AETUF Q3 2025 Earnings Call
Operator: Good morning, ladies and gentlemen, and welcome to ARC Resources Q3 2025 Earnings Conference Call. [Operator Instructions] This call is being recorded on Friday, November 7, 2025. I would now like to turn the conference over to Taryn Bolder. Please go ahead.
Taryn Bolder: Thank you, operator. Good morning, everyone, and thank you for joining us for our third quarter earnings conference call. Joining me today are Terry Anderson, President and Chief Executive Officer; Kris Bibby, Chief Financial Officer; Armin Jahangiri, Chief Operating Officer; Ryan Berrett, Senior Vice President, Marketing. Before I turn it over to Terry and Kris to take you through our third quarter results, I'll remind everyone that this conference call includes forward-looking statements and non-GAAP measures with the associated risks outlined in the earnings release and our MD&A. All dollar amounts discussed today are in Canadian dollars unless otherwise stated. Finally, the press release, financial statements and MD&A are available on our website as well as SEDAR. Following our prepared remarks, we'll open the line to questions. With that, I'll turn it over to our President and CEO, Terry Anderson. Terry, please go ahead.
Terry Anderson: Good morning, everyone, and thank you for joining us today. This morning, we'll discuss our third quarter results and the 2026 budget. After that, I'll hand it over to Kris to review our financial results and provide a little more color on our plans for next year. Beginning with the quarter, overall, we executed a safe, efficient capital program and remain focused on profitability over BOEs, delivering solid operational and financial results. Third quarter production averaged approximately 360,000 BOE per day, which represents a 10% increase year-over-year and a 13% increase on a per share basis. This included a record high 114,000 barrels per day of condensate and oil, driven primarily from Kakwa and Attachie. In the quarter, we generated $283 million of free cash flow and returned it all to shareholders. This is a result of our low-cost structure and a balanced commodity mix that includes a high proportion of condensate. At Kakwa, which is our largest condensate asset, production averaged 206,000 BOE per day. This was above expectations due to better-than-anticipated performance from the assets we acquired in July. With the integration complete, we have now identified and advanced optimization opportunities to further enhance profitability on those assets and the overall property. Moving on to Attachie. Third quarter production averaged approximately 27,000 BOE per day, which was below our expectations. However, condensate production was 13,000 barrels per day, which is a relatively strong number that drives the returns on this asset. Our recent focus has been on optimizing our well design based on what we have learned to date, to improve predictability and performance. We are seeing evidence of our optimization initiatives on the most recent pads that were successfully drilled and completed as planned and will be on production in Q4. For 2026, we expect condensate production to increase to 15,000 barrels per day, which is in line with our original plan and total production between 30,000 and 35,000 BOE per day. At Sunrise, our low-cost natural gas asset, we curtailed approximately 360 million cubic feet per day or 60,000 BOE per day during the quarter, when Western Canadian natural gas prices were weak. This allowed us to preserve resource and defer capital. In the backdrop of strengthening fundamentals and higher natural gas prices, we resumed production in late October. A core part of our natural gas business is our transportation portfolio. Having long-term, low-cost access to key demand markets in the U.S. has been instrumental in allowing us to maintain high natural gas margins when AECO prices are low. During the third quarter, we realized a natural gas price of $2.75 per Mcf compared to the AECO monthly index of $1 per Mcf. As an extension to our natural gas marketing, our long-term LNG agreements will take effect in late 2026 or 2027. ARC will deliver approximately 140 million cubic feet per day of natural gas to Cheniere's Corpus Christi Stage 3 project and in return receive JKM pricing less about $5.50 per Mcf. Our strategy is to diversify our natural gas sales over the long term by accessing global natural gas prices. Moving on to next year's budget and our strategic priorities. The 2026 budget will deliver higher production, lower capital and higher free cash flow compared to 2025 and aligns with our long-term strategy to grow free funds flow per share. Our budget of $1.8 billion to $1.9 billion will generate annual production between 405,000 and 420,000 BOE per day and condensate production of approximately 110,000 barrels per day. Operationally, the focus will be, first, to continue to deliver consistent results and capture cost-reduction opportunities to achieve a best-in-class cost structure; and second, to apply the learnings we've gained from our first full year of production at Attachie to improve capital efficiencies and profitability. These results will inform the optimal development plan to maximize profits for Attachie Phase 2. At the current forward prices, ARC expects to generate approximately $1.5 billion in free cash flow. With this balance sheet strong, we once again intend to return essentially all free cash flow to shareholders. As evidence of this, we are pleased to announce an 11% increase in our base dividend this quarter, alongside a significant step-up in share repurchases. We continue to believe that the combination of growing base dividend and share buybacks is the optimal way to return capital to shareholders. With that, I'll hand it over to Kris.
