Good morning, and thank you for joining the Pine Cliff Third Quarter Webcast. With us today in the room is Phil Hodge, President and CEO, Terry McNeill, Chief Operating Officer, Kris Zack, Chief Financial Officer, and Austin Nieuwdorp, Vice President Finance. I'm going to turn the call over to Phil for some opening comments. Please register your questions on the webcast, and we'll get through all the questions and provide some additional detail. Thanks, Chris. Thanks, everybody, for joining us this morning. As usual, we won't just read the press release. We'll assume everybody's read the press release, and just kind of what we'd like to do is give a little bit of color and answer any questions that anybody may have. Q3 was, when we looked at 2024 coming into it, Q2 and Q3 were the two quarters that we were most concerned with. We have come off two relatively warm winters. Storage was very high coming into this summer. We knew that there was going to be no major natural gas demand pieces falling into place quite yet. We know that's coming, and that's going to be primarily in the form of LNG, but also in some of the other projects that are launching in Western Canada that are going to use natural gas. We kind of had a bit of a plateau from incremental demand. Because of the warm winters, we knew that it was going to be a summer where producers would, at least in the U.S., reacted quite nicely as they reduced production. It went from 105 BCF a day to under 100. In Canada, as I mentioned in my president's letter that you assume you've read, it was a little bit different because everyone's getting ready for LNG Canada, the first phase. That's expected by mid next year. We're talking about now only eight months away. It won't just go from zero to 1.9 BCF a day. There'll be periods of time where they will be commissioning the plant, testing facilities, testing storage, probably even shipping some ships may leave the port to test everything before they go into full operation. Those are all positive things, and that will require more natural gas to be sent to the Kitimat site. Our industry is watching that closely to see what's happening there. We've seen the same thing happen down in Mexico, where they're starting up a brand new LNG facility at the Altamira. And then we've got the Plaquemines and Golden Pass projects, LNG, that are expected in the next six months as well, coming out of the Gulf of Mexico. So there's a lot of incremental LNG exports that are coming out of North America here in the next six to nine months. But in the short term, it really is about weather. And this is a scenario that we've been through many times before. This is now our 13th year running Pine Cliff. We've had some warm winters before and therefore had the overhang of storage. The one difference that I would say that this period of time versus previous is that the storage is full in both the United States and in Canada and in Europe. But we've seen how quickly that can change. And I think the reason I say that, it's not just a matter of what impact does one project have or a change in weather forecast, but the amount of gas that is used across all our industries and sectors is a lot higher than it has been historically. It continues to grow, and yet storage doesn't grow. And so we've got a situation where we've got very full storage, but the reality is that that storage is now supporting a much bigger infrastructure and environment, if you will, of natural gas demand. And therefore, it can get pulled down a lot quicker because there's a lot of projects and different sources or different demand uses for the natural gas. We saw this in Europe here just recently in the last few weeks, where their storage came down quite a bit faster than they were anticipating. And therefore, prices went over to $13. That's what they're at currently in Europe. We've seen a movement from both AECO in Western Canada and NYMEX in the United States as some cold weather is starting to set in. We're starting to get some blue in the weather maps. And I'd say that's positive for natural gas prices. But it's very, very early. I mean, November is not a month that typically uses a tremendous amount of natural gas for heating. Those are usually more reserved for December, January, February. And so people are speculating on what that's going to look like. But we're starting to see weather maps go into December now or projections and, like I say, some of the blue. So that's kind of an overall. Maybe I'll turn it over to Terry for just a few comments on our production and how we dealt with operations over the last couple of quarters. Sure. Thanks, Phil. Terry McNeill. I'm the Chief Operating Officer for Pine Cliff. And as Phil said, Q2 and Q3 were challenging quarters when it comes to gas prices and production in particular. One thing that we did have this summer, which I think we had done a pretty decent job of this year than previous times of low AECO prices, is we had some good hedge support in place. And between forward selling and hedges, we actually had very little gas exposed to day pricing. So that was very, very helpful. We did have some shut-ins in September and into October, which did impact production, but not nearly as significantly as we had had if I look back to 2018, 2019, and into 2020. So one of the things we were concerned about was low pricing, and we made sure we protected ourselves