Peyto Exploration & Development Corp

TSX:PEY

Earnings Call Transcript 2019-Q1

[Operator]

Good day, ladies and gentlemen, and welcome to the Peyto's Q1 2019 Financial Results Conference Call. [Operator Instructions] As a reminder, this call may be recorded. I would now like to introduce your host for today's conference, Darren Gee, President and CEO. Please, go ahead.

[Darren Gee, President, CEO & Director]

All right. Well, thanks, Chris, and good morning, ladies and gentlemen. Thanks, everybody, for tuning in to Peyto's First Quarter 2019 Results Conference Call. Before we get started today, I would like to remind everybody that all statements made by the company during this call are subject to the forward-looking disclaimer and advisory that was set forth in our news release yesterday.In the room today, we've got Kathy Turgeon, our Chief Financial Officer; JP Lachance, Our VP Engineering and Chief Operating Officer; we've got Dave Thomas, our VP Exploration; Lee Curran, our VP of Drilling and Completions is here; Todd Burdick our VP Production is here; and Tim Louie our VP of Land is also here. So we've got the entire Peyto management team here for you in case you've got some questions. Before I get started with my comments today about our quarter, I just again want to recognize the efforts of the entire Peyto team, including all of our field personnel. We had a very active first quarter and we also had some very bitter cold to deal with in February and a lot of snow as usual. But our team did a great job, 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 want to start off this morning with some general comments before we open it up to questions from those listening in. I'm going to try and keep this very brief. This is a busy week of reporting so I'm sure everybody has lots of calls to listen to this morning. We do have some e-mail questions that came in overnight and we'll try to get to those at the end. As mentioned in the release, we spent the quarter working on our Cardium program. That involved drilling, completing wells, installing pipelines in new facilities, and of course, buying some new land. We acquired some new Cardium lands really cheap and continue to do so. We've been doing that for a while now and that's really allowing us to back fill the inventory that we're drilling for very little capital. In reality, we're adding inventory at a pace that's far exceeding our pace of drilling right now but that's actually kind of always been the case at Peyto.We're really now starting to see the effect of the more liquids rich Cardium on our total production blend and on our cash flow, which is nice. It's also creating some problems, of course, with all the liquids that are gathering up in the pipelines and increasing the pressure in the system. That tends to back out some of our older base production and older wells that are a little bit weaker. But we have a plan that we'll put into action here after breakup to rectify that pressure drop.Got some looping that we're going to do and some other facility installs to get some of that production back. Since the start of the year, I think we've been extremely pleased with the well results. We're getting consistently good production results from this new batch of Cardium wells. We're getting consistently good execution on our operations and consistently good costs. So well done guys, it was a great quarter from that perspective.As far as commodity prices go, AECO gas price is still all over the place. First quarter, with all the cold weather that we had kind of surprised everybody and day prices were a lot stronger than predicted, stronger than the monthly price, which was rare. We put the majority of our gas to the AECO monthly price because we hedge against the monthly. And so we need to match those 2 up, which is why we did it that way. Typically, the monthly does beat the daily but the market was a little caught off guard this year I think with the cold weather and we had a particularly strong pull on storage in March. Interestingly, when you look at Eastgate storage, it got pulled down so far that we started to see storage reservoir productivities fall off, and the storage at the end of winter really wasn't there in the way that the market predicted. So that really helped with March prices. Now we're in the shoulder season, of course, and prices are quite sensitive to the outages on TCPL and the weather on any given week. One day they're $0.20 and the next day they're $2.50. And it really just goes to show, I think, how closely balanced the market at AECO really is. Those days when receipts are running around 11.5 Bcf on Nova, the price is north of $2. And when we're back up at about 12 Bcf a day it drops to $0.50. So again, I