On Thursday, Pine Cliff Energy (TSX:PNE) discussed second-quarter financial results during its earnings call. The full transcript is provided below.

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Summary

Pine Cliff Energy reported improved natural gas prices compared to last year, driven by increased LNG exports, though prices are not at desired levels.

The company has increased its capital expenditure to exploit the Glauconite and Pekisko well inventories, with plans to drill more wells due to improved cash flow from stronger commodity prices.

The 423 well performed better than expected, contributing significantly to revenue with a balance of gas and liquid production.

Pine Cliff Energy is maintaining its dividend and focusing on capital allocation towards drilling rather than issuing equity at current stock prices.

The company is optimistic about future natural gas prices due to LNG export growth and potential new demand from data centers and distributed power generation.

Pine Cliff Energy's hedging strategy has delivered a realized gas price significantly above market levels, providing cash flow stability.

No anticipated impact from carbon taxes as the company is classified as a small emitter under current regulations.

Full Transcript

Christopher Zak, Chief Financial Officer

Good morning and thank you for joining us on the Pine Cliff Energy second quarter webcast. We will open with remarks from President and CEO Phil Hodge today. Mr. Hodge is joined by Chief Financial Officer Christopher Zak, Chief Operating Officer Terry McNeil, and Vice President, Finance, Austin Newdorp. Questions for the management team can be registered online during the webcast. Prior to starting, we would like to remind participants that the call may contain comments on or discussion of forward-looking information.

As such, we refer participants to the cautionary statements on forward-looking information included in the presentation on our website, www.pinecliffenergy.com. With that, we'll turn the call over to Phil Hodge, President and CEO.

Phil Hodge, President and CEO

Thanks, Chris. Good morning everybody. As we've done in the past, we're not going to bother to read the press release or give kind of scripted answers. We've had lots of questions, so thank you very much. A lot of people that might be listening get our quarterly update that I do, and that's stimulated a bunch of different questions more around the macro on natural gas and what's happening, and we're happy to address those. So I think we'll get to those pretty quick.

Just on 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, but I think a big reason for that is around LNG. We've had LNG Canada on now for a year, but it's not been a consistent draw on the system, and 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 the tanker leaving every couple of days out of LNG Canada Phase 1, and that hasn't been the case for the last six or seven weeks. The two things we watch pretty closely are 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 has got a public service website availability where you can actually see when Willow Valley is drawing. What that means is if Willow Valley has got gas flowing through it, they're drawing off the NGTL/Nova system and therefore natural gas is going to Kitimat, which is where the site for LNG Canada is. That's not always the case when it's at lower than full capacity or even lower than mid capacity. So if it's under a Bcf a day of exports, they tend to 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 and 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 last summer. You really saw it in June, because in June LNG Canada was at pretty much full capacity. They were about 1.8 Bcf a day in exports, and 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 in storage in the shoulder season, which is typically 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 of days, Willow Valley started to show life again of gas pulling off, and that's a good thing. So it's positive, which is why gas prices are well over a dollar higher per Mcf in Western Canada than they were this time last year. We're optimistic that things are turning the corner on that. And, as I've mentioned before in these webcasts and in interviews, that 1.8 Bcf a day up to 2 Bcf a day is a big, big number when our entire country only produces 19 Bcf a day.

So we're talking about 10% of all of our production coming on or off on demand. That's going to make a material swing, so that's something we're watching pretty closely. We had some questions about that. Another question was around our capex because we just announced a capex increase. This 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 23rd acquisition—we've been wanting to get after those well locations ever since we've owned those assets, and that's been two years now.

Prices were weak, and therefore, as we're very highly correlated to AECO pricing, 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 and 9 million dollars all-in when you drill, complete, and tie them in, and so 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, and 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 Middle East 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—but in the last quarter more than 50% of our revenue actually came from liquids, and a big part of that was the 423 well from the Glauconite.

So we'll pass over to Terry to talk a little bit about the well results to date.