going into the Q2 and Q3. One of the other challenges we had in a quarter where we predicted cash flow wasn't going to be as strong as in the past and in these low prices is we reduced the amount of field optimization and swabbing programs. Pretty well anything that wouldn't have paid out in a month or two is we just deferred it. And just as capital preservation as we did not know where prices were going to go. Many of those projects were done in early October. Once we started to see some movement in AECO positive and get closer to winter, we started to do some of those optimization projects. Swabbing in all our dry gas areas was resumed, and we have definitely seen a production response. So right now, we're between 23,000 to 23,500 BOE a day on any given day, which is a pretty healthy amount. I mean, we're looking at some 10% corporate decline throughout the year. And so the assets are performing very, very well. And so I think from a deliverability perspective, we're really quite satisfied with that. So I think that's probably. Yeah. Maybe the production is an interesting one, and maybe you, Terry, you're probably the best suited to comment on this. Maybe a little bit of a look back on the Certus acquisition and how we feel about that now or nine months after acquiring it. Yeah. Certus acquisition, as many of you know, we did a major corporate acquisition of Certus Oil & Gas. It closed in December of 2023, so almost an exact calendar year ago, and when we took it on, we knew there was going to be some ups and downs on it, but that's part of the opportunity that we had seen. It's hard to quantify exactly what you're getting until you get in the driver's seat. So once the deal closed and we were able to get in the driver's seat, there were some challenges right off the bat, but cold weather, start of winter last year, January came out of the gates pretty chilly, and so we had to kind of work through a few different things, transitioning assets, staff over to Pine Cliff. We did work our way through a lot of that, but I would say there was really an inflection point on those assets. Probably middle of the year by we got them in, we understood them, made sure that they were fully integrated into Pine Cliff. Systems were updated and integrated, and staff was fully updated and integrated into the way we would want to operate those assets going forward. So I think it's been a fantastic acquisition. I think looking back, it's going to be probably one of the better ones that we've done. Some of the things that we've done, I mean, net operating income and cash flow from those properties has been actually quite strong. It's been, I would say, pretty well as we would have expected when we did the acquisition in December of last year, which is actually quite telling considering the forward strip at December 2023 was quite a bit stronger than it actually ended up being in reality, so cash flow was really quite strong from the properties. Drilling inventory, we've been able to work with some area producers and do some mutual undeveloped land swaps in the area to consolidate a good operated land position around our owned and operated infrastructure that will allow us to drill at our pace that we want, which is actually really quite exciting and increase the inventory of drillable locations considerably. The prolific OverPressured block in the area is the main play today, and we've really been able to add a significant number of locations of two-mile OverPressured block locations. OpEx, we've seen a 10% reduction in OpEx from pre-acquisition to post-acquisition, and probably the assets themselves from a production basis, when we announced the transaction in October of 2023, that we were entering into an agreement, we had 5,300 BOE a day of announced production, and today, we're at just a shade over 5,300 BOE per day of announced production, which is essentially flat production for 12 months, and again, that's a kudos to the operating team and to making sure that we optimize everywhere that we can and bring on some old legacy production, so we're happy to say the assets are fully integrated. Cash flow is excellent. Drilling inventory is more than what we would have expected. OpEx is reduced and decline. The assets are performing very, very well. So yeah, I think it was a good job by our team to be able to identify the opportunity, get it over the finish line, and integrate it. So we're really, really quite excited about those assets going forward. Thanks, Terry. Yeah. I think looking back, I mean, there's no doubt that that acquisition enabled us to have a stronger cash flow going into 2024 because of the liquids being added, and that was able to sustain our dividend throughout 2024, which was a key part of why we did the transaction. Maybe we'll turn to questions, and again, we encourage you to send any questions through the email if you've got any. We've got a few here teed up. One is with regard to LNG, and actually, we had a couple about LNG and the timing. We watch this pretty closely. There is a new, I guess it's a data point over the Willow Valley. It's a new, I guess it's an offshoot of the TC Energy system that goes directly to Kitimat. So you can tell if gas is being drawn through that site or through that location. And the only place it could be going is to LNG, the Kitimat site. So we watch that pretty closely. And it's been sporadic, but we do see