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Good day, and thank you for standing by. Welcome to the Peyto's Q1 2021 Financial Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions] I would now like to hand the conference over to your speaker today, Darren Gee, President and CEO. Please go ahead.
Well, thank you, Mary. Sorry for the little technical mix up here this morning, that we've got a delayed start by a minute or 2. But good morning, ladies and gentlemen, and thanks to everybody for tuning in to Peyto's First Quarter 2021 results conference call. Before we get into it 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 set forth in the company's news release issued yesterday. In the room with me today, we've got most of the Peyto management team JP Lachance, our VP Engineering and Chief Operating Officer is here; Kathy Turgeon, our Chief Financial Officer is here. Dave Thomas, our VP Exploration is here; Todd Burdick, he's our VP of Production, he's here; Lee Curran, our VP of Drilling and Completions; and Derick Czember, our VP of Land, is here. The only thing I'm missing today is Scott Robinson, our VP of Business Development. I think the sign on his door says he's working remotely today. But feel free to fire your questions away at anybody from the Peyto management team. We're all here to answer them. Of course, all 7 of us are physically distanced in the boardroom and taking all the safety precautions with respect to COVID-19 that we need to take. But I can say that we're all somewhat relieved since I think everyone in the room, but maybe Todd, has already had their first vaccination shot. So we're all eager to help bring this pandemic to an end. I think our management team is typical of the larger Peyto staff in that close to 80% to 90% of our staff have already had their first shot by now as well. So hopefully, that lowers our collective risk to COVID going forward. I do want to recognize the efforts of both our office and field personnel this past quarter. They continue to conduct operations with safety foremost, in mind, particularly with COVID and all the other operational risks that exist on an ongoing basis in the oil and gas industry. We didn't have any major outbreaks of COVID that shut us down at all this past quarter, which was great, whether that's on the drilling rigs, with the rig crews or our big frac crews that show up for fracture operations during completions, the pipeline crews that obviously have to work closely together. Even our own plant and well operations crews, it was great to see everybody was making sure we were staying safe and not passing any COVID along. So we had another strong safety record this quarter. So well done, everybody. And I just want to say a big thank you to all our people, both here in Calgary and out in the field for continuing to keep the gas flowing so that Albertans can keep the lights on and especially the heat flowing because this past first quarter, particularly in February, was brutally cold. And so that was a life-saving supply of energy that we all needed. So thank you to all our people. Okay. Onto our first quarter results. Operationally, we continue to drill some very strong wells in Q1. Our base production came into the year at around 86,000 barrels a day. And that grew from our drilling operations to around 88,000 by the end of the quarter. Obviously, we had to offset the annual 25% decline, which is actually steeper in the first part of the year, probably closer to 28% to 30%. So that meant capital efficiency on that organic activity was extremely good. I think we're way less than 8,000 of flowing on that. And then we layered on top of that production, the 2 Cecilia acquisitions. They were effective January 1, 2021. That added close to 3,000 barrels a day for around $36 million. So that ratio would be around $12,000 of flowing. And so collectively, we're in at around $8,000 of flowing for the trailing 12 months, which is some of the best capital efficiency we've seen at Peyto. And on a combined basis, we exited the quarter at around 91,000 BOEs a day, about 86% of that was gas and the rest was NGLs. We drilled a total of 27 wells in the quarter. So a very active quarter. Seven of those were our newly designed extended reach horizontal wells. We define those extended reach wells as having over 2 kilometers of horizontal lateral. And this new well design, I think, is a real game changer for Peyto, and we're excited about what this means for our future resource potential. Lee and Dave can provide some more color on this later, I think. Drilling was spread out across many of the core areas, actually, through the quarter. But we continue to take advantage of our extensive pipeline and facility infrastructure capacity. So our spud to onstream times continue to lead the industry. I think over the last 5 quarters, we've been putting wells on production within about 40 days of commencing drilling, and that's even with all the pad drilling that we're doing. So that's very quick conversion, yes, even for us, And very quick conversion relative to most others in the industry. Other operational highlights for the quarter include our emissions reduction work, we continue to swap