Good day, ladies and gentlemen. Welcome to Peyto's Q1 2019 Financial Results Conference Call. At this time, all participants are in a listen-only mode. Later, we'll conduct a question-and-answer session. Instructions will follow at that time. If anyone should require operator assistance, please press star and the 0 key on your touch-tone telephone. As a reminder, this call may be recorded. I would now like to introduce yours for today's conference, Darren Gee, President and CEO. Please go ahead.
All right. Thanks, Chris. 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 of Production is here. Tim Louie, our VP of Land is also here. 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. We also had some very bitter cold to deal with in February and a lot of snow as usual. Our team did a great job. On behalf of all Peyto shareholders, I'd just like to say thank you to the entire Peyto team for that effort. 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. I'm sure everybody has lots of calls to listen to this morning.
We do have some email questions that came in overnight. We'll try and 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 and new facilities. Of course, buying some new land. We acquired new Cardium lands really cheap and continue to do so. We've been doing that for a while now. That's really allowing us to backfill 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. 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. We have a plan that we'll put into action here after breakup to rectify that pressure drop. We've 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. 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, surprised everybody, Day prices were a lot stronger than predicted, and 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, We need to match those two up, which is why we did it that way. Typically, the monthly does beat the daily, 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. That really helped with March prices. We're in the shoulder season, of course, Prices are quite sensitive to the outages on TCPL and the weather on any given week. One day they're CAD 0.20 and the next day they're CAD 2.50. 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 on NOVA, the price is north of CAD 2, and when we're back up at about 12 Bcf a day, it drops to CAD 0.50.
Again, I think that shows us that we're very close to balance in this AECO market, about maybe half a Bcf a day out of balance, which is not very far off. It also kind of suggests that just a little discipline from the producers, I think we could have a very decent AECO market for everyone, including the Alberta Crown. 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 liquid 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 blow out. 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 when the refineries went down, and the draw for butane dropped. That's putting some pretty heavy pressure on the price right now, that's likely all that glut will clear here over the next six 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, they're going to be exporting a significant amount of Canadian propane off the West Coast, 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 CAD 20 a BOE FOB Edmonton, I think we need about CAD 25 a barrel to generate a 20% rate of return on our deep cut. We're almost there, we just want to see that propane price strengthen a bit look like on the forward curve it's going to stay there. We can make our call on the Swanson deep cut. Financial results for the quarter were good.
Cash costs were up a bit, that's really typical for the winter quarters when we use more methanol and chemical, and this Q1, as was mentioned in the release, was particularly cold. 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, that chemical consumption obviously drops off. We paid down another CAD 30 million or so in debt this quarter. Obviously, our total debt went up, net debt was down. That makes over CAD 150 million of debt repayment since the start of 2018, when we cut our dividend and reduced our capital program, all of that was a longer-term strategy, a three-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. We thought we'd put all this extra free cash flow on the debt strengthen our balance sheet in the short term. G&A on the quarter was up a little bit. Our G&A is always really low anyway, we did make some one-time investments supporting some advocacy groups like CAPP membership, EPAC membership, Canada Action, 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 got four Cardium completions to catch up on. We've got our Montney well to get completed. That's going to be exciting. 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.
The plan is to have a couple to three 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. That's just a quick summary of the quarter. Chris, if we could maybe throw the call open for questions from the listeners.
Thank you. Ladies and gentlemen, if you have a question at this time, please press the star and the one key on your touch-tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. To prevent any background noise, we ask that you please place your line on mute once your question has been stated. Our first question comes from the line of Adam Gill with Eight Capital. Your line is now open.
Good morning, gentlemen. two questions for 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 would have panned out in Q1, should that have been running for the full quarter? The second question was just on operating cost. 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. Thank you.
Okay. Thanks, Adam. Good questions. May start with the deep cut question first. We had the deep cut shut in actually for January and February, right, Todd?
February and March.
Sorry, February and March, because we had strong gas prices in February, March, and the butane and propane prices were actually quite weak. 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 cost to strip them out into liquid form. We shut off our deep cut, and we were basically increasing our gas volume then. 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've been. We could've had higher liquids in the first quarter than we even did. 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. Our liquids production has stepped up again, and our gas production's down a little bit. Our operating costs are reflective of that deep cut running, but I don't think, Todd, maybe you can chime in here. It doesn't 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.
