Thanks, Latif. Good morning, folks, and thanks for joining Peyto's third quarter 2025 conference call.

Before we begin, 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. Here in the room with me is Riley Frame, our COO; Tavis Carlson, our CFO; Lee Curran, our VP of Drilling and Completions; Todd Burdick, our VP of Production; Mike Collins, our VP of Marketing; Derick Czember, our VP of Land and Business Development; Kathy Rife, our VP of Finance; and Mike Reese, our VP of Geoscience.

Before we discuss the quarter, on behalf of this group here and the management team, I'd like to sincerely thank the entire Peyto team, both here in the office and in the field, for their contributions to yet another strong quarter. We had a busy quarter that has carried on through into Q4.

July was a little wet, somewhat unusually wet, and that slowed our activity in the month down a little bit. We had some plant turnarounds, we built and started up a new field compressor in Sundance, we added a fifth rig, we shut in some gas in September due to low prices, and most recently we extended our credit facility, and that's just to name a few things.

Corporately, production per share was up 5% compared to Q3 last year, relatively flat quarter-over-quarter production at approximately 130,000 boe a day. Our cash costs of $1.21 per mcfe, or $1.13 per mcfe without royalties, were down to their lowest levels since we purchased the Repsol Canada assets in the fourth quarter of 2023.

That's not just unit costs due to some production dilution, that's absolute costs as well. AECO 7A prices averaged a mere 94 cents per GJ or about $1.08 per mcf when you account for the heat content of our gas for the quarter.

Our strong hedge book added $87 million of gains, or about $1.38 per mcf for gas, and our marketing diversification contributed another $1.11 per mcf, yielding $3.57 per mcf all-in realized natural gas price, which equates to about 3.3 times that of AECO for the quarter. Putting all these elements together resulted in funds from operations of nearly $200 million, or 98 cents per diluted share, and that's up from 29 up by 29% from Q3 last year or 26% on a per-share basis.

We also achieved a top-tier operating margin of 72%, with a profit margin of 29%, and which at the end of the day, we feel is the most important. After all, it's generating profits, right?

It's those profits that we can return back to our shareholders in the form of dividends, which we paid out 33 cents per share in the quarter, or a total of $66 million. We spent $126 million of capital in Q3, up from previous quarters, and that's mainly due to the addition of the Sundance compressor station, the addition of a fifth rig later in the quarter, and the Oldman plant turnarounds.

Nevertheless, our payout ratio was just under 100%, and we were able to pay down a little more net debt of $20.5 million, bringing our year-to-date net debt repayment to $126 million. I think, more importantly, the increase in capital activity in late Q3 allows us to increase production into Q4 and Q1 and capitalize on improving winter price.

Let's talk a little bit about our operations during the quarter, and so far into Q4. We had a couple of minor production interruptions in the quarter with planned Oldman turnarounds and some gas that we elected to shut in when prices went negative.

We also brought on a new field compressor in Sundance, which added some gas by pulling down the gathering system pressure. We brought on another rig in Sundance to help us catch up on the activity delayed from the wet July.

Our drilling program shifted to the Pekisko, Notikewin/Falher, and Bluesky species in the third quarter, and we're now drilling and completing what we expect will be the most productive wells of the 2025 program. We don't advertise individual well rates, but we expect that the wells that we just drilled in the second half of 2025 will to outperform those from earlier in the year, such that our full-year vintage production curve should look a whole lot like 2024.

That really relates to the complexion of the species in the second half as compared to the first half. Of course, it isn't just the rates that matter; it's also the amount of capital that we deployed to achieve them, and we expect that these wells will rank as some of our highest rates of return projects this year.

What does all this mean? I expect we're going to set a new production record for the company in November, and we're well on our way and very comfortable to reaching our target of 140,000 boe per day exit for December, which correlates to the midpoint of our guidance of capital spending.

Also subsequent to the third quarter, we renewed and extended our credit facility for another four years. We rolled in what was left of the term loan that we put in place for the Repsol acquisition, our new revolving credit facility now stands at $1.05 billion, of which we were drawn $745 million on closing of that extension.

We still have approximately $491 million of long-term private notes that mature at various times over the next nine years. When you take all this together, it provides Peyto with a strong liquidity position to execute our business plan.

