Peyto Exploration & Development Q2 2024 Earnings Call Transcript

Quartr
Provided by Quartr
August 14, 2024

There are 7 speakers on the call.

Operator

Good day and thank you for standing by. Welcome to the 2024 Second Quarter PATOS Financial Results Conference Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. Please be advised that today's conference is being recorded.

Operator

I'd now like to hand the conference over to your first speaker today, JP Lachance, President and CEO. Please go ahead.

Speaker 1

Thanks, Marvin. Good morning, folks, and thanks for joining Peyto's 2nd quarter 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. Present with me in the room here is Riley Freme, our VP of Engineering and Chief Operating Officer Tavis Carlson, our VP of Finance and CFO Lee Curran, our VP of Drilling and Completions Todd Burdick, our VP of Production and Derek Zember, our VP of Land and Business Development. Firstly, we'd like to thank the entire Peyto team, both in the office and in the field for their strong execution this past quarter.

Speaker 1

And it was a strong quarter for Peyto despite very low gas prices. In fact, the lowest we've seen since 2019 at AECO anyway. We still managed to generate $155,000,000 of funds from operations and $51,000,000 of earnings, in large part due to our systematic hedging program, which realized $68,000,000 in gains along with our industry leading low cash costs. And a reminder that our mechanistic hedging program is designed to de risk and smooth out prices and give us predictable revenues so we can provide confidence to run our capital program, manage the balance sheet and pay shareholders a dividend. Ideally, we'd be out of the money on our hedges, but this approach to date has accumulated over $350,000,000 in hedge gains since we started.

Speaker 1

And the other point I would like to point out about the quarter is that I think Peyto's operating margin of 62% with these low gas price screens very well as compared to our competitors. And it's a testament to how we run the business. So let's talk a bit about drilling program. We completed another string of very long laterals in the Q2, mostly Wilberich across different areas in Greater Sundance and in our core Brazeau area. The average lateral lengths of these wells drilled in the program were just over 2,300 meters, which I think is another record for the size of the program from a quarterly program perspective.

Speaker 1

We were set up on 3 well pads for most part for the most part through Q2 during what was typically what was a typical wet season through spring breakup. And of course that minimizes moving equipment around and slogging through the mud. Obviously that slows down our on stream timing, but it certainly helps to keep and even drive cost down as we saw overall improvements in our average cost per meter on both drilling and completions operations this past quarter. We continue to be excited about the drilling results on the newly acquired Repsol lands. We had 21 wells on stream to the end of Q2 with enough history that showed us that shows a sustained 30% increase of average well productivity as compared to the performance of recent legacy programs.

Speaker 1

These wells were drilled in the Willeridge, the Flair, the Nootaquen and they were drilled over a large portion of the Repsol land base. And that's important because it provides us confidence that isn't just one species that's outperforming, but the good results are coming over a wider area and up and down the strata. The other thing that's important here is that the cost to attain these outcomes are similar to or even slightly cheaper than what we're currently spending on our legacy lands since we're using the same well designed to drill in the fleet. Cash costs for the quarter were $1.50 per Mcfe or 1.24 per Mcfe excluding royalties. We had an annual GCA adjustment to our royalties on the Repsol assets this past quarter that inflated our cost by about $0.05 per Mcfe.

Speaker 1

Going forward, we expect our royalty rates to be around 7% to 8% on a pre hedged sales revenue basis. Or if you include the revenue from our hedge gains, our royalty rate is more like 5% to 6% since of course we pay royalties based on Alberta reference prices and not our hedge book. Pingo continues to have the lowest cash costs in the business and more of highest margins. But despite the fact that we have the lowest cash cost, we still endeavor to improve. We set a goal last quarter to reduce our operating expenses by 10% per Mcfe by the end of this year.

Speaker 1

And we're pleased that we are basically on target with that goal having reduced 5% in the Q2 already. Part of that gain was the redirection of gas volumes from a third party deep cut facility where we used to extract low value ethane as a liquid and we moved that over to our owned and operated Edson gas plant through the Central Foothills gas gathering system. In that, we had to give up about 2,000 barrels a day BOEs a day of NGL liquid by selling that ethane back in the gas space, but the value we realized was essentially no different and we are saving 3rd party fees and increasing the plant utilization at the ethane gas plant. And I think this is a good example of the way we look at the business, the way we run the business, it's about making money on both BOEs. Along the same vein, we recently shut down the sour gas sweetening side of the Edison Gas Plant.

