Thanks, Chris. Good morning, everybody.

As we've done in the past, we're not going to bother to read the press release or kind of give kind of scripted answers. We've had lots of questions, thank you very much.

A lot of the people that might be listening get our quarterly update that I do, and that's stimulated a bunch of different questions kind of more around the macro on natural gas and what's happening. We're happy to address those, I think we'll get to those pretty quick.

I think just a summary on the quarter, it was a case of natural gas prices being much better than last year, but still not at the level that we would like to see them at. I guess maybe we always want to see them higher.

I think a big reason for that is around the LNG. We've had LNG Canada on now for a year, but it's not been a consistent draw on the system.

That was problematic in July and August, which is when storage levels started to rise again because LNG Canada Phase 1 wasn't at its full capacity. We're starting to see indications again that it's heading back to full capacity like it was in June when it set export records for Canada for LNG.

Ideally, you're wanting to see a tanker leaving every couple days out of LNG Canada Phase 1. That hasn't been the case for the last six or seven weeks.

The two things we watch pretty closely is we watch the draws coming out of the Willow Valley and the Sunset Creek. I don't want to get too technical, but for those of you who are interested, just send me an email afterwards and I'll send you the link.

TC Energy is got a public website availability that you can actually see when Willow Valley is drawing. What that means is if Willow Valley has got gas flowing through it, that means that they're drawing off the NOVA system.

Therefore, natural gas is going to Kitimat, which is where the site for LNG Canada is. That's not always the case.

It's when it's at lower than full capacity or even lower than mid-capacity, if it's under a Bcf/d of exports, they can just be using gas directly from the producers that own LNG Canada and therefore not drawing gas off the system. We really watch that closely because as they ramp up their capacity, they then start to draw off the system.

Then that impacts the rest of the entire natural gas infrastructure because you're now pulling gas off that otherwise would be going into a crowded system and a crowded storage system. You can really see that if you look at the storage for the last summer.

You really saw it in June move, because in June, LNG Canada was at pretty much full capacity. About 1.8 Bcf/d was what they were exporting.

You saw that storage then started to drop. As longtime followers of the natural gas landscape know, storage is kind of the scoreboard as to what's happening between supply and demand.

You do not want to see storage at its peak in the summer months because then there's a risk that there'll be nowhere to put gas storage in the shoulder season, which is typically kind of in that August-October period, which we're now into. Right now, it doesn't look like we're going to have a full storage, which is good.

LNG Canada is now, as of the last couple days, Willow Valley started to show life again of gas pulling off, and so that's a good thing. It's positive, which is why gas prices are well over a dollar higher an Mcf in Western Canada than they were this time last year.

We're optimistic that things are turning the corner on that. As what I've mentioned before in these webcasts and in interviews, that 1.8 Bcf/d up to 2 Bcf/d, that's a big, big number when our entire country only produces 19 Bcf/d.

We're talking about 10% of all of our production coming on or off on demand. That's going to make a material swing.

That's something we're watching pretty closely. We had some questions about that.

We had another question was kind of just around our CapEx because we just announced a CapEx increase. This is something that shouldn't be a surprise to our shareholders or people that have been following us.

The Glauconite inventory that we picked up in the December '23 acquisition, we've been wanting to get after those well locations ever since we've owned those assets. That's been now two years.

Now, prices were weak, and therefore, if prices are weak, we're very highly correlated to AECO pricing, and therefore, our cash flow weakened with the lower AECO prices. We managed to drill the one well earlier this year.

These wells are typically between $8 million and $9 million all-in when you drill, and you complete, and you tie them in. We've got that one well, and I'll turn it over to Terry to talk about how it's doing.

We wanted to get another well done this fall. Luckily, our cash flow has improved this summer, as we talked about.

AECO's been a little bit stronger. WTI has definitely been stronger with the Mideast crisis and war situation.

We've seen WTI rise, and that's had a big impact on us. I know we're definitely thought of as a natural gas producer, as we should be, since about 80% of our production is natural gas.

