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Good day, ladies and gentlemen, and welcome to Peyto's Second Quarter 2018 Financial Results Conference Call. [Operator Instructions] As a reminder, this conference call may be recorded. I would now like to introduce your host for today's conference, Mr. Darren Gee, President and Chief Executive Officer of Peyto Exploration. Sir, you may begin.
Okay. Thanks, Joelle, and good morning, ladies and gentlemen. Thanks to everybody for tuning into Peyto's Second Quarter of 2018 Results Conference Call. Before we get started today, I would like to remind everybody that all the statements made by the company during this call this morning are subject to the same forward-looking disclaimer and advisory that we set forth in our news release issued yesterday. So have a read of that, please. In the room with me today, we've got most of Peyto's management team. We've got Kathy Turgeon, our Chief Financial Officer; JP Lachance is here, our COO; we've got Dave Thomas, our VP, Exploration; Lee Curran is our VP of Drilling and Completions, he's here; Todd Burdick, our VP of Production; and Tim Louie, our VP of Land, is here. The only one missing is Scott Robinson, our VP of New Ventures, who is taking some much-needed vacation.Before I get started with our comments today about our quarterly release, I do want to recognize the efforts of the entire Peyto team, including all of our field personnel. We didn't have a lot of drilling or completion activity in the quarter, but we were still very hard at work with production operations, grinding away on our cost, as always. We did a planned turnaround on our Oldman Deep Cut plant in the quarter and so that kept a bunch of our field guys busy. And as usual, all of our team did a tremendous job. So on behalf of all Peyto's shareholders, I'd just like to say thank you to the entire Peyto team for that excellent effort. I just want to start off supporting with some general comments before we get into the specifics about the quarter, and then we can take some questions from those listening in. I'm going to try and keep this brief, of course, we've got a very busy week. And it's been a busy week for reporting as well, so I'm sure those listening in have got lots to do. So on the drilling front, as I mentioned, it was a pretty quiet quarter other than June. We had a couple of months of downtime, mostly breakup, getting ourselves reorganized and watching the commodity prices. We started up with 3 rigs and then added a fourth in June to get started on our Cardium program. And unfortunately, the first few wells were all on pad sites, or multi-well pads, so that meant completions had to wait a bit until July before we could get on the wells and start fracking. Lee can elaborate a little further on those operations, but I think we're achieving some very nice cost outcomes on the drilling and completion front. And probably, as JP can elaborate a little further, the wells we've completed to-date are slowly cleaning up but looking good. As I mentioned, we're using 2 to 3x as much water as before so the cleanup times are longer. It also means it's going to take a little bit longer to show investors just how good these Cardium wells are that we're drilling. But I think as the data comes out, and we will present that, everyone will see that. On the commodity price front, oil and condensate prices are always strong and stronger than we expected, I think, in the quarter. Gas prices were as weak as we expected, unfortunately. So that confirmed our strategic plan to time our capital program around the commodity price and that looks to be a smart decision. We remain quite optimistic about the potential for this winter's AECO gas price. Our storage looks quite good to us, both in the U.S. and in Canada. But really, even without further recovery, the winter right now is pricing at about $2 a gigajoule, which is up some 60% on the summer price $1.25 that we've just seen and are seeing right now. So that's a pretty nice improvement. It looks, again, like producing more gas in the winter and less in the summer makes perfect sense. And so to that end, we're still looking at ways in which we can time our business around that commodity price volatility. As we mentioned, we've made some headway on the market diversification front. We're continuously working in that direction. We've now executed a deal with an Alberta power producer. And granted it doesn't kick in until 2022 or 2023, but even so, it gets around 10% of our gas today. Anyway, it connects us directly to an industrial user, and that's important. That keeps it off of the export pipelines so that we don't have to find a home for that gas outside of Alberta. We keep it here in Alberta. We're targeting about 20% of our volume to be direct connect within Alberta over the longer term, so we've still got some more work to do on that front, only got 10% so far. And hopefully by the time we actually get to this time, that'll even be a smaller percentage because we'll have drilled in our volumes by that point. So we do have some more deals to do, and we'll continue to work and look for those kinds