Peyto Exploration & Development Corp

TSX:PEY

Earnings Call Transcript 2019-Q2

[Operator]

Good morning, ladies and gentlemen, and welcome to the Peyto Second Quarter 2019 Financial Results Conference Call. [Operator Instructions] As a reminder, this conference call may be recorded. I would now like to turn the conference over to your host, Mr. Darren Gee, President and Chief Executive Officer.

[Darren Gee, President, CEO & Director]

Well, good morning, and thanks, Ming. Thanks, everybody, for tuning in to Peyto's Second Quarter 2019 Results Conference Call. Before we get started today, I just want to remind everybody that all the statements made by the company during this call are subject to the forward-looking disclaimer and advisory that we set forth in the news release issued yesterday. In the room with me today, we've got Kathy Turgeon, our Chief Financial Officer; JP Lachance, our VP of Engineering and Chief Operating Officer. We've got Dave Thomas, our VP Exploration here; Todd Burdick, our VP Production; and Tim Louie, our VP of Land. The only one we're missing here is Lee Curran, our VP Drilling and Completions, who's off this week. But everybody else, no holidays. So we're all here working away for Peyto shareholders. Before I get started though with my comments today about our results, I do want to recognize the efforts of the entire Peyto team, including our field personnel over this last quarter. It was a tough second quarter, how second quarter's go. Our guys in the field, hate mud even more than they hate snow, and they had far more mud to deal with this past quarter, the spring rains in Edson just won't quit, and the entire area has turned into a virtual lake. But they toughed it out in the quarter, and they did a great job keeping production flowing and getting done what we could in the quarter. So on behalf of all Peyto shareholders, I'd just like to say thank you to the entire Peyto team for that effort. So I just wanted to start off this morning with some general comments before we open it up for questions. For those listening in, I'm going to try and keep this very brief. It's a busy week of reporting. And so I'm sure everybody's got lots to read and listen to. And then we'll hopefully get to e-mail questions here right away. As mentioned in the release, we spent the quarter working on that part of our Cardium program that we could get to. Many of the forestry roads that we use to access our fields were actually banned to heavy equipment for much of the quarter. So even though we've got drilling rigs sitting on pad sites drilling away in the field, we couldn't move in frac equipment or pipeline crews to get any of those new wells completed or tied in. We had one small window that we did get a few completions done, including our Montney well. So that was pretty exciting. Then, of course, we were stuck waiting to get it tested and on production to see what we really have. The well was sweet or virtually sweet with H2S concentrations varying somewhere between 10 and 60 parts per million. So that's something we can deal with. And that also meant we could process it through our Wildhay gathering system and gas plant. That's a big win for us because that means that we can get the well tied in right away, our op costs are going to be lower than if we had a third-party sour plant that we had to go to. So hopefully, the H2S will stay at this level, and we can continue to produce the well this way. The well has just come on stream and it's producing a lot of completion water back right now. So we're not quite sure what we have yet, but it is flowing. Recall that we modeled this well after some Montney wells that were drilled recently to the north of us, and those wells have taken several months to clean up. Every month the gas rates on those wells are continuously increasing. So we're hopeful that our well would perform exactly the same. It looks like it should. The early test rates looks very similar. But it's going to be a while really before we can talk about any kind of stabilized production rates or what we're going to expect for reserves and economics going forward on this play. But at this point, I think we're still all very excited about the play. It may be that we decide to keep all this information confidential. This is an exploratory well and where we can, and we're going to use, obviously, the information to our particular advantage. So we'll see how much we end up disclosing at the end of the day. Our Cardium program, though, is having a material impact on our liquids production as we predicted, we saw a doubling of condensate and C5+ production this year, year-over-year, so Q2 of '19 over '18, which is nice because that's really the only hydrocarbon that's making much money these days. Oil prices, while having pulled back a little bit, are still much stronger, obviously, than gas or other NGLs. AECO gas prices, as an example, I mean, they were all over the map this quarter. The lowest we saw, I think, in the quarter was negative $0.10. The highest we saw was $2.85. So just massive volatility. As we mentioned, though, we're starting to really see the benefit of our marketing efforts with the vast majority of our gas either hedged at AECO or hedged at Henry Hub after using basis deals to get there. We also had some gas exposed to Ventura, which is near Chicago, but we also have that hedged for Q2. We had a little bit of gas floating at the Dawn market and a little bit at Emerson that we directed one way or another. And then we had around 10% of our gas that was exposed to the spot AECO market. We need that amount to at least exposed here just to be able to deal with operational flexibility. But we were throttling that gas on and off depending really on the day price. So we had a lot of gas revenue for the quarter fixed, which was nice. That just leaves us the condensate and NGL revenues that were unhedged for the most part. We had a little bit of oil hedges in there for condensate. NGL prices, quite frankly, in the quarter were terrible. Propane prices were very weak, and butane prices were even worse than propane as a result of some refinery turnarounds last fall that created a huge cloud of butane volume. And we're working through that. So marketing arrangements for butane, starting in April, were particularly weak. We hope that those butane and propane prices, though, are going to start to recover here. Propane, in particular, obviously driven a lot by the Conway and Bellevue prices, and those are quite soft as well, a lot of supply in the U.S. But as we're seeing, both in Canada and in the United States, a lot of capital programs are being pulled back. Drilling activity is dropping. And so we should start to see the effect of all of that on supply, particularly a lot of these NGL supplies. And so where we're tight in terms of the market, we hope we can see some recovery on those products. At the same time, there is advancements in export projects to get more of those NGL products out of North America exported to other markets in the world. So that should help, obviously, strengthen those products as well. I think probably one of the most material things we did in the quarter was on the marketing side. We secured a very large chunk of Empress service, that's firm delivery service off the Nova system at the Alberta and Saskatchewan border at Empress. That starts November 2020. That's really going to allow us to get to Dawn equivalent pricing or Chicago pricing for that entire volume, which is much better than AECO, obviously. In fact, right now, the Dawn strip is basically equivalent to NYMEX, not trading at much of a discount at all. And hopefully, if mainline tolls come down, it should be even cheaper to get to Dawn. So starting next fall, we should be looking at a much better gas price for that entire volume, which is a pretty large chunk of our gas production. And that has, obviously, a material impact on our cash flows. You can recall, for 2018, at that Empress service, which tolls cost $0.12, somewhere between $0.12 and $0.15, traded for an average of $1.48, while the AECO daily price averages a $1.42. So really, for last year, you would have doubled your gas price, your spot gas price, had you had that Empress service. It's a very valuable service to us. And really, will go a long ways on our marketing initiatives. So in a lot of ways, I think our patience is paying off on the marketing side. I think Peyto was initially criticized for not moving quick enough to diversify our gas markets out of AECO but when the market here started to fall apart, but it looks like we're going to be very successful in moving a large portion of our production out to those other North American hubs for effectively pipeline tolls. So that's really a positive thing going forward here and it's going to allow us to ramp back up our production in the back half of 2020 and into 2021, start growing again and growing our cash flows again and taking advantage of much better gas prices. So I think that's enough summary on the quarter in terms of commentary, maybe we can throw it open to the listeners for questions that they have. Ming?

