Ovintiv Inc. (DE)

Good day, ladies and gentlemen, and thank you for standing by. Welcome to OVNTIV'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 1. For members of the media attending in a listen-only mode today, you may quote statements made by any of the OVNTIV 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 expressed consent of OVNTIV. I would now like to turn the conference call over to Jason Verheist from Investor Relations. Please go ahead, Mr. Verheist.

Jason Verheist, Investor Relations Thanks, Joanna, and welcome everyone to our first quarter 25 conference call. This call is being webcast and the slides are available on our website at ovntiv.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 CDAR+. 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 NIMEX 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 to 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 montany for Uintah 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 NIMEX gas. Now, assuming $60 WTI and $3.75 NIMEX 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 NIMEX for the rest of the year, we still expect to generate $1 billion 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 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 concurrently. All of our Canadian condensate is sold locally in Alberta and is not subject to tariffs, and 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 E&P. 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 BOEs 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 planned to 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 $60.375 NIMAC 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. We're 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 quarter, our debt to cap ratio is 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've 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 motney 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 radical level of activity for the remainder of the year with four rigs and one frat 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 travel fracked 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 money, 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 reflected in the strong initial well results we are seeing on this acreage. Our three most recent paths 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 event of -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 the first quarter due to the timing of the acquisition flows, but from now through the end of the year, we expect our run rates 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 a Montney condensate was 95% of WTI. We have 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 completion 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 well cost and 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 have 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 am incredibly proud of the team and I am 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 NIMEX in the first quarter. We plan to run an average of 1.5 rigs in the play this year, delivering a 25 to 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. The first question comes from Arun Jayaram at JP Morgan. Please go ahead.

Yeah, good morning gentlemen. I wanted to ask around how you're thinking around for your CAPEX. If you use the midpoint of the 2Q guide, OVB would have spent 54% of the total $2.2 billion budget in first half. Just confidence on hitting your target because you'd have to 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's really completely an activity story. This makes it really easy to follow that path. What you're seeing is a bit of an activity downshift off of the back of integrating the new Montney assets. We just dropped the last rig that we inherited from Paramount. We just dropped that, so that's part of the capital deceleration that's happening. We had a little bit of you into capital that pre-closed that was in the Q1 number, so obviously that's gone. Then because, as Greg pointed out, we're drilling those Montney wells already 10 days faster than the prior operator, that's meant some activity has pulled forward into Q2 in the Montney in particular. It's purely an activity story, so 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 Antidarko. Just maybe a question here. You delivered 24 kBD of oil condensate production in the Antidarko basin. It was a little bit below what we're modeling, and just confidence to bring that up to 30 over the balance of the year.

Yeah. Thanks for the question, Arun. 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 Antidarko, if you'll recall, the end of last year, we didn't 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 so 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's kind of gone as planned as far as that goes. Great. Thanks a lot.

Thank you. The next question comes from Gabe Daud at TD Cowan. Please go ahead.

Thanks. Hey, morning, everyone. I 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. 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 1Q was pretty heavy from a -the-line standpoint, but just curious how much conservatism is maybe in that 120,000 barrel a day number?

Yeah, I think, Gabe, great question. I appreciate the acknowledgement of the strong Permian performance. Really what's been driving that is really strong wells. What we're seeing is exactly what you described is a bit of an activity cadence story. With the 53 turn-in lines in Q1, stepping down to more like a 27 rateable 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 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, where you're seeing the geological degradation and the innovation has 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. Then perhaps the more tier two lower sophistication operators are struggling to keep up. You're seeing this bifurcation of performance. I think it is a real differentiation factor for us and something that is very valuable for our investors.

Sure. Thanks, Brendan. That's helpful. I guess this 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 mining operations. Thanks, guys.

Yeah, no, appreciate it. Obviously just had a federal election in Canada, just had the prime minister in DC yesterday. 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 are next week. 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 US 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 US and Canada, but that's something that Canada really needs to address from a competitiveness perspective that could really help. Then 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, I appreciate your thoughts.

Yeah thanks Gabe, appreciate it.