Terry McNeil, Chief Operating Officer

Sure. Thanks, Phil. Appreciate it. Yeah, the 423 well came on in the middle of February, was cleaning up 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, but we've had it on almost 100% of the time from a financial perspective from March until June. So over that four-month period—those are the latest financials we have—it's averaged 1,100 boe a day, and 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 and, I guess more importantly, it's 50% gas, 50% liquids. So the liquids exposure makes a considerable difference to Pine Cliff and the volumes do too. I mean it's pretty well 5% of our corporate production. So it's a good well. We're excited it's performing well, and we'd like to do more.

Phil Hodge, President and CEO

Yeah, and that ties it up. A good segue, Terry. We've got several questions here on what our increased capex means going forward, and 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 as liquids, and so 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 the economics of the wells both from an 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 got the NPV—in other words, the net present value—of each one of those well locations kind of in that $8 to $10 million range. And we've got 37 net locations to get at, so we're talking about $300 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 and it's a very active area. So it's definitely something that we want to get to a pace of development where we're drilling at least two to four wells a year, and it could be, 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 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. So we're looking to increase that pace of development. These wells pay out, depending on the commodity price, in between that 12- and 15-month period, so they're very quick paybacks, but they continue to pay. As Terry mentioned, the 423 well has been surprisingly resilient. You know, 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.

And then our 1-27 well—you may remember—was the well that we had when we first did the acquisition. We didn't drill it, but it came with the acquisition. 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. So that's the attractiveness of these locations and why we want to get after those. But 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 probably even drill the second well this fall along with this Glauconite well. And 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. But these are all things we look at all the time. There's different ways to finance an accelerated drill program, and we've considered, I think, just about every one of them.

So initially, we've 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. And you've heard us speak about capital allocation before. We are very cognizant of the fact that our model lends itself to free cash flow in rising commodity prices—especially on gas, but obviously also on oil—having low-cost opex, having low G&A, having the low decline rate.

All of those things help you generate more free cash flow, and so 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. The capex—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, which is the impact of the El Niño effect, a weather pattern that is projected to have warmer winter temperatures for this winter.

Maybe I'll pass it over to Chris to chat about our hedging program.

Christopher Zak, Chief Financial Officer

Yeah, thanks, Bill. So we continue to actively manage our hedge book with the view of reducing volatility in our price realizations. And I would say, as highlighted in the press release, I think you saw continued evidence of that in our Q2 results, noting that our hedge and diversification strategy delivered a realized gas price of $2.38 per Mcf. In Q2 that was a 47% premium to A5, a price of $1.62. And 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 is 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 and around $3.10. So 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.

Phil Hodge, President and CEO

Thanks, Chris. Another question we had was around the makeup of these Glock wells from our liquids perspective, and one of the questions I got last night was how much wetter are these? In other words, what is the NGL component of the wells? Maybe I'll flip that back over to Terry to discuss.

Terry McNeil, Chief Operating Officer

Sure, thanks. With regard to the wetness of the location, it will vary from location to location. It gets a little bit drier as you go from east to west. But with our concentrated land position, we're still trying to vet it out a little bit, and I don't think it's going to change appreciably across our land base. So I think we'll be fairly consistent on liquid production on our future wells as we are in our existing wells. 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.

So the condensate value will come down over time. But initially, of the 1,100, we're about 20% to 25% condensate, and it is condensate, not oil.

Phil Hodge, President and CEO

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, obviously, our liquids. And so we've gone from, at one point, Pine Cliff Energy was 96% natural-gas weighted. And with the acquisitions that we've done over the last few years, starting in 2019, we did each of our, the Alphabo Apogee Certus acquisitions all kind of have added more liquids exposure.