volumes flowing towards the Kitimat site, which means that they are using natural gas. They are commissioning. We saw that they are now flaring. For those of you who receive my quarterly email, you'll see that we had a picture on there of kind of the flare site that's up there. Every indication, they keep talking about mid-2025 being in full operation. I saw some speculation by a research analyst as to how fast that might ramp up. No one knows for sure other than probably the LNG Canada operations team. What we can look at is other LNG facilities and how they've come out of the Gulf of Mexico and how did they ramp up? How did they get to full commercial production or exports? And so it's going to be sporadic. And I think what we're seeing now is expected. They seem to say that they are fully on course. The site is over 95% complete. The Coastal GasLink pipeline is 100% complete. So we're fully expecting that it will be in operation within nine months. How much will that be at the full 1.9 BCF a day going out every single day? Or will it be some reduced amount gradually moving up to 1.9? That we don't know. But we watch it closely, obviously, because this will be the first time that Canada has ever had exports to anybody other than the United States. So that's a pretty big chapter from a natural gas producer's standpoint. We've got another question about hedging. Maybe I'll throw that over to Kris. Yeah. Thanks, Phil. So as Terry highlighted, we really did benefit from our hedge positions in the third quarter. To put some specifics around that, we had an average realized gas price in the third quarter of $2, while the average AECO daily 5A price averaged just $0.68. For the balance of the year for the fourth quarter, we're about 44% hedged on our natural gas at $2.77 an MCF. Looking out to 2025, the hedge positions do start to taper off that are currently in place. So speaking on an annual basis, we're about 25% hedged at around $3 an MCF for 2025. The balance of our production, 75%, so 10% of that will be priced at Dawn and 65%, pardon me, will be AECO Plus. So we have significant leverage to improving AECO gas prices. But as a dividend-paying company with capital commitments, we will continue to look to layer hedges on opportunistically, particularly going into the back half of 2025 as the forward strip going into 2026 is still strong. And so expect us to continue to layer on hedge positions to help protect our cash flow, which in turn will help protect our cash outflows, including our dividend. Thank you. Another question here with regards to the dividend and how we think about that going forward. And the specific question is, have we considered kind of a hybrid dividend structure, which would be a base dividend and maybe a variable dividend as free cash flow permits? It's a good question. It is something that we have spent a lot of time talking about, thinking about. And I wouldn't say we've made a definitive decision on this at all. I think as we believe the free cash flow is going to be increasing in the next couple of years from 2024. The forward strip would seem to dictate that that's going to be the case. We've got to think about how we do it from a capital. This year, 2024, we felt it wasn't prudent to be drilling wells and bringing on new wells with the gas price being as low as it was. But as gas price looks like it's going to be continuing to improve into 2025 and 2026, then we will go back and look at our capital expenditure budget. And so we haven't set the budget yet for 2025, but that'll be something that will be done here in the next few months. Typically, we kind of announce that usually in Q1-ish of the next year. The variable dividend is something we watch. Many of the several producers in the United States and a couple here in Canada that are kind of using the variable dividend structure. The advantage of that is that you're not committing to it. And therefore, it's kind of like share buybacks is that you can dedicate as much as you feel comfortable in any given time period. That's definitely the advantage. The disadvantage is that from investors, you don't have as much visibility as to how much what is your dividend yield going to be. So like I say, there's pros and cons. It's something that we will keep an eye on going forward. I think we still believe that dividend is probably the best way to return capital to our shareholders at this time and going into 2025. At some point, it may make sense for us to look at share buybacks. That's not been something that we've considered at this point. We are very, I think it's no secret, we're an acquisitive company. We've gone from 100 barrels a day to 23,000 in the last decade. And so we're always looking for more assets that will fit the model. As Terry just highlighted, the last transaction we did was a very good fit for our business model. And we did that without issuing any shares. And we just took on the debt, which we were now paying down. We'd like to get that, even though the debt on a forward basis, depending on what your cash flow, we're very comfortable with it from the level of debt we have. We'd still like to see it go down because it gives us maximum flexibility for potential acquisitions. So debt reduction, maintenance of dividend, those are the two primary focuses for us right now. As free cash flow grows, then we'll look at kind of the CapEx program. We'll look at