Speaker 1

Although we had some 3rd party income coming in from that, it wasn't enough to offset the cost to run and maintain that part of the plant. Not to mention running, it impacted plant reliability, higher emissions and slightly higher safety risks to operate sour gas, of course. We had to shut in a small amount of our pitonet production from the sour gas unit that fed that part of the plant. But those wells produce very little NGLs and they have higher shrinkage and the sort of cost to operate to make it doesn't make economic sense, especially at today's gas prices. Currently, we have 4 rigs running across our core areas, 3 in Sundance and 1 in Brazeau.

Speaker 1

2 of those Sundance rigs are on the former Repsol land. We have a steady diet of non acumen wells for the balance of the year along with several Dunbegan, Wilberich and some Flair wells that are all left on the docket here for the rest of the year. We plan to drill and complete these wells and we may or may not bring them on production or if we do, it will be at restricted rates depending on where gas prices are. But at the very least, we'll use this time to evaluate the gathering system impacts to determine the evolving projects and build productive capability for later when we expect prices to be better. We're still planning to spend around $450,000,000 this year at the low end of our guidance, and we're targeting year end exit around 135,000 BOEs a day, of course, assuming prices cooperating and the improvement in the manner as we expect.

Speaker 1

As mentioned in the release and previous monthly, we have been providing gas to the Cascade power plant directly through our pipeline for some time now for testing and commissioning purposes. Our contract is expected to formally kick off here on or before September 1, so soon. In closing, I'd like to remind everyone, we remain bullish on natural gas for the near future as demand forecasts continue to rise in North America and natural gas is a reliable critical field for industrial use for power generation or just to heat our homes. Significant LNG egress is coming online in North America in the near term and the potential for data center expansion to meet the needs of AI is also being contemplated in many places that should be constructed for both gas prices and of course our power deal. And specific to Peyto, been we protected revenues with our low cost focus and disciplined hedging strategy, not only for the balance of 24, but we have lots of gas hedged into 25 and even 26 at prices that are at or above $4 an Mcf.

Speaker 1

And as I mentioned earlier, we hope prices go even higher, but it's kind of nice to know we have that cushion in our business so we can grow modestly while we return a healthy dividend to our shareholders. Our new assets are working great. We have room to grow without large cost to expand. So despite the current gas price environment, things look pretty good. So I imagine there's some questions.

Speaker 1

We have a few coming overnight here via email, but I think we'll go to the phones first. Marvin, if there's some questions folks have queued up for some questions. We'll take those now.

Operator

Thank you. At this time, we'll conduct a question and answer session. Our first question comes from the line of Aaron Prokoski of TD Cowen. Your line is now open.

Speaker 2

Thanks. Good morning. So my first question is, one of your deep basin producers has been seeing capital efficiency benefits as a result of using higher resolution seismic data. I guess my question is, is this something that you've been doing as well? And if not, do you see there being opportunity here to unlock?

Speaker 1

Sorry, hi, Aaron. It's higher resolution seismic data. Is that what your question was?

Speaker 2

Yes.

Speaker 1

We've always used seismic data to help guide us, not only on especially on the fluvial channel systems in the deep basin, but also for structural reasons to help us understand structural elements of the play. I'm not sure about the high resolution part of that equation. We've always used seismic as a tool. It's not the only tool we use. Of course, we've got lots of well control as well.

Speaker 1

So we actually put marry those 2 together to make decisions on drilling wells and to reduce risk. So from our perspective, whether it's high resolution or just typical seismic data that we use 3 d always generally is something that we continue to employ and will sort of aid us, but it's not the be all end all to the solution to making deciding where a well is going to be drilled, for example.

Speaker 2

Thanks, JP. Can I follow-up with a slightly different question? It seems like there is a looming rail strike that could start in the next week or so. If rail service was out for, say, a week or 2, do you see that having an impact on your business in terms of frac sand availability or the ability to move liquids? Just any color you could provide would be interesting.