Kristen Bibby: Thanks, Terry. Good morning, everyone. First, I'll discuss our quarterly results, followed by an overview of our 2026 budget and resulting guidance. Quarter itself was ahead of expectations. Relative to analyst estimates, production was in line, while funds from operations was 10% above and free cash flow of $283 million was 80% above expectations. As mentioned, we returned all of that free cash flow to shareholders during the quarter. We were particularly active and opportunistic on our share buyback, investing $170 million to purchase 6.5 million shares. Since we introduced the NCIB in 2021, we've repurchased and retired a total of 155 million common shares, reducing the share count by roughly 21%. Moving on to production. ARC delivered average production of 360,000 BOEs per day, which represents a 10% increase year-over-year, 13% increase on a per share basis. Record condensate and oil production of 114,000 barrels per day represents a 30% increase from the prior year, driven by Attachie and the Kakwa acquisition that closed in July. Production from our newly acquired capital assets delivered at the higher end of our internal expectations, averaging around 40,000 BOEs per day in the quarter, which included roughly 13,000 barrels a day of condensate. We invested approximately $500 million this quarter drilling 50 wells and conceding 36. Activity focused primarily in our condensate-rich assets at Kakwa, Greater Dawson and Attachie. With the closing of the Kakwa acquisition from Strathcona in July, we ended the quarter with net debt of approximately $3.1 billion, implying a debt to cash flow ratio of approximately 1x. We view this as an appropriate amount of leverage for our business, given our low-cost structure and deep drilling inventory. The 2026 budget, we plan to invest $1.8 billion to $1.9 billion, which represents approximately $100 million decrease from 2025. Capital program is expected to generate 11% production growth with average production between 405,000 and 420,000 BOEs per day, of which 40% is liquids. In 2026, year-over-year growth will be driven by our 2 biggest condensate assets: First, at Attachie, where we expect stronger organic volumes; and second, at Kakwa, where we will have a full year with the recently acquired assets. We plan to allocate 80% of the capital towards well-related activities. The remainder is earmarked for facilities and maintenance, a nominal amount towards Phase 2 at Attachie and certain margin expansion initiatives. As one example, we are investing about $40 million towards water infrastructure and disposal at Kakwa. This investment will pay out in less than a year by lowering operating costs, while improving safety by reducing our reliance on trucking. As mentioned at current strip pricing, we will generate approximately $1.5 billion of free cash flow or roughly 10% of our market cap. For the fourth consecutive year, essentially all free cash flow will be returned to shareholders through our growing base dividend and continued share repurchases. With that, I'll pass it back to Terry for closing remarks.
Terry Anderson: Thanks, Kris. In 2026, ARC will celebrate 30 years of being a proud responsible Canadian energy producer. We created a budget that supports our long-term strategy of investing in our assets to grow free cash flow while returning a meaningful amount of capital to our shareholders, providing an attractive and sustainable return. Our outlook is strong. We're fortunate to have amassed long-duration top-tier Montney assets. We've built a large network of company-owned infrastructure, and we have the best people to execute on our plan to deliver sustainable value to our shareholders. With that, we can open the line to questions.
Operator: [Operator Instructions] With that, our first question comes from the line of Michael Harvey with RBC Capital Markets.
Michael Harvey: So just a couple of questions. I guess the first one, maybe just walk us through some of the key learnings you've taken from Attachie Phase 1 and kind of how those would be applied to Phase 2? What changes would be applied just given the passage of time and kind of how would that affect cost, productivity, et cetera? And then the second one is just a little broader. How do you compare the 2 options, the first being going ahead with Phase 2, the second being just deferring for a longer period and just kind of buying back $1 billion or so in stock per year and staying flat. A lots of moving parts. I suspect that's the hot topic in the boardroom. I'd just love to get a bit of color on how you folks would kind of think through that complex topic.
Terry Anderson: Michael, it's Terry. Why don't I start with your second question. So we've always stated that we are focused on improving our per share metrics. And so obviously, and Armin will touch on some of the learnings here for Phase 2 because we want to make sure that we are going to be the most capital efficient when we move into that second phase. So we're focused on the profitability side. But for us, where our shares are trading today, it's a good use of capital to be buying back our shares. And there's going to be times where it makes more sense to buy back our shares, and there's going to be times where we're going to invest more. And that's exactly what we had laid out in our long-term plan. When we're not investing in our assets, we're going to be buying back the shares. So it all ends up at the same spot of improving our per share metrics and in particular, the free cash flow per share.
Armin Jahangiri: Yes. Michael, on your first question, most of our focus in terms of learnings are going to be on subsurface optimization of our well and frac design. Some of the activities already started, as Terry mentioned in his remarks that we are going to see the results of them in the next few months. That is going to really help us better understand the capital efficiency. What we are trying to do is to find that balance between recovery factor and capital efficiency and make sure not only Phase 2, but also the remainder of Phase 1 development activity set up for success. So in terms of cost, obviously, with improvement in capital efficiency, we have to look at exactly what the cost numbers are going to be. But what we are trying to achieve, as Terry mentioned, is profitability.
