Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2025 first quarter results conference call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star one. For members of the media attending in a listen-only mode today, you may quote statements made by any of the Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or be broadcast without the express consent of Ovintiv. I will now turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest. Thanks, Joanne, and welcome everyone to our first quarter 2025 conference call. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and in our disclosure documents filed on EDGAR and SEDAR+. Following prepared remarks, we will be available to take your questions. I will now turn the call over to our President and CEO, Brendan McCracken. Thanks, Jason. Good morning, everybody, and thanks for joining us. Before we get into the details of the quarter and our outlook for the rest of the year, I want to start with the current uncertainty in the macro environment and the resulting lower oil prices and how we are positioned to handle it. Our business was built using mid-cycle prices of $55 WTI and $2.75 NYMEX to discipline and inform our decisions. This was purposeful to ensure we can continue generating solid bottom-line corporate returns and free cash flow through the bottom of the cycle. With a post-dividend break-even price under $40 WTI, 10-20 years of premium drilling inventory in each of our three assets, and our industry-leading capital efficiency, we are positioned to do just that. Our Montney for Uinta transactions, which both closed in January, have boosted our free cash flow by increasing our average price realizations, lowering our cost structure, and enhancing our capital efficiency. Each of our three assets is expected to generate premium returns at prices even lower than we see today. This return parity across our portfolio is a deliberate design feature of our business. At $50 and $3.75, all three of our assets deliver greater than 35% returns at the well level. This translates into a mid to high-teen, bottom-line corporate return. We started the year expecting to generate about $2.1 billion of free cash flow, assuming full-year commodity prices of $70 WTI and $4 NYMEX gas. Now, assuming $60 WTI and $3.75 NYMEX for the rest of the year, we expect to generate $1.5 billion of free cash flow. Even if we assume $50 WTI and $3.75 NYMEX for the rest of the year, we still expect to generate a billion dollars of free cash flow. Because of this robust profitability, we are maintaining our original full-year guidance, which reflects a maintenance level of investment. Simply put, with the business we have built today, it doesn't make sense for our shareholders to choose to shrink today. That said, we have complete flexibility to pull back activity in our development program with essentially no fees or penalties if we need to take that step. One change from the last couple of years: with lower oil prices, any savings from further efficiency gains will flow through to capital savings, whereas previously we'd been keeping activity going and seeing our production level settle higher. We also have access to $3.5 billion of liquidity, and our leverage remains at 1.2 times. Our debt at the end of the first quarter is already about $350 million lower than when we announced the acquisition of the Montney assets in November. We are committed to continuing to reduce debt while also maintaining returns to our shareholders through buybacks. Furthermore, our business is not subject to any material impacts from the tariffs that have been announced to date. We pre-purchased essentially all of the steel and tubular goods needed for our 2025 program and have no other significant supply chain exposure currently. All of our Canadian condensate is sold locally in Alberta and is not subject to tariffs. Our Canadian natural gas that is sold in the U.S. is USMCA compliant and therefore not subject to the 10% tariff on Canadian energy products. We are operating from a position of strength, and we can be agile to respond to changing market conditions. Over the past several years, we have high-graded and streamlined our portfolio, and today we have one of the most valuable premium inventory positions in our industry. Our anchor positions in the Permian and Montney, the two largest remaining oil resources in North America, provide the foundation for a differentiated multi-basin EMP. We have meaningful scale with about 205,000 barrels a day of oil and condensate production and over 1.7 BCF a day of natural gas. That makes us also among the top 10 public gas producers in North America. Our work to build inventory depth over the past several years means we have close to 15 years of premium oil inventory in the Permian, close to 20 years of premium oil inventory in the Montney, and over a decade in the Anadarko. Our operational excellence is translating into highly competitive rates of return, and our capital discipline is ensuring those returns flow through to the bottom line. We've had a strong start to the year, and our first quarter results continued to build on the track record of