Peyto Exploration & Development Corp

TSX:PEY

Earnings Call Analysis

Peyto Shows Strong Performance Amid Low Gas Prices

Peyto generated $155 million in funds from operations and $51 million in earnings in the second quarter, despite low gas prices, thanks to their hedging program which realized $68 million in gains. The company benefited from industry-leading low cash costs and maintained a strong operating margin of 62%. Peyto saw a 30% increase in well productivity in newly acquired lands, and reduced operating expenses by 5% with a goal of a 10% reduction by year-end. They plan to spend $450 million this year and target a year-end exit of 135,000 BOEs per day.

Peyto's Strong Performance Amid Low Gas Prices

In the second quarter of 2024, Peyto delivered a commendable performance, generating $155 million in funds from operations and $51 million in earnings. This success came despite facing the lowest gas prices since 2019, primarily due to a well-implemented systematic hedging program that resulted in $68 million in gains. The company's operating margin stood at an impressive 62%, showcasing its ability to manage costs effectively in a challenging market.

Drilling Program Success and Productivity Gains

Peyto's drilling program has demonstrated remarkable efficiency, with an average lateral length of over 2,300 meters achieved in recent operations. This is indicative of the company's commitment to maximizing productivity. The newly acquired Repsol lands have proven particularly fruitful, yielding a 30% increase in average well productivity compared to previous legacy programs. Early results are impressive, with new wells achieving nearly double the output of older drilling techniques. This bodes well for future revenue generation as more wells come online.

Cost Management and Future Guidance

In terms of cost management, Peyto is on track to meet its objective of a 10% reduction in operating expenses per Mcfe by year-end, having already achieved a 5% reduction in Q2. The cash costs per Mcfe were reported at $1.50, going down to $1.24 when excluding royalties. Looking ahead, the company estimates royalty rates will range between 7% to 8% pre-hedged sales revenue, or about 5% to 6% when factoring in hedge gains.

Production Strategy and Future Outlook

Peyto aims to exit 2024 with production levels around 135,000 BOE per day, despite having to account for a slight reduction in operating capacity due to maintenance activities. The company has around 10 drilled but uncompleted (DUC) wells ready, which it plans to bring online as market conditions improve. For the rest of the year, Peyto will focus on flat production to shield itself from current unfavorable gas prices, while managing production strategically to maximize returns.

Dividend Confidence and Hedging Strategy

Peyto's disciplined hedging strategy provides a substantial safety net, with gas prices hedged above $4 per Mcf for 2025 and 2026. This strategy allows the company to cautiously plan capital expenditures while still committing to returning dividends to shareholders. The recognition of growing natural gas demand due to increased industrial usage and upcoming LNG projects reinforces the confidence in Peyto's long-term outlook.

Innovative Projects and Future Potential

Peyto is also exploring innovative projects like the shutdown of its sour gas sweetening facility, which is expected to reduce operating costs by 10% by year-end. Although the company temporarily shut in production from some wells during maintenance, the long-term benefits include enhanced reliability and reduced operational costs, supporting further growth in a competitive market.

Conclusion: Strong Position for Future Growth

Overall, Peyto's solid financial performance amidst low gas prices, focus on operational efficiency, and strategic planning position it well for future growth. The company remains optimistic about the evolving natural gas landscape, ensuring investors are not just buying into current performance but also the promising trajectory of Peyto's operational capacity and market strategy.

Earnings Call Transcript 2024-Q2

[Operator]

Good day, and thank you for standing by. Welcome to the 2024 Second Quarter Peyto's Financial Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, JP Lachance, President and CEO. Please go ahead.

[Jean-Paul Lachance, executive]

Thanks, Marvin. Good morning, folks, and thanks for joining Peyto's second 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 to answer your questions in the room here is Riley Frame, 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 Derick Czember, 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. 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 million of funds from operations and $51 million of earnings, in large part due to our systematic hedging program, which realized $68 million in gains, along with our industry-leading low cash costs.

