Peyto Exploration & Development Corp

TSX:PEY

Earnings Call Transcript 2019-Q3

[Operator]

Ladies and gentlemen, thank you for standing by, and welcome to the Peyto Q3 2019 Financial Results Conference Call. [Operator Instructions] I would now like to hand the conference over to your speaker today, Darren Gee, President and CEO. Thank you. Please go ahead, sir.

[Darren Gee, President, CEO & Director]

All right. Well, thanks, Justin, and good morning, everyone. Thanks for tuning in to Peyto's Third Quarter 2019 Results Conference Call. Before we get started today, I'd 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 the company's news release issued yesterday. In the room with me today, we've got virtually the entire Peyto management team, Kathy Turgeon, our Chief Financial Officer. We've got JP Lachance, our VP Engineering and Chief Operating Officer; Dave Thomas, VP, Exploration, is here; Todd Burdick, VP, Production; Lee Curran, our VP of Drilling and Completions; and Tim Louie, our VP of Land. The only person missing this morning is both our newest and oldest member of the Peyto management team and that's Scott Robinson. So Scott tried out retirement a bit over the last year, decided he liked working at Peyto better. So we're happy to have him back on the team. But he's out today. Anyway, before I get started with my comments today about our results, I want to again recognize the efforts of the entire Peyto team, including all of our field personnel. This summer, our field personnel had to deal with so much wetter conditions than normal as well as commodity prices that were bouncing all over the place and us wanting to react to them. Their ability to be nimble and react to these constantly changing conditions is really what allows Peyto to be nimble and in extracting the maximum value at the minimum cost from our resources. So on behalf of all Peyto shareholders, I'd just like to throw a big shout out and thank you to the entire Peyto team for that effort during the quarter. 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'll try and keep this very brief. I understand there's a bunch of conference calls going on this morning, so we'll try and keep this concise. As we mentioned in the release, we spent the quarter continuing to execute on our reduced capital program, focused exclusively on our most liquids-rich Cardium play. That play continues to achieve better well productivities at lower and lower costs. So really, we're just getting better and better at it. Since the start of 2018, we drilled around 80-some Cardium wells with this new well design. I think there were 44 in 2018 and 40-plus wells here in 2019. When we started, wells were costing around $3.25 million for drilling and completions. Now we're down to around $2.25 million, so we've saved $1 million off. And as far as results go, the average of the first 30 days of production or that IP30 for the first 10 wells in 2018 was around 430 Boes a day. The average of the last 10 in 2019 that I just looked at was 825 Boes a day. So we've almost doubled the IP30 number. Of course, a 30-day IP doesn't mean that much for a well that's expected to produce for 50 or 60 years, but it is a good start and does indicate that we're doing better. We'll just have to see how all these numbers play out as far as increased reserve recovery goes. And then more importantly, when you combine that with the reduced costs and the current commodity prices, what does that mean for returns? The last post-mortem returns analysis we did with the first half of this year suggests we're definitely getting better returns now on our Cardium wells than we did even in 2018. Spot commodity prices in the quarter were not very good. AECO gas was less than $1. NYMEX prices were also really soft at around $2.30. Propane and butane prices were weak. And after you deducted the fixed fractionation and transportation charges, and actually, we have much better pipe and frac fees than most in the industry, there wasn't much left for NGLs. We got just $2.79 a barrel. Really, the only product in the quarter that made much money was condensate and pentanes. We averaged about $68 a barrel for that product, which was still a discount from the light oil price of $75 a barrel. Thankfully, we were very well hedged on our gas sales. We did a good job of keeping cash costs down, too. So that allowed us to still deliver a cash netback of around $10 a Boe. And obviously, that allowed us to continue with our streak of quarterly earnings, which is up to, I think, 59 consecutive quarters now. I haven't seen too many gas producers this quarter, who have been able to post earnings, so that is a testament to our low-cost and high-margin business. Perhaps one of the most material things that happened in the quarter was the achieved negotiation with TC Energy, TransCanada, the Alberta government and the industry altogether got together on a new supply management system for next summer. Peyto was very involved in that effort to get this new temporary service protocol, as they call it, in place. And now we've started to see the effect of it. It's been in place for the last 25 days of October. And during that period, AECO traded much better than Dawn or NYMEX, for that matter. So the net of transportation. So the net effect is a very well-connected Alberta gas market. That's what we were striving for with this protocol. And so to have it in place, ready to go for next summer to help keep the market connected is really important. It significantly improved the forward curve for AECO, particularly in light of this winter. Of course, very low storage levels were also at play, and those are going to ensure some very strong AECO prices for this winter. And then the temporary service protocol for next summer, we'll ensure we have access to storage over the summer and should drive stronger summer prices. We think next summer's AECO actually still had some room to move up as this starts to get absorbed by the market. Yesterday, TransCanada announced preliminary maintenance periods for the summer, when obviously this TSP would kick in. So that's important news for the market, and we'll see how AECO responds to that. More broadly, we even see the storage situation in Alberta having a positive effect on NYMEX. Really, if AECO storage was at normal levels, and instead, the U.S. storage was 200 Bcf less today, we think NYMEX would be much higher than it is today. So it's going to be interesting to see how this winter plays out with less gas available to be exported from Western Canada into the U.S. market because of the storage deficit. So it will be interesting to see how NYMEX responds to the shortage of gas supply in Alberta. All of these things translate into much better forward-looking prices for natural gas, which, again, means that our economics are looking much better for all of our suite of gas locations, and it's time to put more capital to work. So we sparked up 2 more drilling rigs to get after it. I think we've even got a fifth rig in the wings if we need it. These 2 rigs are likely going to drill mostly Spirit River locations, give us a little more exposure to this unhedged AECO spot price through the winter, and then we'll see how things are shaping up for next summer. We haven't quite finalized our 2020 capital budget, obviously, reacting most recently to the commodity prices here, and we're going to be doing that over the next few weeks. We'll release that after we've got Board approval and then share those details of our plan for 2020 going forward. As far as the balance sheet goes, really by growing production and getting a better price for it, we should see significant improvement in our funds from operations from what we were looking at before. And since we're doing all of this with cash flow and we're not adding any debt, we'll see a better ratio of debt to cash flow going forward. So that's a stronger balance sheet, generally speaking, and looks positive into the future. So all in all, I think Q3 was a tough quarter, but we're through it and are already looking forward to much better days ahead as we head into the winter. So we're pretty positive about the outlook here going forward, particularly for Peyto and of course, for the natural gas industry in Western Canada. So maybe that's enough about the quarter. Justin, maybe we could throw it open to questions from our listeners?

