Pine Cliff Energy Ltd.

Good morning, and welcome to the First Quarter Pine Cliff Energy Conference Call. My name is Kris Zack, Chief Financial Officer.

We will open with remarks from President and CEO, Phil Hodge. Joining Mr.

Hodge today is Terry McNeill, Chief Operating Officer; Austin Nieuwdorp, Vice President of Finance; and Dan Keenan, Vice President Exploitation. Questions for the management team can be registered on the webcast.

Prior to starting, I 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, I will turn the call over to Phil Hodge, President and CEO.

Thanks, Kris. I think we'll just do a couple of introductory comments and then jump right into the questions.

The -- you've got the press release and also my President's letter. Those of you who are subscribers to our e-mail would have already received our quarterly e-mail as well.

First quarter was quite positive in the sense that it's been a long time since we've seen kind of a period of time where we're seeing over $3 forward prices in the AECO market. And so we've touched on that before about our -- how we've been layering hedges into that market and the most recent hedges that we've put in place going into 2026.

And even into the winter of 2026, 2027, we're seeing prices that are well over $3 and actually to $3.50. So this is -- it's been a while since we've seen that.

So the first quarter was one of the strongest quarters we've had in about eight quarters from a cash flow perspective. And so that's quite positive.

We're not by any means out of the woods yet where this -- the summer months here Q2, Q3, AECO is not as strong as we're seeing in kind of for Q4 and Q1 of going into the winter season. But it's still better.

And we're about 50% hedged, which Kris has highlighted before for the summer months, especially in Q2 as we kind of wait for LNG Canada to start up. From an operational standpoint, Q1 where our production was a little bit lower because of the freeze offs, but then that's like -- the inverse of the freeze-offs means that you've got very cold weather and therefore, gas prices were higher.

So the actual financial results weren't impacted and actually were more positive in Q1, even though we did have some production shut in because of the cold weather. The -- I think what -- the main thing for us is that we've kind of positioned our balance sheet and the -- trying to create as much flexibility as we can going into the back half of this year.

We've created CapEx, and we've set a budget for the year to be spending about $12.5 million on CapEx. That is always subject to what's going on in the markets.

We're fortunate that we don't have to make any decisions on the drill programs until the back half of the year. So we're -- as we come out of breakup, we'll kind of -- we're going through a lot of internal processes and starting to talk to partners in our key areas but with the optimal way for us to allocate the CapEx.

And so this is something that we'll be watching very closely. The -- I think from our perspective continuing to pay down debt is a key piece.

And so -- well actually that's one of the things I want to pass back over to Kris. One of the questions was that we received last night was about the -- kind of how we're looking at our debt, how are we looking at -- as we move from our credit facility from one bank to another bank which is a process undergoing is happening right now.

Kris maybe I'll pass back to you to comment on that.

Yeah. Thanks, Phil.

So you might have noticed in the notes of the financial statements that the increased demand loan that we had outstanding at the end of the year was extended at $15 million to the end of May. And that's really to accommodate the timing of as Phil suggested, our bank reviews, which have taken a little bit longer than expected we're moving over to a new bank platform.

But we noted at the end of March, we had about $8.6 million drawn, which is still well below the increase that was sustained at $15 million. For our term loan, I just note that we're at just below $45 million at the end of the first quarter That's down about 19% since the inception of the loan, which was taken out to help finance a strategic acquisition at the end of 2023.

And debt repayment will always be an important part of our allocation of capital considerations as we move forward as we're looking to continue to bring that down. But we're also always looking to optimize our capital structure, and we're continuing to work with our debt partners to make sure that we have the most flexibility within our capital structure to accomplish the -- supporting our free cash flow and our development program as we look ahead into 2025 and into 2026.

Okay. I think we'll jump right into the questions.

One of the questions we've got is around LNG, both in LNG Canada and in US LNG. The LNG Canada, there was actually -- when I set out my e-mail yesterday, shortly afterwards, kind of pressed the send button there was another update that there was some discussion from some undisclosed sources that they could see shipments out of the LNG Canada sooner rather than later in other words, possibly in June July as opposed to kind of later in the summer.

