ARC Resources Ltd

TSX:ARX

Q2-2025 Earnings Call

[Operator]

Good morning, ladies and gentlemen, and welcome to the ARC Resources Limited Second Quarter 2025 Earnings Conference Call.

[Operator Instructions]

This call is being recorded on Friday, August 1, 2025. I would now like to turn the call over to Dale Lewko , Manager Capital Markets. Please go ahead.

[Dale Lewko, executive]

Thank you, operator. Good morning, everyone, and thank you for joining us for our second 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; and Ryan Berrett, Senior Vice President, Marketing.

Before I turn it over to Terry and Kris to take you through our second quarter results. I'll remind everyone that this conference call includes forward-looking statements and non-GAAP and other financial 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 for questions. With that, I'll turn it over to our President and CEO, Terry Anderson. Terry, please go ahead.

[Terry Anderson, executive]

Thanks, Dale, and good morning, everyone. Today, I'd like to walk you through our Q2 results, provide an operational update on some of our key assets and share a little more insight into our most recent announcements including the Kakwa acquisition and a new land acquisition at Attachie. After that, I'll hand it over to Kris, who will go through our financial results and revised guidance. Beginning with the quarter. Production averaged approximately 357,000 BOE per day, which represents an 8% increase year-over-year, an 11% increase on a per share basis.

Production was about 40% liquids and 60% natural gas and included 100,000 barrels per day of light oil and condensate. This represents a more condensate weighted production mix with the addition of Attachie. This quarter, we continue to realize the benefits of a diversified commodity mix and long-term transportation to the U.S. for our natural gas. We generated $186 million of free funds flow and with a strong balance sheet, we returned all of it to our shareholders through the base dividend and share buybacks. We believe buying back our shares represents an accretive use of capital, so we plan to return essentially all free cash flow to shareholders in this manner for the foreseeable future.

Turning now to Kakwa. Second quarter production averaged approximately 170,000 BOE per day, including about 66,000 barrels per day of condensate. In early July, we closed our agreement to acquire Kakwa assets from Strathcona, which adds approximately 40,000 BOE per day of production, including 11,000 barrels per day of condensate. The assets are directly adjacent to our existing development, extending the inventory duration of Kakwa to 15 years. In addition, the Montney lands are 100% working interest and include owned and operated infrastructure that supports our low-cost structure and provides additional operational flexibility. Since closing, the integration has gone well. I'm pleased with how our staff have integrated this asset into our portfolio in a short time. The team is engaged, and we are seeing some positive preliminary results out of the new asset.

Right now, we are focused on optimizing the area infrastructure and the go-forward development plan. The strategy moving forward at Kakwa is to maintain production at approximately 205,000 to 210,000 BOE per day and optimize free cash flow. Moving over to Attachie. Production during the second quarter averaged approximately 27,000 BOE per day, including 16,000 barrels per day of condensate and liquids Production came in lower than forecast due to unplanned third-party downtime and production emulsion, both of which were resolved late in the quarter. Today, the plant is operating as expected. Attachie production reached 39,000 BOE per day at a point in June, including strong condensate production of approximately 21,000 barrels per day.

Our last 3 pads have been successfully drilled, completed as planned and are being placed on production as I speak. This will provide momentum into the second half of the year, where we expect Attachie production to average between 35,000 and 40,000 BOE per day. We continue to evaluate ways to optimize capital efficiencies and returns at Attachie. One example is we have trials in the ground at wider inter-well spacing and higher intensity fracs, that are generating results above our type curve. Through the initial 6 months, the average well from this trial pad produced approximately 170,000 -- 107,000 barrels of condensate or around 600 barrels per day. We remain confident in the long-term profitability at Attachie. Reservoir deliverability is strong and performing in line with our expectations and we are advancing Phase 2 in alignment with our long-term strategy.

We are investing $50 million towards Phase II this year into site preparation and the purchase of long lead items for the facility. In addition, we're excited to have acquired more land at Attachie through a unique development agreement with Tsaa Dunne Za Energy, a limited partnership owned by Halfway River First Nation. The agreement will allow for a development of up to 36 new contiguous sections of land located immediately northwest of Attachie. This is in the condensate-rich area of the Montney offering the potential to develop some of the highest quality acreage in Western Canada. This agreement increases our Attachie position by more than 10% to greater than 360 sections, extending our long development runway at one of the largest condensate-rich assets in Canada. We look forward to integrating this opportunity into our long-term development strategy at Attachie and working alongside side Tsaa Dunne Za Energy.