out measurement equipment in the field that significantly reduces methane emissions. This lowers, of course, our carbon tax bill and increases our methane sales, all the while being better for the environment. So really, that's a triple win. We also continue to work with our suppliers on a new design for our well site packages that have next to 0 emissions. We have some of the -- those new designs being installed this year. We'll trial those and see how they work with the ultimate goal, of course, to minimize our emissions, if we can. But at the same time, we have to make sure that we have reliable systems for production operations. I think we all saw the examples of having systems too integrated, and then one of them failing, causing all of them to fail down in Texas this winter. So we have to make sure that even though we're putting in more environmentally friendly systems in our production operations, they still have to work, especially in the winter time. Zero emissions, but Albertan's freezing to death is not our goal. We want to make sure that we can get down to very low emissions, but have very reliable energy. Moving on to the financial results for the quarter. We maintained some very good cash costs throughout the quarter. Operating costs were lower. So nice job, Todd. Royalties, of course, were predictably higher due to stronger commodity prices. Those scale, of course, with commodity prices. Our interest charges were also a little bit higher, which was tied to our revised covenants in our banking agreement. Those are coming down as we move forward. And Kathy can speak to that later. Natural gas prices were obviously very strong during the quarter. We alluded to that in our last conference call. And really, we made off like bandits in a couple of places, particularly the volumes we had diversified to the Ventura market, which is just outside Chicago. When the cold spell hit mid-February, we saw spot prices there spiked to over $150 in MMBtu so we cashed in on that for about a week, and that windfall actually almost offset all of our expensive market diversification costs for the quarter. So in the end, we were close to achieving AECO-like prices for the quarter, which gives us cash flows that are extremely strong. And I think that's a bit indicative of what we'll look like in a few quarters from now when the higher cost basis deals fall away. Funds from operations were more than double what they were in Q1 2020. That was obviously a pretty ugly period. So we are happy to see our funds from operations back up to where they're supposed to be, and that $117 million really covered all of our capital program. It covered our dividend, and it even covered the acquisitions that we made in Q1. So we ended up growing production while still paying down some debt, and that's obviously an ideal situation. Earnings or profits were also way up in the quarter, basically, back to the level of profit margin we're used to at Peyto. I think our average profit margin over the 10 -- last 10 years has been right around 20%. That's earnings to revenue. So 22% this quarter was right in line, and it's exactly what we expect to see. On the marketing side, we've added to our basis deals going out to 2024 with more AECO to Henry Hub and AECO to Dawn deals that are significantly below the pipeline tolls, very attractive-looking basis deals. I much prefer the synthetic transportation of a basis deal since there's no physical delivery risk. We get to market, and get market diversification, but we only have to deliver our gas to the sales meter, which is just outside our plant gate. If anything happens to the pipe beyond that, like a ransomware attack or some governor trying to shut it down, it's not really our problem. We've already delivered our gas to the sales point, and we get paid. But we get access effectively to those diversified markets across North America. So the basis deals look very attractive to us right now. We secured 40,000 gigajoules a day to Dawn at a cost that's almost $0.25 at MMBtu below the LTFP toll. So I really like that. Gas prices are setting up very well for this coming winter. We're looking at storage refills this summer, and both European storage is filling very, very slowly. Even U.S. storages and Canadian storage is filling pretty slowly. So even though there's obviously strong demand to get that gas into storage, the supplies are pretty thin. A lot of demand for those supplies. We're seeing a lot of gas exiting the Gulf of Mexico through LNG exports and pipelines down into Mexico. And so that's pulling a lot of gas away from the North American market, which is very constructive for gas prices. So we're pretty excited about how that's setting up. That's probably pretty much it for the quarter, a very solid quarter, both operationally and financially. So Mary, why don't we take this time to throw it open to questions from those listening in?
[Operator Instructions] Your first question comes from the line of [ Dale Lunen ] with Natural [indiscernible].
I'm just wondering, given your comments on storage access and improving fundamentals in North America, if you tempered your expectations at end of the world -- volatility in August with AECO?