[Operator]

[Operator Instructions] And our first question is going to come from Adam Gill from Eight Capital.

[Adam Gill, Principal]

A 2-part question here. With the second -- with the 2 additional rigs added in Q4, targeting Spirit River, how many wells do you expect to bring on stream in Q4 in both the Cardium and Spirit River plays? And where do you expect Q4 CapEx to shake out? And the second part of the question is, based on the contemplated $250 million to $300 million in spending next year, how many Cardium and Spirit River wells are envisioned in that plan?

[Darren Gee, President, CEO & Director]

Okay. Adam, thanks for those questions. So maybe we'll start with the first one and just look at Q4 here with these extra rigs. What was the well count we anticipated there, JP?

[Jean-Paul H. Lachance]

So our total well count for the year, we expect, was about 53 wells. We still have another -- if you count this last quarter, about another 9 wells to drill. We are looking right now at accelerating some of that into -- from even 2020 into 2019. So depending if we do that and drill through Christmas, that might change a little bit, but capital spend for the quarter is expected to be about to round us up closer to the $200 million mark that we have in our guidance.

[Darren Gee, President, CEO & Director]

Okay. Perfect. And then the $250 million to $300 million next year. I mean we haven't got an official approved budget by the Board yet, but directionally, what's the sort of breakdown there?

[Jean-Paul H. Lachance]

So the breakdown there, we've -- with that strip price coming up. It's a good question. In our leaner gas, and our Spirit River opportunities start to hunt as we -- and that's what we're going to target a lot more with these 2 rigs, a lot more of the Spirit River program. So perhaps as much as 30% to 40% of our planned well count, assuming we continue to get the prices that we expect and the results. So 30% to 40% of our program next year will be geared towards that. That plan for next year for total wells would be somewhere in the range of about 80 gross wells. So depending on working interest and whatnot. So 30% to 40% of that would be in the Spirit River, I'd expect.

[Darren Gee, President, CEO & Director]

Then the rest in the Cardium.

[Jean-Paul H. Lachance]

And the rest in the Cardium, yes.

[Darren Gee, President, CEO & Director]

Okay. Perfect. Does that answer your question, Adam?

[Adam Gill, Principal]

Yes. Thank you.

