ARC Resources Ltd.

Good morning, my name is Ivo and I will be your conference operator today. At this time, I would like to welcome everyone to the AHRQ Resources Third Quarter 2024 Earnings Conference Call. All lines have been placed to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. If you would like to withdraw your question, Please press star followed by the number two. Thank you. Mr. Luko, you may begin your conference.

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, Chris Bibby, Chief Financial Officer, Armin Jahangiri, Chief Operating Officer, Lara Conrad, Chief Development Officer, and Ryan Barrett, Senior Vice President, Marketing. Before I turn it over to Chris and Terry to talk you through our third quarter results and 2025 budget, 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 in 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 all available on our website as well as CDAR+. 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.

Thanks, Dale, and good morning, everyone. I want to begin by stating that AHRQ's longstanding principles of safety, capital discipline, and operational excellence are embedded in our culture and were once again evident in the quarter. We delivered strong operational results And in October, we successfully commissioned the first phase at Hitachi, which is our eighth major Montney development project. In addition, we continue to deliver on our commitment to shareholder returns, announcing a 12% dividend increase while continuing to buy back shares, both proof points that reaffirm our conviction in our business. Looking ahead, our asset base are performing very well with Hitachi on stream, ARP is positioned to deliver a significant step change in free cash flow per share growth in 2025. To expand on the quarter, we delivered average production of 327,000 DOE per day. This included 89,000 barrels per day of light oil and condensate, representing 20% growth quarter over quarter. This increase in condensate contributed to high margins and strong free cash flow generation. offsetting weak Western Canadian natural gas prices. We also maintain 2024 guidance as high deliverability at CAQA helped offset voluntary natural gas curtailment at our Sunrise asset. The strong CAQA performance was partly the result of frac design changes the team implemented earlier this year. Production at CAQA averaged 180,000 BOE per day and at times was producing in excess of 200,000 BUE per day. This is a great example of the technical strengths of our people and our commitment to continuous improvement. While Sunrise is one of the lowest cost dry gas assets in North America, the decision to curtail production showed our disciplined approach to profitability. As Western Canadian natural gas prices stayed low, we elected to shut in approximately 250 million cubic feet per day to preserve resource for a period of higher pricing. And currently, we're able to leverage our dual connected infrastructure and redirect gas to more attractively priced markets in the U.S. This resulted in higher realized pricing and better margins. An additional benefit of curtailing sunrise production is we can defer 20 to 30 million of capital next year that we would have spent maintaining production. In mid-October, we restored some volumes at Sunrise when natural gas prices recovered above levels required to exceed our hurdle rates. We have said this before, but it's worth mentioning again. ARC will always operate with a profitability over BOE mindset, and our operational decisions at Sunrise are a proof point of this. Moving on to Attachee. Back in May of 2023, when we announced we were proceeding with Phase 1, we committed to an 18-month construction timeframe. Today, 18 months later, I'm pleased to announce we've delivered on this promise and have commissioned phase one on time, on budget, and most importantly, safely. The achievement is the culmination of years of development planning, stakeholder and Indigenous engagement, and detailed technical work. Project management is what we do well. In total, This project involved more than 3 million combined work hours for construction and commissioning with our service providers. And I am proud of the way our team has executed this project, demonstrating once again that operational excellence and safety are core to how ARC operates. Today, Hitachi is producing about 20,000 BUE a day, of which 11,000 barrels per day is condensate. With our startup drilling and completion activities nearing completion, we are right on track to ramp up to our productive capacity of 40,000 DOE per day by year end. Hitachi is a critical part of achieving the profitable growth embedded in our long-term plan, so to see it come together is very exciting. Thank you to the whole team at ARC for successfully executing this project and for your continued focus on safe and efficient operations across our companies. Moving on to the budget. Next year, we have all the pieces in place to deliver a meaningful increase in free cash flow per share. Our capital budget of $1.6 to $1.7 billion is expected to deliver record average production of 380,000 to 395,000 BOE per day, representing 10% production growth, 20% growth in concept production, and a concurrent 10% reduction in capital of expenditures compared to 2024. We expect this program to more than double cut free cash flow to about $1.5 billion at strip pricing, which we plan to return to shareholders through a growing base dividend and share repurchases. Hitachi is set to deliver approximately 500 million in asset level cash flow on an annual basis. It will also increase margins by adding high value while cash costs per BOE remain flat. The result is a combination of production growth and margin expansion as we grow ATACHI. The improvement in the implied capital efficiencies compared to 2024 is driven by three main factors. First, we get the benefits of a full year of production from ATACHI phase one. Second, with the infrastructure investments at ATACHI complete, 90% of the capital is directed towards well-related activities, which drive a strong return on invested capital. And lastly, we are benefiting from better capital efficiencies at some of our core Montney assets, like Capua and Sunrise. Before I turn it over to Chris, I'd like to touch on Hitachi Phase 2. As a reminder, Phase 2 is a near replica of Phase 1, a 40,000 BOE per day facility that is comprised of approximately 60% of liquids of which the majority is condensate. We are ready to advance phase two as part of our long-term plan. We expect to include the capital investments with the 2026 budget with an on-stream date of 2028. Today, we have taken steps to gain further confidence in the regulatory environment. We maintain positive relationships with the First Nations with whom we operate, and the returns are well above our hurdle rates under low commodity price scenarios. Phase 2 lies in the heart of the concept-rich areas of the Montney. As a result, we expect growth and margin expansion to continue as we introduce higher margin Hitachi barrels into our base production. In summary, our conviction in Phase 2 remains strong, and we look forward to sharing more as we continue to advance this project. With that, I'll turn it over to Chris.