Yeah, I think we've got things down now where we have to take a portion of the plant down, the old plant down for about 3 hours to shut off and then turn the deep cut back on. From a cost perspective, it's just a pipe and crew, so it's not really impactful at all. It can be done quickly.
Adam, your second question on 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. The way you prevent the freeze-offs is you use a lot of methanol, obviously, to grab that water vapor and prevent any hydrates from forming. You tend to use a bunch more methanol. It was a tough quarter for methanol. Todd, can you give us some color on the methanol pricing?
Yeah. We've seen methanol pricing climb for probably the last year and a half. We locked in some pricing kind of late summer last year at a low for the year. 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 warmer weather, and we've been able to bring down that consumption significantly. By the end of June, we're typically 50% of what we see in January or February on consumption.
The-
Sorry.
The government-
Just back to the deep cut, do you guys have an idea where the yield was for April?
The deep cut, in full operation, I think pulls somewhere between 750 barrels a day, more C3, C4 for us.
Okay.
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. That's kind of the volume that we'd be looking at.
Okay, thanks for that.
It applies to just ours too. The last comment I'd make, Adam, on the first quarter op costs would be that about a third of our operating cost is actually government charges like AER fees and municipal taxes, and that doesn't even count the fee we pay to the municipalities to move rigs around. Road use factors in there a bit. I think we're hopeful that with this new UCP government, that we can start to see some of this regulatory burden cost 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 the rather pointed message within that the municipal taxes were what really killed that company. We're a very low-cost operator. It's a little bit amplified, those charges on our operating costs. For most guys, it's not 30% of their operating cost. It's a lot smaller. It's still a meaningful amount of cost structure. 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.
Great. Thanks for those details, guys.
Yeah, you bet.
Thank you. Our next question comes from the line of Thomas Matthews with AltaCorp Capital. Your line is now open.
Hey, guys. Just wanted to follow up there. Essentially with the higher liquids yields, irrespective of whether you're not forecasting any sort of increase to unitized op costs in order to process those liquids going forward?
Yeah, that's right. 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 cost of the deep cut. I don't think the deep cut op costs are that material that they're going to shift our corporate cost that much. Remember, this is just about three-quarters of one plant out of our nine gas plants. It's not like it's the entire company that's moving from a deep cut operation or our entire production base that goes from a deep cut operation to a non-deep cut operation.
Right. I guess just recovering more condensate and pentanes, there's no additional processing that goes along with that would increase the unit cost with the decline in gas production along with that?
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 it that way, get 95% or more of the C5 plus out. We have to take it virtually all out. Otherwise, we can't make hydrocarbon dew point spec-
Got it
on the. It's really an optionality. Yeah, it's just option on the butane.
Sorry, Todd.
Okay. Yeah.
Also got our liquid pipelines that are connected, so there's no incremental cost 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.
Right
It's not a material increase.
Yeah. It's a good point. We're pipe connected to Plains with all our LPG or the majority of our LPG and to Pembina with the majority of the condensate. 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.
Right. Okay. No, that's very helpful. Darren, I was just wondering if you could just touch on butane prices. I know that, in our discussions, you said later in the year you expect the glut to clear. 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. Just wondering if you could just give us some color on what you expect for the next two quarters until the glut clears. Are you back to spot pricing, or are you still going to receive that premium?
Yeah. Butane prices are not good, really. Historically, butane, I think has traded at close to 50% of oil price. What we saw in the fall and the impact that had to the entire butane market, is percolating through here into Q1. 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's only, I think, about a dozen producers that actually take their butane and market it themselves. Most producers just dump their LPG into the frack plants and 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. I think hopefully we've done a better than average job than finding markets for that butane and getting a little bit better pricing on it. That premium to what the average realized price will 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 significant amount of butane production in the basin is typically locked in for a year worth of sort of takeaway. The refiners buy it, I guess, mostly for blending in to make gasoline. They do all their deals in March or April. Everybody's tied up with them for a 12-month period until the next year.
The spot market is just a sort of little bit of volume that's not tied up. That trades kind of all over the place a little bit. I would say that we've obviously factored that into our budgets going forward, that the butane price is going to be weaker for the industry. You're going to see that across the board through the summer. Into the fall, hopefully, we're back to a little more balanced market.
Great. That is helpful. Thank you so much.