of opportunities. We also have some NYMEX basis deals in place that helps diversify about the 1/3 of our summer gas for the next few years before we take on physical transportation to get to those U.S. markets. Again, we're targeting around 40% of our gas volume to be based at U.S. markets. And so these first NYMEX deals help us get at least the summer there. And that's, for us, what looks to be the most dangerous part of the forward curve is Alberta's summer pricing. Alberta gas prices in the summer, where we don't have a lot of access to storage anymore, so we see a lot more volatility seasonally. Then, of course, we're moving forward on to some exciting new exploration initiatives, talked about that in the press release. And I'm sure Dave can elaborate a little more on that in a few minutes. On the financial front, operating and profit margins were down little bit, mostly due to the temporary drop in production. As we grow production back up again to the end of the year, we should hopefully see the per unit costs and our margins improving a little bit. We're trying to offset the rising government costs and taxes with improvements in efficiencies as well as some other efforts. Todd can elaborate on that a little bit. And finally, we're advancing plans to expand our infrastructure to extract more liquids from our gas and get it to higher-priced markets. As those Asian markets become more established in the next 6 months to a year, we'll be able to find a much more firm commitment, I think. And make much more firm commitments to our infrastructure projects with a lot more confidence in the expectation of our returns, knowing what pricing we're going to be able to get. So those are some exciting things on the horizon as well. All in all, I think a very successful quarter for Peyto. We had a lot of initiatives other than just drilling wells, and we were successful on many of those. So a good quarter behind us, and we've got lots to look forward to in the back half of the year. And that's all despite sort of the softness in natural gas prices that we're having to navigate through. So maybe before I open it up to questions from those listening in, I just want to engage some of the Peyto management team here in some discussion about some of these issues and some of the outlook for the future and hopefully provide a little bit more color than what was in the press release. And so maybe we'll start with Lee Curran, our VP of Drilling. Lee, you know we're back drilling after breakup here, relatively busy in June and getting looks like more busier as the fall progresses. How are operations going so far? What are we seeing in terms of costs and efficiencies as we get back rolling again?
Sure, Darren. After a slower first quarter and certainly what was a very atypical spring breakup for Peyto, getting our rigs and completion crews back to work was a very welcome event. Having rigs shut down through the typical breakup April and May period has been something rather foreign to us for many years for that matter. The last time we had a complete pause in field activity in the spring thaw was 2013. Now that said, we took that opportunity to really explore our well designs and completion intensity variables. And I'll defer some discussion regarding the completion recipe elements to JP and maybe just highlight a little bit on the hardware itself. Given what's essentially become a wholesale shift in -- by industry towards multi-stage horizontal fracture completions, the available options of configurations has grown rapidly. If we circle back nearly a decade, pretty much the only options at our disposal were open-hole, ball-drop systems and the very costly option of cemented perf-and-plug configurations. And through the industry's appetite for higher-stage counts and greater reliability point towards lower overall cost of execution, which just made that basket of options massive and arguably somewhat overwhelming to evaluate, especially with -- when our small team had been so busy maintaining industry-leading position on low-cost execution with 8 to 10 rigs for the past several years. So that's what we did with our little sabbatical. We did a lot of evaluation. Now since resuming our -- resuming operations after breakup, we spud a total of 17 wells to date. Predominantly, those are focused on Cardium and the Greater Sundance. Many of these have been drilled as multi-well pads, where we put all of that breakup evaluation at work. We've methodically implemented variations and completion techniques, specifically related to that gear installed in the wellbore. We've varied stage counts and some of the frac ingredients, but we've also installed direct comparatives on multi-well pads with open-hole, ball-drop systems, cemented ball-drop systems and, at this stage, a small number of cemented in coil annulus fracs from 2 different venders.Now once we've had an opportunity to complete all of these wells and the wells themselves have had an adequate opportunity to clean up, we should have some very useful data to steer us in our pursuit of optimizing both well results and our overall well construction cost. This year boasts the