Thanks, Terry, and good morning, everyone. First, I'll touch on the quarter. We delivered average production of 327,000 BOEs per day, generated funds from operations of $592 million. Production was 2% above analyst expectations, while cash flow was 12% higher than analyst forecasts. Third quarter production was at the upper end of our previously guided range of 315,000 to 330,000 BOEs per day. The increase relative to our expectation was driven by strong wealth productivity at CAFLA. This contributed to light oil and condensate production, which averaged 89,000 barrels per day in the quarter, representing a 20% growth on a quarter-over-quarter basis and 4% year-over-year. Over the past several months, ARC has consistently been recognized in several top well reports across a few of our assets. The most recent is screening with nine of the top ten oil and liquids wells in Alberta in September. Despite the recent volatility in WTIA, Condensate demand remains robust and is notable by the tight differentials, with condensate currently trading at a premium to WTI. We continue to manage risk and exercise discipline across our business. This quarter, we elected to curtail a portion of our natural gas production at Sunrise to limit our exposure to weak Western Canadian-based natural gas pricing, where prices were especially weak. As a result, we realized a natural gas price of $1.78 Canadian per MCF in the quarter, which was effectively double the local ACO market. Looking back, the decision to shut in gas resulted in a realized natural gas price that was 20 cents greater at a corporate level than if we elected to produce the gas. By doing this, we preserved the resource for a period when prices are higher, realized higher margins, and are able to defer $20 to $30 million of capital expenditures previously earmarked to sustain production in 2025. In our view, this was a simple decision and something we will continue to consider as we think about optimizing our assets to create value. To this end, while natural gas prices are at low levels today, demand in North America from LNG and power generation is set to grow at an accelerated pace in 2025, which we believe will drive a positive fundamental shift in supply-demand. For ARC, we have amassed a deep inventory in the monotony, which sits well below the marginal cost needed to supply this demand growth. We have a transportation portfolio underpinning that resource that allows us to deliver our natural gas to key demand markets in North America. Our natural gas diversification will extend internationally beginning in 2026 when our first LNG contract with Chenier takes effect. Moving on to capital, we invested approximately $460 million in the quarter, including roughly $200 million to complete our first phase at Attachee. After investments, our business yielded $135 million of free cash flow in the quarter. In terms of capital returns, we distributed $220 million to our shareholders this quarter through a combination of dividends and share buybacks. This included the $135 million of free cash flow in the quarter, as well as $80 million of proceeds from a non-core asset disposition. Looking ahead, with Hitachi Phase 1 on stream and production at Sunrise partially restored, we are anticipating a record quarter production in the fourth quarter, with average production between 380,000 and 385,000 BOEs per day. This will result in a full-year production at the low end of our 2024 production guidance range, despite the natural gas curtailments which reduced our full-year average production by approximately 10,000 BOEs per day. Put differently, if we did not curtail any natural gas production, we would have expected to reach the top end of our production guidance for 2024. Finally, to round out the quarter, we exited with $1.6 billion of net debt and $1.4 billion of long-term debt. This is a comfortable level of debt given the asset quality and inventory depth that underpins our business and implies a net debt to cash flow ratio of roughly 0.6 times. Turning to the 2025 budget, We put forth a capital program that emphasizes profitability and balances organic growth with a meaningful capital return. The $1.6 to $1.7 billion budget results in 10% production growth or reinvesting approximately 50% of cash flow at strip pricing of US $60 WTI and $2.40 Canadian ACO. We estimate our program to generate about $3.2 billion of cash flow and approximately $1.5 billion of free cash flow. For the third straight year, we intend to return essentially all free cash flow to shareholders. Based on our guidance, the budget represents a record year in terms of natural gas and condensate production, with average production of 380,000 to 395,000 BOEs per day, including approximately 105,000 barrels per day of light oil and condensate. This reflects stable production of our base assets, of about 350,000 BOEs per day and a full year of production at Hitachi of between 35 and 40,000 BOEs per day. Capital expenditures represent a roughly $200 million decrease year over year as we conclude the infrastructure investments in Hitachi phase one and incorporate some of the capital efficiency gains we've observed at CAQA and Sunrise. Margin expansion in 2025 reflects a higher condensate weighted production mix along with all in cash costs on a dollars per BOE basis that are expected to be flat to slightly down year over year. Based on dividends of approximately $400 million or a 3% yield, the budget implies $1.1 billion of free funds low after dividends, which could be used to repurchase roughly 8% of our shares outstanding based on the share price yesterday. This aligns directly with our long-term plan to profitably grow on a per share basis while continuing to return capital to shareholders. Maintaining a strong balance sheet and resilient business are core to ARC. Net debt to cash flow is approximately 0.6 times and less than one times at $50 U.S. WTI and $2.50 U.S. Henry Hub. Capital program and dividend are fully funded by cash flow at below U.S. $50 WTI and and U.S. $2.50 Henry Hub, a result of ARC's low-cost structure, balanced commodity mix, and owned and operated infrastructure.

