ARC Resources Ltd.

Good morning, ladies and gentlemen, and welcome to the ARC Resources Limited Second Quarter 2025 Earnings Conference Call. At this time, all lines are now 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-0 for the operator. This call is being recorded on Friday, August 1, 2025. I would now like to turn the conference over to Dale Luko, Manager, Capital Markets. Please go ahead.

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, Chris Dibby, Chief Financial Officer, Carmen Janangiri, Chief Operating Officer, and Ryan Barrett, Senior Vice President, Marketing.

Before I turn it over to Terry and Chris to take you through our second quarter results, I'll remind everyone that this conference call includes forward-looking statements and non-gap 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 and less otherwise stated. Finally, the press release, financial statements, and MD&A are available on our website as well as the article. Following our prepared remarks, we'll open the line to questions. With that, I'll turn it over to our present CEO, Terry Anderson. Terry, please go ahead.

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 CAQA acquisition and a new land acquisition at Itachi. After that, I'll hand it over to Chris, who will go through our financial results and revise guidance. Beginning with the quarter, production averaged approximately 357,000 BUE 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 Hitachi. 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 CapQuest. 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 CAQA 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 TACLA 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 CAFWA is to maintain production at approximately 205,000 to 210,000 VOE per day and optimize free cash flow. Moving over to the TACHI. Production during the second quarter averaged approximately 27,000 BOE per day, including 16,000 barrels per day of consate 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. Attachee 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 three paths 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 Hitachi production to average between 35,000 and 40,000 BOE per day. We continue to evaluate ways to optimize capital efficiencies and returns at Hitachi. One is we have trials in the ground at wider inter-well spacing and higher intensity fracks that are generating results above our tight curve. Through the initial six 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 Hitachi. 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 2 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 Itachi through a unique development agreement with Saadaneza Energy. a limited partnership owned by Halfway River First Nation. The agreement will allow for development of up to 36 new contiguous sections of land located immediately northwest of Itachi. This is in the confate-rich area of the Montney, offering the potential to develop some of the highest quality acreage in western Canada. This agreement increases our Itachi position by more than 10%, to greater than 360 sections, extending our long development runway at one of the largest CONSATE-rich assets in Canada. We look forward to integrating this opportunity into our long-term development strategy at Atachi and working alongside Saad Dhani Saad 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 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 Chris.

Thanks, Jerry.

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 narrowest spread for the second quarter in four 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, ARC realized an average natural gas price of $3.19 per mcf, which was $1.12 higher than the ACO 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 when we generated in the quarter was returned shareholders through our base dividend and share buyback. 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 capital acquisition on July 2nd. The acquisition was funded entirely with debt, and consistent with our guiding principles, we retained significant financial strength and flexibility. We raised $1 billion of unsecured notes in June, a new $500 million two-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 capital acquisition, natural gas shut-ins at Sunrise, and first half actuals at Hitachi. 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 capital 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-up rate at Hitachi in the first half of the year. Production during the second half of the year is forecast to be greater than 410,000 BWs per day, including approximately 120,000 barrels of light oil and condensate. This reflects production from our acquired assets at Takwa, restored production at Sunrise late in the year, and Hitachi volumes between 35,000 to 40,000 DOEs per day. In terms of capital, we expect to invest between $1.85 and $1.95 billion in 2025, an increase from the previous guidance of $1.6 to $1.7 billion. This increase reflects $150 million to sustain production on the acquired capital assets and approximately $50 million of investment towards Hitachi Phase II. 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 CAQA, lower sunrise volumes from shut-ins, and the CAQA 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 its shareholders through a growing base dividend and additional share repurchases.

With that, I'll pass it back to Terry for some closing remarks.

Thanks, Chris. To close, we remain committed to executing our strategy to grow free cash flow per share to profitable investment in the Montney and share buybacks. With our recent acquisition at CAQA and the land consolidation at Hitachi, we have further extended our top tier Montney inventory, reinforcing our position as the largest Montney producer with decades of development ahead of us. Over the near term, we are focused on operational execution at Hitachi, optimizing our recently acquired asset at CAQA, 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 approximately $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.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the one on your touch-tone phone. You will hear a prompt that your hand has been raised. If you wish to decline from the polling process, please press the star followed by the two. And if you are using a speakerphone, please lift the handset before pressing any keys. The first question comes from Sam Burwell at Jefferies. Please go ahead.

Hey, good morning, guys. You called out the solid early results from the pad that was trialing, wider spacing, and the more intense completion. So, I'm 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?

Hey, Sam. This is Armin.

It's hard to answer that question because obviously as you increase the interval 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 you're remaining effectively neutral by moving capital from one bucket to the other.

Okay, 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 ACO to its currently low levels. But 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?

Yeah, hey, Sam. This is Ryan. Yeah, just in terms of the pipeline maintenance, obviously, I think 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 LG Canada is quite in line and actually maybe slightly ahead of where some of those project startups 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 normal level.

Okay, understood. Thank you. Thank you. The next question comes from Patrick O'Rourke at ATP Capital Markets.

Please go ahead.