In the last quarter, more than 50% of our revenue actually came from liquids. A big part of that was the 4-23 well from the Glauconite.

Maybe I'll pass it over to Terry to talk a little bit about the well results to date.

Sure. Thanks, Phil.

Appreciate it. The 4-23 well came on in middle of February, was cleaning up sort of towards the end of February.

It's been on pretty well continuously from March until right today, despite some third-party maintenance going on in the quarter. We've had it on almost 100% of the time.

From a financial perspective, from March until June, over that four-month period, those are the latest financial reports or financials we have, it's averaged 1,100 BOE a day. It's pretty well flat month to month, and it's performing very, very well.

It's in accordance with our type curve. It exceeds our engineering type curve.

I guess, more importantly, it's 50% gas, 50% liquids. The liquid exposure makes a considerable difference to Pine Cliff.

The volumes do too. It's pretty well 5% of our corporate production.

It's a good well. We're excited.

It's performing well, and we'd like to do more.

That ties up a good segue, Terry. Thanks.

We've got several questions here on kind of what does our increased CapEx mean going forward? That's a very legitimate question because our goal would be to continue to exploit the Glauconite well inventory, and frankly, our Pekisko well inventory as well.

Let's not forget that we've got some really good drill locations in Pekisko. The Glauconite is about over 50% of that production that comes on is liquids.

That is why the economics go around very strongly. I would direct you to our presentation on our website at www.pinecliffenergy.com.

You'll see kind of the economics of the wells, and both from a internal rate of return and also from a payback standpoint. At these prices, even with a weaker AECO price and with WTI prices being in and around that $75-$80 range, you've kind of got the NPV, in other words, the net present value of each one of those well locations is kind of that $8 million to $10 million range, and we've got 37 net locations to get at.

We're talking about $300 million to $350 million of inventory that's just sitting there. This isn't high-risk inventory.

This is inventory that's been very proven by a lot of well control in the area. It's a very active area.

It's definitely something that we want to get to a pace of development where we're drilling at least kind of two to four wells a year. It could be, if in the proper pricing environment, maybe that gets accelerated even further or we throw in some Pekisko wells at the same time.

At this level, we're not interested in issuing equity out at the current stock prices. We think things are going to get better on the AECO pricing for all the various reasons I set forth in the email that many of you would have got.

We're looking to increase that pace of development. These wells pay out, depending on the commodity price, kind of in between that 12- and 15-month period.

They're very quick paybacks, but they continue to pay. As Terry mentioned, the 4-23 well has been surprisingly resilient.

It will show decline at some point, but it hasn't yet, even though it's been online for getting close to half a year. Then our 1-27 well, you may remember, was a well that we had when we first did the acquisition.

We didn't drill it, but it came with the acquisition, but it just had come online. It's now in a stage of paying itself again, in other words, it paid itself out.

It's now for a second time. Then that's the attractiveness of these locations and why we want to get after those.

We've got to do that prudently. We're not going to ramp up our debt to do it.

We have to do this within our cash flow. Ideally, we'd like to probably even have drilled a second well this fall along with this Glauconite well.

If prices were to swing in our favor or if we were to do a transaction. We've had a lot of interest from people wanting to farm in on this area.

We're kind of reluctant to do that because we really like the ownership position that we've established. These are all things we look at all the time.

There's different ways to finance kind of a accelerated drill program, and we've considered I think just about every one of them. Initially, we got enough cash flow.

The board of directors approved us drilling another well this fall. Our goal would be to drill several, again, that two to four range next year.

If prices are stronger, then maybe we look at doing more. It is exciting because this is an area that really does deserve to have capital allocated towards it.

Then you've heard us speak about capital allocation before. We're very cognizant of the fact that our model lends itself to a free cash flow in rising commodity prices, especially on gas, but obviously also on oil.

Having a low-cost OpEx, having low G&A, having the low decline rate, all of those things help you generate more free cash flow. In a rising commodity environment, we've got that cash flow we can deploy as we see fit.