And clearly this drilling inventory is definitely liquid exposure, with the majority of it. And because of where AECO's at, it actually is, even from a revenue and from a cash flow standpoint, it's even more than just the percentage of the volume; it punches well above its weight because of where WTI is these days. And for some of you who may not be aware, WTI is very highly correlated to the condensate price that Terry mentioned. So quite often condensate is 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 what the Canadian dollar impact onto our balance sheet is. A few more questions here. One of the questions was the Ask—I'll just read it. It says that we've done 16 transactions in 14 years and we haven't issued equity in nine years. That's accurate. With the Shell ARC deal, LNG Canada phase two 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. And so 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 was Canada—it was a $22 billion company, very heavily weighted towards natural gas and condensate. I personally took that as a positive signal that foreign investors that can put capital anywhere they want in the world were making significant investments into Western Canada and saw this environment as finally an environment that they could come back and deploy capital to. And that's not been the case for 10 years. We saw a lot 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. And I think that goes as a testament to the governments both at the federal level and at the provincial level, welcoming back that foreign direct investment. And 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. So it's nice to see the foreign direct investment returning, and I think that one project—bringing it back down to 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, you know, I've been at Pine Cliff Energy now for 15 years. There was a lot more junior capital energy pools available when I first started.

I remember, you know, 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. So 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 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.

And that's already started. And I think that 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 is going to stop. Part of it is, as a junior company—and we're 20,000 boe a day—10 years ago that would have been considered a decent-sized intermediate. Now we would be junior, 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.

And your regulatory costs, your cost of doing business, has gone up. That's just the reality. And so we continually look for assets that make sense, or acquisitions or mergers that would make sense to us as shareholders. And that's been the constant theme ever since we've started Pine Cliff Energy: it's all about how do we make the shares more valuable. And if a transaction has the potential to make our shares more valuable, then we're definitely interested in it.

We haven't done a material transaction now in a couple of years. But that's not from lack of looking. I think when you get this volatility in commodity prices, it does make transactions more difficult. Like I said, we've done a lot of transactions, and our team has been involved in different places that they've worked in a tremendous amount of transactions. You almost need 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 oil price when we've had this 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? And so there's that spread that needs to be negotiated. Natural gas is a bit more consistent. I mean, 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 our view, and 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. So hopefully that answers that. We did get a question about data centers 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 Western Canada. We watch this very closely and we've had a lot of conversations with a lot of different groups.

And it's not just data centers. It also includes the cryptocurrency mining space because that's still very active and still, you know, we kind of think of it simply as turning gas into power and how they use that power. It can be used for different applications. What trend we are seeing—there's definitely, and I mentioned this in my quarterly email, we're seeing a real push to go to distributed generation. And 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 around the globe they're quite often attached to coal. But in North America, the reality is that every time that we add more demand for electricity, we're increasing the demand for natural gas. There's a statistic that I often use when I talk to people in the US is they don't realize that 43% of all of their electricity in the United States comes from natural gas.

And second place is nuclear and coal, each around that 16% to 18% level. So it's pretty significant. And this goes to the same argument around electric vehicles. If there's going to be a shift towards electric vehicles—with this rise in WTI and oil pricing that's become a topic again—what's going to happen with all electric vehicles? Again, that's great, but you're going to need more electricity. And so the power grid is going to come under pressure.

And what we have seen in just about every jurisdiction is that almost nobody's got extra power. The grids have been maintained at a level 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. And that's a legitimate concern, which is again why there's a real trend towards people finding distributed power generation.

And so there was a big announcement up in the Edmonton area—the biggest data center that will be built in Canada, close to a gigawatt size—but they're building right beside it a huge natural gas power facility. And so you see different projections as to how much natural gas demand might be impacted by the data centers. I've seen numbers kind of 3 to 8 Bcf a day. That's a North American number. Just to give everybody context, I mentioned the 19 Bcf a day is what the natural gas supply is in Western Canada.

Essentially it's about 107 right now Bcf a day in the US. But the two big demand sources besides the power grid are really the LNG and then how many data centers are actually going to get built. And these projects just 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. And so it has the potential to be pretty significant here in Alberta. I think it could be probably more like a 1 to 2 Bcf a day, maybe as high as 3 Bcf a day depending on—I mean 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. And like I said, it is very real. 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 are very hopeful that they'll get the financing and that we can move forward with the permitting of that site. But we also are talking to multiple groups about other sites and what we might be able to do.

So it's kind of not a tomorrow impact on natural gas prices in Western Canada. 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 timeframe is the exact same time that you're going to start to see more LNG demand. One of the questions that we got here was, is the phase two of LNG Canada built into the AECO price?