[Operator]

[Operator Instructions] Our first question comes from [ Gary Grant ], a private investor.

[Unknown Attendee]

I was just wondering if you could elaborate on a basis deal, whether you deal directly with the counter party or through a financial firm or through an exchange.

[Darren Gee, President, CEO & Director]

Yes, Gary, we have done several basis deals, mostly to get exposure to Henry Hub so that we can then hedge the Henry Hub price. And the counterparties for most of those basis deals are large financial institutions, banks typically, that we deal with, that we have relationships with. We're always very cognizant, I think, of counterparty risk and whether or not the party that we're dealing with on the other side is financially sound. And so we always are making sure that we've got a short list, obviously, of individual institutions that we will deal with that are comfortable -- we're comfortable with on the other side. But those basis deals are financial. And so the physical delivery of gas for us ends up being just on that, basically just getting our gas onto the Nova system, and then we can effectively access that Henry Hub market. In any basis that we did, for instance, from -- we did a little bit of basis deal from Empress to Henry Hub as well for what Empress service we have got. That obviously also allows us then to just deliver the gas to Empress. So as far as the border between Alberta and Saskatchewan, and then we can hedge at the endpoint. So they're good in a way because they give us a reduced physical risk, but it's a synthetic transportation arrangement. And obviously, it's short term, we're not signing up for a 20 years of pipe capacity or tolls necessarily with those synthetic deals. So they do have some good value in our entire marketing portfolio.