consistent execution. We delivered cash flow per share of $3.86 and free cash flow of $387 million, both beating consensus estimates. Production during the quarter was within or above our guidance ranges on all products. Oil and condensate volumes averaged 206,000 barrels a day, with total volumes of 588,000 BOE per day. We also came in below the midpoint on capital and met or beat on all cost guidance items. The oil and condensate beat was driven by the Permian, where we continue to see strong well results and outperformance from our base volumes. We are now through the noise associated with the Montney and the Uinta transaction close timing, and we expect our asset-level oil and condensate volumes to stabilize through the second quarter with a more consistent profile for the remainder of the year. I'll now turn the call over to Corey. Thanks, Brendan. We remain committed to our capital return framework, and we were pleased to restart share buybacks earlier this quarter. We temporarily paused the buyback program in the fourth quarter of last year to recover the difference between the Montney acquisition cost and the Uinta divestiture proceeds of $377 million. At the start of the second quarter, only $9 million remained outstanding, and as such, we have resumed buybacks and plan to repurchase approximately $146 million of shares in the second quarter. In April, we repurchased 1.2 million shares for about $40 million. As a reminder, our framework returns at least 50% of post-base dividend free cash flow to shareholders and allocates the remaining 50% to the balance sheet. Since the inception of the program in the third quarter of 2021, we have repurchased a total of $2 billion worth of shares and distributed approximately $1.1 billion in base dividend payments for total shareholder returns of more than $3 billion. While debt reduction is a big area of focus for us in the near term, as Brendan mentioned, we can generate significant free cash flow at today's prices, which ensures our shareholder return framework will stay consistent. We can repurchase attractively priced shares with a 16% free cash flow yield and improve the capital structure with continued debt reduction. Our balance sheet remains strong and is backed by a deep liquidity profile. With just over $5.5 billion of total debt at quarter end, our leverage ratio was 1.2 times. With a $60 and $3.75 NYMEX price deck for the rest of the year, we will still be near our $5 billion of total debt at year-end as we continue to work towards our $4 billion target, or about one times leverage assuming mid-cycle prices. We plan to pay our upcoming maturity in May of this year using a combination of cash on hand, commercial paper, and our credit facilities. Our credit facilities have a total capacity of $3.5 billion. These facilities were renewed near the end of last year and are not subject to any changes through 2029. We do not have a borrowing base or annual redetermination process. Our facilities are unsecured and are not reserves based. We have no cash flow, EBITDA, or leverage covenants. The credit facilities have one financial covenant, which is our debt to adjusted book capitalization must remain below 60%. This calculation includes a $7.7 billion permanent capitalization add-back for legacy non-cash write-downs. At the end of the first quarter, our debt to cap ratio was 24%. Maintaining our investment-grade credit rating remains a key priority, and we are currently investment-grade rated with a stable or better outlook at all four rating agencies. In fact, earlier this month, Fitch upgraded our outlook to positive from stable. I'll now turn the call over to Greg, who will speak to our guidance and operational highlights. Thanks, Corey. As Brendan highlighted, we've been very intentional in building a high-quality portfolio with deep inventory in each asset, and we have demonstrated that we are disciplined stewards of our shareholders' capital. Our team is laser-focused on continually improving our capital efficiency, and our outstanding operational performance through the first quarter gives us confidence in what we can achieve through the rest of the year. We expect our second quarter production to average approximately 595,000 barrels of oil equivalent per day, including about 205,000 barrels of oil and condensate per day. Oil and condensate production should remain largely flat through the end of the year. We expect our second half natural gas volumes to be higher than the first half of the year, as gas systems in Western Canada are currently full in anticipation of LNG Canada coming online, which is backing out volumes. Our full-year gas guidance remains unchanged. As a reminder, all of our capital is directed to oil and condensate development. Our capital spend will come in around $575 million in the second quarter, which reflects an acceleration of activity in the Montney thanks to our efficient integration of the newly acquired assets. Although our full-year capital plans remain unchanged, we have significant flexibility and can be agile in adjusting activity levels across the program should conditions warrant. Let's shift now to