Good morning, ladies and gentlemen, and welcome to the Advantage Energy Limited Q3 2025 results conference call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you need assistance, please press star zero for the operator. This call is being recorded on Wednesday, October 29th, 2025. I will now turn the conference over to Brian Bagnell, Vice President. Please go ahead. Thank you, Joanna, and welcome everybody to our conference call to discuss Advantage 's third quarter 2025 results. Before we get started, I'd like to refer you to our advisories on forward-looking statements that are contained in the news release, as well as advisories contained in Advantage 's MD&A and annual information form, both of which are available on SEDAR and on our website. I'm here with Mike Belenkie, President and CEO, and Craig Blackwood, our CFO, as well as other members of our executive team. We'll start by speaking to some of our financial and operational results. Once Mike has finished speaking, we'll pass it back to the operator for questions. If you have any detailed modeling questions, we ask that you follow up with us individually after the call. Finally, I'll note that we have posted an updated corporate presentation on our website. With that, I'll turn it over to Mike Belenkie. Mike, please go ahead. Thank you, Brian, and thanks everyone for joining us this morning. For Canadian gas producers, the third quarter was clouded by the lowest AECO prices in modern history. However, there were many silver linings for Advantage. We delivered steady results that demonstrated the resilience of our business and our ability to create shareholder value through all phases of the commodity cycle. The average AECO price for the quarter was only $0.60 per GJ, which includes a September average of just $0.24 per GJ, with about one week of negative prices. Even under these extreme conditions, we generated adjusted funds flow of $72 million, or $0.43 per share, fully funding our $72 million capital spending program and keeping our debt level neutral. This is a solid demonstration of our ability to fund an annual capital program of about $300 million in virtually any price environment. Revenue for the quarter was dominated by liquids sales, which composed 17% of our boes, but accounted for 64% of our revenue. The Charlie Lake contributed approximately 40% of our total revenue and 31% of our total operating income on its own. Gas revenues for the quarter were 16% higher than the same quarter last year, despite much lower Canadian gas prices, thanks to a larger contribution from downstream market diversification profits. Our risk management program delivered $34 million in realized hedging gains in the third quarter. Production in the third quarter averaged 71,482 boe/d, down 4% year-over-year and 8% versus the prior quarter. This was driven entirely by price-driven curtailments and maintenance. We curtailed an average of 60 million a day of dry natural gas in the quarter, and at times in September, this was over 300 million cu ft per day that was shut in while AECO prices were negative. We've been asked why Advantage is one of the very few companies in the basin that actively curtail production during periods of exceptionally weak prices. We do this for multiple reasons. We refuse to waste our precious resource by selling it for no value or worse, paying marketers to take it away. During the third quarter, we mitigated over $5 million of depletion expense, which is another way to say that we avoided wasting $5 million of capital investment. Since our strategy is centered on maximizing AFF per share or cash flow per share, we won't sacrifice cash flow to defend headline production growth numbers. That is simply put, if it isn't profitable to sell it, we shut it in. To manage our physical downstream delivery commitments, which we do have several of, we were able to improve our cash flow by $2 million this quarter by shutting off our own gas and purchasing, in a way, third-party gas at negative prices and immediately reselling those volumes in the downstream markets for a tidy profit. That is to say, while we preserved our own resource, somebody else paid us to take away their resource and flow it to downstream markets using our pipeline capacity. We also don't believe that having our volumes financially hedged is a justification for producing uneconomic physical volumes. They are separate and discrete revenue streams. Hedging and marketing gains, broadly speaking, are generated by financial agreements that don't require you to produce the gas. Our shut-in decisions are made based on operating income at the plant gate, and everything downstream of that is accounted for separately. To summarize, our curtailments in Q3 maximized adjusted funds flow, preserved our resource base, reduced our capital depletion and expected capital spending, all while allowing us to fully capture our hedging profits. Now, with that behind us and with AECO prices starting to recover as of earlier this month, production curtailments have ended and corporate production has been restored to full capacity, positioning Advantage for a strong finish to the year. We expect fourth quarter production to average between 79,000 and 83,000 boe/ day, resulting in a full year 2025 production of 78,100 - 79,100 boe/d. The new well results that we mentioned in the press release yesterday will certainly help keep our production levels high, and it's worth unpacking that a little. Typically, we would not announce well results with less than an IP30, but at Glacier, the shorter well tests reliably translate into longer-term production expectations, especially given our extensive experience and knowledge of the mining in the area. In this case, the results of our newest pad in the northwest corner of Glacier are truly exceptional. The first well produced at 32 million a day of gas over the last 7 days prior to print and is tracking towards a full 30-day IP, just under 30 million a day, although it hasn't had enough time to actually realize that. This is roughly 3x the productivity of the closest offset wells, only 1 km away to the north. In fact, we believe this well to have the highest initial productivity of any well ever drilled in the Alberta Montney. The second well in the pad produced at a restricted rate of 20 million cu ft per day of raw gas over the last 7 days, over the same last 7 days, restricted as a result of the high rates from the first well, which is already filling the gathering system. The third well on the pad, which targeted the upper Montney, has not been brought in production yet for the same reason, but its cleanup rates look comparable. This is an outstanding result from our multidisciplinary technical team and a testament to their relentless drive for improvement. Looking ahead into the winter, we see natural gas fundamentals at a positive inflection point with oversupplied conditions easing as we move into winter and as LNG Canada is starting to export meaningful volumes. As gas prices recover, our debt repayment is expected to accelerate in the coming months. We are therefore keeping our debt target at $450 million, but introducing a range of ± $50 million, which increases our flexibility around the timing of aggressive share buybacks as we enter 2026. As in the past, when our balance sheet is where we want it, we put everything we have into the buybacks. Our strategy remains focused on maximizing cash flow per share while maintaining balance sheet strength. Thanks to our highly efficient capital program and low-cost structure, Advantage is able to deliver shareholder returns in two ways: disciplined production growth and free cash flow generation. Over the next 2 years, production growth is expected to average about 9% per year. At strip pricing, free cash flow yield is expected to average 10% per year for a total annual return tracking 19%. This outlook is difficult to match. I would like to thank our employees for another great quarter with a lot of nimble reactions and high-quality outcomes. I would also like to thank our board and shareholders for the support. I'll pass it back to Brian for questions. Thanks, Mike. I'll pass it back to Joanna for any questions on the phone line first. