Good morning, ladies and gentlemen, and welcome to the ARC Resources Limited Q4 2024 Earnings Conference Call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. During this time, should you wish to ask a question, please press star and one on your touch-tone phone. And if at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on Friday, February 7, 2025. And I would now like to hand the call over to your first speaker today, Dale Lewko. Please go ahead. Thank you, Operator. Good morning, everyone, and thank you for joining us for our fourth 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, Lara Conrad, Chief Development Officer, and Ryan Berrett, Senior Vice President, Marketing. Before I turn it over to Terry and Kris to take you through our fourth quarter results and 2024 reserves, 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 disclosed 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. Thanks, Dale. Good morning, everyone, and thank you for joining us today. I'm excited to take you through our fourth quarter results and 2024 reserves and provide some insight into how things are shaping up in 2025. 2024 can be summarized as a milestone year for ARC and one that was defined by operational excellence, capital discipline, and long-term profitability. I'll begin with our fourth quarter results. The quarter was headlined by production of 382,000 BOE a day, the highest in our 29-year history. This included record condensate and light oil production of approximately 105,000 barrels per day, which represents a 20% increase year-over-year. The increase was primarily driven by two material events: production contribution from Attachie and strong results at Kakwa. At Kakwa, production averaged approximately 195,000 BOE per day during the fourth quarter, which included greater than 100,000 barrels per day of condensate and natural gas liquids. The growth in condensate is a result of focusing our development in areas with higher condensate-to-gas ratios, which we plan to continue in 2025. In addition, we continue to optimize our completion design, resulting in more effective frac placement and ultimately better capital efficiencies. Moving on to Attachie, it's been four months since we began commissioning phase one last October, and overall, we are on track to achieve what we set out to do in 2025. The facility is operating as anticipated, with the majority of startup wells now on production. Production continued to increase in December, averaging about 29,000 BOE per day. This included 18,000 barrels per day of liquids, of which 14,000 barrels per day was condensate. Production currently exceeds 30,000 BOE per day, and we are on track to deliver average production in the first quarter between 30,000-35,000 BOE a day, 60% condensate and NGLs. For 2025, we expect full-year average production of approximately 37,500 BOE per day. I'd like to thank our staff and service providers for their support in the safe and successful construction and startup of Attachie. Phase one is the first milestone in delivering on our long-term plan, and your efforts have ensured we are right on track. Our 2024 results were achieved executing a CAD 1.85 billion capital program, which represented one of our largest and most efficient development programs. We delivered annual free funds flow of CAD 627 million, which was all returned to shareholders through our base dividend and share buybacks. With the upfront capital associated with phase one behind us, we anticipate a material increase in free cash flow in 2025. At current strip, we expect to generate free cash flow of approximately CAD 1.8 billion. Looking back, our low-cost structure and market diversification once again provided a material competitive advantage in achieving high margins and being profitable through cycles. Our operating costs in the quarter were CAD 4.20 per BOE. This low-cost structure is a result of owning and operating our infrastructure and despite low natural gas prices in Western Canada, ARC realized an average price in 2024 of CAD 2.37 per MCF, which is 65% greater than the AECO benchmark. This was another year of incredible activity, and I'm pleased with our operational and financial results. It's also worth noting that these accomplishments were achieved while maintaining strong safety performance, which will always be our top priority. Finally, before I turn it over to Kris, I'll speak to reserves. We delivered another year of consistent reserve growth, positive technical revisions, and low finding and development costs. This is a track record we've established over the years and what you should expect from ARC going forward, validating the inventory depth and reaffirming the profitability of our Montney assets. Three notable takeaways from this year's report. First, it was another year of record reserves across all categories: PDP, 1P, and 2P. PDP reserves and 2P reserves grew by 5%. At Attachie, ARC booked an additional 50 million BOEs of 2P reserves, bringing the total at Attachie to 174 million BOEs. This represents just 9% of ARC's internal inventory estimate at Attachie, providing a runway for long-term reserve growth. As well, we received positive technical revisions across all categories. This was due to relative outperformance across several assets, most notably at Kakwa. Positive technical revisions and extensions represented a 28% increase to 2023 PDP reserves. Kakwa technical revisions were noteworthy, representing 41 million barrels of oil equivalent on a total proved basis. Second, ARC's before-tax NPV of 2P reserves discounted at 10%, increased to CAD 