Very well.
As a reminder, if you have a question, please press star on the one key on your touchtone telephone. Our next question comes from the line of Faye Lee with Adlam Brown. Your line is now open.
Oh, hi, Darren. It is Faye here.
Hi.
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 going on a go-forward basis? Is there a point where it just shows up as cash, or do you continue to reduce your accounts payable or, and accrued liabilities?
Yeah. 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. I'm going to force Kathy to explain it maybe if she can or as best as she can.
We really have two components to our long-term debt, which is the unsecured notes, which of course, are a fixed amount. There's no repayment of it. We also have our credit facility, which is like a line of credit, we draw it on using bankers' acceptances, and we repay the bankers' acceptances. Typically, we do between one and three months bankers' acceptances. When you look at drawn debt, which did go up from the end of the year, it's really about timing of cash flow. You'll also notice our bank overdrafts had gone down, and our payables had gone down. It's just timing of payments. In Q1, our CapEx was much less, our cash requirements are less. Now we've actually been repaying some of that drawn debt since the end of March.
This drawn debt is just a function of timing of cash flows, where net debt is looking at where's our actual trend going. Looking at the receivables and the payables, as 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. 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 and our non-cash working capital. 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. That's really where there can be a bit of a divergence between net debt and drawn debt.
Net debt is the most relevant indicator, we think, because that's really showing where our financial assets are going.
No, I said Sorry. Go ahead.
Sorry. I was just going to chime in, Faye, that, yeah, absolutely. Net debt is the one you want to watch. It effectively measures what our debt should be at March 31-
Right. 30th.
once all the paper comes in. 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.
And I would-
once all that is cleared.
There are some times, like at the end of the year, we have certain payments for compensation that are one-time things that have to be funded through cash, but the expense is recognized over time. Since March 31, we've had a change in that because the payables are already paid, and they're not being replaced at the same rate. We've actually been repaying our drawn debt. Like I said, a lot of that CAD 500 million is on bankers' acceptances, which are very short-term in nature, and so we can draw and repay in a rapid timeframe.
Okay. Yeah, no, I understand the difference between the debt and the net debt. I just was wondering.
Yeah
Whether it's going to come either as an increase in cash or, as we saw this quarter, a reduction in payables or a reduction in the actual debt levels. I guess, and more of the question.
Well.
Is whether payables have stabilized or not. It sounds like they did.
It varies.
Yeah.
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. Q2 also has far less capital. We'll start seeing an actual increase in cash balance or decrease in drawn debt and bank overdraft.
Okay. All right. That helps. Thanks.
[Ava]?
We are expecting to repay debt this year, though.
Oh, yeah.
Thank you. We do have a follow-up from the line of Thomas Matthews with AltaCorp Capital. Your line is now open.
Sorry, everyone. Just one last final question. Just on your Cardium kind of completion evolution here, you're on your 2nd-gen horizontals. Just looking at the charts you have in your presentation, have you guys reached the best practice, do you think, or is there further evolution? Is there going to be more cost reduction as you go or potentially higher liquid 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.
Yeah. 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. JP can chime in here with some more color on the Cardium. 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 down even more. I'd say that, yeah, we're looking to make the results that we're currently getting even better. JP, maybe you can add some more color.
Recall, 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. We did that across several areas, right? We were, in a sense, testing out these different attributes or features, of which now we've had some time, we've had some production history, we can go back. We looked at these things. We looked at them late last year and early into this year and said, "Okay, these are the features that make sense to us that really influence productivity and ultimately value creation." We've always looked at things from a value perspective, not necessarily just what gives us 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 to the specifics of what it is and what our formula is, I'd rather not. As we look forward, Q1 program is far better than last year's in aggregate so far. Just looking at numbers, like last year's program on our reserves price deck in aggregate was around 26% rate of return, whereas when I compare that on the same price deck to our 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 just brought on with even better results. We'll see them play out here, which should improve on that. I think we're seeing a step change.
Like Darren says, we'll continue to innovate costs. We've just had these conversations. We're going to continue to have these conversations about how can-
lever on different parts of our cost structure to see if we can pull those back and still get the same sort of outcomes we're getting lately. Yes, by all means, this is a continuation of we're excited about what's happening.
