. The other question I was curious about is, how do you guys think about how fierce 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. More just maybe 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 a hedge? Do you need to reconfigure?
It's really the same as it's always been. People have been trying to bypass us for what, 7 years now? 8 years. We've had private equity come, we've had private equity go, and we just march along. 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 than what run around trying to get enough business. We really are extremely busy, and we're high-grading opportunities and quite comfortable with our position.
Okay. All right. Thanks, Mick. Thanks, Jaret.
We have no further-
Sorry, it's just Scott Burrows here. I just wanted to clarify one comment. Our overall EBITDA exposed to US dollars is roughly 20%-25%, just to clarify.
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.