PEYUF - Peyto Exploration & Development Corp. (PEYUF) Q1 2023 Earnings Call Transcript
2023-05-12 22:37:06 ET
Peyto Exploration & Development Corp. (PEYUF)
Q1 2023 Earnings Conference Call
May 11, 2023 11:00 AM ET
Company Participants
JP Lachance – President and Chief Executive Officer
Tavis Carlson – Vice President-Finance
Kathy Turgeon – Chief Financial Officer
Riley Frame – Vice President-Engineering
Lee Curran – Vice President-Drilling and Completions
Conference Call Participants
Chris Thompson – CIBC World Markets
Presentation
Operator
Thank you for standing by, and welcome to the Peyto's First Quarter 2023 Financial Results Conference Call. At this time, all participants are in listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions] As a reminder, today's program is being recorded.
And now I'd like to introduce your host for today's program, Mr. JP Lachance, President and CEO. Please go ahead, sir.
JP Lachance
Well, thanks, Jonathan. Good morning, folks, and thanks for joining Peyto's first quarter 2023 results conference call. I'd like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory set forth in the company's news release issued yesterday. In the room with me today, we have the entire management team: Kathy Turgeon, our Chief Financial Officer; Riley Frame, our VP of Engineering; Tavis Carlson, our VP of Finance; Todd Burdick, our VP of Production; Derick Czember, our VP of Land and Business Development; and Lee Curran, our VP of Drilling and Completions.
Before we get into the details, I'd like to acknowledge and thank the Peyto team for their efforts over the past quarter and especially our people in the field for their extraordinary commitment to Peyto. Many of these folks were evacuated from their homes, and they had to get themselves and loved ones to safety during last week due to the wildfires burning near Edson while also taking care of Peyto's assets in the field. So on behalf of the entire management team and the folks here in the office, know that you're on our minds, and we appreciate what you do.
We'd also like to acknowledge the great efforts of the wildfire emergency responders and those who continue to be displaced from their homes. The recent cooler weather has provided some reprieve for those fighting the blazes. But we know the forecast contain some hot, dry weather in the future, so we're thinking of you as well during this difficult time. Despite the rapid drop in prices throughout the quarter, Peyto managed to deliver strong operating margin of 71%, coupled with a profit margin of 32%, that delivered earnings of $9 million, and we declared $58 million in dividends. Funds from operations was obviously quite strong, considering where prices were, thanks in a large part to our disciplined hedging program.
When we look back at the past 10 quarters, we've increased production by 32% from 78,000 up to 103,000. We paid out $184 million to shareholders in the form of dividends, and we paid down $300 million worth of debt, too. Quite impressive. Unfortunately, we did not participate in the Malin price frenzy this winter, but we still have 40,000 MMBtus pointed at that market over the next year, and we'll take advantage of any future price spikes there. Operating costs were up in the quarter, which is usually the case in the winter when we use a little more methanol and power costs are higher. But we also had many supplies and services that were up due to inflation. We expect these costs will come down throughout the year. And despite these increases, we still have the lowest cash cost in the industry.
As far as capital activity in the quarter, we ran with 4 rigs through the end of March, and we drilled our longest drilling program, well program ever using our extended reach horizontal design across several formation targets. And perhaps later, we'll get Riley to expand on the results of that program. We drilled more wells on the lands we acquired last year in Brazeau and we've increased production on those assets by tenfold, which has filled the new Aurora plant after we did some gathering and sales pipeline optimizations.
In the first quarter, we also built a large diameter pipeline from our Swanson plant down to the Cascade power plant, which is under construction. We're proud to be a supplier – a gas supplier of 60,000 GJs a day. That's about half the natural gas requirements for the plant to what will be the most efficient power plant – generation plant in the province when it comes onstream later this year. We can’t share the confidential pricing agreement we have, but if power prices are anywhere close to where they were in 2022 or even 2021, we’ll be very pleased relative to what we would sell that gas at AECO – for what we’d sell at AECO. And speaking of AECO, we don’t have any exposure to that market this summer or next since we’ve got a broad diversification portfolio to other markets where our gas will be sold.