Thank you. Next question comes from Doug Leggett at Wolf 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 Anadarco? 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 for on the balance sheet.

Yeah, maybe just take that last part first. Doug, obviously if we slowed oil, I think 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've been left and where we continue are today is that it's 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's a function of how we're valued today. We continue to see the right thing to do for our business to stay in maintenance mode on both gas and oil. Should that evolve and change in the case for growth to open up, for that gate to open up, then absolutely the optionality we have in their 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's NIMEX effectively. I think the numbers were 102% of NIMEX realization in the quarter. You get that torque to NIMEX pricing there.

I guess I don't want to hold 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 define that 10 years get bigger?

On oil or gas, Doug?

On gas.

Well, our gas inventory is like 20 plus years.

I'll take it offline. I meant the economics of the Anadarko, but we can come back to that. My follow-up is for Cory. Cory, 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. We agree that there's no question your stock is undervalued. The question is what do you do with that and what can you do about it? 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. What I mean is your equity value is 8.5 billion, your debt is 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 rerate 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. Some of the metrics that we tend to point to are intended to be a little bit simpler, kind of backward looking, third party. It's really just to simplify the conversation on a conference call. It's obviously much more nuanced than that, as you're pointing out. As we think about, and Brendan kind of alluded to this in the capital allocation conversation, look, we think there's room for both. Our position on our capital structure is yeah, we'd like to have less debt in there. We think our equity will agree that value from debt reduction. I agree with you, but I also think at this level of free cash flow yield and 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. It's a little bit more nuanced as you have that debate every day.

I 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 the question before about kind of pausing activity, given the operational efficiency gains that you guys have developed in the permeability of each primal crack, would pausing any portion of this kind of cause a bigger disruption, meaning like 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 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 innovation perspective. It's more the free cashflow flywheel that's telling us, hey, don't preemptively shrink the business because we could cut capital this year and not have a huge outsized effect on this year's production. So we could maximize free cashflow in 2025, but then we'd have a hole to fill in 2026. So 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 cashflow that'll let us both reduce debt and buy shares back, it doesn't make sense to preemptively shrink the business at this commodity environment. But we've got the ability to take that decision if we need to.

And then, and then, Bonnie, 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, something you have to deal with or are there other solutions in place that you 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, so lots of excitement, lots of producer activity drilling into it and preparing for it. So I think this one's kind of a unique event as opposed to a recurrent

event. Thanks, Josh. 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 cashflow breakeven oil price and the strong return to S50. In a scenario where the macro does get worse and 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 is going to drive that decision. And so with today's setup, we're still delivering strong returns and free cash down to $50 WTI. So 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, then that's when we'd be driven to drop capital below that maintenance level.

Okay, perfect. And then just looking at the Canadian gas volumes that are exposed to obviously that percentage steps up next year to around 40% or so. What's your outlook on the ACO 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 ACO are fundamentally export markets. And so 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. And so our view has been to continue to diversify our market access away from ACO, and that's what you'll see us continue to do over time. So our team's been very busy working on a variety of different options for to do that. Everything from some international gas pricing exposure, more gas into the west coast in Chicago and Don markets that we already do, to some of the emergent opportunities for behind meter projects and pet chem projects locally in western Canada. So I think what you should expect from us over time is a sort of a basket of diversification. And we think that's the right strategy for our ACO 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 price, just talk about how you're thinking about ACO and Waha pricing from here. You know, as you show in I-24, the business does have a lot of torque to gas prices and doesn't always get credit for it, but I think one of the challenges, some of those local prices, so just how you're thinking about those specific markers would be helpful.

Yeah, Neil, I think, you know, our view is to produce gas in those places and not sell gas in those places. And so I think our one queue realization was with 87% of NYMEX, so I think that shows up in that outcome. And so the plan go forward is to continue to expose our investors to NYMEX or even greater than NYMEX prices and not leave them, you know, selling our gas at ACO and Waha.

Yeah, makes sense. And 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. So can you just talk about how the market should be thinking about the sensitivity north of the border?