Now the dividend, we've kept the dividend going through this entire period. I think right now it makes more sense to allocate capital towards the drill program, and so that's what we've done for the remainder of the year.

One of the other questions we've got was around one of the concerns out there I think for natural gas producers is the impact of the El Niño effect, which is a weather pattern that is projected to have warmer temperatures for this winter. Maybe I'll pass it over to Kris to chat about our hedging program?

Thanks, Phil. We continue to actively manage our hedge book with the view of reducing volatility in our price realizations.

I would say as highlighted in the press release, I think you saw a continued evidence of that in our Q2 results, noting that our hedge and diversification strategy delivered an realized gas price of $2.38 an Mcf in Q2. That was a 47% premium to AECO 5A price of $1.62.

We're pretty well hedged for the balance of the year. We're about 41% for the balance of 2026 at $3.16, which is well above the market, and so provides good cash flow support to the operations.

While weather's hard to predict, it's certainly something that's considered in our thought process when we look and we think about our hedge program. If you look at Q4 through Q1, our average hedge is about 36% of our production at around $3.10.

Again, we've got a very good start on the winter, but we'll continue to potentially look to add more hedges where it makes sense on a go-forward basis.

Thanks, Kris. Another question we had was around kind of the make up of these Glauconite wells from a liquids perspective, and one of the questions I got last night was how much wetter are these?

In other words, what is the NGLs component of the wells? Maybe I'll flip that back over to Terry to discuss.

Sure. Thanks.

With regards to the wetness of a location, it will vary from location to location. It gets a little bit drier as you go west from east.

Our concentrated land position, we're still trying to vet it out a little bit, but I don't think it's going to change appreciably across our land base. I think we'll be fairly consistent on liquid production on our future wells as we are in our existing well.

From a condensate versus NGL makeup, initially the wells are about 20% to 25% condensate and NGL on the total BOE, and that'll taper down over time. The condensate value will come down over time, but initially, of the 1,100, we're about 20% to 25% condensate.

It is condensate, not oil.

Thanks, Terry. I think those of you who have been following our story for some time will recognize the fact that as these wells come on, each time they come on, it has an impact on on obviously our our liquids.

We've gone from, at one point, Pine Cliff was 96% natural gas weighted. With the acquisitions that we've done over the last few years starting in 2019, we did each of our the Alphabow, Apache, Certus acquisitions all kind of have added more liquids exposure, and clearly this drilling inventory is definitely liquid exposure with the with the majority of it.

Because of where AECO's at, it actually is even from a from a revenue and from a cash flow standpoint, it's even more than just the the percentage of the volume. It punches well above its weight because of the of where WTI is these days.

As for some of you may not be aware, WTI is very highly correlated to the condensate price that that that Terry mentioned. Quite often, condensate's actually even higher than WTI.

When you've got the lower Canadian dollar like we do right now at $1.39, that even has a greater impact on kind of what the Canadian dollar impact for onto our balance sheet is. A few more questions here.

One one of the questions was the asking us I'll just read it. It says that we've done 16 transactions in 14 years and we haven't issued equity in 9 years.

That's accurate. "With the Shell-ARC deal, LNG Canada Phase 2 momentum, and $22 billion of infrastructure announced in Q2, is the M&A environment starting to look interesting again or does the current strip suggest sellers are holding off?"

I think my own view is we're going to continue to see consolidation. The reference there is, for those who aren't watching really closely, Shell, which is obviously one of the largest oil and gas producers in the world, just recently announced an acquisition of ARC Resources, which is a was Canada's It was a $22 billion company, very heavily weighted towards natural gas and to condensate.

I I personally took that as a as a positive signal that that foreign investors that can put capital anywhere they want in the world were making significant investments into into Western Canada, and saw this environment as finally an environment that they could come back in and and deploy capital to. That's not been the case for 10 years.