Thanks for the question, [ Dale ]. It's a good one. I don't think we have changed our opinion of what could potentially happen here in Alberta. There's a lot of maintenance and work that's planned for August on the Nova system. We still anticipate that, that's going to have a fairly significant impact in Alberta. We're hoping it's short-lived. And I think when you look right now at the injections in Alberta going into storage and you look at the price differentials between summer and next winter, it really -- there's not a lot of financial incentive to actually put gas into storage, and yet there is a fair amount of gas still going into storage right now, which kind of tells us that people are anticipating. There's going to be a window there where they're not going to be able to inject gas. And so they're trying to get ahead of it a little bit with the injections. Even as it is, we're projecting that AECO storage or the AECO-connected storage, so that's the stuff off the Nova system, is only going to get to about 70% to 75% full. We were a lot fuller last winter going into that cold winter last year, a good thing because we took about 225 Bcf out. We're only anticipating that we're probably going to refill something a little over 100 or so. So it still looks to us like a bit of a delicate situation for natural gas storage in Alberta. And we still think that August is going to be a difficult time, particularly for Alberta prices, which is why we diversified away from the AECO market for this summer.
[Operator Instructions] Next question comes from the line of Jeremy McCrea with Raymond James.
Just a follow-up question on your extended lateral wells. I'm just curious to know how much that -- how much of that is expected to improve your profitability going forward in terms of your payout, maybe the NPV per well? And how much you've built that production improvement into your guidance?
Yes. It's a great question, Jeremy. These are -- this is a relatively new well design for us. We drilled a few of these wells last year to sort of push the envelope that test the risk out, I think. Maybe JP, you could talk a little bit about the economics of those, and how that changes things for us?
Yes. Sure, Darren. We drilled about 6 wells last year, where we tested longer reach horizontals of 6.5 miles. And so we drill them about 70% longer, and we probably put about twice as much sand in these laterals. So we increased the intensity as well. And we did that for a cost per meter that was about 20% lower. So all a very good program. The rate of return on those -- on that group of wells is around 40%. And that might compare to something that was closer to 20% in the past. And the payouts here would be just under the 2-year mark. So -- and again, we probably would have seen payouts a lot longer than that. I don't have an NPV number off the top of my head. But obviously, the economics for these are a lot better. And we have factored in this into our 2021 program, which we have about 20 wells planned for this year to follow-up on that program in different species, in different areas. So yes, we're very happy with the success of that program, Jeremy.
Jeremy, these extended reach though are -- they are different -- I would characterize them as a little bit different risk profile. But Lee, maybe you can comment a little bit about the drilling risks, whether there are any more dangerous drilling longer laterals than what we traditionally do.
Sure. I guess backing up, I don't know if it's necessarily a truly new design in any way. We've always stuck with our standard open-all-ball-drop system that we've been doing for the last decade. And many of these targets still carry intermediate casing design in their actual well design. So it's just really how they factored into our program as a percentage of our activity. We drilled our first extended reach horizontal back in 2014 being our [ 8028 ], [ 5422 ] Wilrich horizontal. What's really changed is back then, we were kind of fighting our lift as we drilled it. That well was TD-ed at 6,000 meters with a 3,000-meter lateral. We were nervous deploying a 21-stage system into that. And the drill cost was just over $3.3 million, I believe. And that was with a flawless execution. So that wasn't flagged with wellbore challenges. Our completion cost on that well was $2.2 million. So D&C totaled just over $5.5 million. It was hard to -- the results didn't really professed to us at that time that, that was the way we should move forward with these wells. In 2020, as JP mentioned, we drilled 6 of these on the 64 well programs, that was about 9% of our program. We experimented with a little bit of technical changes as compared to our regular drilling program, use of brine in our laterals, and that development continues to evolve. We were able to execute this program for about -- these wells were $2.1 million on average for a 5,500-meter well, and we were installing 30 to 32 stages. So we grew our confidence in this longer design, in our ability to drill it to get our liners on bottom to successfully complete it. In 2021, we continue pushing that stage count up to 40 stages. On the risk front, Dave's group -- and Dave will probably talk to this here in a little later. I got to give a shout out to those guys, give a little bit