41 per share, an increase of 6% per share. For perspective, that value is based on the development of just 23% of ARC's internally identified inventory. As always, the pace of capital investment and development underpinning ARC's reserves report aligns with the long-term plan we provided to our investors in 2023. Finally, PDP F&D costs of CAD 11.87 per BOE, including future development capital, equated to a 1.9 times recycle ratio and a 2P recycle ratio of 2.4 times, based on a 2P F&D of CAD 9.19 per BOE. With that, I'll turn it over to Kris. Thanks, Terry. And good morning, everyone. I'll provide a summary of the financial results and then turn it back to Terry for some closing remarks. After that, we'll open it up for questions and answers. Fourth quarter production was a record, despite ARC's curtailment of natural gas production at Sunrise due to low gas prices. Production of 382,000 BOEs per day was in line with company guidance as well as analyst forecasts. Record volumes were driven by Attachie and industry-leading results at Kakwa. ARC has consistently been recognized in several top well reports across several assets, most notably having achieved all 10 of the top 10 condensate wells in Alberta, based on recent public data. Full-year production in 2024 averaged just shy of 348,000 BOEs per day. Light oil, condensate, and NGLs were all within guidance, while natural gas was slightly below due to curtailments at Sunrise. By curtailing production at Sunrise, we accomplished a few things. First, we were able to preserve resources for a time when pricing strengthens. Second, it allowed us to defer about CAD 20 million of capital expenditures that we would have had to previously spend to offset declines in 2025. We will always operate with profitability in mind versus achieving a top-line BOE production number. As we closed out the year, natural gas prices in Western Canada recovered, and production at Sunrise was fully restored. Turning to our financial performance, ARC reported fourth quarter cash flow of CAD 770 million and free cash flow of CAD 420 million, which was 5% and 17% above analyst estimates. There were three primary contributing factors. First, ARC is Canada's largest condensate producer, and it represents approximately 70% of our revenue. In the quarter, we delivered record condensate production into a strong pricing environment, with benchmark condensate pricing averaging above CAD 100 per barrel. Second, we continue to realize relatively strong natural gas prices by utilizing our transportation to reach more attractive end markets in the U.S. ARC's realized natural gas price of $2.58 per MCF in the quarter equated to a 77% premium to the average AECO 7A monthly index price. For the year, ARC realized $2.37 per MCF, which compared to the local AECO benchmark of CAD 1.44 and the average at Henry Hub of $2.27 per MCF. This marks the 12th straight year that ARC's market diversification strategy resulted in a realized natural gas price that exceeded AECO by 20% or greater. Third, and as Terry mentioned, we kept our costs low, a reflection of the quality of our assets, operational excellence, and our infrastructure ownership. Altogether, operating and transportation costs were below $10 per BOE, which was below the bottom end of our guidance. Total cash costs, defined as operating costs, transportation, royalties, general and administrative costs, and interest, were $16 per BOE, resulting in a $25 per BOE netback. Altogether, ARC generated $420 million of free funds flow during the quarter and $627 million for the year. For the second straight year, ARC distributed essentially all free funds flow to shareholders through a combination of dividends and share buybacks. Finally, ARC exited the year with $1.3 billion of net debt, flat year-over-year, representing approximately 0.5 times 2024 cash flow. This is a comfortable level of debt given the asset quality and inventory depth that underpin our business. Looking ahead, we have made no changes to 2025 guidance or the long-term plan. For 2025, we expect capital expenditures to trend lower year-over-year into the range of CAD 1.6-CAD 1.7 billion, with average annual production between 380,000 BOEs a day and 395,000 BOEs per day. Production guidance includes approximately 105,000 barrels per day of condensate and light oil, representing a 25% year-over-year growth in that category. The result is an increase in corporate margins and record free funds flow expected of approximately CAD 1.8 billion, based on the forward curve. Sticking to our strategy, ARC plans to return essentially all free funds flow to shareholders in 2025, providing an attractive and competitive total return. With that, I'll pass it back to Terry for closing remarks. Thanks, Kris. 2024 was a pivotal year in demonstrating our ability to execute and instill confidence in achieving the goals of our long-term strategy. In 2024, we executed the largest capital program in our history, completing the first phase of Attachie. At the same time, we returned CAD 600 million to our shareholders without adding any debt, which shows the financial strength of our business. 2024 has set us up well for 2025, where our priority is to demonstrate the profitability of ARC incorporating a full year of Attachie. This will be measured by a marked increase in free cash flow, which will be distributed to our shareholders through our growing base dividend and share repurchases. In 2025, we'll continue to invest in our new operating area of Attachie, and our focus has already shifted towards phase two, the next major milestone in our long-term strategy. This is an exciting time for ARC, and I'd like to thank our employees, service providers, and partners for your continued support. We look forward to building on our momentum from 2024 and delivering strong results once again in 2025. 