largest Cardium horizontal program I think we've ever had, and materially the first true opportunity to implement programs, style optimization to our Cardium species, at least since 2012. We're forecasting further gains in this regard as our schedule contemplates a significant increase in multi-well pad drilling for the bulk majority of the last part of this year. And that will carry significant drill and completion savings. Now getting the machine rolling again after such a lull, it comes with what I'd call a continuity challenge. Gaining back the high-quality field workforce that we had when we were so active takes a little bit extra time and occasionally a little bit extra scrutiny to make sure that the bolts didn't get rusty. But based on an operation results that we're generating, with all 4 of our active rigs, I'd say the machine is proving to be well-oiled. Our drill costs are consistently rolling in, in the sub-$1.5 million a well gross mark and couple of pacesetters at $1.2 million. Now due to the lag I the -- lag associated with pad drills, we're really just starting to get the first round of completions wrapped up. And given the relatively significant differences in costs associated with those previously mentioned completion techniques, there's really inadequate data to give specific numbers. But I would say, based on an increased overall stage count, it will be accurate to say for the first time since embarking on our horizontal multi-stage program, our completion costs are now going to rival drill cost for the largest piece of our capital allocation. Early information indicates our completion designs are going to land in the $1.5 million to $1.6 million a well range. And so that's certainly an improvement of what we had forecasted with those respective stage count increases. As a result of those successes associated with our continued refinements and cost-saving measures, the team is working hard towards what's a welcomed opportunity to potentially increase our current activity level and plans to add a couple more rigs to the fleet in the coming months.
Okay, great. Thanks for that color. Maybe, JP, more along those same lines then. This new -- this experimentation we've done, a lot of these new Cardium completion design changes that we've made, what are we're seeing? Can we make any conclusions yet? Have we picked the winner in terms of design? Or is there a lot more, sort of, experimentation we're going to continue to do? Or -- and what are the wells showing us?
Sure, Darren. I'll start with a reminder of where we've come from prior to 2017. We drilled 50 Cardium horizontal wells in the Sundance area, mostly with the same design, which consisted of about 8 stages at 50 tons sand per stage over a 1,200-meter horizontal length. And we convey that with a cross-linked gel water system. We pump about 1,800 meters cubed of water for that style of completion. And last year, we completed 2 wells with about the same amount of sand, total sand, but we spread it over twice as many stages, 16 stages, and placed it with about 3,400 cubes -- meters cubed of slickwater. We were encouraged by the significant improvement of well performance, so we continued in the first quarter of 2018 with 3 additional wells, increasing stage count to as high as 30 stages at 50-meter spacing. And those results also validate that our new design was working. Most recently, we've further increased the number of fracs, that's as high as 45 stages, deploying them with the different liner systems, as Lee described. In this case, water and sand volumes are much higher as compared to the original design, obviously, where we pumped as much as 6,000 meters cubed of water, slickwater, and close to 900 tons of sand in a couple of wells. So we intentionally, as Lee alluded to, we intentionally loaded up the front end of our program with passes of this higher-frac stage count and at different deployment mechanisms so we can make these side-by-side comparisons and in different areas. I mean, not only to compare performance, but also to test the execution of these different systems to get that early feedback so we can optimize our design going forward. So where are we at? We've got 7 new Cardium wells now completed since we restarted drilling. They're all in various stages of flowback and cleanup. So it's still too early to tell what these wells may build to, but we're encouraged that the early rates are trending up as we pull out more of this increase in lode water that we've pumped. I should also mention that the liquid ratios from the older wells completed with the new design have held up in that 40 to 50 barrels per million range, with some of our new wells exhibiting early NGL ratios that are up as high as 100 barrels a million.So we plan -- going forward, we plan to continue to drill our 40- to 50-well program, our Cardium program, throughout Q3 and into Q4. We'll adjust the designs as we get the feedback. We'll also plan -- we also plan to test wells in Brazeau and Kakwa, in those areas, with our latest design by year-end. So it's probably a bit too early to pick a winner at this point, but so far, things are encouraging.