of a hats off to Mike Reis. They did a great job at mitigating the geologic risk. A lot of these are Wilrich wells, and Wilrich has the unfortunate situation of being bound with an overlying coal that is markedly unstable. And so as we chase the best rock in the uppermost portion of this Wilrich, we flirt with that coal. And those guys have done a great job through offset well research and seismic review, just staying away from that coal. So that helps us, a, execute the wells to full length and reduce the risk. It's a huge stuck-type risk. Historically, more gear means more problems. So as I mentioned, we're pushing up high 30s, even low 40 stage count in these wells, and we'll probably see that continue to evolve through the year. Our vendor alignments and quality control has dramatically improved our confidence in these higher stage count and tight tolerance systems that these long laterals require. Risk of deployments, that continues to actually improve these longer laterals as we adhere to really strong wellbore conditioning procedures. We're seeing our ability to get these long liners with a lot of gear to bottom easier than I would say we used to a couple of years ago with lower stage counts and shorter laterals. So just experience, and our ability to keep those wellbore's conditions along with what I mentioned, the geo steering team keeping these wellbores smooth has really reduced our risk in getting our liners at the bottom. And then post-frac drill outs, that's a risk, more gear, more balls. That's more stages, more sand. There's more probability of a post-frac flowback, plus in the wellbore. And we've seen that. And I don't know if there's anything other than continued development on dissolvable material technology. There's nothing really we can do to mitigate that per se, other than our small completions group. Joe and Jerad have made a big leap on the cost metrics on our coiled tubing drill outs post frac. We just recently drilled 2 of these extended reach wells out to fully to TD to 5,700 meters, and we did it for about $150,000 a well. So those are -- those make that risk pretty small in the whole scheme of things. There's a big prize, as JP mentioned, on the rate of return front. So we've -- through the course of time, maybe our uptake has been a little slower than some of the industry, but we pride ourselves in our cost control and in our operational execution. And I think we're seeing that we're not really adding a lot of risk but we're adding this incremental length on these additional stages.
Thanks, Lee. Jeremy, hopefully, that color gives you some perspective on some of the operational challenges of some of these horizontal multi-stage frac wells. And also, when we talk about changing well designs, it's not a small decision because there's a lot of factors to consider, and risk being one of the primary ones, but it comes in all different forms and shapes and all different steps of the operation. So -- anyway, hopefully, that gives you some color on the new design.
No. No, it does. And just going back to that payout that you were just talking about at that 2 years. What commodity price assumptions that you using, especially on the NGLs. Just I know NGLs are starting to move up here a little bit more now. And then just -- it's just -- are you taking advantage of those NGL pricings? Just maybe a quick comment on that as well.
Yes. Typically, we write all of our new well economics at strip, accounting for sort of where gas prices are headed. Of course, they're quite severely backwardated at AECO right now. So it's not a great gas price forecast to run gas wells against. But so be it. It is what it is, and we'll have to make it work. You're right on the NGL side. Propane, particularly, is quite a bit stronger. We realized that in the first quarter of this year. Butane is obviously back up to more typical levels, closer to 40% to 50% of light oil price. 2020 butane prices were terrible, obviously, there -- because in that refinery shutdown, that gave us a lot of butane. And it took a while to wear that off. But I think last year, that came away. Butane prices strengthened quite a bit. So I think our propane and butane prices in Q1 that we realized that were about $30 a barrel, are more typical. And yes, that is a big driver. It's helpful to -- we've got a deep cut, only one -- at one of our plants. But obviously, it strips a lot more butane and propane out as well. So if we can bring these extended reach horizontal wells with more reserves, even if it's leaner reserves into the deep cut, then we're getting more liquids out of those wells, too. And so that helps the economics. But really, we're not trying to, I don't think, only make economic return when the prices are really good. We obviously have to survive the volatility in the price. And so we've got to build a robust investment here that can survive some of the dips as well as some of the strong spikes.
[Operator Instructions] Our next question comes from [ Trevor Heber ] as a shareholder.
I note in your release reference to reducing debt. So I did go back and look at your annual reports and find that your long-term debt has basically been flat. I went back to 2015. So I wonder if you could comment on your statement in your release about dealing with debt.