We recently received our long-awaited tranche five service that has – that was part of that 2021 NGTL expansion and – which was delayed and delayed over the last couple of years due to COVID and construction problems. So, we have ample service now to ensure our gas gets out of the province and then some – a little bit extra on top of that. We also have more than enough NGTL firm receipt service in case there are curtailments due to summer maintenance this year. This also allows us on top that – to grow our future volumes without fear of the system being full and having to wait on future expansions. So, we’re well positioned there, too, on our service.
We currently have three rigs running now through breakup. And although it’s obviously relatively dry out there now, we’re all too aware how wet June can get. And so we’ve made sure these rigs are positioned on sites with good access. We’re drilling multi-well pads and minimizing the moves. After that, we’ll see where prices are and where costs are at, and we’ll determine how aggressive we go after the back half of the year.
In the short term, we need to navigate through this current wildfire situation. And as we said in the release, we’ve actually been able to restore essentially all of our production from the two plants that we shut down as a precaution. And I think now all we’re really waiting on is these, the non-operated production to come back onstream, which should be shortly.
And we’ve also learned some things, and we’ve shut – we’ve put in place some responses in case this flares up again. But at this time, we feel the impact on quarterly production is minimal, providing we don’t get hit again with another evacuation or something like that. And we’re working with our third-party liquids egress operators to ensure we have contingency plans as well.
Ultimately, we believe that natural gas is the fuel of the future. We have a real opportunity to displace dirtier fuels around the world if we continue to build out our LNG export capacity here in Canada and in the U.S. because nobody does it better than Canadian producers when it comes to responsible low-emissions development.
Renewables have a place, but natural gas has proven to be the most reliable energy source, especially in harsher climates, where solar and wind just can’t meet demand when you most need it. And we believe Peyto is well equipped to supply that gas as we go forward with our low-cost structure, our low-emissions intensity production, our price risk management and our disciplined approach to shareholder returns.
Okay. Before we turn it over to questions, I’d just – a reminder that our Annual General Meeting is next Wednesday, May 17 at 3:00 p.m. here in Calgary. And you can get the details on the venue at the bottom of the press release.
And before we go to the phone for questions, I think I’d just like to address a few comments or questions about the hedging loss in Q1 that came in overnight. And I might ask Tavis to give me a hand with this. But I think we just want to remind folks why we hedge, and I guess another reminder of what we should expect going forward with our hedging program under the current strip.
So maybe, Tavis, if you could elaborate a little bit more on that and also on the fact that what other market diversification, how we’ve been able to get this quarter and then how is our approach going to be on hedging that as well.
Tavis Carlson
Yes, sure, JP. So we’re really hedged to secure revenue. We want to protect our balance sheet, we want to protect the project economics, and we want to stabilize our funds from operations quarter-to-quarter so we can fund under dividend. I know we've had some significant hedging losses over the last number of quarters as gas prices were strong, but going forward, we're now modeling substantial hedging gains for the next year and a half. Our mark-to-market hedge position at the end of March was $149 million, which increased from a liability of $111 million at the end of last year and really that those linked contracts rolling off and then the falling natural gas prices, really that position for us.
In terms of diversification, in 2023, we've added around 90,000 MMBtu a day of basis deal on NYMEX in Chicago and those are in 2025, 2026, and 2027. So we're getting ahead securing various markets. So that's going to provide exposure to good prices. We like the basis deal and we can get the basis at or the low pipe costs. And the other benefit is we don't have long-term commitments with those.
JP Lachance
So when we talk about hedging…
Tavis Carlson
At those markets, I think it's safe to say, we're going to leave some of these more volatile markets open, Malin being one. Obviously, right now it's come back in, but it could easily spike again. It wasn't just two years ago in the winter where we had the Ventura really pay off and we had left that exposed, and I think we made $25 million over a weekend. So it's safe to say that, as we look forward here, we are going to leave some of these more volatile markets expose, so we hedge those $25 million [ph] volumes two years ago. And at that time, that was a superior price to what we could get at AECO at the time. So that’s why we did it.