Okay, good. We pride ourselves at Peyto having some of the very lowest operating costs in the industry, if not the lowest. And Todd, we're always grinding away on costs. We've obviously seen some increase in government fees and other things like that. Maybe can you give us a little more color on what initiatives we got going forward to keep grinding those costs down?
Sure, Darren. Yes, definitely, we're seeing government costs and taxes keep rising. But it doesn't look like they have any initiative to reduce their cost, so we have to do our part to absorb that. So we need to keep looking at ways to offset those increases. In July, we've swung gas out of our underutilized Galloway gas plant and directed it over to the Swanson gas plant through a new pipeline we built earlier in the year. This was done mainly to take advantage of better liquid to recovery at Swanson, which is about 5x more efficient at recovering propane and 2.5x more efficient at recovering butane than Galloway. Swanson's also tied directly to our liquid line infrastructure that we built in 2017. So that incremental liquid that we're extracting out of the Galloway gas now receives better liquids pricing since it no longer has to be trucked. But making the switch also means we'll -- we will see a reduction in operating costs. Galloway was an underutilized plant and that results in higher operating cost per unit of production. And Swanson is now near capacity, which results in lower operating cost per unit of production. And in absolute terms, this operating cost reduction is not significant. In fact, it could be as much as $1 million a year. Additionally, power and fuel prices have been steadily increasing since January. In fact, they rose 85% in May and June as compared to the previous 4 months in 2018. And they're now 230% higher than Q2 of 2017. So after the Oldman turnaround in late June, we started up our generators at the Oldman North gas plant. And then with Galloway not running, we expect to see a 15% reduction in our power consumption corporately. That doesn't translate to a 15% reduction in our power bill. There's a fixed component to the cost, but it does go a long ways to offset that large jump in the pool price. We're also currently investigating the idea of selling any excess generator power back to the grid. We're still waiting on feedback from a third-party on whether the idea is operationally and economically feasible. But hopeful -- we're hopeful that we might be able to do something going forward. And I should add that we also generate power at 3 of our other gas plants in addition to Oldman North. Those plants are connected to the grid, so there's no option to sell the excess back to the grid. But they aren't being exposed to this new high pool price that we're seeing.
Okay, great. Sounds like we're going to be more and more in the electricity business here. Maybe changing gears a little bit. We can talk a bit about our exploration initiatives. Switch over to Dave Thomas, our VP, Exploration. Dave, we captured a very sizable piece of land subsequent to the end of the second quarter. I'm sure that surprised some investors, traditional sort of Deep Basin player, and so they'll start talking about a new exploration initiative sort of outside of our norm. This is probably catching a bit of attention with people, and I know we don't want to talk too much about it. But can you tell us maybe how long we've been working on it? What can you tell us about it? And then what other exploration initiatives, obviously, has Peyto got going?
Darren, we don't typically provide many details on our exploration initiatives, and we're going to stick with that practice here. Other than to say at 50 sections, this is a pretty big Montney opportunity for us, and we hope to drill a test well prior to year-end. Peyto's way is to quietly pursue new opportunities. And this is no different than how we accumulated land in the Brazeau area built into a core producing asset with over 180 sections. Our Montney team has been active since Q1, working on opportunities up the fairway all the way to Grand Prairie and actually into British Columbia. And I'm hopeful their efforts will bear additional fruits in the coming months. Likewise, our Duvernay team has been busy. Some companies, they are currently land-rich but cash-poor, and we've been evaluating gas and also Duvernay oil opportunities that could be a potential fit for us. Lastly, our Cardium team has put together a growing program with over 90 drilling locations, which we've improved so far, and that takes us well into 2019. So we're pushing hard to improve our liquids position. And of course, we're also mindful to try to make those gains at fair value to our shareholders.
Great. Thanks, Dave. Keeps the exploration in Peyto Exploration. Tim, maybe last question, we can lead it off with you. But maybe if you could give us a little bit of color then on the other M&A side of the business. What kind of deal flows are we seeing our there? What kind of maybe land sale prices are we seeing generally? How does that environment look on the horizon?
