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 Finance; and Dan Keenan, Vice President Exploitation. Questions for the management team can be registered on 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, 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. You've got the press release and also my President's letter. Those of you who are subscribers to our email would have already received our quarterly email 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. We have touched on that before about 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 closer to $3.50. It has been a while since we've seen that. The first quarter was one of the strongest quarters we've had in about eight quarters from a cash flow perspective. That is quite positive. We're not by any means out of the woods yet. 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. It is still better. We're over, 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, 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. The actual financial results were not impacted and actually were more positive in Q1, even though we did have some production shut-ins because of the cold weather. I think the main thing for us is that we have kind of positioned our balance sheet and are trying to create as much flexibility as we can going into the back half of this year. We have created CapEx and we have set a budget for the year to be spending about $1 2.5 million on CapEx. That is always subject to what is going on in the markets. We are fortunate that we do not have to make any decisions on the drill programs until the back half of the year. As we come out of breakup, we're going through a lot of internal processes and starting to, excuse me, talk to partners in our key areas about what the optimal way for us to allocate the CapEx is. This is something that we'll be watching very closely. I think from our perspective, continuing to pay down debt is a key piece. Actually, that's one of the things we want to pass back over to Kris. One of the questions that we received last night was about kind of how we're looking at our debt, how are we looking at the, as we move from our credit facility from one bank to another bank, which is a process that's undergoing, is happening right now. Kris, maybe I'll pass back to you to comment on that. Yeah, thank you, Bill. 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. That is really to accommodate the timing of, as Phil suggested, our bank reviews, which have taken a little bit longer than expected as we are moving over to a new bank platform. 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 are at just below $ 45 million at the end of the first quarter. That is down about 19% since the inception of the loan, which was taken out to help finance a strategic acquisition at the end of 2023. 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. We are 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 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 U.S. LNG. The LNG Canada, there was actually, when I sent out my email yesterday, shortly afterwards, I 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 piece to the storage. Our production in Canada has been pretty flat, right around 19 BCF a day. The demand continues to rise for the U.S. exports. It was hit at kind of a peak of 8.8 BCF a day. We continue to see oil sands using about 3.8 BCF a day. Storage levels are actually about 20% below in Canada, below the one year where they were last year. An important piece to that is what happens this summer when demand weakens a little bit. If we do not have a very hot summer, for instance, what happens to storage? That is where LNG Canada comes in. We are all looking forward to seeing the LNG Canada kind of start up and launch in 2025. The question is just when that is going to happen. One of the questions we had was about how much LNG Canada gets produced into LNG and is there a lost percentage. The second one, I will pass over to Terry. The first one, LNG Canada is about 1.8-1.9 BCF a day at full, the first train at full capacity. All of the producers, there are five owners of LNG Canada. There is Petronas, Shell, KOGAS, PetroChina, and Mitsubishi. They have varying, the way LNG Canada works is a little bit different than some of the U.S. LNG facilities, is that each of those owners needs to bring their percentage ownership to LNG Canada. That's their commitment. They also need to find that percentage of buyers. People watch kind of where the production's at. Some of the producers are a little bit below right now, their total amount of production to match phase I of LNG Canada. 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 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? In a conventional plant, typically shrinkages are anywhere from 5%-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? In a traditional processing plant in Western Canada, typically gas shrinkages would be in that 5%-10% range. That shrinkage would encompass fuel and conversion of liquids from gas, recovery of gas, liquids from the gas stream like propane and butane. That's usually 5%-10%. LNG Canada is going to be predominantly electrical powered from an external power source, and there is no liquid recovery. I would expect the shrinkage to be quite small. I would expect it to be maximum 5% or probably lower. 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. A 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. What's important to know is that any LNG projects anywhere in North America are a positive for natural gas producers because all it is is another form of demand. 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. Most of the gas that will be liquefied for any of the LNG projects, and there's multiple LNG projects that are being built off the west coast of British Columbia, that gas is most likely going to come from the Montney area, from Duvernay. It'll come from northwest Alberta, northeast British Columbia. 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 U.S. By virtue of the flow of that gas now going west, that just creates less supply for, it competes with the molecules that we do produce in Alberta. 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 do not know about by surprise, but the Plaquemines LNG phase II in Louisiana came on faster than people thought it would, than I think most people thought it would. I showed a graph of that in my email that went out last night is that there was a kind of a staged as these LNG facilities come online, there's been enough of them now in the U.S. because there's been seven prior to Plaquemines. Plaquemines was number eight. 