JP Lachance
What you said is important. It's about securing revenues and we can't predict a price, so a lost opportunity – a lost opportunity of value here, but again, it's security of the revenue that's importing. So maybe we'll open up to questions from the phone, operator.
Question-and-Answer Session
Operator
Certainly. [Operator Instructions] And our first question comes from the line of Chris Thompson from CIBC World Markets. Your question, please.
Chris Thompson
Yes, good morning everyone, thanks for taking my question. This one's just regarding the $100 million note that you have come in due. Just wondering, at this point, if you have any plans for that or what are some of the scenarios that could play out that we should be thinking about?
JP Lachance
Sure. Okay. I may ask Kathy to address that one, you're referring to the note that comes up in October of this year that's $100 million and 3.7% interest rate. Yes, go ahead, Kathy.
Kathy Turgeon
So we are going to be flexible on that. It's a bit too early to talk to the noteholders on the existing noteholder, but we have strong relationships with that noteholder. It's one noteholder. And so we may roll that note over if we can get reasonable terms. Otherwise, we do have the ability and the capacity on our bank credit facility to just pay it down. So it's really going to be whatever interest rates we can secure.
Chris Thompson
Okay. And just remind me average interest rate on your credit facility right now?
Kathy Turgeon
Our average interest rate right now is probably about 6%, 6.5%.
Chris Thompson
Okay. And that’s 4% on the long-term notes, of which we have 400 – roughly $400 million, little over $400 million of the long-term fixed notes is 4% and coupled with the revolver rate?
Kathy Turgeon
Yes, revolver alone, yes, about 6.5% right now.
Chris Thompson
Right. Okay.
Kathy Turgeon
Underlying interest rate 5%.
Chris Thompson
Okay. Great. And then on my next one just with respect to dividend sustainability, a lot of investors are – have been asking the question, how should we be thinking about the way you look at your dividend stress testing it down to certain commodity prices? What are your thoughts around that?
JP Lachance
Yes. I think that’s – we – Tavis mentioned it earlier, the reason that I did too, the reason we do the hedging program is to help secure those revenues so that we can be comfortable with the level of dividend we set. When we look back at November, when we set this dividend level, we were cognizant of the fact that prices could fall. And we looked at the sensitivity around that.
As – and I think as long as prices the strip played out, everything was going to be just fine. And I think we look at that from two perspectives. One is not only the dividend sustainability, but also the capital program that we’re drilling. We want to make sure that we’re making – that the decisions we’re making on deploying capital is giving us a return.
So we’re cognizant of the fact of where the prices are and we continue to hedge the future. I think that’s the thing to remind everybody, our hedges don’t roll off. We’re continuing to hedge what’s our hedge level now for 4% is already up to 50% on gas, so we are securing those revenues because prices are in contango and we can take that off the table. So it gives us confidence to continue to sustain the dividend.
Chris Thompson
Okay. Great. One other question for me, just with respect to inflation, I noticed in your note you talked a bit about drilling costs per meter coming down a bit, completion costs per meter up a little bit in terms of line of sight to a bit of relaxation in inflationary pressures going forward. I think we’ve seen a bit of an improvement, but it’s still there. Can you give us a bit more color on your outlook for the next three quarters?
JP Lachance
Yes. I think we feel that inflation has tapered off here and that we’re not going to see significant increases like we did last year, prices, we’d like to see them coming down, but I don’t think that in the short-term’s realistic, we’ll see what happens with activity levels here come post breakup – break that changes.
I think on the operating cost side, we’ve seen some inflation that it was a bit of a lag to seeing those costs go up. I think in the drilling and completion side, we saw costs go up quite quickly earlier on. And then operating costs seemed to lag a little bit and we saw more inflation here this quarter. But our look for inflation is it’s – I don’t – we don’t see, we’re not planning to have it to see it freeze. I guess it’ll depend on the activity levels we see going forward.