Sure, Darren. There are several asset-sized opportunities in the market, and we have been active reviewing many of these opportunities. The drive to supplement our existing Cardium and Spirit River inventories will be a part of our continued efforts. Since we have expanded beyond our traditional focus of Cretaceous plays the within the Deep Basin, we have also reviewed numerous Duvernay and Montney prospects. Some companies have noted that they're looking to Peyto as a potential bidder due to our operational efficiencies. We have been active in the bidding process for some of these opportunities. And like David mentioned, we are always cognizant that any deal we negotiate will need to make a profitable return for our shareholders. Even though our technical teams have been very busy reviewing prospects, we continue to add to our land base through a Crown sale process. This year's average acquisition cost is less than half of the 2017 average, and we hope that this trend will continue for the balance of the 2018 Crown sale acquisitions.
Great. Cheap land. I like cheap lands. Well, maybe that's enough color from the management team. We can turn it over to some questions from those listening in. So Joelle, maybe we can start with the questions now?
[Operator Instructions] And our first question comes from Brian Kristjansen with Macquarie.
Just had some questions on the 50 net sections of Montney lands. I'm not sure how much you can say, but I'm looking for how much you paid, where it's at, is it close to existing infrastructure? And what does the evaluation drilling outlook in 2018 mean?
Yes, it's a pressing question, Brian. I know everybody's eager to find out more and more about the play. Obviously, we're being particularly vague because there's still lots of opportunity that we'd like to capture, and we don't want to give up any sort of strategic position just yet. But we've already amassed a fairly sizable position. So we felt it's necessary to disclose that. I think we're going to have a lot more information to talk about towards the end of the year. Obviously, we want to get some test drilling done, some completions done, find out when we do it our way, what wells are going to cost and what the result is going to be. A little bit more about the play, and I think, hopefully by the end of the year, we'll have exhausted the opportunity to get even more lands and more opportunities in this area. So we can then, sort of, come out of the closet and talk a little bit more about where it is and what it holds for us. But I think in the time -- for the time being, I think we want to be a little bit quiet about it, just not talk too much about it and go about capturing what remaining opportunities are in the area. And then we'll get our well drilled. Unfortunately, it takes, what, almost 4 months to get a drilling permit and get a well going. And Lee's pointing to the sky as it's going to take even longer than that. We are lulled into a bit of a, sort of, false world with the Cardium program in Sundance because we're drilling a lot of our wells on existing leases. And so we can get quick turnaround with respect to licensing new wells and getting going on our Cardium program in an existing area that we have lots of infrastructure in. So in a brand new area, where we've got to go get a brand new license, the time lines are actually quite long. I'm looking across the street at the AER, hoping that they're all working feverishly to shorten those, but yes, the regulatory burden right now in Alberta is long, unfortunately. And so to get going on new initiatives outside of someone's core area, it's painfully slow. So I'm afraid that investors are just going to have to hang in there and wait for us to gather some more information and then come out with more detail on this new play area.
Got you, understandable. Just with respect to that evaluation drilling, do you foresee sort of one well? Or do you have to test various dimensions of it in your mind right now? Or is it one well first and then proceed from there?
We're still debating -- me personally, I think I'd like to just go do a well, as we expect to develop the play, so that we've got a true test case. But maybe we will look at drilling a strat test and doing a less significant completion to get some information early on, on the play. We'll see what else we can gather from around us. There is some activity going on around us too that we can watch and learn from. So I think we'll probably drill a full-scale well so that we know exactly what it's going to cost us and what the productivity should look like, probably only one by the end of the year.
Our next question comes from Thomas Matthews with AltaCorp Capital.
I understand that you can't share too much about the Montney play. But I was hoping you would maybe share just kind of the high-level nature of how the land base came together. Was it Crown sales, was it carve-outs, was it potentially a drilling initiative from a third party? Just hoping to get some color around how it came together.
