Advantage Energy Aktie

Good morning, ladies and gentlemen, and welcome to Advantage Energy Limited Q1 2026 Results Conference Call. [Operator Instructions] Also note that this call is being recorded on Friday, May 1, 2026.

And I would like to turn the conference over to Brian Bagnell, Vice President. Please go ahead, sir.

Thank you, Sylvie, and welcome, everybody, to today's conference call to discuss Advantage's first quarter 2026 results. Before we begin, I'd like to remind listeners that our remarks today will include forward-looking information and references to specified financial measures. Advisories on these items are contained in our news release, MD&A and annual information form, which are available on our website and on SEDAR.

I'll also note that we posted an updated corporate presentation on our website. I'm here today with Mike Belenkie, President and CEO of Advantage; Craig Blackwood, our CFO; and the other members of our executive team. We'll start today by speaking to some of our financial and operational highlights. Once Mike has finished speaking, we'll pass it back to the operator for questions. And as usual, I'd like to ask that if you have any detailed modeling questions that you follow up with us individually after the call.

And with that, I'll turn the call over to Mike Belenkie.

Thank you, Brian, and thanks, everyone, for joining us today. It's my pleasure to discuss our results for the first quarter of 2026, and the year is off to a great start. Advantage generated adjusted funds flow of $121 million or $0.73 per share. It was a highly active quarter with capital spending of $136 million, which is almost 50% of our full year capital budget just in the 1 quarter. We offset a portion of our spending by selling an unutilized infrastructure asset for $12 million plus assets in kind with an additional $7 million. And this helped us keep debt levels relatively flat at $556 million.

Production averaged 81,375 BOEs per day in the quarter, which was a 2% increase from the fourth quarter of 2025. And liquids continue to play an increasingly important role in our business, generating 44% of total sales revenue during the quarter at an average realized price of $84 per barrel. So even in a quarter with weak gas prices and an intensive spending profile, the business continues to generate strong cash flows. We drilled 12 gross wells in Glacier and Valhalla and 13 gross wells were recently brought on production.

Our oil-weighted Charlie Lake asset continues to exceed expectations with 5 wells brought on production in the first quarter. We're forecasting the asset will deliver over $120 million of free cash flow this year, reinforcing the benefits of diversification. Meanwhile, our recent wells in Valhalla Montney delivered strong initial rates and well condensate ratios exceeded 185 barrels per million cubic feet, which is in line with the greater Wembley play, though this is early data, and we will be keeping an eye on the decline profiles.

Most significantly during the quarter, construction of our new 75 million cubic feet per day progress gas plant reached mechanical completion and commissioning is now underway. The progress gas plant is perfectly located at the intersection of 3 of our liquids-rich plays, the Valhalla Montney, the Progress Montney and the Charlie Lake. Not only will this plant drive the next phase of growth for Advantage and help reduce operating costs, but it's also a realization of a regional development strategy we've been pursuing for the last 15 years. The last pieces of the puzzle have now fallen into place with Glacier, Valhalla, Progress and the overlapping Charlie Lake assets all the way up to Gordondale, now forming one massive contiguous resource block with a network of owned and operated strategic infrastructure.

This is a significant milestone for us, and I'd like to take a moment to thank our team for their hard work, finishing this important project on time and on budget. With spending on Progress behind us, we're entering a period of highly efficient capital development with escalating free cash flow. We don't plan to spend any capital on capacity expansions for at least 2 years, with almost all spending aimed at high rate of return wells into existing infrastructure. We have less than $100 million of capital planned in the second half of 2026. This has brought us to an important inflection point in our capital efficiency and free cash flow profile.

Beginning in the third quarter of 2026, we expect production to average approximately 90,000 BOEs per day, and it should stay there through to the end of 2027, and beyond and that will deliver production growth in 2027 of about 7% over 2026.