[Operator]

Our next question comes from Adam Gill of Eight Capital.

[Adam Gill, Principal]

Darren, good job on the liquids growth quarter-over-quarter. Just wondering if you can give us a little more color on the breakdown between how you see the NGL mix performing in the back end of the year. I did notice that a lot of the growth in Q2 over Q1 '19 was in propane and butane. Just wondering if that's just really related to the areas that you're able to work on. And how do you see that mix forming in Q3 and Q4?

[Darren Gee, President, CEO & Director]

Yes. Actually, most of the growth we had was in condensate pentanes, and really, that's the impact of the Cardium wells that have a lot more condensate and pentane production as a percentage of their total liquids. When you look across the Deep Basin, for the most part, I think what we see is a lot of the Spirit River wells do produce a fair amount of propane and butane, but not a ton of condensate and pentanes. The condensate and pentanes really comes out of the Cardium stream. So that's obviously why we're focusing on the Cardium so intensely this year because relative to all the commodity prices, condensate prices are the most robust, but oil prices effectively and pentanes too are like oil pricing. So we've been working on those. All of our gas plants are capable of processing Cardium production, which is nice. We built a lot of our infrastructure in the early days and through Peyto's history for Cardium production. That was the zone we started with. And then we advanced to the Spirit River after that. But now we're back drilling the Cardium again and starting to see more like sort of production stream coming from what we used to have, which was Cardium. At one point, I think, up until 2009 or '10 maybe, we were a pure Cardium production stream. So we were 40 to 45 barrels a million corporately, 80% gas, 20% liquids. The only other impact, I guess, I would say, on the liquids is really the operation of our deep cut. We have a deep cut an Oldman or a cheap cut, as we originally coined the phrase, that strips more butane and propane out. It's not a cryo plant, so it doesn't get any ethane recovery, which we wouldn't value much on anyway. So that's why we spent less capital just to go after the butane and propane. And we've had that deep cut plant sort of throttling on and off at times in the past year, depending on what those liquid prices look like. Propane prices relative to gas price, obviously, is always the comparison we're doing for that deep cut. So our liquids production in any given quarter, particularly propane production in any given quarter really swings based on that relationship between gas price and propane price. For now, the deep cut's still running and has been running, I think, for a long time...

[Unknown Executive]

Since the beginning of May...

[Darren Gee, President, CEO & Director]

Of last year, right? April of last year, we've been running the deep cut. So...

[Unknown Executive]

We had it down for a couple of months in Q1.

[Darren Gee, President, CEO & Director]

Because that's when propane prices were weak, but AECO prices were really strong. So it made actually more sense for us to leave the heat content in the gas stream, we were getting paid more there than we were in terms of liquid propane price. But for most of the last 12 months, it reversed, where gas prices are weak and propane are stronger, relatively speaking. So we're extracting propane. So you may see our liquids volume swing back and forth. We're obviously in control of the infrastructure and able to make that call on the fly. And that's really important, only in operating that infrastructure and being able to make that decision as to how to maximize revenue depending on which product stream and what price it's getting. And so in a lot of cases, if we were going through a third-party deep cut, for instance, we wouldn't have that option. We wouldn't be able to turn on or turn off the extraction or leave the gas -- leave the liquids in the gas phase, if that's what gives us better revenues because the operating of that facility would be decided off on by the -- someone else, quite frankly. So I think that's a big value-add for us. Obviously, we're focused on the revenue and the cash flow. The absolute production number is somewhat irrelevant. You've got to look at what's the most valuable product that you can produce.

[Operator]

Our next question comes from Fai Lee of Odlum Brown.

[Fai Lee, Equity Analyst]

Darren, in terms of your new ventures and looking at the gas storage -- development gas storage facility and additional deep cuts. And in terms of discussions with potential capital partners and -- about this, I'm just wondering, do you have a timeline? Or what's your kind of -- can you comment a little bit about the nature of the discussions and where they're heading at this point?