Thomas, we knew that when we slowed down on the leaner gas inventory that we had, that we were going to have some extra time with our exploration group. We've got a lot of horsepower upstairs, and a lot of those guys have a lot of experience in the Montney and the Duvernay from past jobs that they've held at other companies. So we wanted to lever off of some of that experience. So we put these 2 teams together, sort of a Montney team with engineering and exploration in it and a Duvernay team with engineering and exploration in it. And said there's going to be a lot of land turning over, over the next couple of years. Both of these plays, the first land rush happened 5 or 10 years ago, where the first land grabs happened and then people haven't drilled. And as a result, a lot of that land is converting and going back to the Crown. I think we -- late last year Todd laid out how many Montney locations that were undrilled that were looking to revert in the next year or 2, and we got to like 500 potential sections of land in Alberta that were going to flip over. And so we thought, wow, here's a great opportunity for Peyto to maybe branch out into this play, at a time too when, really, people are cash poor and there's not a lot of bidding for new land going on. The companies that still exist in the industry today are inventory rich, but they are not looking to add more inventory. And yet, we have an opportunity here maybe to replenish the pantry for the next decade or 2 at Peyto. We should probably look closely at that.So we started that initiative. Guys started looking, as Dave said, up and down the trend, and we're looking at really all types of entry points. We are not, as you know, a very good acquirer. We don't tend to buy a lot of other people's producing assets. So our activity on the exploration front tends to be very organic. Farm-ins, we've picked up a lot of land over the last 20 years with drilling activity. That's a very tax efficient way to do it, because you get to write it off as CDE or CEE rather than COGPE. We've also bought Crown land and lots of Crown land at times, and very cheaply, because there's just not a lot of competition. Dave alluded to how we put together 150 sections down in Brazeau under -- without anybody really knowing, because we were just chipping away at it and not paying a lot for it and it didn't get a lot of attention. And we've built a nice little core area out of that. So I think it's definitely more on the organic front and it's going to be a big splashy acquisition of somebody's existing stuff. And we're definitely not going to want to spend a lot of money on it, just because we like to put the dollars into the drilling and completion and save the dollars for the profit. If we spend it all on that upfront capture of the opportunity, then a lot of times there isn't much left at the end of the day for shareholders. So we know from our past experience that if we can minimize the amount we're spending to capture the opportunity, then that's all going to be profit at the end of the day for shareholders. I think historically, if you look at Peyto, out of the -- I don't know, what are we up to, almost $6 billion of capital investment, but we've spent maybe 2% on land. So it's a very small number, especially relative to a lot of other guys in the industry that -- so they sort of grow their land positions through very expensive acquisition.
Right. I guess, if you were to do those kind of farm-in deals on ready-to-expire land, of the 50 sections that you have assembled, are you susceptible to a short time window to drill those wells to lock them up?
No, what I can tell you is we've made sure that we've got time. We want to make sure that we're not going to be pressed on an expiry clock to have to drill. We want to be able to go at our own pace. We want to be able to explore and evaluate and then make the right decision on how to develop. And we know too that it takes a lot more time, unfortunately, these days with the regulatory environment that we are in to get drilling permits, to get plant licenses, pipeline licenses, that kind of thing. You've got to give yourself more time, unfortunately. If you leave yourself a 12-month clock or something to have to get it all drilled and put on production in order to continue it, that's a very tight time line. And it puts your back against the wall. So we definitely look at what is the -- what does the timing got to be when we're looking at these land deals and how much time do we have to really take advantage of the opportunities. And I think that's important, because a lot of companies -- you see it in their AIFs. You see how much land they have expiring if they don't drill it every year and you just sort of roll your eyes and go, holy cow, you might have gotten yourself into a lot of new land, but the reality is, you're never going to be able to continue it in time. So 50 sections already is a lot of land, right? I mean, especially when you think about how many locations, how many Montney wells can be drilled in one section of land, considering how thick that zone is. You could be a dozen wells a section. This could be years and years of drilling. So for sure, we are very cognizant of the continuation issue, and our ability to make sure that when we capture these lands, we have them in the inventory forever. And we're not going to lose them.
