Pine Cliff Energy Ltd.

Good morning, and thank you for joining us on the Pinecliffe Energy first quarter webcast. We will open with remarks from President and CEO Phil Hodge. Today, Mr. Hodge is joined by Christopher Zak, Chief Financial Officer, Austin Newdorf, Vice President Finance, and Dan Keenan, Vice President Exploitation. 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.pinecliftenergy.com. With that, we will turn the call over to President and CEO, Phil Hodge.

Thanks, Chris. Thanks, everybody, for attending or listening in on the recording after the fact. Keeping with past tradition on these webcasts, we're not going to read the press release, and I will assume that you've already looked at the information on our Q1. We've got several, actually, we've got more questions we typically have got in these past quarters, so I think we'll just jump right into the questions. For those of you that received my email, because you've subscribed to the email list, you will have seen a lot of comments and graphs on the macro. Some of the questions kind of touch on that, but we'll get into a little bit more detail on the questions. The first question we had was with regard to the natural gas to the southern California market. And the reduction on gas, because we showed some graphs in my email showing that there were about one BCF a day less gas went into the California market this last winter during the first quarter. That had a huge impact on on ACO prices because that's a BCF a day. Keep in mind, the one number I always repeat to people is keep in mind that all of Canada makes BCFs. 18 to 20 BCF a day of natural gas. Today, it's around 18 BCF a day. Typically, it's around 19 BCF a day. But the point being is that when we talk about these projects, the LNG projects, or when we talk about there being a curtailment in gas exports like this of BCF, that's a big number. These numbers make a real impact on the market because the market, unlike the US, which is running around 107 BCF a day, can absorb these impacts a little bit better. So what happened this last winter is it was warm in California. And so therefore they didn't need as much natural gas as they typically need for heating. That led them to taking less gas from Canada. So because of that, that gas then, if it's not going down to the U.S. market, it stays in the Canadian market and therefore it keeps our storage levels higher. And as we've explained in the past, the storage levels really are showing you kind of what's going on between the supply and demand. Because we had that warmer winter, and that was also in Western Canada as well, we're now entering into this summer with higher storage levels than we did last year. Not much, about 7% higher, but that's still higher than last year, which was already on the high end. The one, and I pointed this out in my president's letter, the one thing that's different this summer is we've got LNG Canada up at full operation. And they hit a record in April for the first time they sent out a million metric tons of LNG from Kitimat, B.C., off the West Coast. So that was a significant milestone. We expect and hope that that's going to continue to be the pace of exports all throughout the remainder of 2026. And that will be very interesting because we've never had two BCF a day of LNG exports in the market at the same time. Again, keeping in mind that we only make 19 BCF a day. So there was a question about the warmer weather impacts on our natural gas. And I think that ties into that same comment about the SoCal market. The one ramification of a warmer winter is that, yes, you use less natural gas for heating of homes, However, when you have the warm winter, that probably means you didn't get as much snow and therefore snowpack is down and therefore there's a potential issue with hydro. And so that usually comes to fruition during the summer months if you don't have as much hydro and you still need all the power and electricity that's required for air conditioning. So we're already seeing signs that it could be a warmer summer, which would mean we'll have more natural gas in the summer. And at the same time, hydro may not be able to keep up with that extra demand. Again, keeping in mind is that in the background, you also have the LNG exports that are going to be taking natural gas off the market. So keep a close eye on storage as we go through this summer and into the fall. Because if storage continues to kind of moderate and start to drop down below the averages of the past few years, that's going to make up for a fairly... bullish setup for natural gas going into this winter. I think that's a key point because we've seen all of the massive amount of AI construction around data centers that's happening. And at some point, you're going to start to see the natural gas that flows into those projects start to show up as another piece of demand. The one thing that I've pointed out to shareholders before is that unlike You know, we've been doing this now for this is our 15th year running Prinecliffe. In the past, in the early years, it was all about weather. How hot was it going to be in the summer? How cold was it going to be in the winter? And that was what really drove natural gas demand. These new demand pieces that are entering into the market now in the forms of LNG and in data centers, These are 24-7, 365 demands. They are not weather-related. These things, you know, barring any mechanical issues, they're going to continue to be every day drawing down natural gas demand. So we're adding a lot more bulky, sustainable, and very predictable demand. And so we've seen this in the U.S. when they went from zero LNG exports to 20 BCF a day of exports. it has a huge impact on the drawing of natural gas. So we'll keep an eye on all of that as we head into the summer and the fall. One question was also asked about the natural gas production related to the rig counts. The rig counts had kind of come down, and yet natural gas production had not decreased much. One of the things that we've seen over the years, and a few years ago it wasn't really fair to look at rig counts because they've become so much more efficient. And that efficiency continues today, but now when you look back year over year, I think you're starting to see a little bit more consistency that you are comparing apples to apples. You're not comparing the old drilling techniques to the new ones, because I think we're now in an age where almost all the new wells are horizontal, and in most cases are fracked wells, The one thing we've seen in the Montigny and the Duvernay is that these wells can come on with a lot of initial production. And so the rig count becomes less of a barometer or a measure for activity for production as meters drilled, for instance, because a lot of these rigs are able to go a lot deeper. A good example is even the glauconite well that we did. which was almost a six-kilometer well all in, so two miles down, two miles out. So these wells are very, very technically impressive, and the amount of gas that they're able to access is very large. So we keep a close eye on meters drilled, on frack crews, those types of things, because they seem to be a little bit better indication of where production is going to be going as opposed to just looking at the rig count. One of the questions we had was on our debt and where we expect to see the debt. I'll hand that over to Chris.