[Darren Gee, President, CEO & Director]

Yes, if I -- I can't say too much, obviously. I don't want to jeopardize those discussions or prejudice them in any way. But I can say that there's been a lot of interest, obviously, in our total greater Sundance complex infrastructure. It's a huge asset for us, obviously. And so enhancements by taking those facilities and deep cutting a lot of them, there's a lot of value to be had there, potentially. And so midstream processors are obviously interested in that, private equity guys with midstream platforms are very interested in that. And we're very interested in that, quite frankly. But we also recognize that the earlier we want to get after that, if we're waiting for commodity prices recovery here, that we've got a little bit of a cash shortfall or capital shortfall to get after those real near term. So is there an opportunity to work together with someone on that? Those are the kind of discussions we're having. Our storage facility is a pretty key facility right in the middle of all that complex. And the more that we see gas being used domestically in Alberta, particularly for power generation, the more interest people have in storage. But that's all in flux right now because we've got a provincial government that's quite keen to fix this AECO problem, to try and normalize the extreme seasonal disparities that we're seeing between winter and summer demand on AECO and the price swings. So how do you really model the economic impact of capital into a storage pool, if you don't -- if you can't with confidence, predict what the winter and summer prices are going to be?. Because that's really what you're playing, is that seasonal disparity. So I think we're hopeful we're going to see something out of the crown, if we do see anything at all in short order. They were very keen it seems through Stampede Week, working aggressively with their advisory group, which we were sitting on to come up with solutions for this AECO problem. They're still pushing very hard on that. So I think they're looking for solutions in the very near-term to try and even impact this summer, let alone next summer. So we kind of want to see that evolve and then, make a decision on where we go with the storage facility. But like I say, there's a lot of interest in it, too. So I think we won't have a lack of options in terms of either funding it internally or bringing capital partners into those infrastructure investments.

[Fai Lee, Equity Analyst]

And if -- once you do make a final investment decision and let's say you decide to go ahead, what sort of time frame to completion would we be looking at?

[Darren Gee, President, CEO & Director]

Hard to say. I mean it's mostly compression that you're ordering there? Todd, what's the kind of timeline on new compression orders?

[Todd Burdick, Vice President of Production]

I think we're probably looking similar to the timelines on the gas plants, which would be sort of the 18 months. There's a long pipeline that would [ would -- all that would go in ]. So depending on how the scheme works, there's different grades of pipe that we'd been looking at. But I would say, 18 months would be the -- on the long side.

[Darren Gee, President, CEO & Director]

So we get land pipe in way faster than compression [ on that ]…

[Todd Burdick, Vice President of Production]

[ It will be on that ]. Yes.

[Darren Gee, President, CEO & Director]

There's a lot of -- I don't know. This is a little bit more of a specialized compressor, obviously, that we'd be buying here. But there is a lot of equipment on the street today, too. So maybe there's an opportunity. If we start shopping around, we can find some gear that we don't have to wait to build. We do have to obviously fill up the reservoir. That requires us to start to inject and put a bit of a base gas volume into that thing. And we have to drill some. There's -- ideally, we'd want to put 3 or 4 horizontal wells into that pool so that we have maximum injectivity productivity. We can start injecting through some of the old vertical wells. But really, to put large volume in short order, we need some horizontal injectors in there. But really, like Todd said, the timeline is -- the long-dated piece is really the compression equipment, likely.

[Operator]

[Operator Instructions] We have a follow-up question from [ Gary Grant ], a private investor.

[Unknown Attendee]

Isn't the way to stabilize the gas prices in the summer is to put the gas in storage or -- and/or cut production? So it seems the storage facility might tie in with the effort to stabilize AECO prices or I'm misreading this?