We saw a lot of of US and international groups leaving the country from an investment standpoint. Now we're seeing a lot more interest of coming back to Canada.

I think that's, that goes to is a testament to the governments, both at the federal level and at the provincial level, welcoming back that foreign direct investment. We really, as a country, we really do need that foreign direct investment.

We can't get the projects that we're talking about building, the pipelines across the country, the LNG facilities, all of these things need a tremendous amount of capital, frankly, more capital than our country has. It's nice to see the foreign direct investment returning, and I think that one project Bringing it back down to a a a more a level for the juniors and for the intermediates in the space, the reality is that it's changed a lot in the last, I've been at Pine Cliff now for 15 years.

The There was a lot more junior capital energy pools available when I first started. I remember, you'd go to different cities to do marketing, and you would have a tremendous amount of interest, and you would have, days of meetings with different groups.

The reality is that that is not the case anymore. You've got a smaller number of pure energy investors.

You have a lot more generalist investors, and they, I believe, will come back to the the natural gas and to the energy space when they see the return of capital being deployed and the free cash flow that's being generated. That's already started.

I, I think that the everybody's balance sheets are in much better shape. There's a lot less companies in the sector, and I don't think that trend's going to going to stop.

Part of it is, as a junior company, and, we're 20,000 BOE a day, that at, 10 years ago, that would have been considered a decent-sized intermediate. Now we would be junior, a smaller compared to the rest of the market.

There's companies obviously smaller than us, but there's not a lot in the public domain that are smaller. Your regulatory costs, your just cost of doing business is has gone up, you know.

There's That's just the the reality. It's we continually look for assets that make sense or acquisitions or mergers that that would make sense to us as as shareholders.

That's that's been the constant theme ever since we've started Pine Cliff. Is it's all about what how do we make the shares more valuable?

If a transaction has the potential to make that make our shares more valuable, then we're definitely interested in it. We haven't done a transaction a material transaction now in a couple years, but that's not from lack of looking.

I think there is when you get this volatility in in commodity prices, it does make transactions more difficult. Like I said, we've done a a lot of transactions, and our team has been involved in at different places that they've worked in a tremendous amount of transactions.

It You almost need some a little bit of stability in commodity prices to help get transactions across the board because it's really difficult right now. For instance, on the on the on the oil price, when we've had this huge fairly big, significant run-up in oil prices, what do you use for How do you value the assets?

Do you use today's price of $83 or do you use next year's price where it's under $70? That's so there's that spread that needs to be kind of negotiated.

Natural gas is is a bit more consistent. It's I think on Western Canadian gas, it's contango.

In other words, prices are higher in the future. We think that strip's probably being conservative.

We think that gas prices are going to be probably stronger than what current strip is at, but that's, that's our view. We we hope to be able to add more assets.

In the meantime, we'll grow organically. When we've got the kind of inventory that we are fortunate enough to have, that's a great place to allocate capital to.

Hopefully that answers that. The did get a question about data centers in in a couple different capacities.

One is an update on where we are and then just generally what's the impact that it could have on on Western Canada. It's we watch this very closely, and we've had a lot of conversations with a lot of different groups.

It's not just data centers. It also includes the cryptocurrency mining space because that's still very active and still, what we kind of think of it simply as as turning gas into power.

How they use that power, it can be used for different different applications. What trend we are seeing that is definitely, and I mentioned this in my quarterly email, is we're seeing a real push to go to distributed generation.

What I mean by that is where these power generation sites are not connected to the grid and they're going to be set up very close to where their energy source is. In the case of Alberta, that's going to be natural gas.

There's the odd case where these data centers are being set up near nuclear or in around the globe they're quite often attached to coal. In North America, the reality is that every time that they we add more demand for electricity, we're increasing the demand for natural gas.

That is a statistic that I often use when we when I talk to people in the US is they and they don't realize that 43% of all of their electricity in the United States comes from natural gas. Second place is nuclear and coal, each in around that 16% to 18% level.