the asset-level results. Across our acreage footprint, our Permian well performance continues to deliver. On slide 10, the chart on the left shows our 2025 Permian type curve, unchanged from last year. Our 2024 performance essentially painted the curve with the results from 145 gross wells, and our early 2025 performance is equally in line. As planned, Q1 was a relatively heavier quarter for bringing new wells on stream, with 53 net turn-in lines, or about 40% of our 2025 program. This, combined with a large number of turn-in lines at the end of last year, led to a growth in oil and condensate volumes quarter over quarter to 131,000 barrels per day. As we return to a more ratable level of activity for the remainder of the year, with four rigs and one frac crew, we expect oil and condensate volumes to stabilize at around 120,000 barrels per day from Q2 onward. Our first quarter drilling speed averaged more than 2,000 feet per day, with a pace setter of more than 2,800 feet per day. On completions, our first quarter average completed feet per day was about 3,800 feet. When looking at our Trimulfrac wells in isolation, we averaged 4,400 completed feet per day. These cycle time improvements result in lower costs. Our pace setter DNC cost is among the best in industry at less than $600 per foot. Our performance in the play continues to demonstrate the expertise of our team in maximizing value from this incredible resource. Moving on to the Montney, our team has done a tremendous job integrating the new assets into our portfolio in a safe and efficient manner. Our confidence in the quality of the acquired assets is reflected in the strong initial well results we are seeing on this acreage. Our three most recent pads are tracking 12-month cumulative condensate rates of 16 barrels per foot. These results are consistent with the assumptions in our acquisition case and are a powerful demonstration of the underlying rock quality we've acquired. In fact, the oil productivity of the new assets competes heads-up with that of the top counties in the Midland Basin. The returns are also highly competitive, thanks to lower well costs, lower royalties, and similar oil price realizations. So far, the wells are performing very well, as expected, and we are looking forward to delivering our first oven of end-to-end designed wells late in the third quarter. We are the second largest condensate producer in the Montney. We are currently producing about 55,000 barrels per day of oil and condensate. We were below that level in the first quarter due to the timing of the acquisition close, but from now through the end of the year, we expect our run rate to remain relatively flat. Condensate is the primary driver of value in the play, and since there is a structural long-term deficit in the Western Canadian market, it should continue to trade tightly to WTI for the foreseeable future. In the first quarter, the average price realization for Montney condensate was 95% of WTI. We've made great progress toward achieving our well cost savings target, having already realized about $1 million of our $1.5 million target. All of the savings so far have come on the drilling side, as we have just recently started completions operations on the new acreage. We are seeing about a $600,000 per well cost savings from using a more efficient casing design and eliminating intermediate casing. We are seeing another $400,000 savings from optimizing the directional profile of the wells, optimizing workflows, and using a single bit for our lateral runs. We have taken about 10 days out of the drilling cycle time in the new assets, with the current average of less than 15 days spud to rig release. We've also fully integrated the acquired wells with our operations control center. This allows us to remotely operate the wells and apply the same digital workflows used in our legacy Montney operations to optimize cash flow at the individual well level. I'm incredibly proud of the team, and I'm looking forward to updating the market on our achievements throughout the year. In the Anadarko, we continue to benefit from the strong free cash flow generation from the asset, in part due to its exceptionally low base decline rate at about 16% per year. This asset represents about 15% of our total development program. It provides optionality in deploying capital and has minimal stay-flat capital requirements. The team remains on track to deliver average DNC costs of about $550 per foot, a reduction of about $100 per foot year over year. The returns in the play remain strong, with price realizations averaging 102% of WTI and 104% of NYMEX in the first quarter. We plan to run an average of 1.5 rigs in the play this year, delivering a 25-35 well program. This will grow our oil and condensate volumes to around 30,000 barrels per day, where we plan to maintain it for the remainder of the year. I'll now turn the call back to Brendan. Thanks, Greg, and thanks to our team who safely delivered another strong quarter, meeting or beating all our targets and delivering cash flow per share and free cash flow above consensus estimates. Our focus remains on maximizing efficiencies, generating significant free cash flow, and reducing debt. Our business is resilient thanks to the depth and quality of our inventory, our leading capital efficiency, the flexibility of our 25 program, and the strength of our balance sheet. Our focus on execution excellence, disciplined capital allocation, and driving profitability have put us in a position of strength, both for today's environment and for the future. This concludes our prepared remarks. Operator, we're now ready to open the line for questions. Thank you. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing star one. We will now begin the question and answer session and go to the first caller. First question comes from Arun Jayaram at J.P. Morgan. Please go ahead. Yeah, good morning, gentlemen. I wanted to ask around how you're thinking around full-year CapEx. If you use the midpoint of the 2Q guide, Ovintiv would have spent 54% of the total $2.2 billion budget in the first half. Just confidence on hitting your target because you'd have to downshift capital call to around $500 million a quarter in the back half of the year. Yeah, Arun, thank you for the question. You got the numbers right and full confidence. It is really completely an activity story, so this makes it really easy to follow that path. What you are seeing is a bit of an activity downshift off of the back of integrating the new Montney assets. We just dropped the rig that we inherited from the last rig that we inherited from Paramount. We just dropped that, so that is part of the capital deceleration that is happening. We had a little bit of Uinta capital that pre-closed that was in the Q1 number, so obviously that is gone. Then, because, as Greg pointed out, we are drilling those Montney wells already 10 days faster than the prior operator, that has meant some activity has pulled forward into Q2 in the Montney in particular, and it is purely an activity story. 100% confidence on the capital guide. In fact, what we'll be looking to do in this environment is find savings as we go through the year. Great. Follow-up is maybe for Greg. Greg, you highlighted your expectations for oil condensate production for each asset call: 120 in the Permian, 55 in the Montney, and around 30 in the Anadarko. Just maybe a question here. You delivered 24 KBD of oil condensate production in the Anadarko Basin, was a little bit below what we're modeling, and just kind of confidence to bring that up to 30 over the balance of the year. Yeah, thanks for the question, Arun. Yeah, your numbers are spot on for the Permian and the Montney. We'll be 120,000 barrels a day starting in the second quarter in the Permian. The Montney, we're at 55 today, and confident we'll be able to keep that flat. In the Anadarko, if you'll recall, the end of last year, we did not have any completion activity, so we picked up our completion crews in January, started completing wells, and started growing volumes through the quarter. Looking here into the most recent activity in April, we were at 28,000 barrels a day in that asset, and very confident we'll be able to grow that to 30 and keep it at 30 for the rest of the year. Very confident in the numbers. Teams are executing well. It has kind of gone as planned as far as that goes. Great. Thanks a lot. Thank you. The next question comes from Gabe Daoud at TD Cowen. Please go ahead. Thanks. Hey, morning, everyone. Appreciate the time. Brendan or Greg, maybe just curious if we could start in the Permian, I guess maybe following up a bit on Arun's question, but you guys have had a pretty good momentum there with volume significantly above what you consider the run rate of 120,000 barrels a day of oil and condensate. Just curious how you think Permian trends the rest of the year. I know one Q was pretty heavy from a turn-in-line standpoint, but just curious how much conservatism is maybe in that 120,000 barrel a day number. Yeah, I think Gabe, great question, and yeah, appreciate the acknowledgment of the strong Permian performance. Really, what's been driving that is really strong wells. What we're seeing is exactly what you described as a bit of an activity cadence story. With the 53 turn-in lines in Q1 stepping down to sort of more like a 27 ratable over the rest of the year, you just have a little bit of a production push in the first half of the year, and then that'll stabilize out at that 120. I would say to your question around conservatism, look, the wells have just been really strong. At a time when there's a lot of discussion, even this week, about productivity per foot and how is that going to trend across the Permian, but also the broader North American asset base, we're just thrilled that our team's continuing to find ways to innovate and drive productivity. I think that's very differentiating. Broadly speaking, we've been calling it the late middle innings of shale, and where you're seeing the geological degradation and the innovation has kind of been fighting to a draw really back to 2017. We're just starting to see the early erosion of type well performance broadly across the industry. What we think is happening is the leading operators