Okay. That's helpful. And then, just to follow on Brian's question, from an infrastructure perspective, where that land is, do you see any, sort of, big infrastructure commitments in order to get that production online? Or are there nearby facilities that you can lever off of?
We have a fairly broad network of infrastructure across the basin already. So obviously, we're going to want to use our infrastructure leverage as best as we can. You know us too, we'd like to own our own infrastructure. So if there isn't our own infrastructure available, we're going to want to build more so than -- yes, and maybe in the early days we'll test wells out and test out concepts using other people's infrastructure and go to a third-party, but definitely, we want to control the infrastructure long term. We know that there's huge value in owning the infrastructure that processes the production. So -- we've always been just-in-time with our infrastructure, too. Very careful to make sure that we can not only drill wells and complete and get production on, but we've got infrastructure there when we need it there. So that sort of goes back to the discussion on timing, making sure that when we do embark on drilling, we've got an infrastructure solution already teed up and all ready to go.
Okay. And then just finally, on the power plant agreement, 2023, that's a little ways out. Is there an ability to pull that forward if we have any sustained AECO weakness? Or is that something to do with what they're building that won't come online till 2023? And then what's the likelihood of increasing the volumes under that commitment or under other power plant commitments?
Yes, I doubt we're going to be able to accelerate that. I think that's -- has given substantial buffer. They're going to be ready to take our gas likely sooner than that, but not too much sooner. But this is the first of probably, I hope, many such deals, and so the likelihood that we manage to get more direct connect to enter Alberta industrial users before 2023, I think is still high. I still think there's lots of different projects on the books that -- new builds and existing conversions that we can supply gas to. And we, obviously, haven't finished. We haven't got our percentage that we're looking for in terms of allocation to this market. We've got to add some more, so hopefully, like you say, we can do it and it's going to impact the economics of the Peyto a little sooner. But as Todd was pointing out, power prices are very strong right now and any connection we can get between gas and power is a good one. And I think, just generally speaking in the market, 5 years from now, I don't think there's going to be a lot of coal generating power in Alberta because gas is too cheap and too plentiful and it makes too much sense. So we are going to be in that market, as we've illustrated here and as we prove it we're going to connect our gas to the power market for a good portion of it. Whether we're generating it ourselves from our small gen sets or whether or not we've committed large volumes to other power producers, we plan on having a goodly portion of our gas tied to that market.
Our next question comes from Fai Lee with Odlum Brown.
It's Fai. I was just wondering, in terms of your new exploration plays at Montney and the Duvernay, have you given any thought to, if the results turn out to be what you expect, how the financing plan would work around that? Are you going to reallocate capital from existing operations or would you finance on a stand-alone basis? Just was wondering how you're thinking about that.
We've got -- I guess, lots of different sources of funding to allocate. We've got our cash flow. We do have some available bank lines that we could use. So long as we can bring cash flow on fast enough and grow cash flow faster than debt would be growing, then I'm happy to look at what available funding we have from the banks. As always, it's a competition for capital around Peyto. We're looking to put capital into the highest return projects. So looking across our portfolio of opportunities, we're going to be ranking and allocating as usual, putting stuff to where we feel we're going to get the best returns. So it's going to have to compete with our Cardium results. And as our Cardium results get better and better, it's going to have to get better and better too in terms of the opportunities, or it'll sit on the sidelines as well as some of our other Spirit River opportunities. So it's all a competition here at Peyto. We've obviously got a good amount of cash flow to work with. If things look really, really exciting, perhaps we'd be going back to shareholders and asking to reinvest some of these profits and the earnings that we have that we're currently dividending out. Maybe we ask shareholders, do they want to reinvest that in some of these opportunities because they're just too exciting and there is too much opportunity there that we should be capturing and not waiting on. But arguably, you can put a profile together of just spending our cash flow on it or you could look at external funding if you want to accelerate if the environment's right. I think a lot of that obviously has to do still with gas prices, because even though these are liquids -- more liquids-rich opportunities than they are leaner gas opportunities, they still require some gas price. It's still gas as the energy source to produce these wells. So we still have to think about the impact of the seasonality of gas price and where it's going long-term.