Chris Thompson
Okay. All right. Thank you very much. I’ll hand it back.
Operator
Thank you. [Operator Instructions] And our next question comes from the line of Gerald McKay [ph] from self-employed. Your question, please.
Unidentified Analyst
Hi JP, thanks for all the hard work this quarter. In the monthly letter as well as in all the disclosure, the topic of the influence of commodity prices, hedges, inflation and costs, I think has been well aired. And thank you very, very much for that. The area that I find a little bit harder to understand is there was a target year-end production level of 110,000 barrels a day and $500 million has been spent in the last year, and yet we’ve been down every month since the beginning of the year. Spending continues, and we’re actually not at 110, we’re at 102, and that is a year that we’re actually below the year ago level as per what I saw in the last letter. And I’m a little less clear – I’m very clear on the diversification program, the cost, the escalations, all of these things.
I’m very unclear on capital expenditures and the issue with production. I do understand that decline rates were a bit higher is the way it seemed last time this was aired. But it does seem that there’s a problem here that is deeper. So my first question is, is there a – are you gradually discovering a deeper problem or maybe the easiest way is to just talk about what targets you would be comfortable with on production for the second, third, and fourth quarter or whatever you want in terms of looking forward. But there’s $425 million as you succeed in being in the low end, $425 million and production is lower than it was a year ago. That’s my question. Where are we going and what has happened?
JP Lachance
Well, thanks Jerry. Yes. So we talked a bit about this in the last call, but I’ll just elaborate some more on some of the things that we’re – I think inflation is a big part of this. We’re not – we’re just not drilling as much to really – successfully grow production in the short-term. And so certainly three rigs isn’t going to do that. And so we are going to be somewhat flattish to down slightly over the next little while, I suspect – and then it’s the back half of the year that we’ll ramp up and continue and then grow. And so inflation is a big part of this, but the cost structure and just don’t – we don’t have enough activity. We don’t feel that it’s a good time to be getting aggressive on that, keep considering where prices are at.
So I think it’s prudent for us to be cautious on how much we’re spending. And so the activity levels just aren’t there for us to be able to substantially move the needle. If we look back at our trailing 12 month, I didn’t put in the release, but the trailing 12 month capital efficiency were probably about $14,000 when we look at the last three quarters, when we look backwards at what we spent and what we’ve gained in production. And that’s when I remove some of the bigger hitter – big hit items like, for example, the plant and the acquisitions that we’ve done. So we remove those costs from the equation, which I would consider more one-time opportunities that we took advantage of last year.
So the spend is higher than we would’ve expected over the last year or than we normally. We are targeting – still targeting a cap efficiency metric by the end of the year of around $12,000 per drilling somewhere in that range. So we are still – we look at our projects, if you look what we have going forward, we still expect to achieve that. That means we will be growing production on the back half if we add that fourth rig. We’ll be going back up again. And that’s the plan, Gerry.
Unidentified Analyst
Thank you.
Operator
Thank you. [Operator Instructions] And our next question is a follow-up from the line of Chris Thompson from CIBC. Your question, please.
JP Lachance
Go ahead, Chris.
Chris Thompson
Yes, sorry. Just talking on that same topic from Gerry there. With respect to the extended reach horizontals that you’re drilling, are you seeing an uptick in productivity per lateral meter accessed or are we going to expect sort of the same per meter productivity, but just seeing the overall well cost per meter drop? So like I guess, what I’m asking is to the extended reach horizontals drive an improvement in capital efficiencies over time? How are you thinking about that?
JP Lachance
I’ll maybe get Riley to elaborate on a little bit more. And one of the things with the extended reach horizontals is obviously we are tapping into more resource when we extend out. And so we’re going to see reserves – certainly reserves up, productivity may not be quite as robust and that is a factor. We’re putting more dollars into the ground, but we’re seeing a little bit not quite as – I’ll let Riley to comment on that.