acquisition opportunities, and we'll look at the dividend and see how comfortable we are given where the cash flow is. So I'd say all options are still on the table. And I think that's. I personally think that that's a practical way to run the business. I think we've never been stringent saying we're only going to do this or we're always going to do this. I think you have to continue to adapt. We're going to have a very volatile natural gas market for the next few years. That doesn't mean it's not going to be a good natural gas market. It's just going to be volatile. There's going to be times it's going to be up and down. And so we're going to have to continue to manage that. And again, this is nothing new to us. We've been doing this now for over a decade. I think going into, given how much new demand is coming on in the next few years, primarily with LNG, but also with the data centers and with all the power demand, I think it's going to continue to be a challenging time. There's a question about AIMCo and whether or not any of the recent changes at AIMCo. For those of you who haven't been following this story, the entire board of directors of AIMCo were recently removed by the province of Alberta. AIMCo is the Alberta Investment Management Company for some of our shareholders or listeners that are not in Canada. They are the sixth largest pension fund in Canada. They are about CAD 170 billion, and they are our biggest shareholder. They've been our debt holder at times, and we paid down all that debt, but they continue to be over 10% of our stock. They've been with us now, I think, since 2016-ish. So we're kind of going on eight years with them. The people that we deal with that manage the investments were not let go. They're still with AIMCo as far as we know. And I had a conversation with them just after the announcements came out because along with the board of directors that was removed, so was four of their senior executives, including their Chief Executive Officer, their CEO. We don't think there's any change in the relationship, and they indicated that there's no change in the relationship. So we're very proud of the relationship we got with that group. There's a question about if we will—are we going to consider any countercyclical acquisitions before the ramp-up? And very good question. I think as many of you who know and have been shareholders with us for some time know that there's. I don't think there's ever been a time that you could have asked us, "Are you looking at something?" where the answer would have been no. We're always looking at assets. We're always in data rooms. And quite often, it's multiple things we're looking at. And so we don't have a very big team. So we have to prioritize and put what we think is the most, which transaction might be the best fit for us to focus on. So we are looking at things. It's a bit of a challenge, frankly, because there's the spread between the bid and the ask on the natural gas. We're not the only ones who believe natural gas is going to be a much better place to be in the next couple of years. And because of that, if you're a natural gas, if you're an owner of natural gas assets, you're probably a little reluctant to sell right now because the cash flow on those assets will be quite low. And yet you believe that it's going to be a lot better. The flip side is, as a buyer, you can't give people a lot of, you can't pay up for something that hasn't happened yet. So forward strip is slowly moving up. If that continues, I think that could loosen some assets up because then it becomes a price. As a buyer, you're comfortable buying on forward strip because you can hedge those prices. You can lock those prices in. But we can't be buying assets on the hope that gas is going to be $4 next year. It very well could be $4 next year, but that's not what the forward strip is today. So there's a little bit of a tension there, I think, between buyers and sellers right now, at least on the natural gas side. The flip side is on any of its oil-weighted assets. You've got higher spot prices, but it's got backwardation. And so therefore, somebody says, "Well, give me three and a half times or three times cash flow on today's asset, on today's cash flow." But then you look forward and go, "Well, yeah, but we'd be giving you four or four and a half times cash flow on future cash flow," which is more than what kind of the market's at. So there is a. I think there's multiple assets and multiple companies that are going to be coming available in the next six to nine months. I think this winter could be, we could see some assets come available that would be a good fit for us. And if that's the case, we will definitely be interested. Next question. Let me resume. CapEx, the quickest and highest. So we got a question about when we do go back to spending on a drilling perspective, where do we think we're going to be able to find the quickest and highest returns? Maybe I'll turn that over to Terry a little bit to talk about our inventory and how we look at our portfolio. Thanks, Phil. I mean, our asset team is, our exploitation team is chomping at the bit to get a bit in the ground. They've been carefully cobbling together locations. And as I had said earlier, the Certus area would certainly be one of the top priorities. They are rather expensive wells, sort of that CAD 8 million, give or take, per well. But the