Now looking forward, our corporate strategy remains the same to maximize cash flow per share without compromising our balance sheet. This means a laser-like focus on picking the highest rate of return wells with every penny of discretionary capital. Naturally, our liquids plays have superior returns right now with AECO hovering around $1 per GJ and WTI at $100. This is a historical disconnect. At these prices, we expect our forecasted oil and NGL volumes to average approximately CAD 100 per barrel and account for 58% of sales between the second and fourth quarters of 2026.

We're reallocating approximately $25 million of capital this year from Glacier gas targets, which at strip would be expected to have payouts of about 1.5 years. to Wembley oil targets, which are expected to have payouts of about 8 months. Our Charlie Lake wells currently have payouts of about 6 months. Although the BOE volumes for oil wells are typically lower than gassy wells. And when I say that, I'm speaking about the IP30s and so on. The impact of our -- the impact of these shifting to oil wells in our 2026 program will be minor on our total production forecast. So there is no need to adjust our 2026 production guidance.

Depending on how long oil prices remain strong, we may shift additional capital to liquids drilling later this year. Debt reduction remains a top priority. We expect to achieve our net debt target range of about $400 million to $500 million during the second half of 2026 with cash flows supported by our hedging program and market diversification even if natural gas pricing remains weak. Given our proximity to that target, Advantage is opportunistically allocating a portion of free cash flow to share buybacks through the second quarter and into the summer. That approach is consistent with our long-standing capital allocation framework, especially given our current trading dynamics with Canadian gas producers trading at a significant discount to the greater market and Advantage at a discount within that group.

We have hedged approximately 41% of our forecasted natural gas production in 2026 as well as 29% of our production in '27 and 18% in 2028. As a result of our hedging and downstream market diversification, our AECO exposure has now fallen to approximately 18% for the remainder of 2026. We have also hedged approximately 42% of our crude and NGL production this year and 26% in 2027. These steps have been important to reduce the volatility of our cash flows by reducing exposure to localized pricing weakness.

As we look a little further into the future, we expect to continue our 5% to 10% annual production growth for the foreseeable future, although this growth is always carefully tuned to suit the commodity price outlook. We have owned and operated gas capacity that exceeds 500 million cubic feet per day plus the midstream service, and this is adequate for us to grow our production to 100,000 BOEs per day without any major infrastructure expansions.

Depending on commodity pricing, we could be approaching this 100,000 BOE per day milestone as early as year-end 2028. And as one more thing, we also have an additional 100 million cubic feet per day of capacity ready to be reactivated at Conroy in British Columbia when market conditions are supportive for us to enter the province. I also want to briefly touch on Entropy. Construction of the Glacier CCS Phase 2 project is almost complete and commissioning is expected to begin in the coming months. This project is intended to substantially decarbonize the Glacier facility and drive a positive step change in operating income, which comes from contracted power sales and contractually guaranteed carbon pricing. All funding for the project is being provided by Brookfield and Canada Growth Fund.

Overall, our message today is straightforward. The first quarter reflected a business that continues to perform well through the commodity price cycle while approaching a major step change in capital efficiency. We are bringing the Progress gas plant into service, improving our commodity exposure through hedging and market diversification and moving towards a period of strong free cash flow, driving debt reduction and ramping share buybacks.

So with that, I'd like to thank our employees, our Board and our shareholders for their continued support. I'll pass it back to Brian for questions.

Thank you, Mike. Sylvie, we'll pass it over to you to see if there are any questions from the phone lines.

[Operator Instructions] And currently, sir, it appears we have no questions registered from the phone line.

Okay. Thank you, Sylvie, and thank you, everybody, for joining the call today. If you have any questions, please feel free to follow up with us after the call. Thank you very much.

Thank you, sir. Ladies and gentlemen, this does conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines. Have yourselves a good weekend.

Good morning, ladies and gentlemen, and welcome to the Advantage Energy Limited Year-end 2025 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, March 6, 2026. I would now like to 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 year-end 2025 results. Before we get started, I'd like to refer you to the advisories on forward-looking statements 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'll also note that we posted an updated corporate presentation to our website.