think that shows us that we're very close to balance in this AECO market about maybe 1.5 Bcf a day out of balance, which is not very far off. It also kind of suggests that just a little bit discipline from the producers I think we could have a very decent AECO market for everyone, including the Alberta Crown. And me personally, I wouldn't be surprised if we see Jason Kenney and his new UCP government want to renew discussions on that front with respect to the Alberta gas situation.Regardless though, we have a lot of our summer gas already hedged, even the gas we locked to the NYMEX through basis deals this summer. We fixed those prices as well, which was a good thing because the NYMEX for this summer has fallen off quite a bit.On the liquids side, and liquids are now a more important part of our revenue stream, condensate and pentanes were trading back where they should be trading, the big differentials that we saw in Q4 are now gone for the most part. It really hit condensate prices more than pentane prices, pentane doesn't seem to be quite as sensitive as condensate when we do see the differential blowout. Butane, on the other hand, is struggling a little bit. There's a lot of butane in storage. We built up a bit of a glut of butane in the fall and the refineries went down and the draw for butane dropped. And that's putting some pretty heavy pressure on the price right now, but that's likely -- all that cloud will clear here over the next 6 months, and butane prices should get back to where they've been historically.The one we're watching most closely though really is propane. AltaGas is filling their storage terminal in Ridley Island right now and soon they're going to be exporting a significant amount of Canadian propane off the West Coast, and we're anticipating the impact to prices that, that's going to have. Once we see that, we're going to make our call on our Swanson deep cut. Propane prices right now are sort of floating just under $20 a BOE, FOB Edmonton. And I think we need about $25 a barrel to generate a 20% rate of return on our deep cut. So we're almost there and we just want to see that propane price strengthen a bit and then look like on the forward curve it's going to stay there and then we can make our call on the Swanson deep cut.Financial results for the quarter were good. Cash costs were up a bit, but that's really typical for the winter quarters when we use more methanol and chemical. And this Q1, as we mentioned in the release, was particularly cold, so we used quite a bit of methanol to keep wells from freezing off. Op costs are expected to fall for the next couple of quarters as we get into summer and that chemical consumption obviously drops off. We paid down another $30 million or so in debt this quarter. Obviously our total debt went up but net debt was down. And that makes over $150 million of debt repayment since the start of 2018 when we cut our dividend and reduced our capital program. And all of that was a longer-term strategy, a 3-year strategy we had to wait basically for the new egress that's coming and wait for that impact on prices before we start to grow our production again. So we thought we'd put all this extra free cash flow on the debt and strengthen our balance sheet in the short term.G&A in the quarter was up a little bit. Our G&A is always really low anyway, but we did make some onetime investments supporting some advocacy groups like CAPP membership and EPAC membership and Canada Action and those kind of things. We feel that's important because we need to get that message out that the world needs more Canadian energy, especially if we can displace the dirtier, less responsibly developed fuels in other parts of the world with clean Canadian energy. We need to make sure the world is hearing that message. Really, you just have to look at what the U.S. has done to reduce their greenhouse gas emissions by growing their oil and gas production and exporting it to the world. Canada needs to get on that bandwagon and do that too.As far as the outlook is, we still have a bunch of work to do. Coming out of breakup, we've 4 Cardium completions to catch up on. Then we've got our Montney well to get completed, that's going to be exciting. I've got my fingers crossed here that, that area has sweet gas in it and we can test drive that well through our Wildhay plant. I think we're all quite excited to see what it's capable of. And the plan is to have a couple to 3 rigs running through the summer and into the fall and continue an active program on our Cardium, which is yielding us some of the best results we've seen in the company's history.So that's just a quick summary of the quarter. Chris, if we could maybe throw the call open for questions from the listeners.