results are terrific. The horizontal block well that we own and operate, we own 62.5% of it. It came on production in October of 2023, and it continues to produce today at over 4 million a day with probably 30%, 35% oil and NGLs, and the rest is gas. And it still produces at about 4.5 million a day raw volumes restricted. So we're really, really excited. It would have paid out inside of 12 months. Those are the type of OverPressured block opportunities that really excite us on the former Certus properties. On some of our legacy properties, particularly in the Ghost Pine area, there's some emerging plays coming up around us from the south onto our lands. And it's been very, very exciting. We've invested in some seismic and trying to understand that play. But there is definitely, based on our evaluation, there is definitely some lower-cost emerging plays on some of our legacy wells west of four. So when it comes to capital allocation, where would we go or where we wouldn't go? I think even under today's current forward strip, whether we drill some of our legacy plays in the Ghost Pine area, whether we drill in the Certus area, we are looking at 12-month, give or take, payback. So they are very, very short payback. Certus ones are a little bit higher capital cost, but the results are on a BOE basis, a little bit more BOEs, but both are fantastic rates of return. So I'm not really answering the question, but I think it is an evolution with Pine Cliff as to where we would put the bit in the ground first. But I think suffice to say with our inventory and the way our inventory has evolved over the last 12 months, we've got some fantastic plays that are repeatable that have got 12-month, give or take, payback. So quick return, good economic wells, and we're in the strongest inventory position that we've been in since I've been here in 11 and a half or 11 years at Pine Cliff. So we're very, very excited. Yeah. I think that's a really good point, Terry. I said we've never had this many—this extensive an inventory and the options we've got. The Edson area is something that continues to be an area that has got good drilling upside, more gas and liquid focus there. But we've had very, the Pacheco locations that we've done in the past have been very good rates of return. We're very happy with, and we feel there's still a lot of locations there. And then the last transaction that Terry talked about in the Caroline area, the Certus transaction, the Sundre area, it's got some very good. And then this Basal Quartz area is an existing asset base that we've had. It now has a lot of activity around it. And so we're spending it. So it's a very healthy opportunity that we've got looking at us. And that's a very good thing to have where there's a real debate as to where we should spend the capital. But we are looking forward to spending some of that capital when we've got the free cash flow to do so. We've got a couple of questions here about the interest rate on the debt. Maybe Kris, if you want to handle those. Yeah. Thanks, Phil. So when you look at, we've got two debt instruments that we use. Most of our debt is in the term debt facility that was taken on as part of the Certus acquisition, which we continue to pay down on a quarterly basis. But we also have a small operating line with a financial institution that helps with our working capital on an ongoing basis. If you take the combined effect of those two together, we're just below 10% on a combined interest rate perspective. It's 10.65, I believe, on the term facility and then sub-10 on the operating line. Obviously, the interest rate environment is something that we continue to monitor. There's a sensitivity in our financial statements that would tell you that a 1% increase in the prime rate would impact our net income by about $0.6 million. We paid $1.8 million in total interest on a cash basis in the third quarter. So that was still covered by our cash flow in an extremely difficult commodity price environment for natural gas prices. But obviously, the interest rate environment is something that we will continue to monitor, and we'll look for opportunities where we can improve our position there. And we will continue to pay down our debt. So as our debt declines in 2025, our total interest charges will also come down as a portion of our total cash flow. Yeah. Thanks, Kris. Yeah. I think it's, as I said, lowering our debt back down. As many of you know, we were debt-free for a couple of years before we did the Certus acquisition. But our goal is to continue to pay down the debt. We're paying it down every single quarter. And so that's going to continue into the next year. We've got a couple of questions that are kind of tying to the same theme, is that there are opportunities being provided to natural gas producers in Western Canada, both as to be supplying natural gas to the LNG facility, the Kitimat LNG Canada, and also with regard to the data centers because our provincial government here has been very vocal that they would welcome data center build-out in the province. On the first one, I don't think that we personally haven't been involved with discussions to provide natural gas or that would be dedicated Certus that would be for the LNG facility. I think that's going to be, I think, the domain of the major players or the others that have Station 2 capabilities. So Station 2 is the British Columbia pipeline