It's pretty significant. This goes to the same argument around electric vehicles is that if you're going to be a shift towards electric vehicles, which, with this rise in WTI and oil pricing, that's become a a topic again, is what's going to happen with all electric vehicles.

Again, that's great, but you're you're going to need more electricity, and so the power grid is going to be, come under pressure. What we have seen in just about every jurisdiction is that almost nobody's got extra power.

The The grids have been kind of maintained at a level for for decades, and now you're seeing this power surge and electricity demand surge, and the grids are having to deal with it. That's where you're getting a lot of pushback from a lot of areas and jurisdictions around data centers because they're worried about their power bills going up.

That's a legitimate concern, which is again why there's a real trend towards people finding distributed power generation. There was a a big announcement up in the Edmonton area, the biggest data center that'll be built in Canada, close to a a gigawatt size.

They're building right beside it a huge natural gas power facility. The you see different projections as to how much natural gas demand might be impacted by the data centers.

I've seen numbers as like kind of that 3 to 8 Bcf/d. That's a North American number.

Just to give everybody context, I mentioned the 19 Bcf/d is what the natural gas supply is in Western Canada, Canada essentially. It's about 107 right now, Bcf/d in the US.

There's the two big demand sources besides the power grid that is really that LNG, and then with how many data centers are actually going to get built. There's these projects take on an immense amount of power demand, and therefore, if they're going to try to stay away from the grid, they're going to need a lot more natural gas.

That's it it has the potential to be pretty significant. Here in Alberta, I think it could be probably more like a 1 to 2 Bcf/d, maybe as high as 3 Bcf/d, depending on the Alberta's government has come out and said that they want to attract $100 billion of data center investment into the province.

That's a big number. We like I said, it but it is very real.

We've we have multiple sites that we think would be very attractive to data center groups. We announced the one data center transaction.

They continue to tell us that they're very close to getting financing. We're, we are very hopeful that they'll get that financing and that we can move forward with the permitting of that of that site.

We also are talking to, multiple groups about other sites and what we might be able to do. It's kind of a, there is not a tomorrow impact on natural gas prices in in Western Canada.

It's I think we'll start to see the impact of it probably starting next year. Some of these projects that have already started to break ground and get built, but I think you're really going to see it more in kind of '28, '29, which is interesting because that time frame is the exact same time that you're going to start to see more LNG demand.

One of the questions was that we've got here was, was is the Phase 2 of LNG Canada built into the AECO price? I would say no, I don't think it is, because so Phase 2, for those of you who aren't familiar with the project, LNG Canada is a is in Kitimat, BC.

They have four They have two trains for for for LNG Phase 1, and their plan is to do another four trains in Phase 2. Each phase is about 2 Bcf/d of exports.

They've they've got Phase Phase 1 started exporting in July 1st of last year, and it's been ramping up. It's been quite sporadic, but in June was at the highest we've ever seen it before.

Then, like I said, July and August it fell off again. It looks like it's ramping back up for this fall, which is fantastic.

The second phase, they've already started work on it, construction on the on the pipelines on or, sorry, on the adding compression to that that pipeline facility. It's important to note that they don't need to build a new pipeline for Phase 2.

The pipeline that's been built, the Gateway project, already has the capacity of about 5 Bcf/d. They can add another LNG facility or another, sorry, another phase to that without having to do do anything but add compression.

Even though they haven't announced that their Phase 2 is going to is gone positive FID, which is final investment decision, the work has already started. That's very positive.

We expect that we'll hear a positive final investment decision on that project this year. They've that's what the indication has been as as we head into the back half of the year here.

Then we also the [Ksi Lisims?] project is another project that is expected to go positive final investment decision, and that's another 2 Bcf/d.

You'll see in my in my newsletter or, sorry, my email, the projects that are now being talked about would take Canada to over 7 Bcf/d of exports in LNG by the end of the decade. 7 Bcf/d, again, keep coming back to that same number, on 19 Bcf/d is a tremendous amount, a high incredible high percentage of our total production.