[Operator]

[Operator Instructions] And our first question comes from the line of Adam Gill with Eight Capital.

[Adam Gill, Principal]

Two questions from me. One, once you get the deep cut back up and running, do you have an idea of where the liquids yield is going to pan out? Or where it would have panned out in Q1 should that have been running for the full quarter? And then the second question was just on operating costs. You did mention that there was some per unit creep given the lower volumes. Just wondering if there was any notable impact from the cold weather? Or any impact from the increased liquids handling?

[Darren Gee, President, CEO & Director]

Good. Thanks, Adam, good questions. May I start with the deep cut question first? So we had the deep cut shut in actually for January and February, right, Todd?

[Todd Burdick, Vice President of Production]

February and March.

[Darren Gee, President, CEO & Director]

Sorry, February and March because we had strong gas prices in February and March. And the butane and propane prices were actually quite weak. So we were calculating that it was better to sell those molecules of heat in the form of gas rather than strip them out and pay the extra operating costs to strip them out into liquid form. So we shut off our deep cut and we were basically increasing our gas volume then. So really our liquids production that we reported in the quarter was suppressed because we weren't actually pulling as much C3 and C4 out of the gas stream as we could have been. We could have had higher liquids in the first quarter than we even did. But since, we got through the first quarter and now we're into April, we've turned that deep cut back on again. Gas prices, obviously, have softened a bit as we get into the shoulder. And then the propane and butane prices relative to that gas price, it makes sense then to be pulling those out into liquid form. So our liquids production has stepped up again and our gas production's down a little bit and our operating costs are reflective of that deep cut running. But I don't think, Todd, maybe you can chime in here. Does it cost us a lot to turn the deep cut on and off? We can do it quite quickly now I believe and react to the market.

[Todd Burdick, Vice President of Production]

Yes. I think we've got things down now where we have to take a portion of the plant down, reel that plant down for about 3 hours to shut off and then turn the deep cut back on. So from a cost perspective, it's just a piping crew so it's not really impactful at all. It can be done quickly.

[Darren Gee, President, CEO & Director]

And then, Adam, you had a question on our operating costs. Through the quarter, they did bounce around quite a bit. Weather was quite impactful, obviously, to our operating costs. When there's a lot of snow out there, we've got to do a lot of road clearing obviously of the snow. The really cold weather that causes the freeze offs, our guys are -- I mean, the way you prevent the freeze-offs, just use a lot of methanol obviously to grab that water vapor and prevent any hydrates from forming. So you do tend to use a bunch more methanol. It was a tough quarter for methanol. Todd, can you give us some color on methanol pricing?

[Todd Burdick, Vice President of Production]

Yes. We've seen methanol pricing climb for probably the last 1.5 years. We locked in some pricing kind of late-summer last year, a low for the year. But with the cold weather in February, we really saw a lot more consumption than we normally would that impacted the whole quarter. We've since seen some warm weather and we've been able to bring down that consumption significantly. It'll be -- by the end of June, we're typically 50% of what we see in January or February on consumption.

[Adam Gill, Principal]

The -- just back to the deep cut, do you guys have an idea where the yield was for April?

[Darren Gee, President, CEO & Director]

The deep cut, in full operation, I think, pulls somewhere between 750 barrels a day, more C3, C4 for us. It varies a little bit depending on quite how cold we can get the stream, but somewhere in that range, so 750, 800 barrels of extra liquid out. Now we lose a little bit of gas, obviously because we burn a little more fuel to run the compressors for the deep cut, but that's kind of the volume that we'd be looking at [indiscernible] ours too. The last comment I made, Adam, on the first quarter Op cost would be that a lot of -- so the root of our operating cost is actually government charges like AER fees and municipal taxes, and that doesn't even count the fee we paid to the municipalities to move rigs around. Road use factored in there a bit, but I think we're hopeful that with this new UCP government that we can start to see some of this regulatory burden costs on the industry start to drop. Jason Kenney's been pretty vocal about saying that he needs to improve the efficiency of the regulator. We need to address this municipal tax burden that exists on the industry that is weighing pretty heavily on the industry. Obviously, most people are aware of the recent Trident bankruptcy and rather pointed message within that, that the municipal taxes were what really killed that company. So that -- we're a very low-cost operator so it's a little bit amplified, those charges on our operating costs. For most guys, it's not 30% to their operating costs, it's a lot smaller. But it's still a meaningful amount of cost structure. And so we would hope that actually with some efficiency gain through the new government that we would start to see some of those costs come down.

[Operator]

And our next question comes from the line of Thomas Matthews with AltaCorp Capital.

[Thomas Matthews]

Just wanted to follow up there. So essentially, with the higher liquids yields, irrespective of weather, know you're not forecasting any sort of increase to unitized Op costs in order to process those liquids going forward.