are able to continue to use their private data sets, use their cultures and their expertise to drive productivity improvements, and then perhaps the more tier two, lower sophistication operators are struggling to keep up. You are seeing this bifurcation of performance. I think it is a real differentiation factor for us and something that is very valuable for our investors. For sure. For sure. Thanks, Brendan. That's helpful. I guess just follow-up would be a higher level question. Recent Canadian election. Curious if you could maybe give us your thoughts on how that may or may not impact your Montney operations. Thanks, guys. Yeah, no, appreciate it. Obviously, just had a federal election in Canada, just had the prime minister in D.C. yesterday, so watching that closely. I think there's just a tremendous opportunity for Canada here. Canada finds itself in a real moment to be able to grow its economy tremendously, and energy is going to be a huge foundational part of that. We're watching closely cabinet selections next week, so we'll get a chance to see how Prime Minister Carney fills out his leadership team. We just think there's several really key priorities that we'd love to see the Canadian government focus on to achieve that economic growth. The first one is market access. There's obviously tension between Canada and the U.S. today on trade, and Canada has the opportunity to enhance its market access, particularly for its energy products to the world, both gas and oil. We think that that should be a real priority for the new government. Regulatory reform and regulatory simplification, obviously a huge opportunity both in the U.S. and Canada, but that's something that Canada really needs to address from a competitiveness perspective that could really help. Also, just generally attracting investment. We obviously see the case and the opportunity for the resource in Canada. We made a big investment there earlier this year, and we think the new government can do a lot to attract investment to Canada that would be really exciting and really create economic growth for the country going forward. Thanks so much, Brendan. Appreciate your thoughts. Yeah, thanks, Gabe. Appreciate it. Thank you. Next question comes from Doug Leggate at Wolfe Research. Please go ahead. Good morning, guys. I appreciate the opportunity to get on. Brendan, I wonder if I could ask you about the relative outlook for oil and gas in terms of how it plays into your capital allocation. You walked through the inventory depth earlier, but if I put it to you that obviously we've got a lot of uncertainty around oil, depending whether or not Saudi has a bad day or not, but there is a constructive outlook for gas. How do you think then about relative capital allocation, particularly to the Anadarko? If I can elaborate just a little bit on my question, if the gas price outlook is better, how does that change your view of a decade of inventory? Does that number get higher if you had a different view on the gas price? I've got a quick follow-up on the balance sheet. Yeah. Yeah, maybe just take that last part first, Doug. Obviously, if we slowed oil—I think what your question was—if we slowed oil-directed drilling and shifted capital more towards gas, that would increase the oil duration, just the algebra of it. I think as far as how do we think about the capital allocation between gas and oil today, it still, for us, comes down to a fundamental question around growth first. Why I say that is we've been talking for a while now about the role of capital allocation and how we think about creating value for our shareholders. If we choose to put that capital towards an incremental rig line, whether it's oil or gas, we have to weigh that against the other option, which is to either reduce debt or buy shares back. Where we have been left and where we continue today is that it is a better cash flow per share outcome with less risk from a commodity perspective as well as the execution risk to just buy the shares back. That is a function of how we are valued today. We continue to see the right thing to do for our business is to stay in maintenance mode on both gas and oil. Should that evolve and change and the case for growth open up, for that gate to open up, then absolutely the optionality we have in the portfolio would be very valuable to choose between either gas or oil. In particular, on the Anadarko side, one of the things you like about our Anadarko asset is it is NYMEX effectively. I think the numbers were 102% of NYMEX realization in the quarter. So you get that torque to NYMEX pricing there. I guess I don't want to hog the call here, but I guess I was thinking more that if the gas price outlook is better than your base case, does the inventory depth defined at 10 years get bigger? On oil or gas, Doug? On gas. Our gas inventory is like 20-plus years, so. Yeah, sorry, I'll take it offline. I'm in the economics of the Anadarko, but we can come back to that. My follow-up is for Corey. And Corey, forgive me for this one because the question we get a lot is that your free cash flow outlook, we look at you on a DCF basis. So we kind of agree