Riley Frame
Yes. I would say on the – yes, sorry. I would say on the extended reach, like we’re not necessarily seeing a per meter increase on the upfront productivity. If anything wellbore limitations, friction and other stuff like that actually can joke that initial productivity from these wells. But what we do see is, is a substantial increase or a relatively close to linear increase in the reserves associated with the extra meter that we do drill.
So from the perspective of say an F&B number, we definitely see that scale with how far we drill. So the economic benefit of drilling these wells longer is definitely coming through. And I think you can see it in the dollars we spend as far as the efficiency, as far as that goes.
That – part of the reason that our per meter numbers and our per ton and per horizontal meter numbers for – per stimulated horizontal are where they are is because we are combating rising prices with being more efficient with the dollars as we drill longer. So yes, overall I think the economic benefit of them is definitely paying off for us for sure. So...
Chris Thompson
And then how about on the – this concept of parent-child interference or maybe not even that specific, maybe just thinking Tier 1 versus Tier 2 inventory, like operators in the U.S. have been kind of messaging that move into lower-tier inventory. What are you seeing for Peyto from an inventory quality perspective?
JP Lachance
Yes. We've kind of – like we've almost combated the sort of step-down in reservoir quality by going long. If you look back at what we were drilling 2015, 2016, 2017, and you compare that from a reservoir quality perspective, so what we're getting today, the reservoir quality is poorer today for sure. But we've actually been able to offset that by going long, which is why everybody is going that route, right? So yes, it's a way of – from an economics perspective, it's – the ERH stuff is a way of turning Tier 2 into Tier 1 is kind of the way we look at it, right?
Chris Thompson
Right. Okay. Yes. So yes, it sounds like reservoir quality, kind of the top-tier stuff has been consumed to some extent, and so just trying to upscale the Tier 2 stuff with technology. In terms of your inventory remaining, how would you break down sort of what you have left in terms of Tier 1 opportunities, Tier 2, Tier 3?
Tavis Carlson
Sorry, do you want to comment?
JP Lachance
Yes. I think the way to look at it, Chris, and this is – I mean, if you'd asked that question three, four years ago, we would've – it'd be a different answer than it is today because, obviously, with technology changes in this extended reach horizontal design for example, we moved things from Tier 2 to Tier 1. So we don't look at our inventories the same way. We look at this from the perspective of what we have in front of us and what we want to drill every year, and we just continue to high-grade it.
Even when you look at – so we don't bucket our opportunities. Any geologist is going to drill his best wells first, and that's always the way it goes. And then the engineer's job is to make sure – is to move those things, up the chain as it were into the Tier 1 category with some help with respect to the design of the wellbores or the completion techniques.
Chris Thompson
Okay. All right. Well, thank you for the follow-up. I'll hand it back in again.
JP Lachance
Okay, thanks.
Operator
Thank you. [Operator Instructions] And our next question is a follow-up from Gerald McKay. Your question, please.
Unidentified Analyst
Yes. The last question – the answer to the last question was excellent and – but it does kind of slide into this follow-up. The first part of the follow-up would be a top down question, which is to what degree has the balance of the industry both in Canada and the U.S.? And this is something that you may have the answer right now, or I would look forward to it in your letter or some way in the future. But to what degree has the industry experienced the costs, and I'm interested in that from a competitive viewpoint, how are we doing versus everybody else on this inflation front. But also almost more importantly, if industry CapEx levels are similar or up a bit, but this inflation is actually having that real effect on activity it would theoretically bode well for future prices. So that's the first part.
The second part on a bottoms-up basis is given the new we were at 10,000 per barrel of economics and now we're at 14,000 per barrel, settling back down to 12,000 per barrel, what's the incremental CapEx that implies to hold production flat? Anyway, over to you. And you answered the first question so well, it did kind of lend itself to these follow-ups.
JP Lachance
Yes. Okay. So Gerry, I think to start with the second question first. We think that around somewhere between 375 million and 400 million keeps us flat to answer that question, and that would be up from – I think it's up, it's basically the inflation to the large part, it's driven those – that efficiency costs up, right? So up 20%, 30% easily, right, probably 30% more realistically. Your first question was just I'm sorry, I lost it. I thought there is…
Unidentified Analyst
In industry wide inflation and impact on activity.
