Pembina Pipeline Corp

TSX:PPL

Earnings Call Transcript 2019-Q1

[Operator]

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. [Operator Instructions] Thank you. Scott Burrows, Senior Vice President and Chief Financial Officer, you begin your conference.

[J. Scott Burrows, Senior VP & CFO]

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 Stu Taylor, Senior Vice President, Marketing and New Ventures & 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 on 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 project supporting the ongoing growth of our business.Pembina recorded record quarterly adjusted EBITDA of $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 4 and Phase 5 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 $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 1 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 to $15 million positive impact to both adjusted EBITDA and cash flow from operating activities. The impacted earnings during the quarter was $1 million.On a full year basis, IFRS 16 is expected to increase adjusted EBITDA by approximately $60 million, cash flow from operating activities by approximately $55 million and reduce earnings by approximately $5 million. Based on 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 $50 million to $2.85 billion to $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 $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 eighth consecutive year we have increased our dividend.Now I will turn things over to Mick for an update on key growth projects.

[Michael H. Dilger, President, CEO & Director]

Thanks, Scott. Good morning, everyone. It's been an excellent start to the year, great quarterly result, 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 our announcement that Pembina, along with our partner, PIC of Kuwait, reached a positive final investment decision to construct a 4.5 billion -- $2.5 billion net Pembina 550,000 tonnes per annum integrated propane dehydrogenation plant and polypropylene upgrading facility, we call PDH/PP facility. Sanctioning of the PDH/PP facility is the largest step taken to date by Pembina in executing its strategy to secure global markets for our customers' hydrocarbons and provide 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 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 8, we currently have approximately $5.5 billion 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 PDH/PP 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 or 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 million of Jordan Cove investments for 2019 to support remaining regulatory and permitting work streams, however, limiting the FID capital investment on nonpermit-related activities. Given the anticipated regulatory time line, we expect nonpermitting activities to resume in early 2020.Suspending nonpermit-related activities will affect the construction schedule, and first gas is now expected to delay -- be delayed up to 1 year from the previously anticipated date of 2024. Also as previously disclosed, we have executed nonbinding offtake agreements with customers in excess of planned design capacity of 7.5 million tonne per annum. However, discussions with the same offtakers continue despite the delay.The company intends to see partners for both the pipeline and liquefaction facility to reduce its net ownership interest to between 40% and 60% in order to rightsize 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'll 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 2:00 p.m Mountain time, 4:00 p.m. 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.

[Operator]

[Operator Instructions] Your first question comes from the line of Jeremy Tonet with JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

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?

[Michael H. Dilger, President, CEO & Director]

Not really, Jeremy, I mean, we're -- we just can't absorb the whole project. We love it. We 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.

[Jeremy Bryan Tonet, Senior Analyst]

That's helpful. Just want to touch base with the lower NGL prices that we've seen. How has that -- has that impacted at all, I guess, your conversations with potential customers regarding your PDH/PP facility and contracting there?

[Stuart V. Taylor]

Jeremy, it's Stu 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.

[Jeremy Bryan Tonet, Senior Analyst]

Got you. I just didn't know if the lower propane prices kind of incentivized 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 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?

[J. Scott Burrows, Senior VP & CFO]

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 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.

[Operator]

Your next question comes from the line of Linda Ezergailis with TD Securities.

[Linda Ezergailis, Research Analyst]

Just to follow up on Jeremy's question about Jordan Cove. If there is up to 1-year delay, what sort of additional cost 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?

[J. Scott Burrows, Senior VP & CFO]

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 and -- on the total capital cost.

[Linda Ezergailis, Research Analyst]

Okay. And I'm just wondering if you could provide some context around the $33 million settlement that we saw in marketing. Is that something that -- what periods was that related to? And can you just remind us the context?

[J. Scott Burrows, Senior VP & CFO]

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 a combination 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.

[Linda Ezergailis, Research Analyst]

Okay. And 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? And is that contributing also -- I believe your take-or-pay deferrals were up as well.

[Jason Travis Wiun, Senior VP & COO of Pipelines]

So I can talk to the volumes specifically. Q4 typically is a very strong production period. Typically produces -- try to exit the year with very high exit volumes so you usually see December come in extremely strong. We use -- we tend to see a leveling off in those first couple of months. February was extremely cold in Alberta, so there were some challenges on some of the producer sites 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 the planned outage, so that impacted capacity. But through the quarter, we have seen consistent weekly gains in volumes as we've gone through the quarter. So we do see things trending up right along with what we would have expected at this stage.

[Michael H. Dilger, President, CEO & Director]

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.

[Operator]

Your next question comes from the line of Matthew Taylor with Tudor, Pickering, Holt.

[Matthew Taylor, Analyst of Midstream Research]

Can you just give us an update and [ notice ] any comments on Phase 9 where discussions are at and maybe just how it's progressed through the year?