that there's no question your stock is undervalued. The question is, what do you do with that? What can you do about it? And when I hear CFOs talk about their balance sheet, they often talk about credit metrics, credit quality, debt to EBITDA. Very seldom do you talk about capital structure. And what I mean is your equity value is $8.5 billion, your debt's $5.5 billion, and the implied volatility of your equity as a consequence of that is arguably amplified, especially in a volatile commodity market. My question is, why buy back stock and not reset the capital structure towards equity, reduce the equity volatility, and re-rate the stock rather than using buybacks as a somewhat, I'd say, flawed perception of exploiting a dislocation in value? Yeah, I mean, your observations are correct. I mean, some of the metrics that we tend to point to intend to be a little bit simpler, kind of backward-looking, third-party. It is really just to simplify the conversation on a conference call. It is obviously much more nuanced than that, as you are pointing out. As we think about—and Brendan kind of alluded to this in the capital allocation conversation—look, we think there is room for both. Our position on our capital structure is, yeah, we would like to have less debt in there. We think our equity will accrete that value from debt reduction. I agree with you, but I also think at this level of free cash flow yield and the relative value in our stock, we have enough free cash flow to do both. We often get the question on the debate on is 50/50 the right place to be. We talk about it all the time, and we think that's a good spot to be because we're going to make progress on debt reduction, which I think Brendan highlighted the progress we made even from before the acquisition to today. I think you're right. It's probably just a little bit more simple as we describe it on a conference call and a little bit more nuanced as you have that debate every day. Appreciate you taking the question, guys. Thank you. Thanks, Doug. Thank you. Next question comes from Josh Silverstein at UBS. Please go ahead. Yeah, good morning, guys. Maybe just following up on the question before about kind of pausing activity. Given the operational efficiency gains that you guys have developed in the Permian via Trimulfrac, would pausing any portion of this kind of cause a bigger disruption? Meaning, does it not even make sense to stop just because of how much infrastructure you guys have there and kind of the flywheel stopping that, or a portion of that would hurt the rest of the program? Thanks. Yeah, Josh, I don't think it's so much the flywheel from an efficiency or an innovation perspective. It's more the free cash flow flywheel that's telling us, "Hey, don't pre-emptively shrink the business." Because we could cut capital this year and not have a huge outsized effect on this year's production. We could maximize free cash flow in 2025, but then we'd have a hole to fill in 2026. Our judgment is when we're earning really strong corporate rates of return on our investment today at these prices, when we're generating free cash flow that'll let us both reduce debt and buy shares back, it doesn't make sense to pre-emptively shrink the business at this commodity environment. We've got the ability to take that decision if we need to. Got it. In the Montney, can you talk through some of the long-term solutions you guys might be thinking on the gas side? Obviously, you have a good amount of capacity to get out, but do you just kind of see some of these bottlenecks coming every once a year, every other year, and something you have to deal with, or are there other solutions in place that you guys can work with? No, I think this one's a very unique one because of the startup of the LNG. This is the first LNG exports coming out of Canada. Lots of excitement, lots of producer activity drilling into it and preparing for it. I think this one is kind of a unique event as opposed to a recurrent event. Thanks, guys. Yeah, thanks, Josh. Thank you. Next question comes from Phillips Johnston at Capital One. Please go ahead. Hey, thanks for the call. Appreciate the comments about the very low free cash flow break-even oil price and the strong returns at $50. In a scenario where the macro does get worse and oil prices decline further, what price or what set of circumstances would, in fact, trigger a reduction in activity, and which area or areas would you look to cut first? Yeah, thanks, Phillips. The decision here is going to be based on the returns and free cash that's going to drive that decision. With today's setup, we're still delivering strong returns and free cash down to $50 WTI. Looking out, if we saw the market drop below that $50 level and it was likely to stay there for some time, more than a day or something, that's when we'd be driven to drop capital below that maintenance level. Okay, perfect. Then just looking at the Canadian gas volumes that are exposed to AECO, obviously that percentage steps up next year to around 40% or so. What's your outlook on the AECO market just over the next several years as LNG exports start to ramp up? Yeah, where