Finally, I'll speak to Sunrise, which is our low-cost dry gas asset. During the second quarter, we maintained our commitment to profitability by electing to curtail between 75 million to 200 million cubic feet per day of natural gas production due to low natural gas prices. This effectively eliminated ARC's cash exposure to Western Canadian natural gas pricing, thereby preserving capital and resource for periods when prices are higher and meet our threshold for profitability. Currently, we have shut in all dry gas production, approximately 360 million cubic feet per day or 60,000 BOE a day, which will be fully restored when natural gas prices recover. We expect that will be later this year as the ramp-up in LNG Canada coincides with the conclusion of seasonal pipeline maintenance that is underway today. With that, I'll hand it over to Kris.

[Kristen Bibby, executive]

Thanks, Terry. Good morning, everyone. I'll discuss our quarterly financial results, followed by an overview of our guidance. As it relates to the quarter, we delivered average production of 357,000 BOEs per day which was in line with analyst expectations. Cash flow of $1.17 per share was 5% above analyst estimates on average, while free cash flow of $186 million was approximately 90% above analyst estimates, as capital spending came in below expectations. Light oil and condensate production was roughly 100,000 barrels per day in the quarter, a 34% increase from the same quarter last year. Despite the volatility in WTI, condensate fundamentals remain constructive. Demand is strong, inventories are low and supply is simply difficult to grow.

Typically, differentials for condensate are seasonally wide in Q2, however, this quarter, condensate traded in line with WTI, the narrow spread for the second quarter in 4 years. Turning to natural gas. We continue to realize natural gas prices above the local benchmarks by utilizing our transportation portfolio to reach more attractive end markets in the U.S. In the second quarter, Park realized an average natural gas price of $3.19 per Mcf. which was -- which was $1.12 higher than the AECO average price of $2.07 per Mcf. Western Canadian natural gas prices are low in our view and will remain low until recovery later this year. Prices are well below the cost of supply, and Western Canada is in the early days of a material increase in demand as LNG Canada ramps up. This project will ultimately direct greater than 10% of local supply off the West Coast of Canada, which should support narrow basis and strong natural gas prices locally.

Moving to capital returns. The $186 million of free cash flow we generated in the quarter was returned to shareholders through our base dividend and share buybacks. For the third straight year, we plan to distribute essentially all free cash flow to shareholders as the balance sheet remains strong. To that end, as Terry mentioned, we closed the Kakwa acquisition on July 2. The acquisition was funded entirely with debt. Consistent with our guiding principles, we retained significant financial strength and flexibility. We raised $1 billion unsecured notes in June, a new $500 million 2-year term loan and increased the borrowing capacity under our existing credit facilities to $2 billion.

Moving on to our outlook. We updated our 2025 guidance to incorporate the Kakwa acquisition, natural gas shut-ins at Sunrise and first half actuals at Attachie. Full year production guidance is expected to be between 385,000 and 395,000 BOEs per day. This increase in full year guidance incorporates the Kakwa acquisition and is offset by the natural gas shut-ins that occurred during the second quarter and extended into the third quarter, and also reflects the slower ramp [indiscernible] at Attachie in the first half of the year. Production during the second half of the year is forecast to be greater than 410,000 BOEs per day including approximately 120,000 barrels of light oil and condensate. This reflects production from our acquired assets at Kakwa, restored production at Sunrise late in the year, and Attachie volumes between 35,000 to 40,000 BOEs per day.

In terms of capital, we expect to invest between $1.85 billion and $1.95 billion in 2025, an increase from the previous guidance of $1.6 billion to $1.7 billion. This increase reflects $150 million to sustain production on the acquired Kakwa assets and approximately $50 million of investment towards Attachie Phase 2. Finally, operating cost guidance increased $0.50 per BOE to between $5 and $5.50 per BOE. Increase on a per BOE basis is driven by higher water handling costs at Kakwa, lower Sunrise volumes from shut-ins and the Kakwa acquisition. The Sunrise asset has a very low operating cost as a dry gas asset, so curtailing production naturally increases operating costs corporately on a per BOE basis.