[Operator]

[Operator Instructions] I am showing no further questions. I would now like to turn the call back over to Darren Gee, President and CEO.

[Darren Gee, President, CEO & Director]

Okay. Thanks, Justin. We had a bunch of questions come in over the -- overnight, e-mail questions from shareholders. So I just want to run through and maybe address some of them here this morning. One of them was from [ Jordan ] here. He's asking, again, about capital allocation between Cardium and Spirit River. JP, you addressed that already. He was wondering, though, what the relative economics look like between those plays. Can you give us a sense of maybe how the IRRs are stacking up with the better commodity prices?

[Jean-Paul H. Lachance]

Sure. So when we look at the Cardium program, for example, when we look at our first half program, when we look back to what we've achieved, those economics, especially with this -- the higher NGL yield than we expected and the cheaper drilling cost, drilling and completion costs, the look-backs that we've done on our first half program show that a vast majority of those wells give us returns over 40%, and that's on a $2 gas price. And a $55 WTI. So now the Spirit River would stack up against that. We're certainly targeting wells that are going to have a little bit more liquids and higher gas rates. So those wells would be comparable. And that's why they're going to be competing for that capital allocation for next year.

[Darren Gee, President, CEO & Director]

Okay. Perfect. Justin (sic) [ Jordan ] was also asking, there's a little bit of information leaking out through the public domain about our Montney well. But Todd, maybe, I don't know, can you give us a little more update on the Montney? I don't know how much you want to talk about it.

[Todd Burdick, Vice President of Production]

Yes. Sure. I can talk a bit about it. So we were able to test the well intermittently through the summer and fall. We, of course, did so for a shorter test period, but we had to deal with wet weather and that hampered some water-hauling efforts. And we had a few operational issues that came about due to limitations of our temporary surface facilities as well line pressure impacts due to our Cardium program affected the ability for the well to flow a little bit. But the intent of the test was to flow back as much frac water as possible, get the well cleaned up, confirm the H2S concentration during the flare period and understand the flow characteristics of the well. So through that process, we did determine that the H2S is low enough that we can sweeten it on site, which is great, which has allowed us to produce to our Wildhay gas plant. In fact, through the majority of the test period, we were able to sell gas rather than flare it. We were also able to determine that in order to sufficiently clean up the well, we need to employ a form of gas lift. So we took all that information. We were confident that we had a somewhat steady-state condition so that we could start the engineering work on permanent facilities. So that process is finished, and we're currently waiting on delivery on some of the equipment. We should have the well flowing intermittently again in a few weeks and then have that fit-for-purpose compressor installed and running later in December.

[Darren Gee, President, CEO & Director]

And this is all just to clean up the frac water. What was the volume that we ended up pumping?

[Jean-Paul H. Lachance]

25,000.

[Todd Burdick, Vice President of Production]

25,000.

[Darren Gee, President, CEO & Director]

25,000 cubic meters?

[Todd Burdick, Vice President of Production]

Yes. We're about 31% recovered.

[Darren Gee, President, CEO & Director]

30% recovery to date.

[Todd Burdick, Vice President of Production]

39% recovered.

[Darren Gee, President, CEO & Director]

So we've gotten a lot more to come still?

[Todd Burdick, Vice President of Production]

Still making a lot of water, makes it difficult to the well as well.

[Darren Gee, President, CEO & Director]

Okay. Perfect. Thank you for that. We had a question overnight from an investor, [ Ing ] was asking and maybe I'll direct this to you, Kathy, about debt covenants. Cash flows were obviously falling as our production was dropping off. And as we were going through these low price environments over the last couple of years, now we've got weakness in the U.S. gas price. And that looks like it could persist for a bit. Can we comment on the impact that this might have on our debt covenants and satisfying those debt covenants and maybe further comment on generally Canadian gas producers who are dealing with this difficulty?

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

Sure, Darren. Obviously, lower commodity prices does impact our cash flows and EBITDAs, which has an impact on our debt covenants. However, with the recent strengthening of the commodity prices and higher production going forward, we expect that cash flows will be bolstered, and we'll have a positive impact on these debt covenants. But we do regularly do financial models and forecasts, and we model many scenarios. We stress test these models for a variety of factors, including lower commodity prices. And then we allow -- that allows us to put plans in place to address some of those factors and to develop mitigation strategies whether that's through risk management contracts, financial derivatives, hedging contracts, et cetera. And we also continue to adjust our plan to address any issues and opportunities as they occur. We've always been able to do that at Peyto, and we continue to do that going forward. Another big factor, I think, is that we have extremely good relationships with our lenders, and we have a lot of open communication with them. They always understood our business model and been extremely supportive of that model. And going forward, we still continue to rely on the fact that we're a low-cost producer. And that we've always been strong in risk management.