We're watching that very closely because we think that, that could be a key to the storage. Our production in Canada has been pretty flat right around 19 Bcf a day.

The demand continues to rise in -- for the US exports it was hit, kind of, a peak of 8.8 Bcf a day. We continue to see oil sands using about 3.8 Bcf a day.

So there is -- storage levels are actually about 20% below in Canada below the one year where they were last year. But an important piece to that is what happened this summer if when demand weakens a little bit.

If we don't have a very hot summer, for instance, what happens to storage? And that's where LNG Canada comes in.

And so we're all looking forward to seeing the LNG Canada, kind of, start up and launch in 2025. The question is just when that's going to happen?

One of the questions we had was about the -- how much LNG Canada gets produced into LNG? And is there a loss percentage?

The second one I will pass over to Terry. The first one, LNG Canada is about 1.8 Bcf to 1.9 Bcf a day at full -- the first train at full capacity.

And all of the producers there's five owners of LNG Canada. There's Petronas, Shell, Cogas, PetroChina and Mitsubishi.

And so they have varying -- the way LNG Canada works is a little bit different than some of the US LNG facilities is that each of those owners need to bring their percentage ownership to the LNG Canada that's their commitment. And then they also need to find that percentage of buyers.

So people watch kind of where the production is at. Some of the producers are a little bit below right now their total amount of production than to match the Phase 1 of LNG Canada, but they've also indicated that they're happy to buy on the market.

In other words, they could go in and just fill their share in the -- by buying off of AECO or Station 2 gas. As for the percentage I'll pass that over to Terry.

Thanks, Phil. I'll preface it by saying I'm far from an expert on LNG processing facilities but what we do have extensive knowledge with.

And I believe the nature of the question is what is the typical gas shrinkage that the LNG Canada can expect. And in a conventional plant typically shrinkages are anywhere from 5% to 10% -- actually sorry, I should step back.

I believe the nature of the question is if there's 2 Bcf of gas processed in LNG Canada does that mean there's 2.2 Bcf of feedstock to the plant for a 10% shrinkage? And in a traditional processing plant in Western Canada typically gas shrinkages would be in that 5% to 10% range and that shrinkage would encompass fuel and conversion of liquids from gas -- recovery of gas -- liquids from the gas stream like propane and butane.

So that's usually 5% to 10%. LNG Canada is going to be predominantly electrical powered from an external power source and there is no liquid recovery.

So I would expect the shrinkage to be quite small. I would expect it to be maximum 5% or probably lower.

So shrinkage is probably a handful of percent and that's probably about it. Again, we're not experts at it.

We don't operate these facilities, but that's just kind of my perception of what it would be.

Thanks, Terry. Couple more questions around LNG here.

One is what are your plans for participating as a supplier in LNG? The reality is that our molecules that we produce in Alberta probably are not to be -- are going to be liquefied.

But what's important to know is that any LNG projects, anywhere in North America are positive for natural gas producers because it's -- all it is another form of demand. So just think of LNG exports.

Anytime you're seeing LNG export numbers just think of that as more demand for natural gas just like any other form of demand for natural gas. So the most of the gas that will be liquefied for the -- any of the LNG projects and there's multiple LNG projects that are being built off the West Coast of British Colombia that gas is most likely going to come from the Montney area from Duvernay sort of, it will come from Northwest Alberta, Northeast British Columbia.

But today a lot of that production in those areas is now coming into -- it's flowing east and therefore into Alberta and being -- some of it would be going to Eastern markets and Southern markets into the US. By virtue of the flow of that gas now going west that just creates less supply for -- to compete with the molecules that we do produce in Alberta.

So indirectly it's definitely a positive. One of the other questions was what about the LNG United States?

What else is coming on? The one that cut the market a little bit by -- I don't know by surprise but the Plaquemines LNG Phase 2 in Louisiana came on faster than people thought it would -- than I think most people thought it would.

So I showed a graph of that in my e-mail that went out last night is that there was, kind of, a staged -- as these LNG facilities come online there's been enough of them now in the US because that was there's been seven prior to Plaquemines, Plaquemines was number 8. You can see how they build up their natural gas demand or their flow into the system and how much they use.