At strip pricing and based on our updated guidance, we expect to generate approximately $1.4 billion of free cash flow. Once again, we plan to return essentially all of it to shareholders through a growing base dividend and additional share repurchases. With that, I'll pass it back to Terry for some closing remarks.

[Terry Anderson, executive]

Thanks, Kris. To close, we remain committed to executing our strategy to grow free cash flow per share through profitable investment in the Montney and share buybacks. With our recent acquisition at Kakwa, and the land consolidation at Attachie, we have further extended our top-tier Montney inventory, reinforcing our position as the largest Montney producer of decades of development ahead of us.

Over the near term, we are focused on operational execution at Attachie, optimizing our recently acquired asset at Kakwa, and capturing capital efficiencies across our asset base. We are on track to drive record production and condensate volumes in the back half of the year, and at current strip prices generate approximate $1.4 billion of free cash flow this year, all of which we intend to return to shareholders. Thank you for your continued support. Operator, you can open the line to questions.

[Operator]

[Operator Instructions]

The first question comes from Sam Burwell at Jefferies.

[Unknown Analyst]

You called out the solid early results from the pad that was trialing wider spacing and the more intense completion. So just curious like what sort of incremental capital, if any, is required for that? Like how much wider is the spacing and how much more intensely are the completion designs?

[Armin Jahangiri, executive]

Hey Sam, this is Armin. It's hard to answer that question because obviously, as you increase the inter-well spacing, you require less wellbores or fewer wells. But at the same time, you increase or spend some of that capital that you save from drilling the well into fracking. So I would say probably you can assume that it's -- you're remaining effectively neutral by moving capital from 1 bucket to the other.

[Unknown Analyst]

Great. That's helpful. And then a peer of yours called out that there's heavy August pipeline maintenance, which is restricting gas egress and helping drive AECO to it's currently low levels. But do you -- I mean, first of all, share that view, do you think it can be resolved once that maintenance is complete, and then I guess sort of related to that, I mean what's your view of the LNG Canada ramp thus far? Is it in line with your expectations or a little bit slower than you anticipated?

[Ryan Berrett, executive]

Hey, Sam, this is Ryan. Yes, just in terms of the pipeline and maintenance, obviously, I think that, that is correct. We're seeing extremely low prices here in Western Canada right now. Some of it was projected. Some of it is obviously a result of continued supply being maintained. When we look at LNG Canada, I think when we look at the projects that happen on the Gulf Coast, we actually thought LNG Canada is quite in line and actually maybe slightly ahead of where some of those project start-ups have been. So we were fully expecting volatility. And obviously, we're seeing that today. Moving throughout September, October, I think we expect to see prices recover back to our normalized level.

[Operator]

The next question comes from Patrick O'Rourke at ATB Capital Markets.

[Patrick O'Rourke, analyst]

You started off in the prepared remarks talking about the attractiveness of share buybacks right now and directing 100% of free cash flow towards them. I just wonder from a philosophical perspective, certainly, we would agree with the accretion there based on our modeling. But from a philosophical perspective, there's probably some benefit to consistent and ratable dividend growth as well to the cost of equity here. So wondering what your view is on the right level and how you sort of triangulate on that?

[Kristen Bibby, executive]

Patrick, it's Kris here. Obviously, we have favored share buybacks in terms of a gross amount over the last couple of years. But the dividend is core shareholder returns. I think we've communicated pretty clearly what we're attempting to do is have an annual dividend increase. And so we have not had a dividend increase yet this year, but it's certainly still something we review every quarter.

And if you recall kind of in our balanced capital allocation approach, what we would like to see is a dividend payout ratio of cash flow of roughly 15%. I think in the quarter, we were right around 16%. And for the year, we're forecast around 14%. So that certainly gives us a bit of room to play. But in the fullness of time, dividends are going to be a material portion of shareholder returns. So we want to make sure that we've got a balance between both dividends, cash in people's hands as well as retiring the share count, in addition to profitably growing in the Montney.