Thanks, [ Trevor ]. Great question. Yes. So we are, over the long term, planning to bring our debt down. We did mention, I think, about a year ago, that the strategy in the short-term was actually to get cash flow up. That was something that we could affect quicker and that debt to cash flow ratio or debt-to-EBITDA ratio is one of the covenants within our debt agreement that we were concerned about. And so by putting the cash flow from last year to work drilling wells, and the majority of the cash flow this year to work drilling wells. We're bringing cash flow up quite a bit. And that's actually giving us some relief on that debt-to-EBITDA ratio. And then as that -- as we roll forward, we're going to generate more and more free cash flow at that higher level. And that's where we're really going to materially pay down our long-term debt going forward. So we will pay down a little bit of debt this year. We're forecasting based on the current strip. And next year, we pay it down in a much more material way. Really, though, when you look back over Peyto's 22-year history, our debt-to-EBITDA ratio or debt to cash flow ratio has typically averaged about 2x, which, for some people, they might think that's a bit heavy. But we have used debt very effectively, and it's relatively low cost debt. Obviously, interest rates are relatively low still. And you have to put that into perspective. Peyto has 9 years of producing reserve life, which is extremely long, one of the longest producing reserve life assets in the industry. And so when we think about 2 years of debt on that 9 years of reserves, it doesn't seem overly levered. Of course, if you had a 3-year reserve life and you had 2 years of debt, you would think, wow, I'm 2/3 levered. And so that is pretty heavy leverage. And so when you think about our debt relative to our cash flows and relative to our reserve life, you have to consider those factors. Because we have an asset here that has very long life to it, very significant value beyond the traditional sort of 7 to 8 years. And that's what's really supporting our ability to carry debt against it and to use some debt effectively. But as you would probably point out, we've just come through a period here where carrying debt is at risk. It looks scary to a lot of investors. And for a period of time there where commodity prices were really low, it looked even scary to us. But thankfully, we're through that. And I think by the end of this year, we'll be at a sort of debt to cash flow level that is very historic for us and very comfortable for us.
There are no further questions at this time. Darren Gee, you may continue.
Okay. Well, thanks, Mary. We did get a couple of questions come in overnight, e-mailed in from shareholders. So I did want to approach a couple of topics here. One with respect to -- further on the debt side, with respect to our interest charges. And so maybe I can turn it over to Kathy, and she can talk a little bit about how our interest charges are going to look going forward here. They are changing quite dramatically.
Sure, Darren. So at the end of 2020, we had a leverage or debt to cash EBITDA ratio of 4.3x. In Q1, that came down to 3.36x. And as we decrease our leverage ratios, that actually affects our stamping fees that we pay, which is a significant component of our interest cost. So when we see that coming down under 4, under 3.5, then we have significant changes in our rates. So our interest rate in Q1 was 6.2% based on the historical 4.3x EBITDA. So going forward in the next few quarters, we expect that our interest rates will go down more towards the 4.5x -- 4.5% rate, which would save us approximately $2 million, $2.5 million a quarter. So we're expecting to see our interest costs in Q4 to be more in the $0.30 per Mcf range or about $13 million, which is a significant decrease from the $18 million in Q1.
Great. I like to hear that. Thanks, Kath. One of the other questions that came in overnight was about ESG, some of our ESG initiatives. And so maybe I can put this one to Todd. The question was just what other projects really are we looking at in addition to some of our controller work that's being swapped out that's reducing methane emissions. Todd, are there other things that we're looking at Peyto, long-term things or short-term things that also help reduce our emissions?