system. So although we benefit from, I've always said this, that any LNG exports from North America benefit all of the producers because any gas that's leaving the continent means that there's less gas that's competing with the demand that remains in your own jurisdiction. So we're very big supporters and big fans of all the LNG export projects that are happening right across, like I say, from Kitimat all the way down through to Mexico and the Gulf of Mexico. The second one is an interesting one, the data centers. We've had, four or five years ago, we had multiple groups approach us from the Bitcoin world because what they are seeking is a very dependable, low-decline natural gas source to provide power. And so the idea is that what they call ring fence, they essentially would come in and bring their own power generation. They would use our natural gas to generate the power, and then they would provide that power for their internal facilities. It's essentially the same thing with data centers, in that we now have multiple groups that have approached us to talk about natural gas being the prime source for their power needs. We've had different discussions depending on the size of power needs that they've got. We've got several sites that are very optimal for this type of transaction where we own the land, where there isn't a lot of residents. So from a noise perspective, we've got very low-decline gas production that gets centralized through facilities. These are all key factors that have—they're near fiber optics or near population bases for the people that are going to construction and for running these facilities. So we'll see how that unfolds, but it's definitely something we're spending some time on. And we're quite optimistic that some of our sites could become very good locations. What that means, I suspect that I know these groups are talking to many natural gas producers, not just ourselves. Any of these deals, when they get done, and I believe they will get done, are going to take natural gas off the system. To me, that is very similar to exports going out of Kitimat. Any gas that's taken off the system just means there's less competition, and there's still rising energy demand for natural gas, especially in Western Canada, especially in the province of Alberta because the province of Alberta is the very last coal facility shut down. We are now entirely reliant on natural gas, wind, and solar, a little bit of hydro. But now natural gas is over 60% of all the power in Alberta. As I've highlighted before on my emails, the oil sands continues to use over 3.5 BCF a day for their production up in Fort McMurray. Just to keep that in relative terms, all of Canada, all of Western Canada essentially, produces about 18 BCF a day. That's 3.5 BCF a day is a very high percentage. We've got a question whether we would use our stock as currency in an acquisition. We've done that before, and it's been over five years. We haven't done it since 2019. But yes, that would be a possibility. We look at every transaction as to what is the maximum benefit to the shareholders. And we've been consistent with that ever since we started Pine Cliff. And so when we looked at the Certus acquisition back last year, equity was a possible piece to that. It was a CAD 106 million acquisition. We had about CAD 50 million of cash. Our view was that at that time, taking on the debt would be the most optimal way to structure that transaction for our shareholders. But going forward, we're not sitting with a CAD 50 million cash at this time. If there's a really good accretive opportunity that arises here in the next six to nine months where our shares may need to be a part of it, we definitely would consider that. But I think we've shown just how disciplined we are with regard to issuing stock. So it would have to be a transaction that we think really makes a lot of sense. We see some opportunities where the private sector also sees what's coming for natural gas, and they're not necessarily looking to get out. They would just like liquidity from an illiquid investment. So that type of transaction where you're taking something and you're giving back shares, it's a very tax-efficient way for them to move from an illiquid asset into a liquid asset. So that type of structure could make sense. But again, at the end of the day, it's going to have to make sense to us as shareholders. And as everyone knows, our management team owns a lot of stock. So we're not looking to empire build, grow just for the sake of growth. It has to make sense on a per-share basis. I guess we've got a question about being a low-cost producer and then our lower break-even and what actions we can take to further lower our costs of production. I'll hand that over to Terry. I think if you look at our G&A at the corporate level, it's been moving down quite nicely through 2024, quarter after quarter after quarter. That's as we assimilated and brought in the Certus assets. I think we're very proud. Terry's group in the field has done a tremendous job, not just with this acquisition, but I would argue with every acquisition where we've done on lowering costs but maybe, Terry, you can give a little bit more color. Sure. I can, and I guess on any operated asset, the bringing down cost obviously has to do with providing ownership and leadership in the field, the opportunities to make sure that they can make the