[Darren Gee, President, CEO & Director]

Yes. That's right. I mean, unfortunately, Thomas, as we're flipping the deep cut on and off depending on pricing, it's hard to then find a steady state with respect to the operating costs of the deep cut. But I don't think the deep cut off costs are that material that they're going to shift our corporate costs that much. Remember this is just about 3 quarters of one plant out of our 9 gas plants that -- so it's not like the entire company that's moving from a deep cut operation or entire production base that goes from a deep cut operation to a non-deep cut operation.

[Thomas Matthews]

Right. Then I guess just recovering more condensate and pentane some. There's no additional processing that goes along with that, that would increase the unit costs with the decline in gas production along with that?

[Darren Gee, President, CEO & Director]

No. Not at all. The deep cut really only pulls more butane and propane. Our refrigeration plants under current shallow cut operation if you wanted to describe that way, get 95 or more percent of the C5+ out. You have to take it virtually all out otherwise we can't make hydrocarbon dew point. So it's really a optionality on...

[Thomas Matthews]

Got it. [indiscernible].

[Darren Gee, President, CEO & Director]

Yes. It's just an option on the butane or...

[Todd Burdick, Vice President of Production]

Also got out liquid pipelines that are connected so there's no incremental costs to move those incremental liquids. There is, depending on where we're developing, there may be some small trucking increases to get some of that incremental condensate to the pipelines, but it's not a material increase.

[Darren Gee, President, CEO & Director]

Yes. It's a good point. I mean we're pipe connected to planes with all our LPG or the majority of our LPG and to [indiscernible] with the majority of the condensate so we've got egress for all of that. It's not like when we get more liquids we're immediately incurring more trucking costs or something like that.

[Thomas Matthews]

Right. Okay, okay, that's very helpful. And then, Darren, I was just wondering if you could just touch on butane prices. I know that in our discussion you said kind of later in the year, you expect the glut to clear. But just in the meantime, your premium to the benchmark seems to be going up every quarter, which is a result of, I would assume, some long-term contracts. So just wondering if you could just give us some color on what you expect for the next 2 quarters until the glut clears? Are you kind of back to spot pricing? Or are you still going to receive that premium?

[Darren Gee, President, CEO & Director]

Yes. Butane prices are not good really, I mean, historically, butane, I think, has traded at close to 50% of oil price. And what we saw in the fall and the impact that had to the entire butane market is percolating through here into Q1. And I think through the summer, you're going to see from a lot of producers, that realize butane prices are going to be significantly lower than what you might expect butane to sell for. We're not totally immune from that either. We are a larger butane producer. There is only, I think, about a dozen producers that actually take their butane and market it themselves. Most producers just dump their LPG into the frac plant in the midstream companies and are paid for the blend. They don't really do an active job of marketing their butane because they just don't have enough. We do and so I think, hopefully, we've done a better than average job in finding markets for that butane and getting a little bit better pricing on it. But -- and that premium to what the average realized price might -- we'll likely continue except that the average realized price is going to be quite a bit lower than what it's supposed to be for butane. There's no question. The spot market's a little tough because it's not very liquid. Like I said, most guys lock their -- the significant amount of butane production in the basin is typically locked-in for 1 year worth of sort of takeaway. The refiners buy it, I guess, mostly for blending in to make gasoline and so they do all their deals in March or April and so then everybody's kind of tied up with them for a 12-month period until the next year. But the spot market is just the sort of little bit of volume that's not tied up. And that trade is kind of all over the place a little bit. But I would say that we've obviously factored that into our budgets going forward that the butane prices going to be weaker for the industry. And you're likely -- you're going to see that across-the-board through the summer. And then into the fall hopefully, we're back to a little more balanced market.

[Operator]

[Operator Instructions] And our next question comes with a line of Fai Lee with Odlum Brown.

[Fai Lee, Equity Analyst]

Darren, Fai here. I'm just wondering about the net debt reduction and as you generate free cash flow going forward, this quarter the free cash flow went to paying down your accounts payable largely. I'm just wondering how should we think about it on a go-forward basis? And is there a point where just -- [ shows a bit of ] cash or do you continue to reduce your accounts payable and accrued liabilities?