Hey, guys. Good morning, and thank you for taking my question. 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, and certainly we would agree with the accretion, They're based on our modeling. But from a philosophical perspective, there's probably some benefit to consistent and readable dividend growth as well to the cost equity here. So wondering what your view is on the right level and how you sort of triangulate on that. Hey, Patrick. It's Chris here. You know, 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. 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 of cash in people's hands as well as retiring the share count. in addition to profitably growing in the money. So, you know, 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 shared buybacks as well. We think that's the optimal level right now, given we don't have to deleverage the balance sheet. Yeah, 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 three 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 three sources? And then just on the water handling, is that something – that's transitory or is that a little bit more structural going forward?

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 Trading obviously has a BOE impact, so that impacts the dollar per BOE. The other part is associated with a new asset. So, obviously, as we learn more about the asset, we find ways to optimize the operating cost there. And the other component of that is related to operational things in CAQA field as we move produced water. So, as we look at maybe those buckets, maybe you can look at one-third, one-third, one-third in terms of the impact, in terms of the increase. And obviously, some of those are stuff with With planning and spending a bit more capital over the next few years, we can start to curtail our impact.

Okay. Thank you very much. Thank you.

The next question comes from Aaron Borkoski at TD Cowen. Please go ahead.

Thanks. Good morning. Would you guys be able to talk a bit about how you intend to spread Apache Phase 2 CapEx across 2026 and 2027?

Aaron, it's Chris here.

It's a little early to say with any confidence. We're just going through, you know, the costing and timing of it. If you use Phase 1 as an example, you know, a total cost of roughly $750 million, roughly we spent $350 in the first year and $450 in the second year. So it's going to be, we would expect, pretty even. But as you recall, once we, you know, 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.

Okay, thanks. 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 Attachee. what areas are you planning on spending less on next year?

You know, as we're just getting into the planning phase for 26, as I mentioned, you know, the big moving parts, you're going to have phase one, attaching capital coming down as we are over, you know, initial high decline and into more of a stabilized rate. You obviously already mentioned 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 capital assets, which in 25 happen 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. And then as you mentioned, we will be adding in, we would expect subject to sanctions, some capital for phase two of Attachee. So several moving parts and we'll finalize that in the coming months here.

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

Yeah, I can grab on that one as well. I mean, historically what we've talked about is, you know, full cycle supply costs at Sunrise, you know, in the $1.15 to $1.25 range. So something, you know, 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 refuse to waste the resources 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.

Perfect. Thanks. I appreciate the answers. Thank you, ladies and gentlemen.

As a reminder, should you have any questions, please press the button. The next question comes from Jamie Kubik at CIBC. Please go ahead.

Yeah, good morning. 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 eight for us? Just incremental capital being spent to the Tashi. It looks like there's two 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 two. And can you talk a little bit more on the capital spending increase as well?

Thanks. Yes, Jamie, this is Armin. So, it's actually the extra capital we are spending there is primarily to advance some field construction in progression for phase two. We're taking advantage of the, I guess, seasonal weather conditions to advance that phase. It just basically allows us to maintain project timelines by spending that capital and be more efficient from a capital deployment perspective. Other than that, in Hitachi, it's only DNC, Drilling and Completions Activity, and there's no other capital that goes in the ground. In terms of CAC, well, obviously the incremental, the big budget, the $150 million is the capital that is for that scrap going out. CACO East asset. That's effectively what was planned for the remainder of the year, and that's been carried forward to Archon, so we are going to execute exactly the plan that was laid out there. And the other $50 million budget, you know, 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. You know, there's 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.

Okay. Sorry. Could I maybe just ask you to expand a little bit on Attachee, like outside of the $50 million? Because I guess slide eight has Attachee spending going from $360 to... $425 to $475 this year. So that would be, you know, over and above the $50 million that is going there. Are the completions more expensive? Just anything else on that side, Armin, if you don't mind.

Yeah, no. So, Jamie, we talked about some of the design optimization in Apache that, you know, Terry alluded to earlier on, like higher intensity fracks. Obviously, we have to spend a bit more money on some of that stuff. In addition to that, some mitigation measures for casing deformation 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 paths that we have completed, we have not seen any casing deformation. So some of that is associated with that. We can go through more details if required one-on-one.

Okay, that's great. I appreciate it. I'll hand it back.

Thank you. The next question comes from Kelly Ackermine at Bank of America. Please go ahead.

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

Clay, it's Chris here.

You know, it's really the 150 you're seeing in the second half of the year. We took over this asset, you know, mid-drilling of paths 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 BUEs a day, plus or minus, at a capital efficiency of roughly $15,000 a flowing barrel, you're going to be in that $200-ish million. So whether that's $200,000, $225,000 is kind of high level what you can think of. Obviously, what the teams right now are doing, integrating the asset, incorporating it into our development plans, and you'll get some more details on that later this year when we release the 26th budget. Yeah, I appreciate that detail, Chris. Second question goes to LNG supply agreements. There's a lot of new LNG projects that are taking FID or about to take FID. 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 have signed in the past?

And are you interested in adding more to your marketing book?

Well, this is Brian. 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 a third of our gas priced in Western Canada, a third of our gas priced in the U.S., and a third 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. Got it. Thank you. Thank you, ladies and gentlemen. Again, if you have any questions, please press star 1 now. This does conclude today's Q&A session.

I will turn the call back over to Dale Lueckle for closing comments.

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

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