It also shows the support of our lenders to Peyto's business plan and to our strategy. I mentioned that we shut in some production in September, not because we were exposed to low AECO prices, our hedging and downstream diversification protected us from that, but because it made sense to have someone else pay us to take their gas, which we then used to fulfill our physical contracts and preserve our gas for better pricing in the future.

Our diversification to other markets allowed us to gain a premium price of $1.11 per mcf, as I mentioned earlier, over AECO, and that's net of the costs to get to those markets. Our physical and synthetic service to Henry Hub, Chicago, Dawn, Parkway, Ventura, and the Alberta power market all contributed to this gain, and we expect them to continue to contribute meaningfully into '26 based on the current strip.

We've released our preliminary capital budget for 2026. We plan to invest between $450 to $500 million of capital next year to drill between 70 to 80 net wells.

This program should add between 43,000 to 48,000 boe per day by next December, and more than replace our estimated 26% to 28% corporate production decline over the year. If this sounds a lot like '25, it is.

I guess the key difference here is that we plan to continue drilling with five rigs in the first half of '26, which should change the production profile, and the capital profile, to be a little more front-end loaded than in the past years. We can apply the brakes and slow down the program in the second half if prices or the business environment warrants it.

Conversely, we can keep it going with five rigs and aim for the high end of the guidance if that makes sense. This plan is consistent with our outlook on natural gas prices in 2026.

The preliminary program has us spending about 80% on new wells, with the rest going towards pipeline and plant optimizations. These projects will be undertaken to improve plant reliability, lower our costs, and debottleneck field gas gathering systems to accommodate new drilling.

We also have some minor plant turnarounds planned for later in Q3 next year, when prices tend to be the weakest, and maybe we'll get Todd to expand on with some details on that later. We will firm up the capital budget in February with our reserves release, which should also coincide with the full ramp-up of LNG Canada if it all goes well.

In closing, we think was an excellent quarter, and as we look forward, we're well positioned to grow modestly, 5% to 10%, with enough cash flow not only to fund the capital program, but to return dividends to our shareholders and to continue to pay down debt over the next year. This is thanks to our proven business strategy: to keep the costs that we control as low as possible, while protecting the revenues in the near term with our disciplined hedging strategy and derisking our sales markets to gas demand regions.

This is manifested in stable, long-term returns to our shareholders over the last 27 years, and we aim to continue that. I don't think there's been a more optimistic time in the natural gas market with all the positive demand growth from both recent and future LNG buildouts in North America, and the increasing appetite for power generation from gas in both US and Canada.

Heck, it looks like we've even got a little support from our federal government to the industry, and I think Peyto is well positioned to take advantage of these exciting times. I think there's probably some questions, Latif, for asking if anybody's waiting.

If not, we have some questions that have come in through email overnight.

We'll go to some questions that I've received via email. This one comes from Chris Thompson of CIBC.

He couldn't make the call here this morning. One of his questions is: would Peyto continue to hedge gas volumes on forward strip given AECO basis remains wide for the foreseeable future, and do you believe that the basin is entering a period of increased production discipline given producer hedge books are rolling off and operators have an increasing exposure to AECO?

I'll answer the first part of that. I normally would look to Mike here, but Mike's also having some trouble with his voice this morning, I'll try and do my best.

Mike, you can squeak in if I miss an important point. I think when we look at the business, we've always run the business prudently, and I think when we think about the business of hedging, we're going to continue to be, our disciplined risk management program, we're going to navigate the stormy waters of AECO with care.

We know this is a volatile market, don't plan to change our hedging strategy. As everyone knows, we have the guardrails which we can land on between when we get to a certain season.

We'll continue to run the hedging program as we always have. I don't know about the increased production discipline.

I can't speak to other producers, and I don't know about other producers' hedge books and whether they're rolling off and what their exposure is or isn't to the market. I do know that we don't change our strategy year-over-year around that.

I guess we have some minimums that we'd like to accomplish. Mike, and I think that's, obviously, it's minimum prices that we want to see.

We recognize that future prices are down a little bit from where we've been able to hedge. We've still taken some of that off the table.

It's a price that works for us, and we'll continue to do that. I would say our hedging strategy hasn't changed and won't change in the near future.