[Operator Instructions] Our next question comes from [ Jordan McMillan ] with Tudor Pickering Holt.
Just a quick question on water handling, given the increasing Cardium drilling and more frac water being used. Are investments required on the water-handling disposal side of things, or is the current setup sufficient to handle it?
That's a great question, Jordan. We were talking about that earlier. Lee mentioned that we're going to try and recycle all the water and be as environmentally friendly as we possibly can be with respect to freshwater. And we have been very successful recycling a lot of our frac water. I think we're up to about 80% over the last couple of years of all the frac water that we've recovered, we've recycled back into new fracs. And I'd like to see even more of that going forward, and of course, as we have more and more water coming back, then there'll be more water to recycle. So we have those processes already in place in a lot of cases and we are working that angle as much as we possibly can. We still have to make up some freshwater, unfortunately, because we don't get all the water back. We'll see with these Cardium wells just how much we get back. We're pumping a lot more than we normally were pumping. So this is a bit of a new, uncharted territory for us in terms of how much water we're going to see back from these Cardium wells and what we are going to have to deal with. We do have disposal plans to deal with what water we can't recycle. Obviously, the first try would be to try and reuse a lot of that water and keep it moving in our system and not have to dispose of it. Disposal is expensive. And we don't give them the chance to be the environmental leader that we are in the industry in terms of putting that water back to use. We don't have a real water problem in terms of sourcing. Unlike a lot of plays where there isn't a lot of freshwater to -- it gets really expensive to even bring in new freshwater. We're pretty lucky where we are in the Deep Basin. We've got a lot of shallow aquifers that we draw water from. Obviously, we are very active in ensuring that they remain uncontaminated because we want to pull freshwater from them. So we are very careful with respect to making sure that we're not contaminating them. But there is plentiful water in the area, thankfully. And so we don't have to truck water, freshwater from a long distance away. We're not having to drain a prairie lake somewhere in order to get the water to use for fracking, and so we can ramp up and do things like triple the amount of water we're putting into our Cardium without a whole lot of extra cost from a water source perspective. So water is a big issue, obviously, for a lot of companies, especially as you get into some of these unconventional plays. I fully expect that the Montney drilling that we're going to do is requiring even probably more water for fracking than what we're putting even into the Cardium. So water source and then the water handling is going to become a bigger and bigger issue for us. We are pretty up to speed and we fully understand that every drop of water has a cost to it, both the sourcing cost and then the ultimate handling cost. And that's critical and can have a huge impact on companies' operating costs going forward, not to mention their capital costs with associated completion. So yes, we're on top of it. I can tell you that we're looking at a variety of solutions for dealing with the water when it comes back. I think our preference, of course, is the more environmental solution, which is to recycle and put that water back to use rather than have to dispose of it.
I'm not showing any further questions at this time. I would now like to turn the call back over to Darren Gee for any closing remarks.
Great. Well, thanks Joelle, and thanks for all those listening in and participating in the call this morning. I appreciate the questions. Apologize that we can't provide even more color on some of these initiatives that we've got going and we have to remain, unfortunately, vague on some of them, because of strategic reasons. But as the rest of the year start to progress, I think we are going to have a lot more to talk about. A very exciting time right now at Peyto. We've got a lot of these new exploration initiatives that are really interesting things that we're working on and exciting things that we're working on that should bear fruit for the next 20 years of Peyto. We're celebrating our 20th anniversary in the third quarter and so -- or is it the fourth quarter? I guess it's the start of the fourth quarter. But that's an exciting time, to have been in business 20 years. To have been as successful as we have been over 20 years makes Peyto pretty unique. And we're positioning ourselves to have the same kind of success over the next 20 years. Despite some of the short-term challenges with gas price, we're navigating successfully through that too. And I think long term, there is going to be lots more exciting things to talk about at Peyto, and in the short-term, we should have some interesting results to talk about as well. So please tune back in, in the third quarter, and we'll update you on results then. Thanks again.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program, and you may all disconnect. Everyone, have a great day.