I'm here with Mike Belenkie, President and CEO of Advantage; Craig Blackwood, our CFO; as well as other members of our executive team, and we'll start by speaking to some of our financial and operating highlights. Once Mike is finished, we'll pass it back to the operator for questions. And as usual, we'd ask that if you have any detailed modeling questions that you follow up with us individually after the call.

And with that, I'll turn it over to Mike. Please go ahead.

Thanks, Brian, and thanks, everyone, for joining us today. 2025 was defined by record operational performance, strong capital efficiencies and meaningful progress towards our long-term strategic objectives. Even during this volatile commodity environment, our business delivered exceptional results, demonstrating the strength of our asset base and the resilience of our operating model. Average production -- sorry, annual production averaged 78,267 BOEs per day, the highest in our 25-year history, supported by strong well performance across all of our assets.

Liquids production grew 28% year-over-year. Liquids revenue represented 48% of total revenue despite representing just 16% of our production, reinforcing the high average quality of our liquids products, and the value of our liquids diversification. Advantage generated $382 million in adjusted funds flow or $2.29 per share, with $76 million applied to debt reduction and $287.7 million applied to development capital. These results reflect our continued focus on capital efficiency, cost control and maximizing cash flow per share.

As we look back over the last year, there have been a few key themes. The first theme is that we delivered the strongest operational outcomes we've had in our 25-year history. Our Montney drilling program delivered the top 9 Alberta Montney gas wells of 2025, including what we believe to be the most productive well ever drilled in the Alberta Montney with an IP30 of 4,567 BOEs per day. Every gas well we drilled was in the top 25 list. To be clear, headline rates are great, but it's the corporate average that pays the bills. These uniformly strong outcomes, combined with our low-cost structure, generated a 2.1x recycle ratio on proved reserves despite a very weak commodity price environment. And when we say very weak, this was worse than a bottom decile price environment in 2025. We're very proud of our team for delivering these incredible results.

The second theme for the year is that despite one of the worst periods of AECO prices in history, we still generated significant free cash flow, thanks in part to our strong hedging program and diversification into both downstream gas markets and high-value liquids. Free cash flow was also supported by our price-sensitive production management. At times of extremely low gas prices, we curtailed up to 300 million cubic feet per day gas, averaging 2,600 BOEs per day of dry gas on an annualized basis shut-in. These curtailments reduced our declines, reduced depletion and positively impacted adjusted funds flow by avoiding operating costs and deferring production until prices were stronger. This is consistent with our philosophy. If it won't increase our cash flow, we won't produce it.

Third theme of the year is that marketing strategy really matters. We further diversified away from AECO by adding nearly 60 million cubic feet per day of long-term physical transportation service to downstream markets, including Ventura and Dawn. And we've hedged a meaningful portion of our production out through 2028 to reduce cash flow volatility.

Looking ahead, 2026 will be a pivotal year. Our new 75 million cubic feet per day progress gas plant is on track for commissioning in Q2. And once progress and the Glacier turnaround are complete, we expect to enter a period of highly efficient capital spending and accelerating free cash flow. Beginning in the third quarter of this year, production is expected to average 90,000 BOEs per day through to the end of 2027. That's 6 quarters at about that level. Since there is no additional infrastructure spending required at this level, this program will be unusually efficient with operating costs trending lower as more and more volumes will be flowing through our owned infrastructure.

Disciplined capital allocation is one of our key guiding principles. Beyond 2027, we have a wealth of options for efficient future growth that mirror the efficiencies of our last 5 years. The 75 million a day Progress gas plant is modular and can be expanded with a large lumps of capital. Meanwhile, we own the currently idle Caribou gas plant, which has a capacity of 100 million cubic feet per day right next to our development-ready Conroy assets in Northeast BC. Both processing options, that's Caribou and Progress expansions are unusually efficient. And pending some stability in commodity prices, we will announce what our 2028 to 2030 development plans look like.

