Pembina Pipeline Corporation (PBA) Q1 2019 Earnings Report, Transcript and Summary

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 speakers' remarks, there will be a question and answer session [Operator Instructions]. 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 Stu Taylor, Senior Vice President, Marketing & New Ventures and Corporate Development Officer. Before we start, I’d like to remind you that some of the comments made today maybe 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 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 $773 million, representing a 12% increase over the same period in 2018. Quarterly results were driven by strong year-over-year increases in the Pipelines and Facilities Divisions as a result the 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 barrels. 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 1st of this year, Pembina adopted the IFRS 16 accounting standard, which affect the accounting for leases. For the quarter, the adoption of IFRS 15 contributed to $15 million positive impact to both adjusted EBITDA and cash flow from operating activities. The impact to 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 reduced earnings by approximately $5 million. Based on accepted full year impact of IFRS 16, Pembina is revising both the low and high end of its 2019 adjusted EBITDA guidance range by $50 million to $2.85 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 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 24th and paid on June 14th. This is the eight 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 had throughput record in the month of February during the call. 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-plus and propane-plus segregation on the systems from Gordondale to Marcus. Phase VIII is yet another example of the advantages our strategic footprint provide, mainly the ability to provide phased expansion that deliver timely and reliable transportation service solutions for our customers. The most notable achievement, however, during the quarter was our announcements that Pembina along with our partner EICF Kuwait reached a positive final investment decision to construct a $4.5 billion, $2.5 billion net Pembina, 550,000 tons 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 provides another exciting platform for future growth. Also, last week, the Government of Canada announced the 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 success. It is important to know 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 bid, 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 projects reaching our minimum goal of 50% by year end. With the approval of our PDH/PP and Phase VIII, we currently have approximately $5.5 billion of secured projects that will diversify and strengthen our business, expand 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, or 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 Cole's regulatory processes and we're pleased to receive the draft of environmental impact statement from FERC. This is an important development, which provides constructive framework for approval of the project. We believe the conditions outlined in the statements 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 non-permit related activities. Given the anticipated regulatory timeline, we expect non-permitting activities to resume in early 2020. The spending non-permit related activities will affect the construction schedule and first gas is now expected to be delayed out to one 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 designed capacity of 7.5 million tons per annum. However, discussions with the same off-takers continued despite the delay. The company tends 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 Tuesdays, 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 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 P.M. Mountain Time, 4 P.M. Eastern Time. The AGM will be webcast and the details for the webcast can also be found on our Web site. 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 Instructions] Your first question comes from the line of Jeremy Tonet with JPMorgan. Your line is open.

Just want to start with Jordan Cove here, and changing the dynamics of the spend. Does that impact I guess your pursuit for your conversations with potential partners in the project, or any thought you can provide there?

Not really, Jeremy. I mean, we just 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.

And just want to touch base with the lower NGL prices that we've seen. Has that impacted at all, I guess your conversations with potential customers regarding your PDH/PP facility and contracts in there?

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.

I just didn't know if the lower the propane prices incentivized more people to get more constructive on the project. So that was the question there. And then as far as marketing margins are concerned in this current commodity price environment. Could you just the update there as far as pricing and differentials? How that's tracking versus your expectations when you put our guidance before?

Jeremy, Scott here. I'd say, I mean let's remind everyone just before we get into that question. About half of that marketing margin comes from the crude oil side and half comes from the NGL side. I'd say, the crude oil side is inline, 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. So, when you take that into account, obviously, we were comfortable in revising our guidance range.

Your next question comes from Linda Ezergailis with TD Securities. Your line is open, please go ahead.

Just a follow up on Jeremy's question about Jordan Cove. If there is up to a one year delay. What additional costs beyond carrying the capital for additional year might we see in the project? And when do you think you will be in a position to provide an updated cost estimate?

Linda, I mean, the amount we spend is the same over the same number of years. So we're really only thought about inflation. The PD 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 has greater on the total capital cost.

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

Linda, I'm not going to get into the specifics of it just due to confidentiality. But essentially, it has to do with 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.

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 close 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 volumes specifically. Q4 typically is a very strong production period. Typically, producers try to exit the year with very high exit volumes, so usually see December come in extremely strong. We intend to see a leveling off in the 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, just a three day outage that impacted our HPP 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 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.

Your next question comes from the line of Matthew Taylor with Tudor Pickering Holt. your line is open please go ahead.