And a reminder that our mechanistic hedging program is designed to derisk 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 million in hedge gains since we started. 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 second quarter, mostly Wilrich 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 quality program perspective. We were set up on 3-well pads for the most part through Q2 during what was typically -- it 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 onstream 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 in the newly acquired Repsol lands. We had 21 wells on stream to the end of Q2, with enough history that shows a sustained 30% increase of average well productivity as compared to the performance of recent legacy programs. These wells were drilled in the Wilrich, Falher, the Notikewin, and they were drilled over a large portion of the Repsol land base. And that's important because it provides us confidence that it 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 design to drill and complete them.

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. Going forward, we expect our royalty rates to be around 7% to 8% on a prehedged 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.

Peyto continues to have the lowest cash cost in the business and nice 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, and we're pleased that we are basically on target with that goal, having reduced 5% in the second quarter 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. Didn't know 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 basically we are saving third-party fees and increasing the plant utilization at the Edson 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, not about BOEs. Along the same vein, we recently shutdown the sour gas sweetening side of the Edson gas plant, although we had some third-party income coming in from that, it wasn't enough to offset the cost to run and maintain that part of the plant. We want to mention, running it impacted plant reliability, higher emissions and slightly higher safety risk to operate sour gas, of course. We had to shut in a small amount of our Peyto net 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 -- 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. 2 of those Sundance rigs are on the former Repsol land. We have a steady diet of Notikewin wells for the balance of the year, along with several Dunvegan, Wilrich and some Falher wells 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 [indiscernible] projects and build productive capability for later when we expect prices to be better. We're still planning to spend around $450 million this year at the low end of our guidance, and we're targeting a year-end exit around 135,000 BOEs a day, of course, assuming prices cooperate and the improvement there is as we expect.

As mentioned in the release, in 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 or 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. Natural gas is a reliable, critical fuel 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 disruptive for both gas prices and of course, our power deal.

Specific to Peyto, 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. The prices that are at or above $4 an Mcf. As I mentioned earlier, we hope prices will 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. They have -- we have room to grow without large infrastructure cost to expand. So despite the current gas price environment, things looking pretty good.

So I imagine there's some questions. We have a few come in overnight here via e-mail, but I think we'll go to the phones first. Marvin, if there's some questions -- folks have queued up for some questions, we will pick those now.

[Operator]

[Operator Instructions] Our first question comes from the line of Aaron Bilkoski of TD Cowen.

[Aaron Bilkoski, analyst]

So my first question is, one of your deep basin producers have 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 be an opportunity here to unlock?

[Jean-Paul Lachance, executive]

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

[Aaron Bilkoski, analyst]

Yes.

[Jean-Paul Lachance, executive]

We've always used seismic data to help guide us not only in our -- especially on the fluvial channel systems in the Deep Basin, but also for structural reasons to help us understand the structural elements of the plant. I'm not sure that -- I'm not sure about the high-resolution part of that equation. We've always used seismic as the tool. It's not the only tool we use. Of course, we've got lots of well control as well. So we actually put -- marry those two 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, 3D always generally, is something that we continue to employ and will sort of aid us, but it's not to be all end all the solution to making -- deciding where a well is going to be drilled for example.

[Aaron Bilkoski, analyst]

Can I just 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.

[Jean-Paul Lachance, executive]

No, I don't think we see -- we're aware of the strike -- the pending 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 our federal government than ours to resolve the issue certainly. But no, we don't -- we have enough, enough products. One of the things is NGLs, a lot of NGLs move on rail, but we put those into -- generally go into storage, so there's time there to store things. We also have storage on site for our NGLs should there be a challenge there. It really lasts a long time that we've been looking at, warming up our plants and reducing propane. It's really propane that runs on rail for the most part of the province. So I don't -- we don't see an impact on a rail strike here at this time.