JP Lachance
Yes, we've seen – I mean, it’s two things here. One is that everybody is seeing the same cost increases that we are. Everybody is trying to fight them the same way we are; would be more efficient with what they do. You have to remember we start at a spot that's lower than the rest of the industry. And so these increases to us – we've been squeezing out every bit of cost structure we can all the time. And so that when prices go up, they go up, and we see it all. We don't have a lot of low-hanging fruit on optimizations because we're continuing to do it all the time. And I'd argue that, that's what we're really good at.
So we're going to – we might see a bigger percentage than others, but we're already starting from a lower place, right? So I don't know, Lee, do you want to add to that, anything about what the industry is seeing? But I think rig rates have gone up, everything has gone up. We've actually been quite – we've done pretty well on a lot of these fronts, I think, managing our costs.
Lee Curran
Yes. We were fairly well-insulated relative to industry last year, just a lot of timing on our RFP processes, business contracts, protected us relative to some of those operators that kind of picked up incremental activity late in 2022 and early in 2023. We were locked in on a lot of our services, so that did insulate us relative to our peers. It looks like the battle for personnel has subsided a little bit in the industry. That was a big factor in some of these inflationary pressures.
It seemed like everybody was commanding a top dollar rates just to provide personnel, hopefully, qualified personnel but it seems like that issue has subsided a bit. So, and then pretty much everything we do is tied to fuel price, oil price, it's commodity-related. So as we see some stability and, arguably where it goes forward, oil prices, some of those services we expect to come off. We haven't seen huge reprieve yet. But as JP mentioned, we did start the – we started at a lower point on the scale relative – our data indicates we started at a lower point on the scale relative to our peers.
So some of the percentage increases maybe look a little worse than our peers. But of course, still – that still keeps us in an advantageous position, favorable to the rest of the industry. We really have – the equipment we use; the processes we use are very much simplified. If you can drive downtown on a Civic versus an F-350, that's kind of we try and keep it simple for that purpose. And a lot of industry has pushed towards a lot of automation, a lot of higher-tech stuff. But that comes with a big cost and a big – those services have to command a higher price to capitalize that investment.
So yes, I don't know how else to answer that. Going forward, we do expect steel is a big part of our cost. And the increases in our tubular goods have been dramatic, 2.5 from lows – 2.5-fold of pricing we saw from our all-time lows. And I think we're going to see some retraction in that. When I can't answer, but hopefully later in the year.
Unidentified Analyst
Right. In the silver lining category, if we're kind of peaked out at where we were, and we're down at 102 and we're holding for the rest of the year. And I know you didn't say that was the objective. You said that at three rigs, that's how it would work out. Would it be reasonable to assume that the – absent inflation, that the CapEx level would moderate because the decline level would also be moderating, given that this isn't an expansionary program anymore? And that's the end of my follow-up.
JP Lachance
Yes. Clearly, as you know, tight gas, the first year decline is the highest. And so the less the size of the program we drill, the lower declines are falling the following years. So we've already seen that like three, four years ago, when we were up actually more than that, like in 2017, I think I looked at the numbers here.
So we had a 37% decline, right? We had built a lot of production over that time. And now we're somewhere closer to 29%, 30%, right? So – and that's because we slowed down. And that's – you're right in your assessment that as we moderate the growth, we're going to see an even lower cost to add because our declines will be lower. It all depends on where inflation goes from here, right? Yes.
Unidentified Analyst
Thank you.
Operator
Thank you. This does conclude the question-and-answer session of today's program. I'd like to hand the program back to JP for any further remarks.
JP Lachance
Okay. Well, thanks a lot, folks, and we'll see you next quarter. Actually, again, a reminder, our Annual General Meeting is next week, on Wednesday, here in Calgary. Thanks.
Operator
Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.
For further details see:
Peyto Exploration & Development Corp. (PEYUF) Q1 2023 Earnings Call Transcript