we've been on this one is we feel like both Waha and AECO are fundamentally export markets. Canada's got the benefit of the LNG startup, which we think could have some tightening effect, but likely production just grows back into that new takeaway level. Our view has been to continue to diversify our market access away from AECO, and that's what you'll see us continue to do over time. Our team's been very busy at working on a variety of different options for us to do that, everything from some international gas pricing exposure, more gas into the West Coast and Chicago and Dawn markets that we already do, to some of the emergent opportunities for behind-meter projects and peaking projects locally in Western Canada. I think what you should expect from us over time is sort of a basket of diversification, and we think that's the right strategy for our AECO exposure. Sounds good. Thank you. Yeah, thanks, Phillips. Thank you. Next question comes from Neil Mehta at Goldman Sachs. Please go ahead. Yeah, thanks, Brendan and team. Just to build on those comments about local gas prices, just talk about how you're thinking about AECO and Waha pricing from here. As you show on slide 24, the business does have a lot of torque to gas prices and does not always get credit for it. I think one of the challenges is some of those local prices. Just how you're thinking about those specific markers would be helpful. Yeah, Neil, I think our view is to produce gas in those places and not sell gas in those places. I think our Q1 realization was 87% in NYMEX. I think that shows up in that outcome. The plan going forward is to continue to expose our investors to NYMEX or even greater than NYMEX prices and not leave them selling our gas at AECO and Waha. Yeah, yeah, makes sense. Then royalties, obviously, on the way up was a huge topic of conversation, but on the way down, it can cushion some of the volatility. Can you just talk about how the market should be thinking about that sensitivity north of the border? Yeah, no, absolutely. We do have a really good sensitivity slide in the appendix that'll kind of help you do the math, but you've got it captured. As condensate prices come down, that lowers our condensate royalties and helps cushion that cash flow effect of the lower prices on the Canadian business. It is a nice kind of risk feature on the way down. All right, thanks, Brendan. Yeah, thanks, Neil. Thank you. Next question comes from Kevin MacCurdy at Pickering Energy Partners. Please go ahead. Hey, good morning. Over the past few years, you've mostly emphasized your liquids-rich window of the Montney. Just given the changing pricing dynamics, is there a reasonable scenario where you would change that, or have you seen anything that would indicate your peers are pulling back in the liquids-rich area? Yeah, I think there are some signs of activity shift happening in Western Canada from the oilier parts, whether it's the oilier parts of the Montney or some of the other conventional oil plays in Western Canada. There are some signs that that activity is shifting down, just like it's shifting down in the Permian. I think what we're seeing is actually a relatively ordered behavior here where companies that were pursuing growth investments are pulling that capital back to maintenance. Companies that have got higher break-even prices in their assets are maybe even pulling back below maintenance level. For us, we were already at the maintenance level, and it makes sense for us to just kind of grind away on efficiency gains and use that to bolster free cash. I think we're seeing some of that shift away. Obviously, we're big believers in a multi-product portfolio. Looking back, it's clearly been a decade-plus for oil. We've had the view looking forward; it's much less clear: is this going to be a better decade to be in oil or a better decade to be in gas? It's a little less fundamentally clear to us. I think the right strategy, the best strategy for any MP company is to have very low break-even options in both. Thank you. Very good explanation. As a follow-up, just on the shareholder returns and the buybacks, would anything—commodity prices or in your share price—get you to move off that 50/50 split, for instance, leaning more into the buybacks if your shares got really disconnected from mid-cycle valuations? I think, look, I think there is a natural synergy between the two. Doug was asking this earlier: when you want to do buybacks is when the shares are low, and that happens to be typically when commodity prices are lower. We do think the balanced allocation today makes sense. Obviously, in a future scenario, we would continue to take a look at that, and we are not ideologically stuck in that spot, but today it continues to be the right allocation choice for our shareholders. Thank you. Yeah, thank you. Thank you. Next question comes from Kelly Akamine at Bank of America. Please go ahead. Hey, good morning, guys. I've got two here on the Montney. I guess first one, some operators have highlighted higher steel prices due to tariffs, and you're kind of in the unique position of having operations both inside the U.S. and in Canada. Can you talk to the lower well costs on the Paramount assets and address whether that could have some downside from lower steel prices? Yeah, hey, Kalei, great point. All the steel that we're buying and using in the U.S. is domestically sourced in the U.S. That is a good thing from a tariff perspective, but of course, there's going to be some bleed-through on domestic pricing. That is why we went ahead and pre-purchased that steel out through 2025 so we do not have that tariff exposure pressure on us today. On the Canadian side, of course, that is an opportunity because Canada has not got those tariffs on global steel imports. Absolutely, that is a possible tailwind differentially between the two. Got it. Second, I think you're importing U.S.