So if you think of 50% of the cash flow going back into the ground, growing the asset base and production levels by roughly 3% on a CAGR basis, roughly 15% going out the door in dividends, and that really remains about 35% for share buybacks as well. We think that's the optimal level right now, given we don't have to deleverage the balance sheet.

[Patrick O'Rourke, analyst]

Great. That's very helpful there. And then just going over to the op costs and the change in the guidance here. You sort of had 3 sources driving that. I think the Sunrise shut-ins are probably pretty obvious that, that would push it up. But if you had to break that amount that it's pushed up here down, how would you break it down between the 3 sources? And then just on the water handling, is that something that's transitory? Or is that a little bit more structural going forward?

[Armin Jahangiri, executive]

Patrick, Armin here. So some of it is going to go away and some is obviously because of, I guess, the new portfolio. So the Sunrise shut-in, obviously, has a BOE impact, so that impacts the dollar per BOE. The other part is associated with the new asset. So obviously, as we learn more about the asset, we'll find ways to optimize the operating cost there. And the other component of that is related to operational things in Kakwa field as we move produced water.

So as we look at maybe those buckets, maybe you can look at 1/3, 1/3, 1/3 in terms of the impact, in terms of the increase. And obviously, some of those are stuff with planning and spending a bit more capital over the next few years, we can start to curtail or impact.

[Operator]

The next question comes from Aaron Bilkoski at TD Cowen.

[Aaron Bilkoski, analyst]

Would you guys be able to talk a bit about how you intend to spread Attachie Phase 2 CapEx across 2026 and 2027?

[Kristen Bibby, executive]

Aaron, it's Kris here. It's a little early to say with any confidence. We're just going through the costing and timing of it. If you use Phase 1 as an example, a total cost of roughly $750 million. Roughly, we spent $350 million in the first year and $450 million in the second year. So it's going to be -- we would expect pretty even -- but as you recall, once we sanction a project, really, that just shifts over to Armin and his team, and it's up to them to deploy the capital as efficiently as they can. We don't worry about it too much from a quarter-to-quarter basis just to get the project done as efficiently and safely as possible.

[Aaron Bilkoski, analyst]

Maybe I can ask a follow-up question on CapEx. This is more on the corporate level. It looks like you plan to only spend marginally more CapEx in 2026 than in 2025 despite ramping up capital at Attachie. What areas are you planning on spending less on next year?

[Kristen Bibby, executive]

As we're just getting into the planning phase for '26, as I mentioned, the big moving parts, you're going to have Phase 1 Attache capital coming down as we are over initial high decline and into more of a stabilized rate. You obviously heard us mention a little bit less capital at Sunrise from the shut-ins that we're currently experiencing. And then we will be obviously bumping it up a bit annualized for the new Kakwa assets, which in '25, happened to be a bit back half weighted. So we wouldn't expect it to be double what we're spending this year in terms of the $150 million.

And then as you mentioned, we will be adding in we would expect subject to sanction some capital for Phase 2 of Attachie. So several moving parts, and we'll finalize that in the coming months here.

[Aaron Bilkoski, analyst]

One final question for me on the dry gas settings. Is there a price you'd look to restore those volumes?

[Kristen Bibby, executive]

Yes, I can grab on that one as well. I mean historically, what we've talked about is full cycle supply cost at Sunrise in the $1.15 to $1.25 range. So something consistently above that especially given that we do expect to be in a more constructive pricing environment in the not-too-distant future. We just -- we refused to waste the resource, but we don't have to wait that long to make a better rate of return on those assets and make sure that we're operating profitably.

[Operator]

[Operator Instructions]

The next question comes from James Kubik at CIBC.

[James Kubik, analyst]

Just expanding maybe a little bit on Aaron's question there on the capital spending changes. For the second half change that you outlined in the capital spending increase this year, maybe, can you get into some of the specifics that you have on Slide 8 for us, just incremental capital being spent at Attachie. It looks like there's 2 less wells being drilled there. Can you just talk about what that CapEx is being dedicated to aside from $50 million that you're bringing forward for Phase 2? And can you talk a little bit more on the Kakwa spending increase as well?