Can you just give us an update and if any comments on Phase IX where discussions are at, and maybe just how it’s progressed through the year?

So Phase IX is really -- the activity is really in the West Montney area close to the BC border and into BC and utilizing a lot of our BC assets, so discussions there are progressing well there. We have a number of customers that we're advancing discussions on. Not quite ready to say exactly when we expect to officially announce that project to go, but we are seeing positive movements in 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 VII and VIII expansions, all the way down into the Edmonton area.

And then maybe just one last one, the hedging realized gains flipped from a loss year-over-year. Can you give us some sense of thought process on implementing a hedging program? Or how should we think about how you're heading through during the remainder of 2019. And then also, can you give us an update just on where hedging stands right now?

So overall, there was a lot of hedging noise in the quarter. We obviously had a big unrealized loss that they 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 $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 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.

And then where you're hedged at 25% now is that push prices are there, is that a Q4 run rates or maybe just some thought process there?

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

Your next question comes from the line of Rob Hope with Scotiabank. Your line is open. Please go ahead.

Most of my questions have been answered. But just want to take a look at some longer term opportunities on butane side. Is there potential that on the West Coast you look to export more? Or are there some more Alberta centric solutions that you're looking at?

Butane is 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 -- propane 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 there. 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 at 40. But that said, we continue to look at opportunities for butane, because it's just getting crushed.

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

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?

We always try to take approach where we leverage our value chain. And we've cracked 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, I mean we have been looking for some time. But the greatest probability of us expanding is always around our existing asset base that's our position of the strength and knowledge.

Your next question comes from the line of Robert Catellier with CIBC Capital Markets. Your line is open. Please go ahead.

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

That leads to another question, what have you seen on frac fees in these facilities or segment year-over-year for the new NGL marketing here?

I would say with the low April pricing and still fairly solid NGL pricing, as Scott mentioned, we are seeing high utilization of our extraction facilities, which is leading to overall frac demand and prices are going up.

So looking for a characterization and 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 a macro look at how much capacity is left in the fort. But it's quite soft and we were darn glad we had 100% take or pay over the last number of years. And 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 getting -- it's starting to approach rates at which we did our more normal rates that we projected at the time of construction.

And just one little bit more understanding on what's going on with Jordan Cove. Really, I guess my question is, has anything really changed on the permitting side? Did you get it to stop the non-permitting expense, or is it just really capital management issue you have to take up your permitting spend by 50 million, so you just want to limit the total spending in 2019? Or is there a change in your perception of the permitting risks?

No, I mean I think there is always been a risk. The risk hasn’t changed for us. And I think as we've moved forward, we have greater understanding and we’re working closely with all the regulators on progressing that through the exercise. It was a case of -- in order to maintain our projected and service day, we had to ramp up the capital. And so from a capital spend perspective, we thought it’s prudent to manage that a bit more appropriately in time with the permitting. We've talked about out off takers and they understand that at 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.

One last one here, I did want to clarify your opening remarks, Mick, on PDH contracting. I think I understood you expected to have 50% that you wanted contracted, and 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, o we’ve got a lot of inbounds, so I mean -- forward looking information comments. But I think we’re going to get there.

And then 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 had provided. So we’re anticipating to get our responses out as scheduled and be making our decision in the timeframe that we’ve laid out in the October timeframe?

Your next question comes from the line of Andrew Kuske with Credit Suisse. Your line is open, please go ahead.

I'll probably start with the net to Q1 first and just on the Phase VI Peace expansion, and that’s the only project you’ve got that’s trending a little bit over budget. Just what's the dynamic what’s happening there?

I guess 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. And so there’s bit of a confluence in things going on there right now. 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 plan. So we’re seeing rates where pipeline construction actually going up and that’s a combination of that in very difficult terrain is what’s really driving the cost there. We’re putting into place 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.

And then maybe just a bigger product question, and it’s really on the theme of the quality of the condensates that’s coming out of the base versus what gets -- comes into the province from the U.S. Are you seeing any degradation or just quality of condensate, or the productivity of the condensate coming out of the 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 onto our pipelines came out of the back end of a gas plant and so it was basically almost that condensate. And now what you're seeing is condensate being produced out of the ground essentially. So it's similar. It's 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 specifications that stream and manage that and trying to address those that match more consistently with what's actually produced in Alberta.

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 results, 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.

And then maybe you preempted my next question with, 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 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 to 200,000 barrels a day of running room on Peace. As we know, local production always wins, because its 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 is going to remain healthy. And as I said, thank goodness, we're finding the product we were importing.