[Jason Travis Wiun, Senior VP & COO of Pipelines]

We -- 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 NEBC assets. So discussions, they 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 to Peace Pipeline through the Phase 7 and 8 expansions, all the way down into the Edmonton area.

[Matthew Taylor, Analyst of Midstream Research]

Yes. That's great. And then 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? And then also, can you can give us an update just on where hedging stands right now?

[J. Scott Burrows, Senior VP & CFO]

Yes. So 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, 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 million 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 storge 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.

[Matthew Taylor, Analyst of Midstream Research]

That's great. 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 some thought process there?

[J. Scott Burrows, Senior VP & CFO]

We've layered them in throughout Q1. So it would be kind of a combination of where the strip was throughout Q1.

[Operator]

Your next question comes from the line of Rob Hope with Scotiabank.

[Robert Hope, Analyst]

Most of my questions have been answered. But just want to take a look at some longer-term opportunities on butane side. Is there a 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?

[Michael H. Dilger, President, CEO & Director]

Yes, we're -- I mean butane is kind of 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. So butane's got some -- or propane's 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.

[Jaret A. Sprott, Senior VP & COO of Facilities]

And Rob, Jaret here. I was just going to say, Rob, we're also looking at butane upgrading for which we would rail down to refining customers.

[Robert Hope, Analyst]

Great. That's helpful. And then maybe more broadly speaking, as we'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?

[Michael H. Dilger, President, CEO & Director]

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. So that's a logical place. But we -- I mean 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.

[Operator]

Your next question comes from the line of Robert Catellier with CIBC Capital.

[Robert Catellier]

Scott, you gave some comments about where you stand on marketing vis-à-vis guidance with respect to pricing margins and hedging. Can you make a comment where the volumes are lining up vis-à-vis your expectations?

[J. Scott Burrows, Senior VP & CFO]

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.

[Robert Catellier]

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?

[Michael H. Dilger, President, CEO & Director]

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.

[Robert Catellier]

I was looking for sort of a characterization or quantification of the positive impact on price.

[Michael H. Dilger, President, CEO & Director]

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 gotten quite soft and we were darn glad we had 100% take-or-pays over the last number of years. And we started about 2/3 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 II at kind of more normal rates that we projected at the time of construction.

[Robert Catellier]

Okay. That's helpful. I just want a little bit more understanding what's going on with Jordan Cove. And really, I guess, my question is has anything really changed on the permitting side to get you to do -- stop in nonpermitting expense. Or is it just really a capital management issue? You had to take up your permitting spending by $50 million. You just wanted to limit the total spending in 2019. Or is there a change in your perception of the permitting risk?

[Stuart V. Taylor]

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 date, 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, that timing is well and the ability to continue conversations they're excited about. But again, our prudent management of capital spend, it -- nothing has changed from a risk perspective.

[Robert Catellier]

Okay. 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.

[Michael H. Dilger, President, CEO & Director]

Yes. That's what we're hoping to accomplish. And once you FID something, the phone starts ringing so we've got a lot of inbounds. So I mean I -- forward-looking information comment, but I think we're going to get there.

[Robert Catellier]

Okay. Then maybe just an update on where you stand with EPC part of the process.

[Stuart V. Taylor]

We're in the middle of our RFP packages. They've -- those have got 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're anticipating to get our responses out as scheduled and be making our decision in the time frame that we've laid out in the October time frame.

[Operator]

Your next question comes from the line of Andrew Kuske with Crédit Suisse.

[Andrew M. Kuske]

I'll probably start with the nitpicky one first, and it's just on the Phase 6 Peace expansion. And that's the only project you've got that is trending a little bit over budget. Just what's the dynamic that's happening there?

[Jason Travis Wiun, Senior VP & COO of Pipelines]

Yes. So this is Jason, Andrew. I guess when we went into that area, it's a very difficult territory to construct in. It's 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 bit of a confluence of things going on there right now. There's -- it's actually very active in the pipeline business and so a number of processors. They're building gathering pipelines and things like that behind their plants. So we're seeing rates for the pipeline construction actually going up and that's a combination of that and very difficult terrain is what's really driving the costs there. We're putting into play some procurement strategies that we are 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.

[Andrew M. Kuske]

Okay. That's helpful. And then maybe just a bigger broader question and it's really on the theme of the quality of the condensate that's 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?

[Jason Travis Wiun, Senior VP & COO of Pipelines]

I think the condensate that gets produced in the basin is higher. It's definitely higher-density condensate across the basin. Historically, all the condensates that came on to our pipelines came out of the back end of the 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 is a very active conversation about looking at the specifications that sort of stream has managed that and trying to adjust those to match more consistently with what's actually produced in Alberta.

[Michael H. Dilger, President, CEO & Director]

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.

[Andrew M. Kuske]

And 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?