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

Thanks, Chris. To close, we are on track to achieve the goals introduced with our long-term plan a year and a half ago. We have achieved the first milestone in bringing Hitachi on stream, And this sets the stage to triple free cash flow per share to greater than $4 by 2028. Finally, I want to again thank all of our staff for their continued focus, discipline, and hard work in delivering exceptional results across all aspects of our business. I also want to thank our investors that joined us on the Itachi tour. It was a great opportunity to showcase what we have collectively worked so hard to achieve over the past few years. We appreciate your continued support. Thank you. With that, we can open the line up for questions.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star followed by number one on your touchstone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press star followed by number two. If you are using a speakerphone, please leave the handset before pressing any keys. One moment, please, for your first question. Your first question comes from the line of Michael Harvey of RBC Company. Your line is now open. Please ask your question.

Yeah, sure. Good morning, everybody. Just a couple for me. I guess the first one may be for Lara or Armin. I mean, just wondering if you could give us some early color on the well performance at Hitachi. I know we're kind of early days here, but just anything like number of wells currently producing to hit that 20,000, initial IPs, condensate ratios, that kind of stuff would be helpful to the extent you can provide any high-level detail. And then the second one, maybe for Ryan or others, has LNG Canada given you any indication of when they might start taking your Sunrise gas into phase one? And maybe just remind us what kind of effect that will have on your pricing realizations at the point that that does happen. That's it for me.

Thanks, Mike. Laura here. Yeah, thanks for the question. As far as initial rates, everything we see out of Hitachi is coming on as we expected. Just like you don't see us release rates when we first bring on a well, I don't want to get into specifics because we've got a lot of water coming back. You know, the wells are still cleaning up. But really happy to see gas and strong condensate volumes from these early wells and look forward to talking about it more as we get into more stabilized production from Hitachi.

Hey Mike, it's Ryan. Just on your question on LNG Canada, we are expecting our volumes to start flowing sometime in the first half of 2025. We haven't been given any further notification than that. As you know, the pricing on that deal with Shell is a modest premium to ECO, so we wouldn't expect material changes to our gas price realizations.

Gotcha. Thanks for the comments, guys.