[Darren Gee, President, CEO & Director]

No, you're absolutely right, [ Gary ]. We have a lot of connected storage to the Nova system already, about half a Bcf -- or sorry, 490 Bcf, I think, of connected storage in Alberta. And we're not using very much of it. Quite frankly, I put a graph in my last monthly report that just shows where we were in terms of the storage refill. That's been the big issue over the last couple of years is access to that storage. Industry hasn't been able to inject into the storage because TransCanada has been prioritizing service on their system that's basically denied storage operators the ability to take gas off the system because they rely on interruptible delivery service, and none was available to them. There's none really available to them much this summer either. And so that's one of the things the Alberta government has been working on is how do we bring storage back into the equation? How do we allow for storage injections? Do we have to curtail supply coming on to the system? Or can we take that supply that's coming on to the system and put it into storage? And all of this really has to do, I think, with the TransCanada Nova system and its capacity at various parts of the -- in various parts of the basin. And so up in the northwest portion of the province and into northeast BC, where a lot of the new supply is coming from, that's where the capacity of the system is tight. So -- and then getting the gas from there all the way to the border, where they have firm export contracts to meet, that's also tight. And so that's why they're doing a $9 billion expansion over the next 3 years to open that capacity all up. And that's supposed to get us full access to not only the export markets, but full access to the storage systems as well. And that's all intended, obviously, to get us market connectivity and a more stable AECO market here locally in Alberta. And so the question is, can you manage that pipe? Can you manage those delivery commitments? Can you manage your receipts coming on to the system of supply management in a way that stabilizes that price? And I think that's exactly what the government of Alberta was looking to try and facilitate in discussions with industry and TransCanada. Those discussions continue today. And everybody is eager to try and get to a solution. But it's a complex problem, obviously, and if it was an easy one to solve, we would have solved it a couple of years ago. But we're still working away. And what's good is this new conservative party is very interested, obviously, in solving the problem. They're very up to speed on the problem. The Jason Kenney created an entire ministry within the Energy Ministry, the Associate Minister of Natural Gas, to try to address this issue. So there's a high level of concern and attention to this issue, which is very encouraging. We haven't seen that for a number of years, even though we've been trying to deal with this problem for a few years now. As far as our storage reservoir pertains to helping that problem, we are uniquely positioned in that we have a lot of firm receipt service at Peyto that we can use to take gas out of the ground and put it on the pipe at times when receipt on the system is tight. And that's the problem with a lot of the commercial storage operators upstream on the system is they've got full reservoirs. But they haven't been able to empty them in the winter time because there's no interruptible receipt service available up there. You need firmer receipt service in the upstream parts of the pipe. And we actually have that. So I think producer storage now starts to become an important part of that system. And we're looking at that, too. That's obviously why we positioned ourselves into the storage pool in Sundance is to see if we couldn't take advantage of that and add that. When you sort of step back and look at it from 30,000 feet, fundamentally, I think you can stabilize commodity prices if you introduce more storage into any commodity system. Oil, for instance, around the world, prices are more stabilized when there's more oil storage available. In North America right now, we -- production has grown so much and supply has grown so much and yet, over the last 10 or 15 years, storage really hasn't grown. In fact, if anything, we've probably lost storage capability. The storage reservoirs in California have been -- some of them have been leaking. The ones at Alberta, we haven't been able to access. And so with less storage and more supply, you're introducing greater volatility. That's the net effect of all of that. And that's exactly what we've seen. So in order to take that volatility, that seasonal volatility out, we have to introduce more storage at the end of the day and more usable storage. It has to be workable and functional in the system. And so throughout North America, I think, we should be -- as an industry, we should be pushing for more storage. But that doesn't seem to be the case. We've been adding a lot of supply but -- there's a lot of demand to keep up with that supply, but we haven't been growing storage to keep pace.

[Operator]

I am showing no further questions at this time. I would now like to turn the conference back to Mr. Darren Gee.

[Darren Gee, President, CEO & Director]

Okay. Great. Thanks, Ming. There was a couple of questions that came in overnight. E-mail questions came in from shareholders. One of them had to do with our Montney well, asking about its H2S content. And hopefully, if I've addressed that. Test data, obviously, we don't really have a lot to report until the well gets fully cleaned up, which could take several months here going forward. There was some questions going forward, the dividend coverage and debt repayment plan that we have in place, the lower dividend, the free cash flow generation that we are taking and putting on our debt, lowering our debt, strengthening our balance sheet. And a question about our note that matures here in December of 2020.So just as a reminder for investors, we have a revolver -- a bank revolver with a syndicate of banks, $1.3 billion of capacity, that sits out there with the term until the end of 2022 -- end of or spring of '22?