Yeah, thanks, Bill. So the question revolved around targeted for year-end debt reduction. We continue to make our scheduled debt payments. So all else being equal, you'll see a continued reduction in our term debt at the end of the year. The decision to accelerate debt repayment will continue that will be assessed in comparison to the returns on reinvestment into our assets. So we're going to continue to assess that on a forward basis. Obviously, with the success that we've seen in the 423 well, we continue to evaluate other opportunities for drilling in the area. So we will continue to balance off those capital allocation decisions in the context of the market.

Thanks, Chris. Another question we had was on the impact of what's going on in the Strait of Hormuz and the LNG restrictions, their inability for LNG to get out of Qatar, and what that impact has on North America LNG. I was pointing this out to a shareholder this morning. Right now, the LNG prices globally, both in Asia and in Europe, are over $15 in MCF. Here in North America, we're looking at kind of just over $3 being the US natural gas price per MCF. And in Canada, it's under $2 in MCF. So there's huge arbitrage. The only way that arbitrage gets closed is by LNG build-out. What we're seeing now is we're seeing a lot of these countries, especially in Asia, that previously did rely on some gas LNG exports coming out of the Gulf, sorry, out of the Qatar and the Middle East, are looking for more secure sources of LNG. These things don't happen overnight because these projects are extremely expensive. The LNG projects that were built, the LNG Canada is one of the most expensive and biggest projects in Canada's history. Included with that was the Coastal Gas Lake Pipeline. It appears that this current situation in the globe is actually, would have a benefit for North American LNG exports. You're seeing more and more projects in the United States that are now being proposed for LNG that they're looking at where they could be doubling the amount of, they're already the world's largest LNG exporter, but they're planning on building another 15 BCF a day of export capacity by the end of this decade, and then adding even, and there's been even more projects that are now being added onto that. You can see that in the email that was sent out. There's a new graph we included in that. For North America, it's a positive, and I think we saw the recent announcement of Shell where they have made a bid to buy out one of our largest natural gas producers here in Canada, Arc Resources, for $22 billion. That's one of Shell's biggest acquisitions they've made in the last decade. So for a company like Shell that has got global operations, for them to be putting that type of investment in Western Canada is a positive read-through for where they believe that our industry and where Canada is going to fit going forward. They clearly, you know, they are the largest shareholder in LNG Canada Phase 1. The fact that they are moving forward with the ARC acquisition and their comments after the fact, the CEO of Shell saying that it was highly likely that they were going to be heading towards positive final investment decision on Phase 2 of LNG Canada later this year. The nice thing with that is that because it's a brownfield operation, in other words, they don't have to start from scratch. They're just adding on to the existing... and they don't have to build a new pipeline, that new project could be on as soon as two years. So that's an additional two BCF a day. So just LNG Canada, not including the other LNG projects that are underway, would amount to about four BCF a day of exports. Again, that's a very large number on our market. So I think all of the... I think all this serves Canada well. I think we've got a federal government that appears to want to assist in accelerating or at least de-bottlenecking some of these major projects that need to get passed and through. So we'll see how that plays out. But so far, they appear to be supportive. We had the Minister of Energy here in Calgary just last week talking about their efforts to try to do everything they can to get some of these projects moving forward. So those are all positives because for a decade, Canada didn't have that kind of support. I mean, I understand people's skepticism wanting to see words translate to action, but at least we're seeing the words. We didn't even see that for a decade. Another question was around our data center, if there was any update. We don't have an update. The group that we've entered into an agreement with is in the middle of their financing discussions, and we're told they're close, but we don't have any optics into exactly what that would mean. Just to remind people that may not be aware, we were one of the first to announce a data center that would be developed on our own land We are not putting any money into the data center. We're not an investor in the data center. What we are is the natural gas provider for the data center and the provider of a site that is kind of a very optimal site for that application. So we await, along with everybody else, we hope, we wish them the best of luck. We try to help wherever we can with their process, but we will keep you posted anytime there's an update on that. Another question was on hedging. So maybe I'll pass that over to Chris to give a brief update on the hedging situation.