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. And as a reminder, for those who want to ask a question, please press star and one on your touch-tone phone. And we will now take our first question. And this comes from the line of Aaron Bilkoski. Your line is now open. Please go ahead. Thanks. Good morning, guys. Thanks for taking my question. I was hoping you could provide some details on the water cuts you're seeing at Attachie and how that compares to your original expectations. Thanks, Aaron. Yeah, this is Lara chatting. As far as the water cuts go, we had to pull off the load fluid. We only had a small facility to clean the wells up through until we started up phase one. We definitely were expecting to manage that heavier load fluid recovery period. I'd say we were at about 60% water cut, even just like two, three weeks ago, and we've come down to about 50% at this stage. We definitely are seeing the water cut perform as we would expect it and sort of similar cuts to what we see at Kakwa. Perfect. Thank you. Thank you. And the next question comes from the line of Michael Harvey from RBC Capital Markets. The line is now open. Please go ahead. Yes, sure. Good morning. So a couple of questions for me, I guess, just on the reserve bookings at Attachie. I think you went through it, but just confirming it really is only phase one that's booked right now to reserves. And then if that's the case, what would cause the evaluators to start booking phase two? Would that happen at the end of this year, or does it require more time and actual drilling results as you get kind of into the phase two startup period? And then second one, just I know it's early days, but any learnings so far from the ramp of a phase one that you can apply to phase two or subsequent phases could be related to cost, well productivity, any of the water items that Aaron mentioned, or any facility stuff? Just anything that would give some folks a bit more understanding of what could change or remain the same into the next phase. Yeah. Hi, Mike. It's Lara here again. As far as reserves, you bet. Right now at Attachie, we only have reserves associated with phase one. So how we define phase one border is really the Halfway River. So we have not put any undeveloped locations east of the Halfway River. As far as when we will do that, really, it's not so much waiting on well results. We do have a pilot test over there, and we've got wells that are on production right on our eastern edge of the field. So what will initiate reserve bookings will be the actual moving forward with sanction and investment in a phase two. So very similar to what you saw us do with phase one, once we actually were committing investment to the project, we started booking the reserves associated. With that, I'll pass over to Armin on the second part of your question. Hi, Mike. Armin here. So in terms of phase two, what we expect is pretty much the same exact type of design and approach to phase one. Really, there's nothing new as far as execution of phase two is concerned. We are going through finalizing some of the plans and make some final adjustment decisions, but nothing that materially changes our approach to phase two. Great. Thanks for the call, guys. Thank you. And the next question comes from the line of Patrick O'Rourke from ATB Capital Markets. Your line is now open. Please go ahead. Hey, guys. Good morning and congratulations on some very strong performance there and bringing Attachie up here. Thanks for the rundown in terms of the performance there as well and what you've learned. Maybe to shift gears just slightly, you noted the Cedar LNG, the potential to sign an LNG offtake agreement there. Could you maybe walk through some of the parameters around that? Obviously, I'm understanding there's still some commercial sensitivity. And then with respect to the project itself, what the next key milestones we should be watching for are? Hey, Patrick. It's Ryan. Thanks for the question. Yeah, we're still proceeding with the SPA with our offtaker on the Cedar project. We're extremely close. Just haven't got quite across the finish line yet. As it pertains to the project, as you know, projects fully FIDed. They are obviously fully contracted for the capacity of the project. So from our perspective, right on track, and at this point, we're still very early in the project, and we're just monitoring it as it stands today. Any sort of timeframe that you can point to? At this point, no. At this point, again, it's very preliminary in the project design. Okay. No problem. And then just more of a sort of philosophical question around capital allocation. You're very likely booked at Attachie. You just spoke to that. About 75% of your inventory is still unbooked here. How do you think about sort of the right mix of growth, pulling value realization for that inventory, massive inventory that you have, against return of capital to shareholders and the scope and scale of sort of capitalization of infrastructure today? Yeah. Patrick, it's Terry here. We're sticking to the five-year plan. And what we laid in that five-year plan is this balanced capital allocation approach. And that's reinvesting 50% of that cash flow back into growing the business moderately. We think that's just prudent to grow moderately. And then the other 50% is going back to