Yes. Absolutely, Darren. We had set a target back in 2016 of a 50% reduction in our emissions intensity and through Q1 here with our retrofit program. We're pretty much there. We should be very close, if not there now. So we'll have a new target coming out here sometime in the next few months. We're in our sixth year, really with our emissions reduction team of researching and trialing, engaging with industry and then implementing a lot of meaningful initiatives that have saved methane going into the atmosphere, so we can sell it. And as you mentioned, it's good for Peyto, and it's good for the environment. That work continues. All these initiatives that we've implemented are -- go above and beyond the Directive 60 Compliance requirements. So we're doing better than what the industry would ask of us. So this year, we'll continue with our high bleed to low-bleed controller retrofit program. We expect that program -- that project to be completed in June. We'll also be removing controllers on some low rate wells. So essentially turning them from low vent to a no-vent-type well. We'll continue to install collection devices that capture vented methane from legacy pneumatic chemical pumps and use it as fuel gas and well site heaters. We'll also be retrofitting older high-rate wells equipped with pneumatic pumps with electric pumps. This was something that didn't really make sense economically when we started installing electric pumps on our new wells in 2017 but with advances in power efficiency and pump technology, we can now do it effectively and reliably. Today, 1 pump can do what 4 pumps used to do, that's injecting different chemicals at different rates with less power consumption than our first generation of electric pumps. As you mentioned, this summer, we'll start receiving our first shipment of fully electric separator skids. So we've actually been trialing a design and refining that design in the field since 2019. So we've gone through 2 winter seasons with a fully electric skid. And we now have an extremely reliable design. And as I mentioned, with a really low power consumption. So with a couple of extra solar panels and a couple of extra batteries, we haven't had any issues through 2 winters. The team has also set to trial an in-stream pipeline power generator at 2 separate pads this year. And that provides all the power needs for each pad as well as recharging the backup batteries. And if successful, it could replace solar panels in some applications. So over the past 5 years, our efforts are really focused on well sites. It was sort of low-hanging fruit from a cost perspective. But we've also engaged with technology providers that have been developing solutions at gas plants. That includes compressor waste heat recovery, where the captured waste heat can be used to supplement utility heat duty in a plant and reduce the gas -- the fuel gas by fired heaters. Later this year, we'll initiate a feasibility study for a solar panel farm that could supplement the power needs of one of our gas plants. We've also been working with a company to trial a geothermal application that has a multitude of potential applications, both at well sites and gas plants. So we hope to advance that trial by the end of the year. Obviously, the facility implementations can be quite capital intensive, especially compared to what we've been able to do at well sites. But like we've seen with well sites, the technology is getting more efficient and the costs are going down. So we anticipate being able to implement some of these applications in the future. Also, there's been a lot of discussion recently about -- around carbon capture and storage and blue hydrogen. So that's something that we continue to monitor, and we're excited to see what may come of those 2 emerging technologies.
Great. That sounds all really good. The last question that we saw was actually with respect to acquisitions. We're not typically a big acquirer at Peyto. We've built almost everything we have today from scratch. But we did a couple of acquisitions in the first quarter. Those were the first that we've done in a long time, of size. So maybe I can turn to Derick and ask him what else are we seeing coming down the pipe, Derick? Are we looking at some more sizable acquisitions, is the land sale opportunities starting to emerge now that Crown land sales are back on the table or...
Yes. Thanks, Darren. We're constantly endeavoring to grow our land base with tuck-in acquisitions, whether they be purchasing assets, farming in with drilling commitments, we're entering into swaps. Generally, I believe activity often creates opportunity. So with us being active, helps us both be proactive and reactive as required. Also -- I also believe being quick and flexible within the different internal departments helps in this regard. Our low-cost capital structure, technical know-how and abundant amount of infrastructure can be used as a sort of currency at times to allow us to withstand down promos on farmings and purchases, where others may not be able to do so. Our BD group is actively looking at additional growth areas while also continuing to look at tuck-in acquisitions like Cecilia, for example. In terms of Crown sales, it's definitely a lot more active than last year in Q1 2021. There's about $11 million in bonuses for an average of $195.5, which is obviously substantially higher than 2020 when there was about 7.5 months of no Crown sales. So all in all, as you mentioned, we're not -- we're constantly looking at further acquisition targets, and we mark them as they come up or as we are able to generate them.
Okay. Great. Well, I think that's all the questions that we saw from people and shareholders. And so thanks everybody, for tuning in. We'll obviously be back to you mid-summer with Q2 results. We're looking forward actually to another busy year of drilling here at Peyto. And economics are starting to look stronger and stronger. Prices are looking better. So cash flows are getting stronger. Our balance sheet is getting a lot better. So things are definitely looking up. We're excited about the balance of this year. And we're excited about is probably most people are to put COVID behind us and finally get to maybe have dinner together at some point in the hopefully not-too-distant future. So anyway, thanks for tuning in. Watch the website. JP and I will get a presentation, an updated presentation videotaped, and we'll get that up on the website since we can't have an AGM with everybody in the same room. We'll get a video presentation up. And hopefully, that can shed some more light on where Peyto is going, and how we're doing. So thanks for tuning in this morning, and we'll be back to you in August.
This concludes today's conference call. Thank you all for your participation. You may now disconnect.