Speaker 1

No, I don't think we see we're aware of the strike depending or the potential for a strike. We don't see an impact on our business. I don't think it would last very long. A lot of industry will be a lot of other industries will be affected, one that might get a little more attention from federal government than ours to resolve the issue certainly. But no, we have enough products.

Speaker 1

One of the things is NGLs, a lot of NGLs move on rail, but we put those into those generally go into storage. So there's time there to store these things. We also have storage on-site for our NGL should be a challenge there. And if it really lasts a long time that we would be looking at warming up our plants and reducing propane. It's really propane that runs on rail for the most part of the province.

Speaker 1

So I don't we don't see an impact on a rail strike here at this time.

Speaker 2

Perfect. Thanks, JP.

Operator

Thank you. One moment for our next question. Our next question comes from the line of Chris Thompson of CIBC. Your line is now open.

Speaker 3

Hey, good morning, everyone. Thanks for taking my questions here. Just the first one on managing your capital and building that productive capacity. I mean, when we look back at some of your disclosure through the year thus far, It looks like you might have about 9 drilled and uncompleted wells that have been added to the inventory. So just wondering if we can talk through a bit of color on that.

Speaker 3

And then sort of as we get into closer to Q4, can you help us quantify like how many wells will you have sitting ready to come on production in a better price environment?

Speaker 1

Yes. Hi, Chris. Thanks for your questions. As far as managing the inventory, we have about 10 DUCs right now to answer your question. And as far as how we manage those, I mentioned that we might we likely will bring them on at least at some rates.

Speaker 1

So I don't see us having a large amount of DUCs. It will be more that we have other chokes and wells back and we've shut in some other production that's probably less economic. In fact, I think we have some production right now that goes to third party about 500 BOEs a day, Todd. It goes to 3rd parties where we have higher cost structure. So those are the things.

Speaker 1

And so it's really more about managing the existing production, the new wedge of production that comes on be choked and or shut in depending. We want to do some testing here while we got the chance, right? And so we'll do that to check to test the gathering Back out is always an issue for us because we've got a lot of legacy production that is habituated to certain pressures in the system. So we're always set to see how wells respond to that and this is giving us an opportunity to do that. So wells will come on and come off.

Speaker 1

And so this productive capability we're going to build, it's hard to give it's hard to point to a number like what is that value. But like I said, we expect to we will still exit this year at 135,000 and that's despite the fact sorry, 135,000 by the end of the year. That's despite the fact that we've actually taken out roughly 2,000 barrels plus some gas from the sour unit out of our base decline, right?

Speaker 3

Right. Okay. Yes. And then I guess just thinking about the shape of that profile, you've previously talked about maintaining relatively flat production through Q3. Just wondering if that's still the intention and therefore we sort of new backlog volumes sort of somewhere between $50,000,000 maybe $1,000,000 come out in line.

Speaker 3

So any guidance around that would be helpful?

Speaker 1

Yes. So we said we were keeping production flat. And we're keeping production flat to basically minimize any exposure to the AECOEMPRIS market. I always say we don't have AECO exposure and we don't. We have it's mostly we can sell it at Empress, but the Empress market is really not has not disconnect or is basically selling the same price as AECO.

Speaker 1

So we're not there's no value in that. So really how we're managing production right now is at a state where we're going to continue to deliver obviously our hedged volumes and then anything above that is going to go to our diversified locations, which is another $150,000,000 and if you include Cascade in that $160,000,000 so in total, sorry there. And so when you add that all up, that's where we get sort of 122 level in our current mix of gas and liquids. So we'll maintain that roughly that level until we see prices improve. And that right now, if you look at the strip, there's quite a difference between October November.

Speaker 1

We expect those prices will obviously come in, but there's a dollar difference at AECO right now when you look from October to November. So October does turn out to just be a dollar then we'll defer the production ramp up to November, whatever it takes, right?

Speaker 3

Okay, got it. Yes. I guess is there in terms of historically Peyto has always guided an exit rate. If pricing remained weak, I mean is there a time where you'd look to updating the market in terms of how you're thinking about those exit volumes?

Speaker 1

Yes, of course. I think we are next time we'll be on the call here in November I'll be a likely time to do that if things were to fall apart as we're assuming.