[Operator]

[Operator Instructions] Our next question comes from the line of Chris Thompson of CIBC.

[Christopher Thompson, analyst]

Just the first one on managing your capital and building that productive capacity. I mean when you 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. 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?

[Jean-Paul Lachance, executive]

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 rate. 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 a third party about 500 BOEs a day, it goes to third parties where we have higher cost structure. So those are the things -- and so it's really more about managing the existing production, the new edge of production that comes on will likely be choked and/or shut in depending. We want to do some testing here while we got a chance, right? So we'll do that to check -- to test the gathering system, back out is always an issue for us because we've got a lot of legacy production is habituated to certain pressures in the system. So we're always sensitive 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. And so this productive capability we're going to build, it's hard to give -- just hard to point to a number, like what is that value. But like I said, we expect we will still exit this year at 135. 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?

[Christopher Thompson, analyst]

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 volumes sort of somewhere between 50 million and 80 million come out in the line. So any guidance around that would be helpful.

[Jean-Paul Lachance, executive]

Yes. So what we said we were keeping production flat. And we're keeping production flat to basically minimize any exposure to the AECO/Empress market. I always say we don't have AECO exposure. And we don't we have -- it's mostly [indiscernible] the Empress, but the Empress market has really not -- is basically selling the same price as AECO. So we're not -- there's no value in that. So really what -- 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 million. And if you include Cascade in that, 160 million, so in total story there. And so when you -- as at all -- that's where we get to sort of 122 level 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 and November, we expect those prices will obviously come in, but there's a $1 difference at AECO right now when you look from October to November. So October does turn out to just be a $1, then we will defer the production ramp up to November, whatever it takes, right?

[Christopher Thompson, analyst]

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

[Jean-Paul Lachance, executive]

Yes, of course. I think we -- next time we'll be on the call here, it will be November, and I'll be likely trying to do that if things were to fall as what you're describing.

[Christopher Thompson, analyst]

Okay. 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?

[Tavis Carlson, executive]

Chris, it's Tavis Carlson here. So we manage the current tax provision based on our 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 to [ progressing ] now.

[Operator]

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

[Jean-Paul Lachance, executive]

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 Wilrich program that we mentioned in the press release that we drilled recently through the quarter. So we will get Riley to elaborate on the Wilrich results we drilled, particularly on the Repsol lands in the quarter. Riley, do you want...

[Riley Frame, executive]

Sure. Yes. So I think some of the results we've been getting from the Repsol lands and the Wilrich are worth highlighting a bit, particularly the Sundance Wilrich program really stands out. So over the years, we've developed the Wilrich and Sundance pretty extensively. But with these new lands, we're actually seeing some of the best results that 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. So we're really expecting to be able to continue to lean on this and drive some really great results rate in those core areas.

[Jean-Paul Lachance, executive]

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 maybe from the perspective of operating costs and maybe production a little bit of what you see for normal impact.

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 Q3 initiative that you guys have -- we did a little early because prices were bad, and we had some -- it did make sense to continue to operate that facility. So we did accelerate it. It's maybe saving a little bit on the turnaround. So maybe you can elaborate more about this whole sweetening project.

[Todd Burdick, executive]

Yes. Sure. So as far as the production impact, it was just under 1,500 BOE that was shut in, majority of that coming from the [indiscernible] unit and then some from wells or 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 Mcfe safer we're modeling for 2025. So some of that will manifest in Q3 and Q4. Obviously, there's some capital costs and operating costs to shut down the [indiscernible] process, the sulfur process, that sort of thing. There's work to be done on the [indiscernible] 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. 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 cost 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.

[Jean-Paul Lachance, executive]

Yes, sounds great. Okay. I'm just going to turn back to the operator here for another rounds of question.

[Operator]

[Operator Instructions] I'm showing further questions at this time. I would now like to turn it back to JP Lachance for closing remarks.

[Jean-Paul Lachance, executive]

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 if you're off to [ college ] 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.