decisions they need. A lot of them have got some great ideas on how to make sure we optimize production at the lowest cost and cut costs, so on the existing assets, that's what we've done. During lower gas prices, quite often what we'll do is, again, lack of swabbing. It hurts production a little bit, but it certainly saves us. So any longer payout items, we are constantly reviewing more marginal fields to decide if they are reaching their end of life. We've got a couple that are getting awfully close. And as part of that whole closure side of it, over the last number of years, we've abandoned over 1,000 wells. This year, we're going to get over 75 reclamation certificates. And each one of those helps remove some marginal and inactive liability off of our records and gets rid of those fixed costs. I think we've probably abandoned this year; we're going to be about 110 pipeline segments that are going to be abandoned. But if I went back over the last three or four years, we're closer to 500 pipeline segments abandoned plus facilities abandoned. Again, all these help reduce the tax burden. And anytime we get a reclamation certificate, that helps eliminate fixed costs associated with surface land. And so we continue to ramp up our Reclamation Certificates, reclamation, and remediation activities. So those are all very, very helpful. And then, like I said, finally, some of our more marginal fields that are reaching the end of life, they are ultimately going to get shut in and flip to abandonment and reclamation, so. Thanks, Terry. We've got a question here on what we've heard about phase II of LNG Canada. We're sitting on the outside, but we talked to a lot of players, so one thing that gave me a lot of comfort around the potential, sorry, I should reset for not everybody maybe is aware of this, so LNG Canada, phase I is 1.8 BCF a day to 2 BCF a day, depending on if you're counting the fuel gas that they're using, etc. That has gone positive FID. FID is final investment decision. What we're all waiting for is positive FID on phase II, and this is, we think, a highly likely event to happen because the Coastal GasLink pipeline was built with the capacity to be able to support both phases, and we think they've been very clear. Shell is the lead on this, along with its four other partners being PETRONAS and KOGAS and Mitsubishi and PetroChina, that they will. I think it's a highly likely event. I think we have not heard specific timing. We've watched what they say in their webcasts and their quarter announcements. We think that the BC government election, now that it's complete, that hopefully will be a positive because the same government that was in place when phase I was approved is still in place and still in power. So I think it's going to be a high probability, but I'm really just looking from the outside along with everybody else. What I find more interesting, or just as interesting, I guess, is the Rockies LNG project at Ksi Lisims. And this one is involved with several of the producers of Western Canada have banded together to look at another project that is just north of the Kitimat site. And it would be another 2 BCF a day. So you could, in theory, with the Woodfibre and the Haisla project, that's about 0.4, 0.3 BCF a day. Then with the phase I and phase II of LNG Canada, you're now up to close to 5 BCF a day. And then if you add in the Ksi Lisims, another 2 BCF a day, it is conceivable that we could be exporting up to 7 BCF a day off the west coast of British Columbia by the end of this decade. And the fact that Tourmaline is now involved in the Ksi Lisims project, that I take as a very strong positive, as Tourmaline is Canada's largest natural gas producer. So the fact that they're involved in that project, I think, increases the probability that that could go forward. We've got a question here on the drilling. I think it's just a follow-up on Terry's earlier comments on the Ghost Pine area and the drilling. So I'll hand that over to Terry. Sure. I think the question has to do with the emerging play that I had referenced a little bit earlier in the call in the Ghost Pine area. It is a Basal Quartz play that is coming up from the south onto our lands. It's predominantly in the Drumheller area. And it's a very, very exciting play. There's a number of, mainly at this point in time, privately owned companies that are developing that play. Drill cost, the drill complete cost for those wells are about CAD 3 million. They come on fairly strong, heavily weighted to oil, which is another way to help deleverage the risk on the gas side. And we've got a significant land holding in the area. The play has been coming to us. We've been watching it probably for two to three years, and the initial results were quite variable. But now they seem to be starting to get locked in relatively well. We've had advanced discussions with many of the private producers in the area to see how we can participate not only on our existing land base. I think the other key piece to the puzzle is we've got the single biggest gas plant with available capacity in the area to process the gas from those wells. They do start out quite oily and turn quite gassy. The GOR increases over time. So they do need a place to take those volumes to. And we've got an extensive gathering system with a gas processing facility with capacity in that area. And we are the single biggest processor