However, and I want to make this very clear, we are not interested in growing for the sake of growth. Any future growth investment will be fully funded by cash flow and justified by full cycle returns with a supportive commodity price outlook in mind. During times of volatility, we -- as we are experiencing right now with geopolitical events and with local supply-demand imbalances, the right strategy is to focus on making a short cycle time investments and scrutinizing every penny. As an example, we recently reduced our 2026 capital budget by $20 million. Thanks to our continued strong well performance, our production guidance remains unchanged.

Debt reduction remains a top priority. We will continue allocating substantially all free cash flow to debt reduction until we reach our debt target range of $400 million to $500 million. We expect that to happen in the second half year of 2026. So we're very close already. Thereafter, we will balance further debt reduction with opportunistic share buybacks. This will be consistent with our long-standing capital allocation framework.

Finally, I want to highlight some progress at Entropy. Construction of the Glacier Phase 2 CCS project is expected to be completed within months here around mid-2026. This project will be -- will substantially decarbonize the Glacier facility and is fully funded entirely by Brookfield and the Canada Growth Fund. It represents a major milestone for Entropy and a meaningful step forward for commercial CCS globally. Although Advantage is not contributing any capital to the project, our working interest is now just under 50%, and we will benefit as partial owners from all EBITDA that's delivered by that project.

So with that, I'd like to thank our employees, our Board and our shareholders for their continued support, and I'll pass it back to Brian for questions.

Thanks, Mike. Joanna, we'll go to the phone line to see if there are any questions, and then we'll check with you. Thank you.

[Operator Instructions] There appear to be no questions. I will turn the call back over to Brian Bagnell.

Great. Thank you, everybody, for joining the call today. And if you have any follow-up questions, please reach out following the call. Thank you.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.

Good morning, ladies and gentlemen, and welcome to the Advantage Energy Limited Q3 2025 Results Conference Call. [Operator Instructions] This call is being recorded on Wednesday, October 29, 2025.

I would now like to 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.

And as usual, we'd like to ask that if you have any detailed modeling questions that you follow up with us individually after the call, and finally, I'll note that we have posted an updated corporate presentation on our website. So 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 lines 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 1 week of negative prices. Under -- 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 any -- in virtually any price environment.

Revenue for the quarter was dominated by liquid 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, and our risk management program delivered $34 million in realized hedging gains in the third quarter.

Production in the third quarter averaged 71,482 BOEs per day, 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 cubic feet 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 curtailed production during periods of exceptionally weak prices, and we do this for multiple reasons. We refused 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 tiny profit.

Again, 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 as 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 gas -- at the plant gate and everything downstream of that is accounted over separately.

So 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 BOEs per day, resulting in a full year 2025 production of 78,100 to 79,100 BOEs per day.

The new well results that we mentioned in the press release yesterday will certainly help our -- 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 to reliably translate into longer-term production expectations, especially given our extensive experience and knowledge of the Montney 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 kilometer 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 on the pad produced at a restricted rate of 20 million cubic feet per day of raw gas over the last 7 days -- over the last -- same last 7 days, restricted as a result of the higher rates from the first well, which is already filling a gathering system.

The third well on the pad, which targeted the Upper Montney has not been brought on production yet for the same reason, but its cleanup rates looked 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 oversupply conditions easing as we move into winter and as LNG Canada is starting to export meaningful volumes. As gas prices recover, debt repayment -- our debt repayment is expected to accelerate in the coming months. We are -- so we are, therefore, keeping our debt target at $450 million, but introducing a range of plus or minus $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 2 ways, disciplined production growth and free cash flow generation.

Over the next 2 years, production growth is expected to average about 9% per year. And 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.

So with that, I'd like to thank our employees for another great quarter with a lot of nimble reactions and high-quality outcomes. And I'd also like to thank our Board and shareholders for their support, and 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.