Yeah, no, absolutely. And we do have a really good sensitivity slide in the appendix that it'll kind of help you do the math, but you've got it captured. So as condensate prices come down, that lowers our condensate royalties and helps, you know, cushion that cash flow effect of the lower prices on the Canadian business. So 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 McCurdy at Pickering Energy.

Please go ahead.

Hey, good morning. Over the past few years, you've mostly emphasized your liquids-rich window of the Montney. Just, you know, 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's some signs of activity shift happening in Western Canada from the oilier parts, whether it's the oilier parts of the Montney or the some of the other conventional oil plays in Western Canada. There's some signs that that activity is shifting down, just like it's shifting down in the Permian. You know, 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. And then, you know, for us, we were already at the maintenance level. And so it makes sense for us to just kind of grind away on efficiency gains and use that to bolster free cash. So 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. And, you know, 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. And so I think the right strategy, the best strategy for an EMP company is to have very low break-even options in both.

Thank you. Very good explanation. And as a follow-up, just on the shareholder returns and the buybacks, would anything, you know, in commodity prices or in your share price get you to move off that 50-50 split, you know, for instance, you know, leaning into more into the buybacks if your shares got really disconnected from mid-cycle valuations?

Yeah, I think, you know, look, I think there's a natural synergy between the two. And, you know, Doug was asking this earlier is the, when you want to do buybacks is when the shares are low, and that happens to be when commodity, typically when commodity prices are lower. And so we do think the balanced allocation today makes sense. Obviously, in a future scenario, we continue to take a look at that and we're not, you know, 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 Callie Ackermine

at Bank of America. Please go ahead.

Hey, good morning, guys. I've got two here on the Motney. 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 cost and the paramount assets and address whether that could have some downside from lower steel prices?

Yeah, hey, Clay, you know, great, great point. You know, all the steel that we're buying and using in the U.S. is domestically sourced in the U.S. That is, you know, a good thing from a perspective, but of course there's going to be some bleed through on domestic pricing and so that's why we went ahead and pre-purchased that steel out through 25 so we don't have that tariff exposure pressure on us today. And then on the Canadian side, of course, you know, that's an opportunity because Canada hasn't got those tariffs on global steel imports. So absolutely, that's 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? And 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 tills that are tip to tail of into drilling complete, they'll kind of start to hit at the end of the third quarter. So that's probably something we'll talk about on our third quarter call. So we're excited to do that and, you know, 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. And so, you know, we've got knowledge sharing and data and innovation happening on both sides and back and forth. And that lets us be on the leading edge on completion design, both in the Fermi and in the Anadarko, but also in the Montney, certainly.

Got it. Thanks, Martin. Yeah, thanks, Clay.

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 a possibility of a spot crew. And I'm just curious, when you bring those spot crews in, do you deploy them on simulfrac and trimulfrac work? And if so, how does that performance typically track relative to the dedicated crew you guys have?

Yeah, thanks for the question, John. And, you know, 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. And so when we do get to tight spots in the schedule where we need to bring someone else in, we really don't 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 don't 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. So, but 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. And then just one follow-up, just looking at the Permian efficiency metrics in Q1. I don't 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? And can you remind me what they were back half of last year? And that's it for me. Thank you.

Yeah, I think, you know, if you're just talking the pure cost efficiency, John, like I think you've seen us come down over $50 a foot there year over year. So, you know, pretty, pretty significant improvements. I know, you know, lots of discussion around like how much more can that come and, you know, clearly, you know, these don't 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. You know, if you think about, you know, anything digital today 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, you know, not destroy the premium resource by cherry picking it or upspacing it. You know, we've been in cube development mode for a long time. And then some of the things we've been doing on the innovation side, like Triomal Frac, and then some things we're doing to drive, you know, single bit runs and, you know, really the fastest drilling pace in industry. Those are all representative or examples, I guess, of that overall approach. So, I land in the spot of optimism on further efficiency gains. I think, you know, maybe it's not quite the same pace as the last five years, but I don't think we're done.

Okay. Well, 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. Barheist.

Thanks, Joanna. 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.