[Darren Gee, President, CEO & Director]

Great. Actually, [ Ing ] asks a second question there regarding some of that risk management and the marketing strategy. He notes there's been a departure from the past practice of putting hedges on regularly and mechanically without trying to time the market, but has that changed. And also with respect to the U.S. gas prices and the weakness down there, we've got some AECO Henry Hub bases deals that aren't looking nearly as attractive as they were. And so if this situation between AECO getting stronger and Henry Hub getting weaker persists, can we reverse out of some of those deals? The first observation is correct. When gas prices started to fall a year or so ago, and they really got particularly weak, we did stop our mechanical hedging practice. We have sort of 2 gas marketing strategies. One is to diversify our markets, have some exposure to AECO, some exposure to U.S. markets, trying to even get some direct connection. We'd outlined that a couple of years ago as a strategy that we were going to pursue, but then we would expect to be fixing prices at those various markets in order to get security of price going forward, to be able to plan our capital programs, pay our dividends and whatnot. And we had to depart from that because the pricing we saw at some of those markets, particularly the AECO market, got so weak that we would be locking in prices that didn't really work with our business. So we actually stopped hedging. We've become more exposed going forward to the spot prices. And the fact that the seasonal pricing has become so volatile meant that we had to have protections. Going forward, we really need to have protections in place more in the summer than we do in the winter. So we've taken on a bit of a modified strategy, where we're going to be hedging more of our future gas in the summer and less in the winter to be able to take advantage of some of the volatility on the winter price on the high side and protect against some of the volatility on the gas price on the low side during the summer. So it is a bit of an evolving marketing strategy, for sure, especially as we diversify to different markets. As pointed out, we do have a bunch of AECO/Henry Hub bases in place, which is like a synthetic transportation to the Henry Hub. It allows us to fix Henry Hub prices, which we did throughout this past summer successfully, but they are relatively expensive. And as Henry Hub drops and as AECO strengthens, that doesn't look like it's a good opportunity to be heading south with the gas. Now that being said, markets are always changing and we're trying to forecast and predict which markets are going to be the best. That's kind of hard to do in the short term. Bases deals actually allow us to be very flexible that way. The only physical commitment with the bases is to get our gas onto the Nova pipe and deliver it at net. So beyond that, it's really more of a financial effect. We could, in fact, forgo the Henry Hub sales and sell the gas at net and just eke the cost of the bases if we wanted to. So that's kind of like unwinding it. We don't -- if AECO gets that strong, we'd rather just sell it there. We don't have to actually sell it at the Henry Hub. Alternatively, if Henry Hub strengthens, we can start to fix the price at Henry Hub, along with that bases discount, that gives us a fixed price sort of an AECO equivalent price, but gets us a diversified market. So we get to choose which market really to sell it into with those bases deals. So I think they're a flexible thing. Obviously, we've put them in place when the cost to get to the Henry Hub was a lot higher -- when the prices at Henry Hub was a lot higher. So those bases look expensive today relative to the current bases, but so would they for everybody else that had the same strategy. So that's a good question regarding our marketing strategy, and that has definitely changed over time. There was another question that came in overnight from [ Dan ]. He's asking about what this fourth quarter looks like with a meaningful increase in capital. How is production going to ramp up? We are obviously drilling more today. And we started up these 2 extra rigs here in the fourth quarter. Of course, we want to take advantage of pad drilling. And so we've got basically all our rigs working off of multi-well pad sites. So that takes it a little longer than -- to get wells drilled and completed, but you get the added savings, obviously, of pad drilling. A lot of the production addition from this fourth quarter activity shows up in December after we've gotten all the fracs on. I think, JP, you counted up. How many wells should we bring on here by the end of the year?

[Jean-Paul H. Lachance]

Approximately 14 net.