Another question Chris had was on our 2026 goals for cash costs and what are we thinking and how will we achieve those goals. I think simply there are two things that we're going to work on here.

One is opex, and we'll always work on opex, it's relentless pursuit of reducing those costs. The other one is naturally interest costs will come down as we pay down debt over the next year.

Interest costs will come down on a per-unit basis. Maybe, Todd, do you want to elaborate on We've got some plans for next year on our facility capital.

Maybe you can tie that into maybe how that helps us reduce our costs. I would say all in all, the target that we're looking at for cash costs for next year should be somewhere around 10% reduction, excluding royalties, of course.

Maybe, Todd, do you want to comment on the operating costs?

Sure. Obviously, we have a number of facility and pipeline projects on the go for next year, which will allow us to I guess see as much of the new wells that are drilled, which will help obviously with opex dilution just through the increased production.

As well, we've been working on a lot of labor, I guess efficiencies with the Edson plant and some of the other integration pieces that we've been able to spread out some of the labor amongst the field, which we're starting to really see bears fruit. As well, we've seen chemicals kind of come down a little bit.

We're hoping that that's going to continue or at least stay flat, which has really helped. Weather has helped a little bit, but obviously through the winter months when pricing typically goes up through this time, we're kind of seeing things hold flat, which is a good sign in the chemical market.

With those two things and sort of I guess our ongoing little pieces that we work on, we expect to see a pretty good drop, like you say, around 10% over next year versus what we've seen so far this year.

Thanks, Todd. I see there's a question there.

Do you want to go to the phones there, please, Latif?

thanks. Good morning, guys.

Just had a quick question on that fifth rig. I think, if I heard you right, in the capital budget it's essentially in the year for half a year, and I'm just curious what kind of spot gas price you'd need sort of to keep it for the whole year, and if you do, how much additional capital we can think about or additional production we can think about if the rig's extended from half a year to full year?

I think the difference with our capital program for next year than this past year is that we're going to front-end load a little bit more, and I'll get Riley to speak to what that means. Essentially, what we're suggesting, we're very happy, first of all, with the rig and how it's operating, we feel like keeping it running.

Last year, with a rig on a window, had to drill a couple of wells, but it couldn't stay there because we would have filled up that plant. Couldn't really effectively use it, but we're down in Sundance right now, things are going well, we'd like to keep it running.

We're going to do that, and that just changed the complexion of the loading. Maybe we'll talk about that first.

The price trigger, I think, God, there's so much more than just the price. It's what have we been able to hedge, what are our cost situations, there's a lot that goes into that.

I wouldn't say there's necessarily a price trigger, but if we kept the five rigs going all year round, that's all through the whole year, that's the high end of the guidance essentially. Removing it somewhere in the middle of the year, should we decide to, would get us towards the midpoint, I would suggest.

Riley, do you want to talk about the complexion of the program and maybe how it's loaded?

The complexion of the program from a sort of an area and species perspective is going to be very similar to what we did this year, and just due to the D&C and non-D&C capital allocation is very similar. As it pertains to sort of the capital program for the year, as we're hitting towards that midpoint of guidance, we'll see it being sort of a 55% capital front-end, 45% capital back-end loading.

Then, yeah, depending on how the year goes and, obviously prices playing a role in that, that could shift to 50/50 if we end up going to the high end as we bring on more activity in the back end with the fifth rig. Yeah.

The production profile will then sort of look that similarly. As opposed in the past, we've had more of a decreasing production profile in the sort of middle quarters because of activity.

Now, we're going to probably build that production profile a little steadier over the year, which is what I think you'd see in our corporate presentation materials for '26. If that helps.

No. Absolutely.

No, that helps, JP. Then just a follow-up question in terms of the cadence of the operating cost improvements you're thinking for '26, is it more tied to the looping projects at Sundance, is it going to be more of a step change at a certain point in the year, or is it sort of gradual as the year unfolds?

We have some projects that are planned that are optimizations at the plants, those are the ones that'll typically help with that. Other than the production growth itself, considering.

We were stung a little bit in Q2 as we didn't expect the government costs now are roughly 30% of our operating costs, which is significant, right? That's the AER fees, that's the fees to pay the orphan well fund, that's property tax, and that's carbon tax.