[Kathy Turgeon, VP of Finance, CFO & Director]

October.

[Darren Gee, President, CEO & Director]

October of 2022?

[Kathy Turgeon, VP of Finance, CFO & Director]

Yes.

[Darren Gee, President, CEO & Director]

So that total amount of debt capacity is more than enough actually to absorb all of the current notes that we have outstanding. So we have about -- of the $1.1 million in change of debt so half of that or so is notes outstanding and half of it is revolving debt. So as those notes come due, we can just use our bank revolver to repay those notes. There's not a concern that we have to necessarily refinance those. The choice will be at the time, do we want to extend those notes, what the interest rate environment looked like, what's the cost of debt relatively speaking between revolving debt and long-term debt. We put a lot of the notes in originally, I think, because we were trying to diversify our debt a little bit. We had a rising interest rate environment for a few years there, where there was fear that as interest rates come up, that our revolving debt was going to be exposed to higher interest rates. And could we fix some of that interest rate? And so that was part of the reason that we've put the longer-term notes in because we could fix the interest rates. And I think that was a sound strategy to have a bit of diversification in our debt. But we've been paying down quite a bit of our debt here and plan to continue to do so through the end of 2019 and through 2020. Really, this is a strategy to wait to grow. We'll start growing again in late 2020 and into 2021, as commodity prices strengthen and we've got a lot of the capacity in the system built out, the access to market, the egress capacity that Nova's expanding. All of that sort of lines up in terms of timing. But because we're going to be paying down our debt, does it make sense to keep renewing the same amount of longer term debt? Or should we be shrinking that proportion of the longer-term debt as well? That's a question that we are looking at and have to forecast exactly where we want to be with that. But really, there's no risk of a refinancing on that note because we will just -- we can buy it out with the existing revolver if we want to. Recall, though, that we did have a note coming -- that came due at the end of 2018, early 2019, in January. We announced that we had renewed one of the notes that we had. One of the first ones actually that we issued, it was a 7-year note at 4.39% Canadian. And we renewed it for another 7 years at exactly the same interest rate. So there is good demand on the debt side and on the lending side, and good interest still to continue to lend to Peyto. So that was encouraging that we were able to replace that note with another one just like it for another 7 years. So we did that at the time, but we needed to look really at that balance between revolving and term debt as our debt comes down over time. So that was one of the questions. Hopefully, that's some color on that. There was a couple of other questions that came in that I did want to maybe hit on. One was about the new land that we bought. Dave, we bought a lot of land in the last year. And even just in 2019, really, I think 97 sections year-to-date, which -- that's almost 3 townships of land. Relative to our land base in the Deep Basin, that's a ton. And so I guess the question is sort of what's the strategy with the new land. Are we planning on drilling it all up right away? Or are we incubating it through 2021 or what's the overall strategy there? If you could talk a little bit about it. I realize that there's some exploration initiative in that, that we may not want to talk about but...

[David Alan Thomas, Vice President of Exploration]

Well, Darren, generally, we don't like to spend a lot of money on land. And when the industry is firing on all cylinders, we don't often get the land that we seek to. That's not available because we just aren't willing to pay the prices that are current. So this is -- frankly, it's an opportunity for us to play a little bit of catch-up. We've bought land in Greater Sundance, in Brazeau and also up in the northern area. And we've also been able to make a nice farm-in deal, which isn't included in that tally. We bought some land on an oil play, which I'd like to get tested, perhaps in 2020. And we're committed to test our Permean block. Some of the lands we've got are quite close in into infrastructure. Some of them are a little farther out. But the main thing is that we're using this as an opportunity to really strengthen our land situation at a time when we can acquire land, when other people just -- they're just not coming to the sales. And this is actually really good for us. And especially with the Cardium play, it's allowed us to build up quite a bit more inventory. Obviously, right now, we're quite focused on the economics of every single well. We want to drill where we're really close to our own infrastructure to maximize returns when prices are quite low. But we're -- we'll be stepping out and testing some of these acquisitions just as soon as pricing gets a little bit better. A lot of talk has been -- a lot of the conversation around our shop here has been focused on November of 2020, when we get this new service to get more gas, to get exposure to some better pricing. So some of these opportunities, which we're acquiring right now won't be tested until a bit later, some of them will be a little bit closer in. But there's a couple that I'm quite anxious to see the results on, that farm-in and the new oil play, hopefully, by the end of the year. If you can say some more on that.