And I would say no, I don't think it is. So Phase Two—for those of you who aren't familiar with the project—LNG Canada is in Kitimat, BC. They have two trains—there's four trains today in Phase One—and their plan is to do another four trains in Phase Two. Each phase is about 2 Bcf a day of exports. So they've got Phase One started exporting on 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.

And then, like I say, July and August it fell off again, and 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 adding compression to that pipeline facility. It's important to know that they don't need to build a new pipeline for Phase Two. The pipeline that's been built, the Gateway project, already has the capacity of about 5 Bcf a day. So they can add another LNG facility or another train—sorry, another phase—to that without having to do anything but add compression.

So even though they haven't announced that their Phase Two has gone positive FID, which is final investment decision, the work has already started. So that's very positive. We expect that we'll hear positive final investment decision on that project this year. That's what the indication has been as we head into the back half of the year here. And then we also—the Salisma project is another project that is expected to go positive final investment decision, and that's another 2 Bcf a day.

And you'll see in my email, the projects that are now being talked about would take Canada to over 7 Bcf a day of exports in LNG by the end of the decade. Seven Bcf a day—again, keep coming back to that same number on 19 Bcf a day—is a tremendous amount, an incredibly high percentage of our total production. So as you add more and more demand, you're going to need that supply. And it's not that we don't have the gas in the ground. The question is at what price do we bring the gas out of the ground.

And so our view is that it's setting up quite positively for natural gas 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 timeframe. So hopefully that's a good update on that. Another question we had is what percentage of US LNG exports is relative to their production? US LNG growth is really one of the greatest industrial stories of our time. I mean, in 2016 the United States exported 0 LNG.

Today they're the world's largest LNG exporter. So it's been an incredible growth. And that number is around—they've been as high as 20 Bcf a day. 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 a day of exports. And then, as I mentioned before, they're about 107 Bcf a day of production. Now keep in mind though, not only do they have the LNG exports, which is in that 18 to 20 Bcf a day—and that number is going to over 35 Bcf a day, so almost double in the next five years.

So by the time we exit into 2030 they're talking about that LNG being over 35 Bcf a day. In addition, they export about 6 to 8 Bcf a day to Mexico every day by pipeline, which is about the same number that they bring in from Canada. So in Canada at times half of our production goes to the US by pipeline. 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 LNG in the world, and that includes Japan and China and Taiwan and South Korea—we're about a 10-day shipping as opposed to 24 days out of the Gulf. So Canada's got a real advantage for sending gas off the West Coast, so much so that even Mexico, which is an importer of natural gas, is building LNG facilities to take advantage of that same shipping advantage or timing being off the West Coast. So it is an exciting area. It's been incredible growth—one of the biggest growth areas from an industrial standpoint in any industry in North America. And it's not slowing down; 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 North American prices today. AECO is like $1.60 roughly. I'd say 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. So that arbitrage—the only way that arbitrage gets closed is by more LNG facilities being built in North America to export gas.

So again, we think that's a positive because we believe that what will happen is that 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. You want them to continue to use a clean source—natural gas. Especially in Asian communities where if they're going to go to coal, the carbon emissions are substantially—30% higher. And if that price comes down so it makes their economies go around better, it also at the same time should be pulling up our pricing and therefore there's the arbitrage price.

You see difference usually between six and eight dollars 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.

Terry McNeil, Chief Operating Officer

Sure. The question was the impact of carbon tax on Pine Cliff Energy going forward. And 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. So 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. So going forward, we've made no allowances for carbon tax as we are not taxable under that program right now.

Phil Hodge, President and CEO

Thanks Terry, and thank you to everybody for all the great questions. We really appreciate that it makes these webcasts a lot, lot more interesting for us and hopefully also for you as opposed to just reading, reading our press release. You know, you can reach us at any time. So 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're positioned ourselves well going into this winter and into 27. We're looking forward to drilling another Glock well. And so 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.

Disclaimer: This transcript is provided for informational purposes only. While we strive for accuracy, there may be errors or omissions in this automated transcription. For official company statements and financial information, please refer to the company's SEC filings and official press releases. Corporate participants' and analysts' statements reflect their views as of the date of this call and are subject to change without notice.