[Darren Gee, President, CEO & Director]

Yes. A good question. I guess I was a bit surprised by how confused people were with respect to our debt. The difference between total debt and net debt, I guess, people that are looking at our financials don't quite understand the difference. So I'm going to force Kathy to explain it maybe, if she can, as best as you can.

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

So we really have 2 components to our long-term debt, which is the unsecured notes, which of course are a fixed amount, there is no repayment of it. But then we also have our credit facility, which is like a line of credit so we draw it on using bankers' acceptances and we repay the banker's acceptances. We can do -- typically we do between 1 and 3 months bankers' acceptances. So when you look at drawn debt, which did go up from the end of the year, it's really about timing of cash flows. So you'll also notice our bank overdrafts have gone down. And our payables had gone down. So it's just timing of payments. In Q1, our CapEx was much less, so our cash cost requirements are less and so now we've actually been repaying some of that drawn debt since the end of March. So this drawn debt is just a function of timing of cash flows where net debt is looking at where is our actual trend going and that's looking at the receivables and the payables that I'm sure you're aware and looking at the timing of the receipts. We collect almost all of our receivables the 25th of the following month. So even production changes can affect just the timing of the receipts. If our production's going up, we'll have more cash in a receivable or noncash working capital, but our cash requirements may be for paying the capital to get that production have to be paid in that time so we have a use of cash. So that's really where there can be a bit of a divergence between net debt and drawn debt, but net debt is the most relevant indicator, we think because that's really showing where our financial assets are going.

[Darren Gee, President, CEO & Director]

Sorry, I was just getting to chime in Fai that yes, absolutely, net debt is the one you want to watch. It effectively measures what our debt should be at March 31 once all the paper comes in. So another 30 days when all of the invoices, all the receivables come in and all the payables go out, that's where your debt is going to be once all that is cleared.

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

And there are sometimes like at the end of the year we have certain payments for performance based compensation that are onetime things that have to be funded through cash. But the expenses is recognized over time. But since March 31, I mean, we've had a change in that because the payables are already paid and they're not being replaced at the same rates, so we've actually been repaying our drawn debt. And like I said, a lot of that $500 million is on bankers' acceptances, which are very short term in nature and so we can draw and repay in rapid timeframe.

[Fai Lee, Equity Analyst]

Okay. Yes, no I understand the difference between the debt and the net debt I just was wondering whether it's going to come as -- or as an increasing cash or as we saw this quarter, reduction in payables or reduction in the actual debt levels, but I guess and more of the question whether payables are stabilized or not? And it sounds like they did.

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

It varied. It does vary, but we expect that Q2, we have certain other cash requirements like property taxes. But we expect to see a reduction in the net debt. We are seeing our cash will be exceeding our payables due to also has far less capital. So then we'll start seeing an actual increase in cash balance or decrease in drawn debt bank overdraft. We are expecting to repay debt this year though.

[Darren Gee, President, CEO & Director]

Oh, yes. Yes, yes.

[Operator]

You'll need to have a follow-up from the line Thomas Matthews with AltaCorp Capital.

[Thomas Matthews]

Just one last final question. Just on your Cardium kind of completion evolution here on your second gen horizontals. And just looking at the charts you have in your presentation. Is that -- have you guys reached the best practice do you think or is there a further evolution? I mean is there going to be more cost reduction as you go or potentially higher liquids yields? Is that a product of where you're drilling? Or is it a product of the completion? Just trying to figure out the next progression and if the type curve and economics are likely to get better or stay the same.

[Darren Gee, President, CEO & Director]

Yes. Thomas, I'd say overall, we're really happy with where the Cardium program is going. I wouldn't want to say that we've stopped innovating because I think we're going to continue to work on optimizing that program going forward, we always do. But -- and JP can chime in here with some more color on the Cardium. But I think, for now, anyway, we think we've found a recipe that is delivering superior results. We like that. We want to obviously optimize and perfect that even more and through repetition hopefully, get the cost of that even down even more. But I'd say that yes, we're looking to make the results that we're currently getting even better. But, JP, maybe you can add some more color.