-style completions into Canada, and therefore your well should be better than the previous operator. When do you think we'll start seeing your well design start to impact production? When you roll this program into 2026, do you think the capital program will be at a similar level? Yeah, I think as we've mapped the timeline out, we'll see the first TILs that are tip-to-tail, Ovintiv drill and complete. They'll kind of start to hit at the end of the third quarter. That's probably something we'll talk about on our third-quarter call. We're excited to do that. I would say how we do it is best ideas and best innovations win. We don't really care which side of the border they come from. We've got knowledge sharing and data and innovation happening on both sides and back and forth, and that lets us be at the leading edge on completion design, both in Permian and the Anadarko, but also in the Montney, certainly. Got it. Thanks, Brendan. Yeah, thanks, Kalei. Thank you. Next question comes from John Daniel at Daniel Energy Partners. Please go ahead. Hey, guys, thanks for including me. I got questions for you, Greg, on the Permian. The slide deck references the possibility of a spot crew. I'm just curious, when you bring those spot crews in, do you deploy them on Simulfrac and Trimulfrac work? If so, how does that performance typically track relative to the dedicated crew you guys have? Yeah, thanks for the question, John. We've had a long history of Simulfrac and Trimulfrac in the Permian with a number of operators. We've successfully performed both with, gosh, three or four different service providers. When we do get to tight spots in the schedule where we need to bring someone else in, we really do not see a significant change in our productivity. We're able to quickly shift over and Simulfrac or Trimulfrac with a third-party provider. That being said, we're continually working with our Zeus fleet to try to reduce cycle time there and make that as efficient as possible so that we do not need spot crews. Ideally, now that we've worked through the backlog of ducks, we'd like to get to a point where we're four rigs, one Trimulfrac crew year-round, which we think is a good combination. No real change when we're shifting to other service providers. There's still a lot of good high-quality service providers we can use out there in the Permian. Fair enough. Thank you for that. Just one follow-up, just looking at the Permian efficiency metrics in Q1. I do not know if you guys are willing to provide forward guidance on this, but how do you expect them to evolve over the course of this year? Can you remind me what they were back half of last year? That is it for me. Thank you. Yeah, I think if you're just talking in pure cost efficiency, John, I think you've seen us come down over $50 a foot there year over year. Pretty significant improvements. I know lots of discussion around how much more can that come. Clearly, these do not get easier with time, but I think what we're seeing is the opportunity really accruing to the sophisticated operators that have built the culture and the expertise to drive innovation, but then have also built the private data sets to work off of. If you think about anything digital today, it is working off of a private data set, and we've really focused on building a unique and deep private data set that helps us drive some of these efficiencies. I think some of the decisions that we've been making around how to capture resource at the right price, how to not destroy the premium resource by cherry-picking it or upspacing it. We've been in cube development mode for a long time. Some of the things we've been doing on the innovation side, like Trimulfrac, and then some things we're doing to drive single-bit runs and really the fastest drilling pace in industry, those are all representative or examples, I guess, of that overall approach. I land in the spot of optimism on further efficiency gains. I think maybe it's not quite the same pace as the last five years, but I don't think we're done. Okay. I appreciate you guys giving me a chance to ask a question. Yeah, thanks, John. Thank you. At this time, we have completed the question-and-answer session, and we'll turn the call back over to Mr. Verhaest. Thanks, Joanne, and thank you, everyone, for joining us today. Our call is now complete. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.