with an extensive gathering system, as I said. So we are going to certainly participate in that side of it. But we did buy quite a bit of seismic earlier this year over our own operated land. And we've got a fairly extensive land position. And so, with a little bit of research, you can go and have a look. But the emerging Basal Quartz play in the Drumheller area is really quite exciting. There's a number of different producers developing it. And we're paying very, very close attention to it. And so the netback's internal rate of return looks good, and the payback is quick. Terry, and what would the really high-level ballpark cost of drilling be in the Ghost Pine area and also in the Caroline area? Ghost Pine, Basal Quartz well is going to be about $3 million gross cost. That'll be drill case complete. And then tie-in will be probably another $500,000 depending on how far you would need to go and how the surface lease is set up. And then on the Sundre area, we're using about $8 million drill case complete. And then tie-in could be on-lease tie-in. I mean, a lot of those are horizontal developments from existing surface locations, which certainly keeps the tie-in and equip cost down. Some of them, as the play emerges on our own land, we are going to have to do some modest pipelines and tie-ins, but those are yet to be determined. So we're using probably 8-8.5 million in Sundre and 3-3.5 million on our Basal Quartz and Drumheller. Thanks, Terry. We got a couple more questions here. The one asking whether we'd ever consider a DRIP. For those that aren't, that's a dividend reinvestment program. They were very popular, very well used. I'd say quite a few years ago. I don't know how many DRIPs are still out there in the oil and gas sector. It's not something we've specifically considered. I do know that we've got multiple shareholders because they tell me that they create their own DRIP. And in the sense that as the dividend comes in, they just buy more stock each month, which is essentially what a DRIP did. So it's not something we've considered. One of the things that one of the reasons that people went away from the DRIP is because they typically were set up as a discount to the market. And therefore, the dilution was not immaterial. And so from our perspective, it's the way I kind of treat it too, because I'll go into the market and just buy stock in the market. That's kind of what we've looked at. So I don't think a DRIP is something that we're considering anytime soon. We also got a question about. There's been some interesting dry gas acquisitions in the U.S. over the last few months. And if we ever look down there, we get sent opportunities from all over the place, even offshore. We've had some people bring us ideas that were in countries around the world and definitely have seen a lot of kind of teasers, if you will, sent to us about U.S. assets. We're very reluctant to move outside the jurisdictions we know. I'm always a little skeptical when management teams feel that they can just go into a new jurisdiction and keep doing what they were doing in the previous jurisdiction. We know how difficult it is to operate in any jurisdiction. And so we've become, I think, very good at operating in the province of Alberta and the province of Saskatchewan. We're even reluctant. We've looked at BC assets in the past, but that's another jurisdiction with another set of regulatory and another set of way of doing business. So we've been a little quite often shy away from those types of assets. I'm not saying we'll never do them in the future, but we prefer to keep them close from a Terry mentioned the operating costs. The more you spread out your assets, the more you're not going to have synergies on the operating costs. And so that's something we're very sensitive to. So the short answer is no. We haven't seriously looked at any U.S. assets. I guess you never say never. It's possible that something comes down the road that is extremely compelling and for whatever reason is something that we think we can actually bring extra value to. We just haven't seen that yet. And so I think there's going to be ample opportunities, I believe, in Western Canada, specifically in Alberta and Saskatchewan, for us to keep us busy for many years to come. That concludes all the questions. Thank you very much. We really appreciate all of that. I think that's probably the most questions we've had in any of the webcasts we've done. And it was a relatively quiet quarter. But I suspect, and we're sensing this from the calls I'm getting from shareholders and potential shareholders, it is going to get, natural gas is going to become extremely topical in the next six to nine months. For now, it's going to be about the winter and about the weather and what impact that's going to have on natural gas. But we're soon going to be talking about a lot of LNG projects that are going to be coming online. The ramp-up of after a plateau of two years, the ramp-up is very steep. And you can see that in our presentation on the one chart we've got about the LNG projects coming on. So thank you, everybody. Thanks for your support. Thanks for continuing to follow the Pine Cliff story. If you've got further questions that weren't fully answered today, please reach out to any one of us, and we're happy to talk to you offline. In the meantime, I wish everybody the best and have a good day. Thank you.