the shareholders through the base dividend growth and through share buybacks. And so last year, we had more capital expenditures. This year, we have less capital expenditures. So more of that free funds flow is coming back to the shareholders. So we're just sticking to that plan. We truly believe just having a very disciplined balanced capital allocation approach over the long haul will deliver the best risk return to the shareholders. There's nothing more than that. Okay. Great. Thank you very much. You're welcome. Thank you, and the next question comes from the line of Josh Silverstein from UBS. Line is now open. Please go ahead. Good morning, guys. Performance at Kakwa continues to be really strong, and you're at 195 for the fourth quarter. Can you just talk about the gap to that versus the game plan to be at 170-175 for 2025? Is there downtime? Any reason for the decline? Because you've now been above that level for the second half of 2024. Thanks. Hey, Josh. It's Kris here. I'll take a stab at it, and then Lara and Armin might have a comment. But really, what happened was late last year, we saw the results of our slightly modified completion. And the effect of that was we had very, very high production coming into year-end. If you recall at Kakwa, you're going to get some pretty big peaks and valleys just given the high productivity of the wells, as well as the fact that we've got some excess productive capacity at Kakwa. So what we do is as soon as the wells are done and we bring them on stream, we do not restrict them. What that does lead to is high production initially, and then you will see decline. So when we talk about 170,000-175,000 BOEs a day, that's what we're targeting as an annual average. The reality is you're going to see probably prints of 150 up to close to 200,000 BOEs a day throughout the year to hit that average. And obviously, just in the way this one worked out is Q4 high at 195. It will be declining in the first half of the year before we bring on some wells late in 2025 again to target that average of 170-175. Got it. Thanks for that clarity. I'm curious just on the natural gas side as well. Relative to the middle of 2024 period when AECO was weak and you curtailed volumes at Sunrise, do you have the potential to flex Sunrise the other way if you do have prices rising over the course of this year or even into next year as well? Thanks. I'll take it again. It's a pretty simple answer. The answer is no. We don't. So Sunrise, we run, generally speaking, at capacity. So it's different than something like a Kakwa that I just explained where you get a lot of variability throughout the year. Sunrise, we would have less variability. And so therefore, we can't flex it substantially above. Colder weather, you can get a little bit more gas through the system, but not a tremendous amount. Thanks, guys. Thank you. And once again, as a reminder, for those who want to ask a question, just press star and one on your touch-tone phone. Star and one for questions. And we will now take the next question. This comes from the line of Travis Wood from National Bank Financial. Please go ahead. Your line is now open. Yeah. Thanks for getting me in the queue. I just wanted to ask around kind of operating through the winter. Obviously, cold weather is great for prices but makes some operations a little more difficult. What types of things do you have in place to help mitigate downtime? Maybe it's just operating items themselves, but also kind of mitigating BC Hydro power outages. And I'm kind of thinking specifically the Attachie region. Yeah. Travis, Armin here. In terms of BC Hydro, we have typically not seen any challenges or issues with winter operations in the region that we are operating and our connectivity to transmission lines. I guess that gives us a certain degree or higher degree of certainty when it comes to our operation. In general, this is not our first winter that we operate in Canada. I think we know exactly how to run our facilities in this type of weather condition. There are certain practices that our teams are actively using in terms of moving fluid and operating our facilities to make sure they are running safely and efficiently. Okay. And is anything done differently from, let's say, Dawson? Just Just as you built out Attachie, were there kind of evolutions as you thought about winter downtime potential as you built out Attachie? Or is it copy-paste? Yeah. The facilities have a fairly similar processing design. Obviously, every facility has its own unique process built into it based on the composition of the fluid and the gas and condensate that you're getting in the facility. So there are some specific design changes that obviously you need to make sure you factor in the power requirement and winterization and all of that stuff. But in general, the principles that we followed in Attachie is based on our many years of learnings building facilities in Canada. Okay. Awesome. Thanks for the color, Armin. That's all. Thank you. And the next question comes from the line of Kalei Akamine from Bank of America. Line is now open. Please go ahead. Hey, good morning, guys. Terry, Kris. I want to ask your views on consolidation here. What we've seen in the US is that consolidation has imposed discipline, and we believe that's leading to a healthier gas macro. Do you think consolidation in your basin is necessary? Do you think we'll see it in that setup? Are you guys a consolidator? It's Terry here. I think consolidation should happen to make the overall industry more efficient from that perspective. Will ARC be a