Speaker 3

Okay. And then just a bit of a different question here. With respect to cash taxes, it looked like sort of your cash tax rate for Q2 versus pretax cash flow was quite light versus Q1. Just wondering how you're thinking about that average tax rate through the rest of the year?

Speaker 4

Hey, Chris, it's Tavis Carlson here. So we manage the current tax provision based on a year to date standpoint. So with the soft prices that we've seen in Q2 and the outlook for Q3, we've lowered our kind of taxable expectation for the full year. So if you look at year to date, we're about 10% on before tax cash flow. So that's probably the best kind of range to go at looking forward for the rest of the year now.

Speaker 3

Okay. That's helpful. Thanks, Tavis, JP, and I'll hand it back.

Operator

Thank you. I'm showing no further questions at this time. I'd now like to turn it back to JP Lachance for closing remarks.

Speaker 1

Yes, okay. There's a couple of questions that have come in about just about a little more looking for a little more color on that Will Ridge program that we mentioned in the press release that we drilled recently through the quarter. So, I'll get Riley to elaborate on the Will Rich results we drilled particularly on the Repsol lands in the quarter. Riley, do you want me? Sure.

Speaker 1

Yes. So I think some of

Speaker 5

the results we've been getting from the Repsol lands and the Wellridge are worth highlighting a bit. Particularly the Sundance Willerich program really stands out. So over the years, we've developed the Willerich and Sundance pretty extensively. But with these new lands, we're actually seeing some

Speaker 1

of the best results that

Speaker 5

we've actually ever achieved. We've talked about in the past how we're able to apply all the stuff that we've learned over the years, horizontal drilling to these new lands. And what we're seeing is this is a good example of applying modern wellbore design to some really premium reservoir and the early time results for these wells are coming in at nearly 2 times the average 1 mile result from just several years ago. So really seeing some great results. And the other nice thing here is we've got a lot of inventory in this particular place.

Speaker 5

So we're really expecting to be able to continue to lean on this and drive some really great results rate in Payless core area.

Speaker 1

Okay. Thanks, Riley. Yes, good color. And I have one other question here about the sweetening project. Maybe, Todd, you could elaborate a little bit more on what are the impacts of this and maybe from the perspective of operating costs and maybe even production a little bit of what you see from an impact.

Speaker 1

Obviously, this is moving the needle towards the 10% reduction by the end of the year and this is part of that project, it's not included in our Q2. So this is a Q3 initiative that you guys have we did a little early because prices were bad and we had some it didn't make sense to continue to operate that facility. So we did accelerate it. It's maybe savings a little bit on the turnaround. So maybe you can elaborate more about this whole suite thing, what we've done.

Speaker 6

Yes, sure. So as far as the production majority of that coming from the Elkton unit and then some from some wells sort of up north in the area we call Berland. So as far as a reduction in operating costs, we're estimating on a full year, it's probably 5% reduction. And that would equate to about $0.03 per Mcf fee, say, for we're modeling for 2025. So some of that will manifest in Q3 and Q4.

Speaker 6

Obviously, there's some capital costs and operating costs to shut down the aiming plant, the aiming process, the sulfur process, that sort of thing. There's work to be done on the CFGGS as that gets sweetened. We'll have to we'll be able to take some EFDs offline that actually caused us quite a bit of grief last winter when it got cold. So it will be nice to have some reliability on that. So yes, we would expect to see kind of in the back half of the year given that the plant came down, the sour side came down in sort of early July that we'll start to see some operating cost reduction for sure that will help to get us to that 10% target.

Speaker 6

It gives us good visibility that we'll we're pretty confident that obviously you've got safety costs, carbon tax will manifest next year, but and high maintenance costs on some of that stuff that's not running anymore. So pretty confident that we'll see that will be a good part of the reduction. Great.

Speaker 1

Okay. I'm just going to turn it back to the operator here for another

Operator

I'm showing no further questions at this time. I would now like to turn it back to JP Lachance for closing remarks.

Speaker 1

Okay. Thanks everyone for tuning in. I realize it's vacation time, so some of you folks may not be even in the office these days, but I appreciate it. Are you off to the cottage somewhere? So thanks for tuning in live and we'll talk to you again next quarter.

Operator

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.

Powered by Quartr
Earnings Conference Call
Peyto Exploration & Development Q2 2024
00:00 / 00:00