As you add more and more demand, you're going to need that supply. It's not that we don't have the gas in the ground, it's a question as at what price do we bring that gas out of the ground?

Our view is that it's setting up quite positively for natural gas in the in the next few years as all these major projects come on in addition to the data center demand that's going to be coming on during that same time frame. Hopefully that's a a a good update on that.

Another question we had is, one, what percentage of US LNG exports relative to their production? The US US LNG growth is really one of the greatest industrial stories of our time.

In 2016, the United States exported zero LNG. Today, they're the world's largest LNG exporter.

It's been an incredible growth. That number is around they've been as high as 20 Bcf/d.

They've got some maintenance projects going on right now, and I think Freeport has had some operational issues. I think they're around today about 18 Bcf/d of exports.

Then, as I mentioned before, they're about 107 Bcf/d of production. Now keep in mind though, not only do they have the LNG exports, which is in that 18 to 20 Bcf/d, and that number's going to over 35 Bcf/d, almost double in the next five years.

By the time we exit into 2030, they're talking about that LNG being over 35 Bcf/d. In addition, they export about 6 to 8 Bcf/d to Mexico every day by pipeline, which is about the same number that they bring in from Canada.

In Canada, at times, half of our production goes to the US by pipeline. We've so it's a it's an incredible amount of investment that's gone into that Gulf area, which is where the exports come out of.

The big advantage for Western Canada is that our shipping time to Asia, and Asia is the biggest importer of of LNG in the world, and that includes Japan, and China, and Taiwan, and South Korea, we're we're about a 10-day shipping as opposed to 24 days out of the Gulf. Canada's got a really advantage for sending gas off the West Coast.

Much so that even Mexico, which is an importer of natural gas, is building LNG facilities to to take advantage of that same shipping advantage or timing being off the West Coast. It is a it's an exciting area.

It's been an incredible growth, one of the biggest growth areas from an industrial standpoint of of in any industry in North America, and it's not slowing down. It's it is picking up speed, and you can see right now there's no reason why that's going to slow down, given the shortage of LNG and the high prices elsewhere in the world.

We've talked about the the North American prices. Today, AECO is like $1.60 roughly.

I'd say the NYMEX, which is the US natural gas price, is a little under $3. In Asia and in Europe, over $20 an Mcf for the exact same molecules.

That arbitrage, the only way that arbitrage gets closed is by more LNG facilities being built in North America to export gas. Again, we think that's a positive because we believe that what will happen is that the the international prices will come down to a more sustainable level for them, which is good because you don't want them going to alternatives.

Want them to continue to use a clean-source natural gas, especially in the Asian communities where if they're going to go to coal, the carbon emissions are substantially 30% higher. If that price comes down, there it makes their economies go around better, it also, at the same time, it should be pulling up our pricing.

Therefore there's, the arbitrage price, you see difference usually between $6 and $8 is kind of the expected price of what it calls for liquefaction and transportation. We did have a question about carbon tax.

Maybe I'll pass that over to Terry?

Sure. The question was the impact of carbon tax on Pine Cliff going forward.

The short answer is we don't expect any impact on carbon taxes. We are classified as a small emitter, and under the current regulations, we are not subject to carbon tax going forward.

As long as the Feds don't reinstate federal fuel tax, at that time, we potentially would be impacted, but that's not anticipated at this point in time. Going forward, we've made no allowances for carbon tax as we are not taxable under that program right now.

Thanks, Terry. Thank you to everybody for all the great questions.

We really appreciate that. It makes these webcasts a lot more interesting for us and hopefully also for you, as opposed to just reading our press release.

You can reach us at any time, if there's any further questions that you want answered, you want to talk to any one of us, just reach out. We're happy to chat with you.

We continue to believe that we've positioned ourselves well going into this winter and into '27. Looking forward to drilling another Glauconite well.

Until next quarter, thank you very much. Thanks for those of you that are shareholders.

Thank you very much for your support. We very much appreciate it.

Have a good day.