Thomas, I'd caveat that this is somewhat of a reduced program for Peyto. The capital program is not very big, 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 two well pads as opposed to four well pads, well, he can't leverage the pad drilling efficiencies as much. I would say this restrictive program actually has some opportunity for improvement just by scaling it up. There's some definite cost advantages to a larger program. 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. We're excited about the repeatability of it. 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 fine-tuned on the Cardium. So far, the rates of return are looking far superior, and it's looking awesome.
Great. Thank you so much.
Yeah, you bet.
Thank you. Our next question comes from the line of Aaron Swanson with TPH. Your line is now open.
Yeah, thanks. I just had a quick question on the Montney. I know you guys are thinking it may be sour. How would you guys establish if the gas is sour, what are the options for completing and testing the well if it is?
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. If we can use all of our sweet infrastructure, it's a huge advantage for us timing-wise and cost-wise. 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 two to seven to 8,000 parts sour. It gets more sour the further north away from our land block you go. 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, 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 plants. 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. Obviously, we could build our own sour plant. We have that sort of optionality.
That's a more significant infrastructure investment, obviously, and we would want to have confidence in the play. 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, we've got a bit of a decision to make on where we want to get it processed. If it's sweet, it's an easy decision. We slam it right into our Wildhay infrastructure, and we test drive that well. The obviously best 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 ask you, 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 result? Are you testing something different in the Montney, or what are we looking at?
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 mile and a half long. As you said, 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 production are producing condensate levels. The CGR, condensate to gas ratio, is pretty stable at around 50 million or 50 barrels per million. Those wells to the north seem to be producing about 3 million a day currently, a couple of them are still increasing, and the condensate levels are pretty stable. We're happy to see that.
We can improve on that. That would be tremendous. 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. Big resource, more than 4 Bcm per well. 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, with a lot more reserves per well. It would be a really good fit for us if things pan out nicely.
Yeah, you bet.
Yeah, that's perfect. Thanks.
Yep.
Thank you. Our last question comes from the line of Garrett McMullan with One Nation Engineering. Your line is now open.
Hi. I'm just wondering, with your free cash flow, have you ever thought of buying back your stock?
Yeah, Garrett, we actually do have an NCIB in place. We have that option. I guess by definition, there's sort of three 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 dividends. We do that, too. One of them is to buy back stock. We can weigh all three 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 year or so.
The cost of that debt was starting to go up a little bit. We thought, maybe we better start to bring that down with the free cash flow. 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. There's impacts and ramifications to that, too. Then there's the buyback. We do have an active NCIB in place that gives us that optionality. Should the board decide that that's one of the paths we'd like to pursue or in combination with the debt repayments and the dividends, it's definitely something that we can entertain.
Okay, perfect. Thank you. You bet.
Thank you. 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.
Well, great. Thanks, Chris. Did we get everything we wanted to talk about today, guys?
Yes.
One of the only questions that came in overnight. This is kind of an open-ended question. We could probably talk about it for a long time. 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?
Well, sure.
That's a tough question.
I might need my own forward-looking statement.
Yeah
It's early days. We've only had our new government for just over a week now. The continuation of the public statement that Alberta's open for business, naming an associate minister of red tape reduction. Those are big messages that I think from our perspective, are very welcome. 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. 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 the AER really to identify large regulatory impediments. 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.
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 long, sorry. 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. If I go back to the ERCB days, we often saw the similar scope approval take 6 weeks.
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 the 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. 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. 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 three-quarters of a million to about a million and a half 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 CAD 7 million.
Ouch.
That's significant, 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, regulator cost reductions that coincide with timeline approvals are just one of those. 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.
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. We want to take advantage of that. Obviously, seasonal gas prices are still extremely volatile. 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.
We didn't have a chance quite to talk about our participation in an LNG consortium. LNG Canada's moving ahead, which is nice to see. Peyto's obviously been actively involved in discussions through that consortium on lots of different LNG options. We are still moving forward a lot of the different initiatives that we had started last year. Initiatives to really add components to our value chain to integrate more of this energy business, to hang on to more of the economic rent, to make all of our future reserves more valuable. We're still pushing on all those fronts. Look for news on that in the coming quarters as well. I think that probably does it for us. Thanks very much for everybody for listening in.
We'll be back to you to report second quarter in August, hopefully we've got some exciting news with respect to our Montney well and with our ongoing Cardium program to talk about.
Thanks, Chris.
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.