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

Just for the Jaret on 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 get some color? And also if you can quantify what the cash flow impact is to you due to the change?

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 is they built 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 that. Secondly, specifically that was a right that team do within the contract. So that was the earliest that we could exercise that 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 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 dividend despite owning 45%. So, on a go forward basis now it will be simply the cash to be available for distribution and we'll get 45% and our partners will get 55%. So we will have a minor impact when you look at the historical distribution profile.

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 seeing Phase IX versus the others as in 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 were doing, the part around the county, just getting heavier. Some of the other projects we talked about, the ability to deal with that products. So 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 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 this 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 products is a product in some regards doesn’t get classified as anything. So the whole industry is actually looking at modifying the spec. And there is active discussions to get rid of what we've referred 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 need any specifications our pipeline at the moment. Virtually, all of it is still on spec as they drill news zones some of it is 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. And I think we've caught up on the 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. So we're really de-bottlenecking our gathering systems to bring this product in. And then taking it all away to the end with your question about is there enough room for multiple projects. I would say when we look at the math 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 the 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 are actively discussing with pretty much every customer across the basin.

If I can just finish up with a quick one here on the scope changes for Duvernay 2 and 3. Is the increase pending with those scope changes that’s recoverable within the contract?

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

Your next question comes from the line of Patrick Kelly with Nation Bank Financial. Your line is open, please go ahead.

Just to confirm there’s the midstream that you’re not exercising the option to top up your ownership to 50%, and you're going to stay at 45% and if so, your thoughts around that decision?

We can confirm we’re not exercising the option. We’re happy with that investment. Partnership is aligned and solid we get all the liquids out of that area. It’s growing. We did the high project in there. And we just don’t feel any need to buy it all or buy part of it at this time.

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?

I mean I actually talked a bit about that this afternoon at the AGM. Let me just zoom out. I mean, we would characterize the Veresen acquisition. We had -- if you think about good, very good and outstanding, we are good trending towards very good quickly adding. If we can get an Alliance open season done then that becomes a very good acquisition. If we get during cold on top of that then we’re into outstanding. So I think it’s highly probable that in a year -- you asked me that question and 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 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.

And then lastly just back to the discussion around some of the cost pressures within Phase VI. Maybe you can comment on the changing government, 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?

I don’t think it’s -- I think way too early to try to connect the construction cost. I mean it feels good, no doubt. Alberta been open for business all long forward 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. Ember 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, good work together, because it was just awesome that we had First Nation, municipal, provincial and federal support for EP projects. 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.

And maybe, Patrick -- this is Jason -- I'll just view and back down on your comment. You were asking specifically about Phase VI 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 AERs and 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.

Your next question comes from the line as Jeremy Tonet with JPMorgan. Your line is open, please go ahead.

Thanks for letting me have another go here. Just wanted 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 can provide there?

Jeremy, maybe come to the Investor Day, we'll have more to say about, because our thoughts are -- I mean, 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. And trust me on within 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 and more to say about at Investor Day. We're just not ready with our partner to say that today.

Makes sense, don’t want to give away all the goodies ahead of the 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?

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 pricing in U.S. dollars. So from a -- let's just take an example advantage 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%.

Your next question comes from the line of Ben Pham with BMO. Your line is open. Please go ahead.

Just wanted to touch on some of the Chevron gas treating facility and some of the Duvernay plants you have been sanctioning last couple of year. And may be just a quick catch-up on since you've announced the Chevron 20 year agreements, just how that track into your expectations, and is it above or below, or inline? And is it still in the billion dollar figure going forward in terms of opportunities?

I would say that 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.

And then the other question I was curious about is how do you guys think about the -- how peers, the competitors and dynamics and your value chain and offering? You've got private equity firms buying gas processing plants. You have some of your peers trying to fight for the condensate molecule and you’ve got this huge network that's a lot of guys try to move product down to the U.S. And more just maybe comment on just how you think about that and how do you respond to if you need to look at new markets that's hedged. Do you need to reconfigure?

It's really the same as it's always been. I mean, people have been trying to bypass for seven years now, eight years. So we have had private equity come, we have had private equity go and we just march along, and we keep raising our dividend, we have more growth now. 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 are high grading opportunities and quite comfortable with our position.

All right, thanks guys.

I just want to clarify one comment. Our overall EBITDA exposed U.S. dollar is roughly 20% to 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 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.