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press star followed by the one on your touchtone phone. You will hear a prompt that your hand has been raised. If you are using a speakerphone, please lift the handset before pressing any keys. The first question on the phone comes from Amir [Rafe] at ATB. Please go ahead. Thanks. Good morning, guys. Just a couple of quick questions. First, on those new wells that you brought on, those are terrific rates on those three-mile wells. I know it's early days, but just curious how you think this can improve the corporate capital efficiency for your drilling in Glacier and whether you plan to introduce more three-mile laterals as you develop the Glacier, just given your land block in the area can allow for longer laterals. Yeah, I mean, obviously, good news story. These are not unusually, you know, designed wells for us. These were well-executed, great rock and really, you know, capitalized on all the team's technical advancements over the years with a few new ones. Really, what does that mean? It probably means if we drill in this area, and certainly we have other areas that we expect to have similar outcomes, that means we drill fewer wells and therefore less capital. I think broadly speaking, our Glacier program is typically somewhere around a dozen wells per year, and those wells tend to cost, I'm going to say, $7 million- $9 million depending on the length. This probably allows us to reduce the number of wells per year, which means maybe you save a few wells per year. The program is already so efficient that it's not going to be a massive swing in total capital per year, just a nice little... It juices our ability to save a little extra cash and put more work on debt repayment and buybacks. Modest impact, but positive for sure. Okay, that's helpful. Could you quantify it in terms of capital efficiency on a three-miler versus your typical two-milers? If I understand your question correctly, you're looking to understand how much more productivity per million dollars spent. I think we're probably looking at a sort of a 15% increase in cost for the well versus a shorter well, and the productivity probably goes up by more like 25% or 30%. You can see these are nice little juicers, but what we're talking about here is only a few million dollars of extra spending for a sizable increase. It's all small adds to our program, small increases in efficiency, and not in isolation either. It's just that in this case here, everything came together for the outlier result. The program itself won't change materially, it'll just get a little stronger. Okay. I appreciate that color. The second question is just more on your net debt target range. As you pay down debt faster, and if gas prices are strong, it sounds like you might be willing to start a structured buyback program sooner at the $500 million level versus the $450 million. Just curious what would change that to the lower end of the range in terms of waiting for debt to get to $400 million instead of the $500 million. You bet. The way that we try to explain this is the last thing we want to do is only be buying shares back at the top of the market and not be buying shares back at the bottom of the market. This is, of course, a volatile business. $100 million of elasticity in the system allows us to buy countercyclically. If we're solving for max cash flow per share, at times where our share price is lowest, it gives us the best return. What we're looking to do is forecast whether we buy earlier, like sooner or later, at lower or higher prices. With our outlook currently, based on AECO, which is in a strong contango environment, our cash flow is expected to rise quickly through the coming year or so. If you use that model, it says you probably want to get back to work earlier. Having more elasticity on the top end of the debt range as we deliver allows us to get back to work more aggressively earlier. Hopefully that's enough. We won't tell people exactly when we're going to buy because that would, of course, not be a very good trading strategy. Think of it as a useful guidance. Yeah, I appreciate that, Mike. Thank you. Okay. Thank you, ladies and gentlemen. As a reminder, please press star one for any questions on the phone. Next question comes from Luke Davis at Raymond James. Please go ahead. Hey, good morning, guys. Just wanted to get some background on how you're thinking about shareholder returns and specifically buybacks in the context of your looser debt policy. Sure. Shareholder returns, of course, I did sort of refer to that in one of the last comments, which is we see shareholder returns in two ways: production growth and free cash flow. The use of that free cash flow is always, you know, up for debate, and everyone has a different perspective on the best use of free cash flow. For us, you have to start from all options, which are debt repayment, share buybacks, and dividends. Dividends, of course, in our case, with a high cost of equity and us being a growth company, are the least efficient way for us to redeploy that free cash. We have stated that we want to get to the range of $400 million- $500 million on debt, and that's a priority. There's almost a mathematical order of priorities, which is deliver, and then once you get to a spot where you have material amounts of free cash to redeploy, there's a question. Do you spend that on drilling a well? Do you deliver further or do you buy back shares? Every penny or every tranche of share buybacks is subject to that same test. What we're looking to do is solve for max cash flow per share in that as a quotient. That can change over time. We won't be too specific, but hopefully that helps you with the framework. Yeah, that's perfect. Thanks. Okay, great. Thank you. Thank you. No further questions on the phone. I'll turn the call back over to Brian Bagnell. Okay, thank you, everybody, for joining our call. I look forward to catching up with you individually. That concludes the call today. Thanks, everybody. Ladies and gentlemen, this concludes today's conference call. We thank you for participating, and we ask that you please.