Plaquemines has gone up very fast quicker than any other LNG facility that's coming online. So that's actually -- now we've gone from about -- it was around 13.5 Bcf to 14 Bcf a day of LNG exports.

Plaquemines has taken that now to over 15. There's been days that has been up as high as 16 Bcf a day.

The other two facilities that are coming online in 2025 in the US are planned to come on is Golden Pass LNG out of Texas and the Rio Grande LNG out of Texas. When all of these come online by the end of 2025, they're talking about that we're probably going to be around that 17 Bcf, 17.5 Bcf a day.

So it's pretty significant. And we've talked about this hockey stick of LNG demand that's coming on.

We've been talking about it for two years now. Just to remind everybody, in 2016 the United States did not export any LNG.

And then they ramped that up to become the largest LNG exporter in the world, which is where they are today. And then -- however, that's kind of paused.

So from 2020 to -- sorry, from 2022 to 2024, there was no new LNG. So they ramped it up to 14 Bcf a day.

Now they're in an expansion phase where we're going to see about another 12 Bcf a day over the next few years come on in the United States. So, very significant.

And so they're looking at by the end of the decade, exiting the decade, somewhere between 28 Bcf to 30 Bcf a day, in addition to the extra LNG facility projects that are happening in Canada and in Mexico. So it's pretty significant.

One of the other questions we had was about data centers. That's something that we're -- we watch extremely closely.

And for those of you who have been reading the quarterly e-mails, you would have seen I've dropped in a lot of information and data and graphs. The province of Alberta has been very vocal in its desire to attract that type of investment into the province.

We're very happy to say that we are one of the very first companies to announce an arrangement with the data center that was in January. We are -- we'll continue to update our investors as that progresses.

What's significant for us is that the -- a lot of these data centers, they need 24/7 365-type power. So they can't have intermittent power.

And therefore, natural gas is an obvious source of their power they need and they need a tremendous amount of power. We're seeing a lot of different speculation as to how much the data centers -- the total amount of natural gas they're going to need and how much -- what percentage of the total electricity grid will be eventually dedicated to these data centers, which are really -- the data centers are just computer warehouses if you will that are used for a lot of the AI.

So the artificial intelligence uses a tremendous amount of power. And so we're using a lot -- we're seeing a lot more adoption of AI into everybody's businesses and everybody's life.

And therefore we're seeing a lot more energy need. And this isn't specific to North America.

This is a global phenomenon. And we're also -- I mean the United States has led the way in the growth of these data centers but we're going to see a huge amount of major projects get announced.

The ones that we are focused on and we've got multiple sites that would be good locations for this type of application, is where it's off grid. In other words, where the power is going to be provided right on site and therefore, it doesn't need the electricity from the power grid for its internal use.

That's key because the Alberta government and just about every other government has said that they do not -- their infrastructure and the grids in the various areas can't take on that kind of new demand without massive investment in the infrastructure. So that's kind of the struggle that data centers are going to have is that where can they find locations where they've got access to power without damaging the grid that's already in place.

So stay tuned. I think Alberta is a prime spot because of our natural gas reserves that we've got throughout the province.

And we've got a government that is very receptive to this type of project getting moved forward. We've got a question about hedging for 2025.

I'll give that back to you Kris.

Yes. Thanks Phil.

So, we continue to be actively active in hedging our forward production. And I think that was again evident in the first quarter.

We averaged a realized natural gas price in the first quarter of $2.90 an Mcf at a premium to the $2.16 an Mcf of the AECO average price over the first quarter. As we indicated for the balance of 2025, we're around 42% hedged at AECO around $2.90 with a bias of that percentage more heavy in the summer months.

We're also 32% hedged on our WTI at $65 for our oil price -- our oil production. And those are all both positive relative to current prices and we'll continue to look at ways in the very near-term to continue to add in hedge positions that will help protect our cash flow.

But also into 2026, I would just note that, we've seen prices now at 2026 that we can hedge over $3 an Mcf for the calendar year. And if you look out to winter 2026-2027, you can actually hedge out at prices that are into the $3.50, $3.60 range right now.

So these are prices that work very well in our model. And so not only will we continue to focus on protecting our near-term cash flow, but we'll continue to look to build out our hedge book into 2016 and into the winter 2026-2027.