[Operator Instructions] And the first question on the phone comes from Amir Arif at ATB.

Just a couple of quick questions. First, on those new wells that you brought on, those are terrific rates on those 3-mile wells. Just -- 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 3-mile laterals as you develop the Glacier, just given your land block in the area can allow for longer laterals?

Yes. I mean, obviously, good news story. These are not unusually designed wells for us. These are well executed, great rock and really capitalized on all the team's technical advancements over the years with a few new ones. So really, what does that mean? Well, 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. Now 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 to $9 million dependently. This probably allows us to reduce the number of wells per year, which means maybe you save a few wells per year, but the program is already so efficient that's not going to be a massive swing in total capital per year, just a nice little -- induces our ability to save a little extra cash and put more work on debt repayment and buybacks. So modest impact, but positive for sure.

That's helpful. But could you quantify it in terms of capital efficiency on a 3-miler versus your typical 2-milers?

So if I understand your question correctly, you're looking to understand how much more productivity per $1 million spent. And I think we're probably looking at a sort of a 15% increase in cost for the well versus the shorter well. And the productivity probably goes up by more like 25% to 30%. So you can see these are nice little juicers, but this is what we're talking about here is only a few million dollars of extra spending for a sizable increase.

So it's all small adds to our program, small increases in efficiency, which -- and not in isolation either, just that in this case here, everything came together for the outlier result. The program itself won't change materially. I just get a little bit stronger.

Okay. No, I appreciate that color. And then the second question is just more on your net debt target range. As you pay down debt faster, if cash prices are strong, it sounds like you might be willing to start a structured buyback program sooner at the $500 million level versus $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. So 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. And, of course, if we're solving for Max cash flow per share, well at times where our share price is lowest gives us the best return. So what we're looking to do is forecast whether we buy earlier, like sooner or later, at lower or higher prices, and 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. Well, having more elasticity on the top end of the debt range as we delever allows us to get back to work more aggressively earlier, okay? So hopefully, that's enough. We won't tell people exactly when we're going to buy because that would, of course, not be very good trading strategy, but think of it as a useful guidance.

[Operator Instructions] Next question comes from Luke Davis at Raymond James.

Just wanted to get some background on how you're thinking about shareholder returns and specifically buybacks in the context of sort of your looser debt policy?

Sure. So shareholder returns, of course, I did sort of refer to that in my -- in one of the last comments, which is we see shareholder returns in 2 ways, production growth and free cash flow. Now the use of that free cash flow is always up for debate, and everyone has a different perspective on the best use of free cash flow. For us, there's -- you have to start from all options, which are debt repayment, share buybacks, and dividends. Now dividends, of course, in our case, with high cost of equity and us being a growth company, dividends 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. So there's almost a mathematical order of priorities, which is delever, 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 delever further? Or do you buy back shares? And every penny or every tranche of share buybacks is subject to that same test.

And what we're looking to do is solve for Max cash flow per share in that as a quotient, and that can change over time. So we won't be too specific, but hopefully that helps you with the framework.

No further questions on the phone. I will turn the call back over to Brian Bagnell.

Okay. Thank you, everybody, for joining our call, and I look forward to catching up with you individually. That concludes the call today.

Thanks, everybody.

Ladies and gentlemen, that concludes today's conference call. We thank you for participating, and we ask that you please disconnect your lines.

Good morning, ladies and gentlemen, and welcome to the Advantage Energy Limited Q2 2025 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, August 7, 2025.

I would now like to turn the conference over to Brian Bagnell, Director of Commodities and Capital Markets. Please go ahead.

Thanks, Andrew, and welcome, everybody, to Advantage's conference call to discuss our second quarter 2025 results.

Before we get started, I'd like to refer you again to our advisories on forward-looking statements 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. We've also posted an updated corporate presentation.