[Michael H. Dilger, President, CEO & Director]

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 Peace 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, 200,000 barrels a day of running room on Peace. As we know, local production always wins because it's advantaged by transportation. And 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's going to remain healthy, and as I said, thank goodness, we're finding the product we were importing.

[Operator]

Your next question comes from the line of Robert Kwan with RBC Capital Markets.

[Robert Michael Kwan, Analyst]

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?

[J. Scott Burrows, Senior VP & CFO]

Yes. Robert, it's Scott here. I mean that was obviously a structure that we inherited from Veresen. 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 built out those assets. So I think from -- just to start off, it 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 in Canada 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 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. We'll get 45% and our partners will get 55%. So we'll have a minor impact when you look at the historical distribution profile.

[Robert Michael Kwan, Analyst]

Got it. Okay. I can come back to the condy discussion we were just having and really how that works into your thoughts on Phase 9 versus competing projects. I guess just overall, though, do you see Phase 9 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 of the part around the condy just getting heavier, some of the other projects we 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?

[Jason Travis Wiun, Senior VP & COO of Pipelines]

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 is a funny dead band in the specification between crude and condensate, and it really doesn't make sense when in Alberta, the majority of those growth product is the product that in some regards doesn't get classified as anything. So this -- 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 is no condensate being turned away because it doesn't meet any specifications on our pipeline at the moment. Most -- 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 of 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, but I think we've caught up on a capacity basis. We -- 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 products. 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. So...

[Robert Michael Kwan, Analyst]

Got it. Okay. If I can just finish up with a quick one here on the scope changes for Duvernay II and III. Is the increased ending with those scope changes was recoverable within contract?

[Jaret A. Sprott, Senior VP & COO of Facilities]

Yes, Robert. Jaret here. Yes, they are.

[Operator]

Your next question comes from the line of Patrick Kelly (sic) [ Patrick Kenny ] with Nation Bank Financial (sic) [ National Bank Financial ].

[Patrick Kenny, Research Analyst]

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%. And if so, your thoughts around that decision.

[Michael H. Dilger, President, CEO & Director]

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 Hythe project in there. And it's -- we just don't feel any need to buy it all or buy a part of it at this time.

[Patrick Kenny, Research Analyst]

Okay. Fair enough. And then just given the cost savings that we saw in the quarter 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?

[Michael H. Dilger, President, CEO & Director]

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 Veresen 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 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. 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.

[Patrick Kenny, Research Analyst]

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 changing government here and whether or not you see that as -- somewhat as a positive tailwind here for your construction cost going forward as it relates to the regulatory environment.

[Michael H. Dilger, President, CEO & Director]

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 longed 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. Amber has taken 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 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. So that's what's possible, and I hope we can get there.

[Jason Travis Wiun, Senior VP & COO of Pipelines]

And maybe, Patrick, I'll -- 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 to 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 approvals. So we're seeing very positive momentum on the regulatory front within Alberta specifically.

[Operator]

Your next question comes from the line of Jeremy Tonet with JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

Just wanted to circle back on Alliance, as you talked about just a moment ago, and if you could provide a bit more color or 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 time line of when we could see an Open Season? Would this just be a post-Bakken expansion? Anything you can provide there?

[Michael H. Dilger, President, CEO & Director]

Jeremy, maybe come to the Investor Day. We'll have 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 under way, 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. We're just not ready with our partner to say that today.

[Jeremy Bryan Tonet, Senior Analyst]

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 and 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.

[J. Scott Burrows, Senior VP & CFO]

Jeremy, it's Scott. [indiscernible] 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, 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%.

[Operator]

Your next question comes from the line of Ben Pham with BMO.

[Benjamin Pham, Analyst]

I just wanted to touch on some of the Chevron gas treating facility and some of the Duvernay plants you've been sanctioned 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 on the billing-dollar figure going forward in terms of opportunities?

[Jaret A. Sprott, Senior VP & COO of Facilities]

Ben, it's Jaret 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 those 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.

[Benjamin Pham, Analyst]

Okay. And the other question I was curious about is how do you guys think about how fierce the competitive dynamics are going to be and I think what you're -- your value chain and offering. You got private equity firm as 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 to comment just how [ high ] you think about that and how you respond to it. Do you need to look at new market as hedged? Do you need to reconfigure?

[Michael H. Dilger, President, CEO & Director]

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 private equity go, and we just march along and we keep raising our dividend. We have more growth now. And 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 and 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.

[J. Scott Burrows, Senior VP & CFO]

Sorry, it's just Scott Burrows. I just wanted to clarify one comment. Our overall EBITDA exposed U.S. dollars is roughly 20% to 25%, just to clarify.

[Operator]

And we have no further questions at this time. I will now turn the call back to Mick Dilger for final comment.

[Michael H. Dilger, President, CEO & Director]

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.

[Operator]

This concludes today's conference. You may now disconnect. Have a great day.