[Darren Gee, President, CEO & Director]

Yes, 14 net wells. So a lot of this production hits us in December, which is great because that's the winter season when we want it. And like you mentioned there, it looks like it probably pushes us up to the high end of our capital guidance for 2019. And perhaps even if we drill right through the Christmas break, we might pop through that upper end of the guidance a little bit. But there's nothing magical about December 31. When it's winter, it's winter, and so we're going to get after drilling right through and bringing on new production into that stronger winter price. So hopefully, that answers [ Dan's ] question. There's a couple of questions that came in overnight from 2 different guys. [ Michael ] had one and another one here from [ Mickey ], and both related to this NGTL temporary service protocol that's in place, and how does that affect things. And could we explain that a little more. Why did it have such an immediate impact on prices? And from a big-picture perspective, what do we expect the basin differentials to do going forward? And why did the regulatory change lead to such a big reversal? The problem with the old sort of priorities that TransCanada had was that they were putting priority on firm receipt and firm delivery service on their Nova system instead of trying to maximize the market that we had available to us. And storage is really a market. And so when they were denying access to storage by not offering any interruptible delivery service, that's what storage relies on, we really took storage out of the game. And storage is a market for Western Canadian gas, particularly in the summer, and we need that market to balance off the seasonal demand variability. So by changing this protocol, we immediately had access to storage, again, the interruptible delivery service in the Eastgate area, where the storage reservoirs exist, went from 0 to 100%. And so storage reservoirs were able to nominate for volume off the system. This was even during October, and so they were buying gas at higher price, even expecting, of course, that this winter, they were going to be able to pull it out and sell it at even higher prices. And with that storage mechanism functioning properly, obviously, it tightened up the differential between the AECO market and the other North American markets. In fact, there was such a huge demand for gas because our storage is so empty that AECO was trading at a premium, as I mentioned. So that's why the impact is so, I mean, material and immediate is because it immediately brings more market -- more demand back to the Alberta market and a large amount of demand, in fact. Storage can accept up to 1 Bcf a day of gas or maybe even more into their reservoirs when there's demand, and they can deliver on to the system the reverse. They can deliver about 1 Bcf or 1.5 Bcf a day. So relative to the 12 Bcf a day Nova system that's very material to the market, it's a significant amount. No different than saying we take 1,000 megawatts power and add it to the Alberta power market, what would it do to prices? Or take it away from the Alberta power market, what would it do to prices? Similar type of thing. So definitely, this is a very important function. It proved to us, really, that storage is a very important part of the Alberta market, and we need it. We need to have storage with the seasonality and the weather and with the demand. And so we want to make sure that we retain that particular part of the market going forward. That's what this temporary service protocol does, particularly for 2020 summer. And then beyond that, I mean, TransCanada is expected to have added significantly to the capacity of their Nova system such that storage will still be allowed to function, but we'll also be able to move all the volume we want to the borders and to the markets within Alberta. And there isn't going to be nearly the same kind of restriction. The industry, quite frankly, is going to have to start growing its supply because TransCanada is adding close to 3 Bcf of additional access to market through their Nova system expansion to the end of '21 and we're not really planning as an industry to grow by 3 Bcf a day, yet that's what the pipe capacity is going to be. So there's going to be an interesting dynamic here coming up. I think pricing is going to have to be the mechanism to drive additional production growth to fill that pipe. And so as we see the AECO price continue to climb, that's going to be the thing that starts to stimulate producers to go out and drill. I guess Peyto is a bit on the front end of that behavior in that activity, but TransCanada is kind of banking with $9 billion of capital investment on the fact that industry is going to grow their supply and be able to access these new markets with this additional pipe. So we've got a big job in front of us as an industry. We've got to get after it, and we're looking forward to that this winter. We've been sort of conservatively spending over the last couple of years, really paying down debt and waiting for this egress to come, waiting for this market connectivity to come. Now we're seeing it. And so as a gas producer in Western Canada, we're pretty excited about getting back to work in a more fulsome way the way we have in the past and delivering a lot more return on a larger capital program to our shareholders going forward. So for as much as it's been a very big struggle over the last couple of years to be a Canadian gas producer, we're seeing a lot of bright days ahead of us, and it looks very exciting to move forward into this new connected market. We're excited at Peyto and we're reengaged, and it's nice to be playing some offense again as opposed to just playing defense. And arguably, since we have the goalie back in the net, now Scott Robinson has always been a goalie in his hockey days, so nice to have him back in the net. We can go ahead and be a little more aggressive on the offensive side. So that's a pretty good wrap up for the quarter. I think that answers everybody's questions. Thanks to those for listening in and participating in the conference call today. We're excited to get going here in this fourth quarter, and we'll be back to you with results in the early part of the year and through the winter, and there should be some exciting times coming up. So Justin, I think that's the end of it. We'll turn it back to you.

[Operator]

Thank you, sir. Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.