Thanks Kris. One of the questions we had here was about our balance sheet and -- as it relates to our acquisition strategy that we've deployed over the last 14 years.

We're always looking at acquisitions. I don't think there's been a time -- or if it has been it's been very brief times, where we -- there's not been something we're looking at over the last 14 years.

And sometimes it's -- we're looking at multiple things at the same time. Having the strong balance sheet is something that was very, very -- I think it's very important for that acquisition strategy.

And many of you who have been with us and have been shareholders with us for many years know that there's been times, where we've been debt free and the -- we sat on cash, as we look for acquisitions. And we again, I think, we showed our discipline that we didn't go out and just buy things because always things for sale.

But -- for instance, I look back to 2022, as a good example, of where we went from $50 million of debt to $50 million of cash. And -- but we went almost two years we did a deal in December of 2021, and then another deal not another deal until December '23.

So even though we are sitting in a really strong position with cash with the balance sheet being able to we could done something during that time we just didn't see prices that made sense to us at that time. And so that's when we kind of started looking at doing more on the CapEx on the drilling side.

So I really, our management team really looks at capital allocation as our prime job and as to where we -- with the resources and the cash flow that we do generate where is the best place to use that. And that was one of the reasons, why we made the adjustment of the dividend here earlier this year is, because we really wanted to put ourselves in an optimal position going into the back half of this year for either drilling or acquisitions or both.

And I think the -- our debt to cash flow on a forward basis would be somewhere around one time, at the end of this year. I'll maybe the -- one of the questions we had is how soon could you be in a position where you don't have any debt.

Well that really depends on future prices. But you can -- if we are entering into 2026 at around one times, you can see there's definitely scenarios where that debt could go down very rapidly very quickly in 2026.

So we'll continue to monitor it. I think there's -- I agree with the comments from the question which has kind of implied that, if you've got a lower debt profile then you're probably in a stronger position for acquisitions.

I agree with that and we've always kind of maintained that. And so that's one of the reasons why that we are paying down debt as quickly as we get.

And Kris already gave you some statistics on that is, how fast we've been paying down the debt. That is going to be a continued focus for us to continue to pay down the debt to put us in a stronger position as possible.

I don't know, Kris if you got anything to add to that?

No, I think that's well put. Again, I continue -- we continue to believe as a management team that the repayment of debt is going to be an important consideration in our allocation of free cash flow as we move forward.

And with better commodity prices we'll be able to pay that down faster. And that provides us with even more options both internally and strategically.

Yes. And as Kris mentioned before, we're dealing with both our - on our credit facility and our term debt.

We've got ongoing discussions with both those groups to try to get that optimal debt structure that gives us as much flexibility as possible going into the back half of this year. So there will be -- as we progress through those discussions we'll be able to update you more on that going forward.

But we're quite pleased with kind of the situation we're in right now with our hedge position with the inventory that we have. I mean, we haven't spent a lot of time talking about the inventory that we've developed through the last few acquisitions.

But it's we've -- I have mentioned to some of you before in the history of Pine Cliff over the last 14 years, we have never had this depth of inventory from a drilling location standpoint. So we've got some -- we're quite excited to get back to exploiting some of those opportunities in the back half of this year.

If commodity prices are weak to the point that it doesn't make sense to do at that time then that's fine. Right now, it still does make sense to do it.

Our economics would indicate that it's still going to make sense for us to spend some of the CapEx in the back half of this year. And so we'll update you further more on that as we go through the year.

But it's an exciting year. I mean, it's been -- this has been -- we went through the last couple of years it's been after the last acquisition we're very fortunate that we did that acquisition because it added a very valuable liquid production to our profile which was very helpful in 2024 when gas prices were much weaker.

Now that gas prices are strengthening you saw it in Q1 of this year gas now is making up over 50% of our revenue again which wasn't -- hadn't been the case in 2024. And so -- and it looks like it's going to continue to make up a higher percentage as we go into the back half of this year and into 2021.

So I think that covers off all the questions we had for Q1, but don't -- if anybody has any further questions or would like more clarification don't hesitate to reach out to any one of us. And we're happy to provide that.

Thanks for your time today. Appreciate it.