Your next question comes from the line of Kalei Ackerman from Bank of America. Your line is now open. Please ask your question.

Hey, good morning, guys. Thanks for getting me on. For my first question, I want to address the soft gas market in ACO. Can you talk a little bit more about your plan to manage this winter? Why not just keep sunrise off for an extended period, perhaps until Canada LNG helps shift the market into a new balance?

You bet. Good morning, Clay. It's Chris here.

You know, what we outlined with our second quarter release when we initially announced guided the market that we were going to bring some production off at Sunrise. You know, we talked about a couple of different price points. The most important one price point for us, and Terry's mentioned it quite a few times, is, you know, our full cycle break even. We don't want to produce the resource below what is required to achieve our targeted return rates. And for an asset like Sunrise, you know, that number is somewhere in the $1 to $1.30 range. So as we saw coming back above those amounts and we can make our hurdle rates, it makes sense to bring that asset back on. We are not constrained by inventory in any way, shape, or form at our assets. So if we can make our hurdle rates and run a profitable asset, we think it makes sense to do so. If somebody was short a little inventory, that decision might get changed and you might want to save all of it for a different day. But given our inventory length, it makes sense and it increases the profitability of the overall organization to continue to run it. You have seen us. We use the word partially restored production at Sunrise. And really what we are doing there is limiting our exposure to Station 2, which is another local market here in Western Canada, as pricing has not yet achieved our hurdle rate. So we'll wait until that does happen before we bring that production back on.

Chris, I appreciate that. I guess the rub here is that condensate players like you don't need a high gas price to get your economics to work, but gas is still going for a pretty cheap price. So kind of thinking about your business commercially, what options do you have to get more gas out of basin? This quarter, one of your U.S. peers announced a new LNG agreement on an existing facility as somebody seemingly gave up their space. wondering if you're seeing similar opportunities on the market, and if you were, would you lean into it?

Yeah, it's a good question. You know, as you know, we move about 50% of our gas already into the U.S. It's something that we're continuously watching for capacity, as you say, that comes up on export pipelines. You know, the export pipelines in Canada are fully subscribed and fully flowing. So it's not opportunities that come up every day, but we're definitely watching it. As you know, we do have our LNG contract starting in 2026. So this is a bit of a longer term view for us. And as you look at our exposures to Western Canadian gas prices next year, they're roughly, you know, roughly 30% of our gas production. So it is very, very minimal for us, our exposure to Western Canada.

Thanks. I appreciate it. Yep.

Your next question comes from the line of George Silverstein of UBS. Your line is now open. Please ask your question.

Yeah, thanks. Good morning, guys. It's George Silverstein at UBS. Great to see the startup at phase one at Hitachi. You know, on the site tour and some of the comments today, you talked about, you know, the next focus, which would be on phase two. What lessons learned from phase one might you be able to apply to phase two for either faster development or the ability to leverage the existing infrastructure that's there for lower costs?

Yeah, thanks for the question. This is Armin.

So phase two, as Terry mentioned, is going to be almost an exact replica as phase one in terms of the facility design. It definitely benefits from some of the infrastructure we've already invested and built in the area, so that is definitely a savings and opportunity for more efficient execution of the project as we move to phase two. In terms of cost, the team has looked into the design of the facility to find and identify opportunities to make it more efficient and make the process a lot streamer from the purpose of construction as well as the operation of the facility. So in all likelihood, I guess the sheer fact that we are just basically repeating what we've done and all the investment we have done in the area already is going to make us a lot more efficient as it comes to phase two.

That's helpful. And then just on the COCOA productivity uplift, this is a big asset. I'm curious if the uplift you're seeing or the improvements you're seeing are concentrated in one area. Is it across the basin and how you're thinking of maybe shifting your program this year relative to 2024, or sorry, next year relative to 2024, to take advantage of some of that productivity? Thanks.

Thanks, Josh, for the question. Laura here. Yeah, so, you know, when you're designing your wells, you really want to make sure you maximize your connectivity to the reservoir. The completion design shift that we've done is really targeted at that. So it would apply across the entire field. It's not really limited to one area. When we're drilling at CAFA, we're managing our super pad capacities as well. So as you mentioned, it's a big asset, 180,000 BOEs a day. So we do have activity throughout the asset, and we've made that same design shift across all of our operations.