I'm here today with Mike Belenkie, President and CEO of Advantage; and Craig Blackwood, our CFO; as well as other members of our executive team. We'll start to speaking to some of our financial and operational highlights. Once Mike has finished speaking, we'll pass it back to the operator for questions. And as usual, we'd ask that if you have any detailed modeling questions that you follow up with us individually after the call.

With that, I'll turn it over to Mike Belenkie. Mike, please go ahead.

Thanks, Brian, and thanks, everyone, for joining us today. Q2 was another solid quarter for Advantage. Despite challenging market conditions, we delivered strong results across the board.

Adjusted funds flow came in at $88.9 million or $0.53 per share, and we reduced net debt by $33 million to about $570 million. Production in the second quarter averaged 78,108 BOEs per day, up 18% year-over-year, while liquids production rose 66% despite significant impacts from third-party facility delays outages.

We're on track to achieve our annual production guidance of 80,000 to 83,000 BOEs per day. And we also continued our strategy of shutting in dry gas wells at times of low AECO prices, as we prioritize value over volumes.

Operating costs were $4.90 per BOE, continuing to beat our expectations, thanks to successful integration of our June 2024 acquisition and a lot of hard work from our team. These successes have allowed us to reduce full year operating cost guidance to between $4.95 and $5.30 per BOE. Our new guidance midpoint represents a reduction of 8% from original guidance.

Our Charlie Lake program continues to outperform our expectations. We now have a full 12 months of actual results since the June 2024 asset acquisition and the results have validated the potential we saw a year ago. We've significantly improved well productivity versus historical and cost structure. These helped deliver an AFF per share, a cash flow per share that was 38% higher corporately than it would have been standalone without the assets, huge increase in value for the company.

Average crude production from our first 7 operated wells in Charlie Lake has averaged 38% above our budget-type curve over their first 30 days. Operating costs on the acquired assets have been reduced by over 25% over last year, which has helped drive the 50% increase in our operating netback and there's lots more to do and optimized by the team that will benefit Advantage for many years to come.

Turning to natural gas markets. It's no secret that NGTL reliability has been exceptionally poor since June although the word exceptional is probably becoming obsolete now, and that looks likely to continue through August. Of course, this has led to some terrible AECO cash pricing.

By shutting in dry gas production, we eliminate variable operating costs, conserve our premium resource, reduce our depletion expense and defer capital that would otherwise be required to replace that depletion. To be clear, we still collect our hedging gains regardless of shut-ins. And from time to time, we've actually bought gas back from the market when prices were negative at profit.

We'll plan to shut in up to 1/3 of our corporate gas production at times when it makes financial sense to do so. And we use the sophisticated algorithm to figure out how much to shut in on a day-to-day basis and that will change rapidly as prices change rapidly. And we remain baffled to see so many of our peers dumping their resources in AECO and Station 2 at a loss on a regular basis.

Despite perennial NGTL issues, we do see near-term fundamentals as encouraging, with oversupply conditions easing as LNG Canada export capacity ramps up. This rebalancing increases the likelihood that AECO basis will tighten and result in better prices than what we currently see in the forward market, even though the forward market is healthy. But we're not just sitting around and hoping that the AECO market improves, we have a balanced program. And even on the current strip, we expect to generate more than $500 million of free cash flow over our 3-year program.

Staying on the marketing front, we've hedged 44% of our natural gas and 41% of our oil and condensate for the remainder of this year. And we also added another 25 million a day of physical transportation to Dawn, starting April 2027, further diversifying our market exposure.

Looking ahead, our strategy remains focused on maximizing cash flow per share while maintaining balance sheet strength. As we approach our $450 million net debt target around the end of this year, we intend to establish a new conservative range and resume aggressive share buybacks.

So with that, I'd like to thank our employees, our Board and our shareholders for your continued support, and I'll pass it back to Brian for questions.

Thanks, Mike. And Andrew, I think we'll pass it to you to see if there are any questions in the queue.