Yeah. So we're, thanks Bill. So we're, we're pretty well hedged on the gas side. Right now we're about 40% of our volumes through the remainder of 2026. We're hedged at a, an average price of $3.16 an MCF. So we'll continue to assess opportunities to continue to protect on the gas side, particularly as we go through the summer and into the fall. On the oil side, we're about 46% of our productions hedged around $65 a barrel. And those were hedges that were put into place before the spike in crude prices as a result of the conflict in the Middle East. There's been significant volatility in a pretty wide variance in hedge opportunities day-to-day, but we continue to look at ways to add to our hedge book at attractive prices so that we can help protect our cash flow for dividends, debt repayment, and capital allocation decisions.

Thanks, Chris. One of the questions we had was about a comment on the gloconite well that we drilled. And on the fact that it's above type curve, our engineering deck type curve, that's all accurate. We're quite happy with the results of that well. We've been talking about, just to give people a little bit of background on this, we did an acquisition in December of 2023. It was $106 million acquisition of a company that brought us into the deep basin for the first time, which is where the Glock and I, this is in central Alberta. And we did not do any drilling on those wells. It came with some production, so there was already wells in place. But we didn't feel comfortable drilling in 24 or 25 because of where natural gas prices are. Now, we believe that natural gas prices are heading into a stronger environment in 26 and 27. We're seeing that in the forward strip contangle, in other words, going up in trajectory. We've completed that well, brought it on in February. It's performing very well, as we talked about. It's still above the tape curve. We are now looking at ways that we could do more drilling in the back half of the year. Cash flow has improved since we set the budget for the year. So we set the budget in March, and we didn't have any drilling built into that budget in March. But cash flow has improved with commodity prices. And so we are definitely looking at trying to accelerate that drill program in the back half of this year. So those are active discussions that are happening right now. We would definitely like to get out and drill a couple more of those wells. And one question we had was actually on the drill costs and how we kind of look forward at that. Maybe I'll hand that over to Dan Keenan to deal with that question.

Thank you, Phil. So a typical drill completion clip and tie-in is in the $8 to $8.5 million range. And there was also a question around repeatability from a geological perspective. And so I can describe it as a delta shore face with a relatively homogeneous stratigraphy. And we have the area, our land, particular land is surrounded by pretty soon wells. So we have high confidence in our type walls going forward.