[Jean-Paul H. Lachance]

Sure. Yes, so recall we've drilled -- we drilled 50 wells last year and that 50-well program tested different completion designs, different deployment methods of our fracs, it also looked at different things like stage counts, amount of sand, all kinds of different things, and then we did that across several areas, right? So we were, in a sense, testing out these different attributes or features which now we've had some time, we've had some production history. We can go back and we looked at these things. So we looked at them late last year and early into this year and said okay, well these are the features that make sense to us that really influence productivity and ultimately value creation. So -- and we've always looked at things from a value perspective not necessarily just what gives us the most -- the highest rates. The liquids are a big part of that. We're seeing much higher liquid yields from the way we're doing things. Without getting into the specifics of what it is and what our formula is, I'd rather not. But if -- as we look forward, Q1 program is far better than last year's in aggregate so far. I mean, that doesn't even -- just looking at numbers like last year's program on our price deck, on our reserves price deck, in aggregate was around 26% rate of return, whereas when I compare on the same-price deck to a program so far in Q1, we're at 55% rate of return. And that's with the wells that we've got on stream with some history. That doesn't include some of the most recent stuff that we've just brought on with even better, I think, with even better results we'll see them play out here, which should improve on that. So I think we're seeing a step change. And like Darren says, we'll continue to innovate, costs. We just had these conversations, we're going to continue to have these conversations about how we now can lever on those -- on different parts of our cost structure to see if we can pull those back and still not -- still get the same sort of outcomes we're getting lately. So yes, by all means, this is a continuation of -- we're excited about what's happening.

[Darren Gee, President, CEO & Director]

Thomas, I gave you that, that this is somewhat of a reduced program for Peyto, the capital program is not very big. And so the number of wells we're drilling this year isn't that large. That actually puts pressure on the cost side of the business and the execution side. Lee would chime in that he can't do as much from a pad drilling efficiency with a smaller total well program. If we're only doing 2-well pads as opposed to 4-well pads, well he can't leverage the pad drilling efficiencies as much. So I would say this restricted program actually has some opportunity for improvement just by scaling it up. There is some definite cost advantages to a larger program. But we wanted to make sure that we had the right recipe. I think the results that we're seeing, especially in this first quarter, are indicating that, that recipe is working very well and we're getting some far superior results to anything we've ever seen actually in the Cardium. And we're excited about the repeatability of it. We're -- like JP says, maybe we're only 15 or 20 wells into using this sort of new technique with this brand-new recipe that we've fine-tuned on the Cardium, but so far the rates of return are looking far superior and it's looking awesome.

[Operator]

And our next question comes from the line of Aaron Swanson with TPH.

[Unknown Analyst]

I just had a quick question on Montney. I know you guys are thinking it may be sour. Like how do you guys establish if the gas is sour? And then what are the options for completing and testing the well if it is?

[Darren Gee, President, CEO & Director]

That's a good question, Aaron. Obviously, sour gas is a little tricky for us because we have all sweet gas infrastructure. The location of our Montney is just on the left side of our Greater Sundance block. So if we can use all of our sweet infrastructure, it's a huge advantage for us timing wise and cost wise. But when we look around us at some of the existing production to the north of us, there's been some new wells drilled and from what we've heard and what we've seen in the field, those wells do have H2S in them anywhere from sort of 2,000 to 7,000 - 8,000 parts sour. It gets more sour the further north away from our land block you go. And then as you go west off our land block, there's a couple of old wells that are actually sweet, which is very intriguing. They don't have any H2S in them and so we're not sure where we are quite frankly with respect to the H2S. If we have, I think, less than 500 parts per million H2S, we can sweeten with chemical at the wellhead. It's a little more expensive but it allows us to use our sweet infrastructure, our sweet gathering systems and our sweet gas lines. If it turns out the well is sour, say it's 2,000 parts per million sour, our options are really to either tie into a third-party to test drive the well if we're not as confident with the results that we've seen and play that well out and look at the next drilling steps or obviously, we could build our own sour plant. And we have that sort of optionality. That's a more significant infrastructure investment, obviously, and we would want to have confidence in the play. So if the well result's really good but it's sour, maybe we've got the confidence to kick off a sour plant installation and get after drilling follow-up wells to that well. If it's sour and weak then we've got a bit of a decision to make on where we want to get it processed. If it's sweet, then it's an easy decision. It's -- we slam it right into Wildhay infrastructure and we test drive that well. And obviously, that scenario for us would be it's sweet and really productive in which case we not only have to get that well on right away through our stuff, but we have to expand all our infrastructure to handle a lot more development that'll be coming down the pipe. Dave, maybe, I'll ask you. What, as far as the Montney goes, what's sort of next steps once we get this well on and tested? Obviously, there's a lot of different paths on that decision tree, but you've got obviously locations teed up off this location. Are they expected to be the similar type of results or are you testing something different in the Montney? Or what are we looking at?