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 come online. That's actually now we've gone from about it was around 13.5 to 14 BCF a day of LNG exports. Plaquemines has taken that now to over 15. There's been days that it's been up as high as 16 BCF a day. The other two facilities that are coming online in 2025 in the U.S. are planned to come on as Golden Pass LNG out of Texas and then the Rio Grande LNG out of Texas. When all of these come online by the end of 2025, they're talking about they were probably going to be around at 17-17.5 BCF a day. It is pretty significant. We have talked about this hockey stick of LNG demand that is coming on. We have been talking about it for two years now. Just to remind everybody, in 2016, the United States did not export any LNG. They ramped that up to become the largest LNG exporter in the world, which is where they are today. However, that has kind of paused. From 2022 to 2024, there was no new LNG. 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. Very significant. They're looking at by the end of the decade, exiting the decade, somewhere between 28-30 BCF a day, in addition to the extra LNG facility projects that are happening in Canada and in Mexico. Pretty significant. One of the other questions we had was about data centers. That's something that we watch extremely closely. For those of you who've been reading the quarterly emails, 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 a data center. That was in January. We will continue to update our investors as that progresses. What's significant for us is that a lot of these data centers, they need 24/7, 365 type power. They can't have intermittent power. Therefore, natural gas is an obvious source of the power they need. They need a tremendous amount of power. We're seeing a lot of different speculation as to how much the data centers are, their total amount of natural gas they're going to need and 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. Artificial intelligence uses a tremendous amount of power. We're seeing a lot more adoption of AI into everybody's businesses and everybody's life. Therefore, we're seeing a lot more energy need. This isn't specific to North America. This is a global phenomena. 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. That's kind of the struggle that the 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? Stay tuned. I think Alberta is a prime spot because of our natural gas reserves that we've got throughout the province. 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 Kris. Yeah. Thanks, Phil. We continue to be active in hedging our forward production. I think that was, again, evident in the first quarter. We averaged a realized natural gas price in the first quarter of CAD 2.90 an MCF. That is at a premium to the CAD 2.16 an MCF of the AECO average price over the first quarter. As we indicated, for the balance of 2025, we are around 42% hedged at AECO at around CAD 2.90 with a bias of that percentage more heavy in the summer months. We are also 32% hedged on our WTI at $65 for our oil production. Those are all both positive relative to current prices. We will continue to look at ways in the very near term to continue to add in hedge positions that will help protect our cash flow. Also into 2026, I would just note that we've seen prices now at 2026 that we can hedge over CAD 3 an MCF for the calendar year. If you look out to winter 2026-2027, you can actually hedge out at prices that are into the CAD 3.50-CAD 3.60 range right now. These are prices that work very well in our model. 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 2026 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 there has been, it's been very brief times where there's not been something we're looking at over the last 14 years. Sometimes 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. 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 we sat on cash as we looked for acquisitions. I think we showed our discipline that we did not go out and just buy things because there is always things for sale. 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. We went almost two years. We did a deal in December of 2021 and then not another deal until December of 2023. Even though we were sitting in a really strong position with cash, with the balance sheet being able to, we could definitely have done something during that time, we just did not see prices that made sense to us at that time. That is when we kind of started looking at doing more on the CapEx on the drilling side. Our management team really looks at capital allocation as our prime job. As to where with the resources and the cash flow that we do generate, where's the best place to use that? That was one of the reasons why we made the adjustment on the dividend here earlier this year, 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. I think our debt to cash flow on a forward basis would be somewhere around one times at the end of this year. One of the questions we had is how soon could you be in a position where you do not have any debt? That really depends on future prices. If we are entering into 2026 at around one times, you can see there are definitely scenarios where that debt could go down very rapidly, very quickly in 2026. We will continue to monitor it. I think I agree with the comment from the question, which is kind of implied that if you have a lower debt profile, then you are probably in a stronger position for acquisitions. I agree with that. We have always kind of maintained that. That is one of the reasons why we are paying down debt as quickly as we can. Kris already gave you some statistics on that, how fast we have 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 as strong a position as possible. I do not know, Kris, if you have anything to add to that. No, I think that's well put. Again, 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. With better commodity prices, we'll be able to pay that debt down faster. That provides us with even more options both internally and strategically. Yeah. As Kris mentioned before, we're dealing with both 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. As we progress through those discussions, we'll be able to update you more on that going forward. 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. 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. We are 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 does not make sense to do it at that time, then that is fine. Right now, it still does make sense to do it. Our economics would indicate that it is still going to make sense for us to spend some of the CapEx in the back half of this year. We will update you further on that as we go through the year. It is an exciting year. I mean, we went through the last couple of years. It has 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 had not been the case in 2024. It looks like it is going to continue to make up a higher percentage as we go into the back half of this year and into 2026. I think that covers off all the questions we had for Q1. If anybody has any further questions or would like more clarification, do not hesitate to reach out to any one of us. We are happy to provide that. Thanks for your time today. Appreciate it.