consolidator? No. I just don't see that in the cards for us. We have too many great assets to invest in, and buying back our shares is a great return for our investors. So we probably won't be the consolidator. But generally speaking, yeah, I think the industry should become more efficient. At 12% free cash flow yield, I would echo your comment that ARC is a great investment. My second question here is operational. In your slide deck, I think you call out better performance at Kakwa due to well designs. Can you kind of characterize what you're doing there and how it compares to your prior designs, but also to offset operators like maybe Ovintiv? Sure. Kalei, this is Lara. As far as the design goes, I think we've talked to it a little bit. We used to have stage lengths that involved five clusters. And therefore, really, when you're completing the well, you're looking for fairly even distribution of your fluids and sand across those five clusters. What we found is by dropping the clusters per stage down to three, keeping all the other sort of main factors of the recipe the same, but dropping down to that three clusters is really allowing us to get better access into the reservoir and better connectivity. And that's what's really improved our performance and our capital efficiency, more importantly, at Kakwa. Awesome. I appreciate that, Kalei. Thank you. Thank you. And the next question comes from the line of Jamie Kubik from CIBC Capital Markets. Line is now open. Please go ahead. Yep. Thanks for taking my questions. I've got two here. So just maybe on the profile for Q1, you noted Attachie producing at about 17,000 BOEs a day in Q4 against corporate production at 382. And then expectations for Attachie to produce between 30,000 to 35,000 BOEs a day in Q1. Can you just talk a little bit more about the Q1 production guide of 370 to 375 and maybe the contribution between the various assets and what's driving the reduction quarter-over-quarter? You bet, Jamie. It's Kris here. Thanks for the question. The main factors that are kind of moving around in the background. So you'll have a full quarter of Sunrise production we would expect at this point. And then the other two main things. We talked about Kakwa coming down from 195,000 BOEs a day and then ramping up Attachie to closer to the full 30,000-35,000 BOEs a day of contribution relative to the contribution of roughly 17 in the quarter, as you mentioned. So those are the big moving parts. Dawson and everywhere else we would expect to stay relatively flat quarter-over-quarter into Q1. And then just for a little more color, we would expect Q1 at this point in time to be the low print of 2025. So 370, 375 is reasonable for Q1. And then growing throughout the remainder of the year to get to the midpoint of guidance for 2025. Great. Thank you. And with respect to the reserves report, can you just touch on the economic factors and the bookings on that side? And then it looked like Kakwa demonstrated a sizable increase in positive technical revisions. Can you talk about how the remaining assets contribute to the tech revisions there? Thanks. For sure. So as far as the economic factors, we use the 3CA forecast. And on gas in particular, the price came down, I want to say, about 18% year-over-year. And so with that price decrease, what we always do is you book all your reserves. And then once you've got your whole book set, you run it against the last price file and see what at the end of life comes off. So despite an 18% drop in pricing, our economic factors removed about 1% of volume at end of life. So I think what that really showcases is how strong our portfolio is and the low-cost structure that we have. So that's the economic factors. As you mentioned, yeah, we talked to Kakwa as far as the positive revisions we saw there. Overall, we saw strong performance across the portfolio. We don't normally talk or sort of pull a whole bunch of detail out on our specific properties. But we noted that the 1P technical revisions were about 41 million barrels equivalent out of Kakwa in the 1P category. We had total 1P tech revisions of 74 million barrels. So that came in from the rest of the properties. Again, just seeing strong performance, our designs are working. We had a good year in 2024. And the reserve book always reflects sort of what the business performance is. Okay. Thank you. That's all for me. Thank you. And we have a follow-up question from Aaron Bilkoski from TD Cowen. Your line is now open. Please go ahead. Thanks. Thanks for taking my second question. I was curious to what extent the capital efficiencies you're seeing from the modified completion at Kakwa have been incorporated into your 2025 guidance or your five-year plan? Yeah. Thanks, Aaron. It's Lara again. As far as the capital efficiency, I mean, what we do from a forecast perspective is we always look at our results as we go into budget. And when I say results, that's both on the production side as well as all of our capital inputs. And that's the basis of the next year's projections tuned for however we're moving around the reservoir and any differences we might see there. So at the end of the day, we're really forecasting very similar results in 2025 as to what we saw in 2024. Thanks again. Thank you. And we have no further questions at this time. I will hand the call over to Dale Lewko. Please go ahead, sir. All right. Thank you to everyone for the questions and for joining the call. That concludes the call. Thank you. Thank you. This concludes our conference call for today. Thank you all for participating. You may now disconnect.