[David Alan Thomas, Vice President of Exploration]

The Montney here is about 100 meters thick, Darren. We're testing the upper Montney, we have about 120 follow-up locations each about a 1.5 miles long as you said, and it's really close to our Wildhay plant. If it is sweet, it's a great resource for us. The wells to the north that are on productions are producing condensate levels. The CGR condensate to gas ratio is pretty stable at around 50 million or -- 50 barrels per million. And those wells to the north seem to give -- producing about [ 3 million ] a day currently. But a couple of them are still increasing and the condensate levels are pretty stable so we're happy to see that. If we could improve on that, that would be tremendous. But there still are a lot of unknown variables here. We're just going to have to wait and see. Even when we complete the well it's going to take some time before we really know what the well is capable of production-wise. But big resource, more than 4 Bcf per well. But if you want to look at it, I guess we've been saying here for a while, these will be similar to our Cardium wells, but with a lot more reserves per well. So it would be a really good fit for us if things kind of [indiscernible].

[Operator]

Our last question comes from the line of Garret McMullin with One Nation Engineering.

[Unknown Analyst]

I'm just wondering, with your free cash flow, have you ever thought of buying back your stock?

[Darren Gee, President, CEO & Director]

Yes. Garret, we actually do have an NCIB in place, so we have that option. I guess by definition there's sort of 3 ways we can return capital to shareholders, one of them is to pay down debt, that's what we've been doing. One of them is to pay a dividends, we do that too. And one of them is to buy back stock. And so we can weigh all 3 of those options in terms of, which path we'd like to go or which combination of them we'd like to entertain.In the near term, we thought the best thing to do really was address the balance sheet and pay down the debt, especially since we sort of started to see interest rates rising over the last years. So the cost of that debt was starting to go up a little bit and so we thought maybe we better start to bring that down with the free cash flow, and that'll reduce our interest cost burden. And we'll start there. We are still paying out some dividend obviously, we could allocate that capital to debt repayment too if we so choose. But there's impacts and ramifications for that too. And then there's the buyback. So we do have an active NCIB in place that gives us that optionality and should the Board decided that that's one of the paths we'd like to pursue or in combination with a debt repayments and the dividends, it's definitely something that we can entertain.

[Operator]

Thank you. And that does conclude today's question-and-answer session. I would now like to turn the call back to Darren Gee, President and CEO, for any further remarks.

[Darren Gee, President, CEO & Director]

Well, great. Thanks, Chris. Did we get everything we wanted to talk about today, guys? I think one of the only questions that came in overnight that -- this was kind of an open-ended question and we could probably talk about it for a long time. But I did want to maybe ask Lee, the new UCP government that obviously just recently got elected, talked a lot about reducing regulations, improving efficiencies for the industry, speeding us up and getting us back to work a little more, hopefully lowering our cost burden when it comes to regulatory side of the business. Lee has been sitting on a bunch of industry groups, advisory groups, working with the old government, I guess, at least the existing bureaucrats that still exist over at AER and some of the other regulatory bodies. I don't know, Lee, can you provide any color on what direction, I guess, the conservative government has sort of indicated to bodies like the AER, how we might expect they're going to behave over the next little while, changes that we might see and how that's going to impact our business?