Michael Harvey: Got you. And just to close it out, do you have an updated breakeven WTI number of where you think the Phase 2 project would give you your specified hurdle rate? Has that kind of changed and maybe just so folks can come with benchmark where it looks good and where it looks kind of less good? I'm not sure if you've updated that number or not.
Kristen Bibby: Mike, it's Kris here. I mean I'm not sure we've given a specific number previously, but based on what Armin and Terry are saying like we don't see the future go-forward cost changing. So I think we've previously talked about in the 60s range, we'd be comfortable driving ahead. The reality is oil macro backdrop right now is quite weak. We do want to take the time, get the learnings in-house. And in the meantime, buy back the shares, but the reality is, even absent the learnings, there's no growth capital really being deployed into our sector right now. So I'm not sure now would be the right time to really be deploying a lot of growth capital. So we'll take that into account. I mean, if it's well above 60, obviously, we'd be very comfortable. If it's below 60, it's still probably economic. I'm just -- it's going to depend on where the shares are trading at the time, trying to make sure we are achieving the best rate of return on the capital we are deploying.
Operator: And the next question comes from Kale Akamine with Bank of America.
Kaleinoheaokealaula Akamine: I'm going to start with Attachie on the well cost. So total spend in full year '26 is [ $275 million ], you're bringing on 14 wells. The simple A divided by B math points to pretty costly wells but this is not a normal year. Can you kind of talk to us about the path towards a maintenance capital number? And remind us what that is? The number that I have in my head is about $150 million.
Armin Jahangiri: Yes. So some of the numbers you see in terms of the capital for next year includes additional capital beyond drilling and completions activity. We have some Phase 2 pre-spend included in that number in addition to that seismic and some water-related infrastructure. So the per well cost is not exactly a straight calculation of the numbers, as you mentioned. As far as your overall capital cost estimate for sustaining is concerned, your numbers are relatively accurate. But remember that this is the second year, so we still are dealing with higher declines in the assets. So as we get into the subsequent years, we have to see those numbers are going to come down.
Kaleinoheaokealaula Akamine: I appreciate that. My second question relates to Phase number 2. Now in '26, you're doing work to finalize the development pattern before taking that FID. Can you kind of talk about what a success case will look like, how are you scoring things like per well productivity or maybe that's measured on a per pad level? Are you pushing productivity to the edge with your completion intensity? Is there kind of an element in there of defining what the arrow extent is to which these best practices are applicable? Just trying to understand what the targets are that will allow you to move forward.
Armin Jahangiri: We definitely see an opportunity to improve the profitability and capital efficiency based on some of the early production results that we have seen from Phase 1. So the objective here, as I said earlier, is that we want to make sure we find that right balance between recovering resource and making sure that we can recover it at a decent capital efficiency. So that's going to really inform our plan moving into Phase 2.
Operator: [Operator Instructions] Your next question comes from the line of Jamie Kubik with CIBC.
James Kubik: Just wanted to ask a little bit more on Attachie. Can you talk a bit more on the underperformance seen in 2025? What led to the underperformance versus your second half guidance of 35,000 to 40,000 BOEs a day that was issued with Q2 results? And I guess how much services have you baked into the 2026 guide for Attachie, just things like that would be great to understand.
Terry Anderson: Jamie, it's Terry here. So the change in forecast is a result of the lower-than-expected production from one pad that came on stream in July here, which has impacted Q3 and Q4 production. And the pad at the 71 is just showing higher water production and it's taking a longer time to clean up. Some wells take longer, some to clean up on the water, some are quicker. We still expect a stabilized water cut around that 50% to 60%, which is very similar to Kakwa and our wells are coming down to this. This one -- this well is just that -- closer to that 70%, 75%. So we just need a little more time for it to clean up here.
Kristen Bibby: And Jamie, I can handle the guidance side. What we focused on is we want to make sure we're setting out realistic guidance that we know we have a good shot at achieving, hence, a little bit wider range, both at the corporate and then specifically at Attachie, where if we're at the high end of the guidance, we're right where we should be. And if we're at the lower end, then we're going to have to do some explaining for that asset. But corporately at [ 405 to 420 ]. That should be rate where everyone is kind of expecting us to be. So pretty happy with how the budget came together and the overall guidance levels.
Operator: [Operator Instructions] And I'm showing no further questions at this time. I would like to turn it back to Taryn Bolder for closing remarks.
Taryn Bolder: Thanks, everyone. Have a great day.
Operator: Thank you. And ladies and gentlemen, this now concludes today's conference call. Thank you all for joining. You may now disconnect.