We didn't have enough in our budget for the property tax in Q2, we went up in Q2. I don't know what surprises are around the corner, but as far as what we control on that side, it'll be the projects that Todd just discussed.

Typically, costs go up in Q1 because it's cold, and we use more chemical, and costs decline as the rest of the year progresses, and that's what I think you can expect on the profile. Go ahead, Todd.

If I can add

on your point on government costs, and fixed costs in general, which is a lot harder to drive down yearly, they're 60 65% of our total opex. We've only got 35% of that opex that we are really able to play with, and when you look at 50% off opex, that means you're talking 15 16 cents that you can really control a lot more effectively than things like property tax going up higher than you thought or orphan well levy or AER admin fees or things like that.

Then just to clarify, should we be thinking about a 10% reduction to your average cost from this year, which is 54 cents, or 10% reduction from your current cost of 51 cents?

I'd say the all-in cost for the year, year-over-year. Quarter-over-quarter is a tough one to call, right?

Like I just mentioned, because it can vary. Year-over-year.

Sounds good. Thank you.

I have another question. If there isn't a question on the phone, I have another question that came in, we had some pretty low royalty rates, and I think that's one of the things we'd like to highlight.

It was obviously, was it 2.6% for the quarter. I just want to ask Tavis how we see the complexion of our royalty rates going forward and what's sort of behind that 2.6%, cuz it's obviously pretty low, one of the lowest in the industry.

JP. There are a few factors that contributed to the low royalties for the quarter.

Firstly, low AECO, again. We were 90 cents on a 7A basis, I think, or 94 cents, I think AECO was 60 cents per GJ.

AECO is really what drives the Alberta reference price that the Crown uses to charge us royalties. Then secondly, we have a lot of our volumes diversified away from AECO, we're getting really strong prices in the US Midwest, in Dawn, Henry Hub, and those additional revenues that we're getting really aren't royaltied the same as the AECO stuff, right?

Right, Tavis? Right.

Then, it would be increased gas cost allowance credits. Those went up in Q2, and we're going to see those for the next three or four quarters.

Then, we also had lower NGL royalties from the decline in WTI and NGL prices. I guess, lastly, would be just we have lower other royalties.

We haven't done any wide-sweeping overriding royalty deals on our lands, our other royalties are probably less than 0.5%.

Besides Crown royalties, we're not encumbered with other royalties, and I think that's a testament to the way we run the business, you pay me now, pay me later scenario, I guess, when you think about it if we had done that. I guess we always think of royalties as not being a controllable cost, but in that sense, it would be if we were to burden our lands with a bunch of overriding royalties to others.

That's about 0.5% you said, roughly, Ron, right? What's our overall run rate going forward here do you think was a reasonable expectation given the strip?

I think for Q4, we're going to be in the 4% to 4.5% range. Next year, though, with the price of strip, we'd probably be modeling more like 5%

to 6%. Right on.

Great, Ron. Back to the phones, if there's another call on the phone, we can take that.

Thank you. This is sort of a macro question, but part of our bull story for natural gas is the increased North American exports of LNG.

There's also some talk of a surplus later in the decade of LNG. Would that ever work against us in terms of North American pricing?

I guess if you're referring to the fact that you might have too much LNG and it gets backed up onto the continent, and of course, that would have a negative impact on pricing out in the future if that's where you're going. I think we've seen certainly the US producers have a lot of discipline in that regard to reacting to that with supply cuts and what not, so that's the big market, right, that'll be if that would be affected.

In Canada here, we're working towards more export capabilities to help our local market, and that's encouraging as we think forward beyond just this year. With LNG Canada slow to getting going here, but then we also have other projects on the com, it's good for the overall future out there.

That's one of the reasons, Mike, we think about hedging, and we think about taking that risk down, and we want to be exposed to different markets so that we can weather those storms, and we feel that they'll be shorter term, and we can weather those storms when we've had an active and continue to have an active hedging program. We still believe gas will be one of the most volatile markets, and we want to be able to smooth those revenues out, right?

Smooth out that volatility.

Right. Thank you.

Thanks, Mike. Any more questions on the line?

Thank you very much for participating in the call. Appreciate the engagement and the involvement, and we'll see you next year.