[Lee Russell Curran, Vice President of Drilling & Completions]

Well, sure. I might need my own forward-looking statement. It's early days. We've only had our new government for just over a week now. But the continuation of the public statement that Alberta's open up a business, naming an associate minister of red tape reduction, those are big messages that I think from our perspective are very welcome.I would wait -- I would anticipate we would have to wait until the summer until we're going to see some really big wins on the reduction of that red tape and timeline improvements. But by all means, they're in the discussion right now. For that matter, since early in 2018, Peyto's been an active participant in a joint-industry group working with AER, really to identify large regulatory impediments. And our objective has been a recipe to push that regulatory system towards something that Alberta companies can operate on a competitive stage with other jurisdictions throughout the rest of North America. Now there's certainly been improvements through that time, and quite frankly, with all due respect, the bar was set pretty low to begin with as project review and approval timelines in this province have become embarrassingly low -- or long story. For example, a simple surface crown lease access associated routine gas well was at times regularly occupying up to 6 months from inception through approval. Now if I go back to the ERCB days, we often saw the similar scope approval take 6 weeks. Now we've currently refined that back down to a much improved 3 to 4 month timeline, but there's still a lot of room for improvement.The problem is that many of the current initiatives to improve those elements of regulatory efficiency have run up against a legislative wall. And that means that to continue those gains we need direct government support and intervention.To compete on the North American stage, not only Peyto but our entire industry peer group has found a lot of ways to do so much more with so much less and specifically, in Alberta, we've learned to do that while we continue to make gains on improving the health and safety of our workforce, stakeholder engagement and protecting the environment. And I think it's kind of overdue for us to stop asking and perhaps, start demanding the same of our regulatory system. Our primary regulator has ballooned into an organization that, at least by Peyto's share, essentially has the net impact of having a full-time equivalent staff in the adjacent building. When the AER was established in 2013 to replace the ERCB, our annual levy effectively doubled from about $0.75 million to about a $1.5 million per year. For context, our production back then had grown to just shy of 65,000 BOE per day. Today, our direct annual AER burden is pushing about $7 million. So that's significant, and people need to understand the escalation that this industry as a whole has seen. Our industry really needs to see some immediate relief of many of these burdens and regulator cost reductions that coincide with timeline approvals are just one of those. And -- but that needs some immediate attention, and it's going to take our new UCP government intervention to make that happen. I'm confident our active participation in these industry working groups and associations will certainly yield rewards for us as a natural gas operator in Alberta going forward.

[Darren Gee, President, CEO & Director]

Great, Lee, thanks for that color. Just final comments. We didn't get a chance to talk much today about our storage scheme that -- we're still pushing that ball forward and we want to take advantage of that. Obviously, seasonal gas prices are still extremely volatile and there's a big opportunity there to take advantage of seasonal storage to improve our commodity prices. We didn't talk much about our power generation initiatives, the fact that we've aligned ourselves with a power producer, we're looking to do more of that work trying to get some more direct consumption alignment inside the boundaries of Alberta and looking to help out the industry with respect to shifting off more coal onto natural gas power generation, getting more of that going using more of Peyto's resources to make that happen. And we didn't have a chance quite to talk about our participation in an LNG consortium. So LNG Canada is moving ahead, which is nice to see. And Peyto's, obviously, been actively involved in discussions through that consortium on lots of different LNG options. So we are still moving forward a lot of the different initiatives that we had started last year, initiatives to really add to components to our value chain, to integrate more of this energy business, to hang onto more of the economic rent in and to make all of our future reserves more valuable. We're still pushing on all those fronts. So look for news on that in the coming quarters as well.But I think that probably does it for us. So thanks very much for everybody for listening in. We'll be back to you to report second quarter in August. And hopefully, we've got some exciting news with respect to our Montney well and with our ongoing Cardium program to talk about. Thanks, Chris.

[Operator]

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program. You may all disconnect, and everyone have a wonderful day.