[Operator Instructions] There are no questions at this time. Please proceed with closing remarks.

Sure. We do have questions on the webcast. So we'll get started here. The first one is we see that operating costs have continued to be lower than expected. Can you provide some more color on the sustainability of those operating costs?

Sure. Thanks, Brian. Yes. So operating costs, as we saw with the reduction to our guidance, operating costs have continued to go in the right direction. We're very pleased with the work that's been done. And I want to just offer a quick shout out to the entire operations team, both in Calgary and in the field for having achieved these outcomes. What's been most refreshing about the accomplishments from -- on reducing operating costs is that these operating cost reductions have been sustainable.

So at first, we were concerned that we'd be able to get quick wins that will be temporary after the asset acquisition. We're finding now though is these are structural changes, allowing us to keep a lower -- less vehicle travel time, fewer unnecessary facilities, reduced rentals and so on. And we've also had some success in reducing exposure to third-party fees of contracts that we inherited with the company. So the outlook is strong. That's what allowed us to move our entire range downwards. So I appreciate the question and our sort of ability to think on a flat level going forward is gaining. Things will change over time, especially as we see different service come on and expire, but stability of that $4.95 to $5.30 range is looking pretty positive.

Okay. Thanks, Mike. Another question on the webcast this time from Jamie Kubik. Can you discuss the potential for dispositions in the current environment?

Yes. Thanks, Jamie, for the question. Yes. So in terms of dispositions, we have always thought about our non-core disposition program as being useful in ensuring that we keep our balance sheet where we want it to be. And the good news is right now that our balance sheet is exactly where we want it to be. There's probably a couple of little things that we would expect to do in the coming, call it, 6 months that might just be rounding error sort of double-digit millions at a time, which just prop us up a little bit, slightly increase our ability to buy back more shares. The things that we look to sell, broadly speaking, aren't price sensitive. So I think, Jamie, I hope that answers the question. We probably will proceed with a few small things.

One follow-up question from Jamie. Can you provide any further color on the ramp-up of the CSV Albright facility and the expected timing?

Well, that's an interesting question. So we have limited exposure to CSV Albright. We do have long-term plans to be -- not even long term, we expect to see our 4-21 gas plant, which is in the same vicinity as the Albright plant. That 4-21 gas plant comes on stream in the second quarter of next year. So while there may be some limited ability for us to, in the near term, reroute excess production, to avoid exposure to CSV Albright. In the -- by second quarter of next year, this is something that actually we have once again excess gas processing capacity in the area. So we haven't really focused on ramp-up of CSV Albright. We've successfully mitigated pretty much all the volumes that we were looking forward to using for some of our upcoming drilling. So any information we have really is the same kind of information Wall Street would have to other companies that are more exposed to that issue.

Okay. One more question from the webcast this time from Chris at Desjardins. Can you remind us of your price trigger to return curtailed dry gas volumes?

Yes, sure. So when I say trigger, we do have an algorithm which is multivariate. And of course, there's certain gas that has a higher cost structure, certain gas that has a lower cost structure. So as prices go lower, we increase the amount of shut-ins. We start to think seriously about shut-ins, might say seriously, we start to see meaningful volumes get shut in when we're below $1. At $0.80, it grows. At $0.30, we're pretty much maxing out that 1/3. At lower volumes -- sorry, lower prices like negative prices, we'll buy back gas and use that to fill our volumes. So I think it's probably not a very simple answer, Chris, being a simple number, but we watch very carefully, and we make sure that each well is treated like a separate revenue source as opposed to sort of a deterministic single number, which might be a bit more handfasted. This is a nuanced game, and we want to make sure we win it.

I might add to that, that in our Investor Day, we did add a slide that kind of highlighted our behavior during periods of price weakness around this time last year, so that might be helpful.

Andrew, we'll turn it back to you to the phone lines to check one last time for any questions. And otherwise, we can end the call.

[Operator Instructions] There are no further questions at this time. So ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.