Thanks, Dan. Yeah, this is an area, like I said, the value, we've just recently updated our presentation, corporate presentation you can find on our website. And we put up, Chris and the team put together, and Dan put together a slide that kind of looks at the value of these locations, depending on what the commodity prices are at. Obviously, because they're 55% liquids production initially, having the higher oil prices that we're experiencing right now puts a quicker payback on these wells and a higher internal rates return. So you can see that scale in our presentation. But in ballpark, you're looking at each location, depending on what commodity prices are, anywhere between $8 to $12 million per location. So when you've got 30 locations, obviously that's a lot of very valuable inventory that we have. And that's another reason why we want to be able to get out and accelerate that and drill those wells going forward. Another question we had here, thanks for all the questions this quarter, is some just details about the plant or operations going forward on Pinecliffe. You know, we've been, like I said, this is year 15, Most of our staff have been with us for a very large proportion of that time. There's just an ongoing effort always to look at lowering costs. I think what we've done, we've become, I think, very, very efficient at running some of the legacy assets that we've inherited from some of our earlier purchases. That's resulted in us lowering our costs in the field. Our field staff does a tremendous job of identifying opportunities. So we've done some re-completion works that have been very successful, and importantly, lowering costs. And that's very critical when you're dealing with the low ACO price that we've had for the last couple of years. You really need to focus on production and trying to have the lowest cost operating as possible. When prices get too low, as they did here recently, we would shut in production. We're not going to run production just for the sake of showing a higher production number. It has to be profitable. Luckily, we've seen ACO start to show a little bit of life here recently. We'll see what that means throughout the rest of the summer, but it's crawling back up to getting close to the $2 in MCF level this morning. Again, we'll keep a close eye on that going forward. Where it gets much more interesting for us is we can see in the fall and in the winter where prices are starting to approach the $3 level. At those prices, our assets make very good cash flow. As investors in Prankliff know, because our decline rates at that 10%, we don't have to spend as much as many other companies do to replace production. And therefore, when in times of better pricing, we will generate more free cash flow. It's frustrating. And as we're all, everybody is aware that insiders own a lot of stock. We're all very frustrated, you know, and we'd like to see the stock price a lot higher than it is today. Very proud of the fact, though, that we've been able to navigate very difficult years of ACO pricing. We are still very much subject to ACO pricing. Of all the commodity price, that has the biggest impact on our cash flow. And that's not been a great price for the last couple of years. So it's been fortunate to have the liquids production that we have. That's why the gloconite wells and continuing growth of that is very important for our cash flow because that brings in liquid pricing and it gives us a higher net back. That'll continue to be a focus. We'll continue to make sure that we're looking after, we've spent about $7.5 million last year on abandonment reclamation. We will continue to do that. For us, that lowers costs. Every time you abandon a well, you reduce some of your fixed costs, some of your municipal taxes. And when you actually reclaim the well, then you are no longer paying surface rentals. And so there is a benefit for the dollars that are spent on the abandonment reclamation. And that'll be something that we're accelerating in 2026. And we're very proud of the fact that we've already received over 30 rec certs this year. So the operations are still very much a focus. We've got 100 great people working for us in the field that are always looking at how we can reduce costs and how we can optimize our production. And so those efforts aren't going to stop anytime soon. One of the questions we had, another one just came in, was about would we consider selling any of our non-core assets? The answer to that is yes. We sold $15 million worth of assets in the last quarter. fourth quarter of last year, they were good assets. Clearly, if you were selling them for $15 million, there was a good value in those assets. It's just they were not assets that we were going to be able to exploit anytime soon. So this is the same argument we make to larger producers when we're looking at buying assets. If you're not going to spend any capital on it, then... Why are you keeping these assets? Because the net present value of those assets is only going to decline the longer you don't drill them. So there's certain areas. We've got some non-core areas that have definitely had interest, and we continue to talk to groups about them. We will continue to do that. If somebody gives us a fair price for those assets, we will definitely look at selling. Central Alberta really has become our core area, and that's where the Glocknight Wells are, but that's also where our Perkisco locations are. So we are spending time on looking at both. The Petisco oil locations are looking even more and more valuable with these higher oil prices. So the short answer is yes, we're always looking to potentially be open to selling non-core assets. And we continue to look at adding to our core assets or adding a new core area, if it makes sense. I mean, we've as those have been around our stock for a while, know we've grown from 100 barrels a day to over 20,000 barrels a day. And so that's been mostly by acquisition. So we continue to look for acquisition opportunities. At the same time, it all comes back to really allocating capital as wisely as we think we can. We're very proud of the fact that we've paid over $100 million in dividends since 2022. There is I don't know of any other companies out there that are $250 million market cap that have paid $100 million in dividends in the last couple of years at a time when gas price, which we don't control, but clearly has a huge impact on our cash flow, has been as low as it has. So we've been able to continue to keep that dividend going. We've raised it twice, lowered it twice. Hopefully, we'll be able to be in a position to be able to move it back up again as we head into 27. I think that is all the questions. That's an impressive list of questions. Thank you for all of those people that have sent in questions today. We're always available if you want to reach out by email, send us any other questions you might have. We appreciate your confidence in us, and for those of you that continue to be shareholders, for those of you that are looking at adding the Prank Lift to your portfolio, I would highly encourage you to take a look at some of the macros trends that we've talked about as to why we think Western Canadian natural gas is going into a better space in the back half of this year. And we're quite bullish on what 2027 looks like. So for those are the same reasons why we hope to be able to get back and to drill some more gloconite wells to bring on that production in 2027. Thank you very much for your time today. Thanks to the rest of the management team today too. Bye.