[Armin Jahangiri, executive]

Yes. Jamie, this is Armin. So Attachie, the extra capital we are spending there is primarily to advance some field construction in repression for Phase II. We're taking advantage of the, I guess, seasonal weather conditions to advance that phase. It just basically allows us to maintain project time lines by spending that capital and be more efficient from a capital deployment perspective. Other than that, in Attachie is only D&C drilling and completions activity, and there's no other capital that goes in the ground.

In terms of Kakwa, obviously, the incremental -- the big bucket, the $150 million is the capital that is for that Strathcona Kakwa East assets. That's effectively what was planned for the remainder of the year, and that's been carried forward to ARC. So we are going to execute exactly the plan that was laid out there. And the other $50 million bucket, this time of the year, it gives us the flexibility to be able to optimize the schedule as we approach the end of the year. There are some white space. There are things we can do to optimize the production for next year. So it gives us some flexibility to deploy that capital to manage production and capital for 2026.

[James Kubik, analyst]

Sorry, could I kind of maybe just ask you to expand a little bit on Attachie, like outside of the $50 million? Because I guess, Slide 8 has Attachie spending going from $360 million to $425 million to $475 million this year. So that would be over and above the $50 million that is going there. Is there -- are the completions more expensive? Just anything else on that side, Armin, if you don't mind?

[Armin Jahangiri, executive]

Yes. No. So Jamie, we talked about some of the design optimization in Attachie that Terry alluded to earlier on, like higher intensity fracs. Obviously, we have to spend a bit more money on some of that stuff. And in addition to that, some mitigation measures for casing the formation that we experienced at the beginning of the year. We put some of that in the ground to be able to manage that. The last few pads that we have completed, we have not seen any case in the formation. So some of that is associated with that. We can go through more details if required, one-on-one.

[Operator]

The next question comes from Kalei Akamine at Bank of America.

[Kaleinoheaokealaula Akamine, analyst]

I want to follow up on the Kakwa CapEx. So the $150 million increase that we're seeing second half of this year, I suppose that's the cost of you guys taking over Strathcona's plan, but you guys have better best practices than they do, and that's going to bring this cost down. So on a full year basis, what's your best guess on the incremental capital from that new asset? And where do you guys think you can take it?

[Kristen Bibby, executive]

Kalei, it's Kris here. It's really the 150 million you're seeing in the second half of the year. We took over this asset, mid drilling on pads and stuff like that. So it's really -- that's kind of what activity they had planned. For '26, it's a little bit early to get too carried away on details. But high level, the way you can kind of think about it or at least the way that we've been thinking about it, if you think of roughly 40,000 BOEs a day, plus or minus, at a capital efficiency of roughly $15,000 of flowing barrel.

You're going to be in that $200-ish million, so whether that's $200 million, $225 million is kind of high level what you can think of. Obviously, what the teams right now are doing integrating the asset and incorporating it into our development plans, and you will get some more details on that later this year when we release the '26 budget.

[Kaleinoheaokealaula Akamine, analyst]

Yes. I appreciate that detail, Kris. Second question goes to LNG supply agreements. There's a lot of new LNG projects that are taking FID or about to take it by your peers are announcing new supply agreements. I imagine it's with them. When you look at the contracts that are out there, do you think that these new agreements are attractive as what you had signed in the past, and are you interested in adding more to your marketing book?

[Ryan Berrett, executive]

Yes, this is Ryan. Thanks for the question. I think starting with your second question there, we're really happy with where our exposures are. We've talked pretty transparently about having about 1/3 of our gas priced in Western Canada, 1/3 of our gas price in the U.S. and 1/3 of our gas priced internationally by the end of the decade. And if you look at where our portfolio sits, we're pretty much in line with that. So I would say no further contracts at this time.

When we look at the cost structure that we have in our agreements, again, we're very happy with those. We were early entrants into these agreements and we feel that's been beneficial for us.

[Operator]

[Operator Instructions]

This does conclude today's Q&A session. I will turn the call back over to Dale Lewco for closing comments.

[Dale Lewko, executive]

Great. That concludes the call. Thanks, everyone. Have a good day.

[Operator]

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