Got it. Thanks, guys.

Once again, everyone, to ask a question, please press star followed by number one on your touchtone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press star followed by number two. If you're using a speakerphone, please lift the handset before pressing any keys. Your next question comes from the line of Travis Wood of National Bank Financial. Your line is now open. Please ask your question.

Yeah, my question was asked, but it sets up well with the last question just as a follow-up. Armin, you kind of talked about the infrastructure spend, the strategic planning around Phase 1 and Phase 2, but can you help us quantify what that would mean on an efficiency capture? So, obviously, the ads that attach here are highly efficient on a capital efficiency measure for 2025. What kind of compression could that look like with the cost savings on the infrastructure spend from phase one and phase two for the future volumes as a percentage? Or if you think there's a better way to think about that, just trying to figure out the efficiency gain on that production ad for the phase two volumes.

So just to be clear, in 2025, we are not spending any money on phase two. So basically our budget for phase two is less than 10 million bucks. When it comes to actual execution of phase two, that is currently scheduled for 26 and is going to be spent over 26 and 27 years for the 2028 on stream timeline. I think we've quantified that in the past that we estimate about $70 million of savings associated with the joint infrastructure This is some of the stuff that we've already done to right-size the pipes and have the water infrastructure and some of the equipment already set up in a way that can handle the extra 40,000 BOE of production coming through the condensate terminal that we have at 7 of 17. So some of the stuff has already been put in place, and I think the way we have quantified that is about $70 million of production of savings associated with Phase 2. Having said that, you know, from Phase 1 to Phase 2, we are realizing some inflationary pressure. I mean, the time that we sanctioned the project and purchased the equipment for Phase 1, we were in a different environment. Our expectation for Phase 2, despite all of that, is to be able to keep the cost flat at roughly $800 million to basically build the infrastructure and all the associated wealth to fill up that facility. The other thing that I can add is that we have also realized some efficiency gains through the drilling and completions activity as we've resumed operation in Hitachi. That is something that phase one and phase two are going to benefit from as we develop the new property, obviously, as well as continue to drill for phase one to keep the facility full.

That's perfect. Really appreciate that detail, Armin. That's all from me.

Your next question comes from the line of Patrick O'Rourke from ATB Capital Market. Your line is now open. Please ask your question.

Good morning, guys. Thanks for the comprehensive rundown. I think you've touched on a lot of the operational and reservoir-related questions. I guess this would be a little bit more on the strategic side in terms of the return of capital plan. Obviously, you've raised the dividend here. I think you spoke to an estimation of about 8%. of the flow being bought back in 2025 under the context of the current share price and free cash flow yield that you have there. But I'm just wondering if maybe you could give us some view into the, when you say balanced return of capital between a dividend and buybacks, how do you define the parameters in terms of that balance? What's the right amount to the dividend versus the share buybacks? Is it based on breakeven, which I think you alluded to being about 50 bucks to fund the CapEx and the dividend? Or is there some sort of other formula that helps you define that kind of divide between the two mechanisms?

Patrick, thanks for the question. It's Chris here. I'll start and Terry might jump in at the end as well. When we talked about a balanced capital allocation, really what we're talking about is our three main buckets. And that's where we talk about, you know, trying to have roughly 50% of our cash flow going back into the assets of the organization, both to fund sustaining capital as well as growth capital. And then that obviously leaves us the remaining 50%. 15% of that, we believe, is a very defensible and sustainable dividend policy. When you see us, you know, bump the dividend here this quarter, on strip will be a little lower than that next year. So we just want to make sure we're being Very prudent on that. And then that leaves roughly 35% of that cash flow amount that we've currently allocated to share buybacks. And that results in the roughly 8% potential stock retirements here over the next 12 months. So when we talk about the balance, it's about those three main buckets. We don't have a specific rule as in terms of dollar amounts that need to go into buybacks versus dividends. But as it, you know, if you look over the last 12 months, dividends is taking more of the free cash flow than buybacks has. But you would think in the next 12 months, it's going to reverse with probably some significant dollars going to the buyback side of the equation.

Okay. Thank you very much. That's all for me.

We do not have any further questions at this time. Presenters, please continue.

Alright, thanks everyone for joining today. That concludes the call. Thank you.

This concludes today's conference call. Thank you for your participation and you may now disconnect.