[Darren Gee, President, CEO & Director]

Great. That's exciting stuff. Maybe just further on that subject, Tim, what are we seeing in terms of then other expiries by other participants in the industry, and therefore, more land potential that we can post and buy? This is obviously an incredible opportunity to fill up the war chest of opportunities, drilling inventory at pricing that, quite frankly, we've almost never seen at Peyto in 20 years, working the Deep Basin. So what are the future expiries look like? What are we looking at?

[Timothy Louie, Vice President of Land]

So Darren, your question kind of ties into Dave's answer about the recent acquisitions where we said year-to-date, we've acquired 97 sections. And out of those 97 sections, 94 were the result of our own postings. So that's reflective of the expiry turnover in the Deep Basin. We always kind of generate maps and queries to figure out what lands are expiring. And a greater portion of the large acquisitions this year have been as a result of us doing the work, bringing the postings in the configurations that we want with the zones that we want. And we've been quite successful in terms of acquiring lands at very cheap prices. So the expiry situation for ourselves, it looks very good for this year. There might be only 13 sections -- sorry, 10 sections that are actually expiring, and we faced 70 expiries at the beginning of the year. So we've done a good job in terms of continuing our expiring lands. Next year for our expiry profile, there's only about 38 sections that are expiring. So again, I'm very confident that we'll do a good job in terms of continuing the majority of these lands as well. So it's a continuing process that we do in terms of checking out expiries in the basin. And where possible, posting those lands in the configurations that we want and acquiring them.

[Darren Gee, President, CEO & Director]

So we get a brand new term on those lands there for 4 or 5 years, depending on...

[Timothy Louie, Vice President of Land]

Yes. In our area, we're picking up either 4- or 5-year license terms or 5-year lease terms.

[Darren Gee, President, CEO & Director]

So that gives us a good period of time here to get those lands developed out into the future. We're seeing, throughout the industry, I think a lot of people starting to lose their land because they're not drilling as much, obviously, and a lot of the big land purchases from either 5 or 10 years ago are starting to come to fruition here and turn back to the crown. So in places like the Montney, we're still looking at a lot of land expiring? Is that true, and we're interested, obviously, in posting some of that too? Or ...

[Timothy Louie, Vice President of Land]

That is true. We'll monitor both the Cardium, Spirit River, Montney as well in terms of expiries and then post accordingly.

[Darren Gee, President, CEO & Director]

Great stuff. Okay. That's probably enough for this morning. But I appreciate everybody listening in to the call. Obviously, if there's any follow-up questions, feel free to either e-mail myself or our investor awareness site, and we'll try and respond to those. And otherwise, we'll be grinding away on our Cardium and test driving our Montney well. And looking forward to a bit of price recovery on some of the commodities here, as we head into the fall and into the winter. AECO has actually strengthened quite a bit through the last couple of months. And so I think the sort of the pullback in activity across the basin is really starting to manifest itself into reduced volume. We're going to see the impact of TransCanada's 2019 capital investments on the system. We'll see some capacity increases. At the same time, I believe that the West Coast system is getting its pressure reading back. So its capacity is returning back to its maximum from before. So we're getting more and more pipe egress at a time when supply in the basin is actually shrinking, which should tighten up the pricing in the basin. And we should see some very good pricing going into the winter. Unfortunately, storage is not very full. So if we got a really cold winter, we could see some really extreme pricing on the AECO side as well, which is all good. We've obviously got, I think, one rig sitting idle, JP, and a program of leaner gas that we could jump on at any point in time here if we see some stronger pricing going forward. So that's all actually teed up and ready to go the minute we want to put our pedal to the metal. But we had thought that we were going to wait until fall of 2020 to get after that. But pricing is going to dictate, obviously, the pace at which we jump on some of those opportunities. But thanks again for listening in, and we'll be back to you next quarter.

[Operator]

Ladies and gentlemen, this concludes today's conference. Thank you for your participation, and have a wonderful day. You may all disconnect.