Ovintiv Inc. Q2 FY2024 Earnings Call

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2024 Second 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. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Thanks, Joanna, and welcome everyone to our second quarter 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'll be available to take your questions. I will now turn the call over to our President and CEO, Brendan McCracken.

Good morning. Thank you for joining us. We announced another strong quarter yesterday. We're pleased to continue our track record of industry-leading execution. Most importantly, we continue to be relentless at converting our execution into bottom line financial results and delivering superior and durable returns for our shareholders. We've been seeing the benefits of our culture of innovation showing up in our results for quite some time now. We're on track to generate 60% more free cash flow per share this year largely because of the efficiency gains and value creation that our innovations have unlocked. For us, innovation is more than simply applying the latest technology to our operations. It is a mindset within our organization. It influences the way we approach challenges and manage complex operational objectives. We've been very deliberate in our efforts to cultivate this over time, and it is delivering tangible results. Ensuring the durability of returns requires a deep inventory of premium drilling locations. Our multiyear strategy of both organic and inorganic inventory extension has added about 1,650 premium locations to our portfolio, delivering a huge boost to our full cycle returns and the durability of our business. The combination of execution, inventory depth and capital discipline is driving the strong capital efficiency you see in our business today, and it is showing up in our financial results as we make sure our operational gains flow through to higher returns. We are raising our annual production guidance once again, and we remain on track to generate approximately $1.9 billion of free cash flow even as realized prices are settling lower than last quarter. We delivered net earnings of $340 million and cash flow of just over $1 billion, beating consensus estimates. Our cash flow beat was driven by both production and cost outperformance as we exceeded the top end of our production guidance ranges on both oil and natural gas, and we came in at the bottom end of the guidance range on combined TMP and LOE costs. We generated free cash flow of $403 million, 60% of which we will return to our shareholders through our base dividend and share buybacks during the third quarter. With our increased production guide, we're set to deliver more production for the same amount of capital. Our full year oil and condensate volumes will average about 208,000 barrels a day, while our capital guidance midpoint is unchanged at $2.3 billion. This is 8,000 barrels a day higher than our original 2024 outlook. Our 2024 program is repeatable in '25 and beyond, allowing us to sustain approximately 205,000 barrels a day of oil and condensate production with capital investment of about $2.3 billion for the next seven to ten years, assuming flat commodity prices. This outcome reflects our leading capital efficiency and the depth of our premium inventory. I'll now turn the call over to Corey.

Thanks and good morning. As Brendan mentioned, we had a very strong operational performance in the second quarter with every item coming in at or better than our second quarter guidance midpoints. Total production came in above the high end of guidance, averaging 594,000 BOEs per day. We achieved this while coming in below the midpoint on capital. Crude and condensate production was strong across all four assets in the quarter. Permian, Uinta and Anadarko crude and condensate levels were all above our internal expectations and Montney demonstrated significant outperformance of about 4,000 barrels per day ahead of plan. Our track record of shareholder returns continued through the quarter. We returned $262 million through share buybacks of $182 million and base dividends of $80 million. This represents a competitive cash return yield of approximately 8%. Since the inception of our buyback program in the third quarter of 2021, through the second quarter of 2024, we've repurchased 37 million shares and distributed approximately $800 million in base dividend payments for total shareholder returns of about $2.5 billion. In the third quarter, as per our shareholder returns framework, we will pay dividends of approximately $80 million while repurchasing shares worth $162 million and allocating $162 million to the balance sheet. We reduced debt by more than $100 million during the quarter and our 12 months trailing leverage ratio was 1.2x. We continue to make progress towards optimizing our capital structure, decreasing our leverage and reducing interest expense. We have lowered our go-forward quarterly interest expense guidance by $10 million to reflect our lower debt levels. We remain committed to our mid-cycle leverage target of 1x or about $4 billion of debt, assuming mid-cycle prices. The maturity profile of our bonds will allow us to optimize our debt paydown schedule over the next couple of years as we work towards that target. Our continuous improvement in capital efficiency will allow us to generate additional cash flow and reach our debt target sooner. This bolsters the resiliency of our business and enables us to withstand market volatility. We remain investment-grade rated with a stable outlook from all four credit rating agencies. Capital efficiency remains a primary focus for us as we work to efficiently convert our inventory into cash flow and generate consistent durable returns for our shareholders. Assuming full year average crude prices of $80 WTI oil and a NYMAX natural gas price of $2.25, we are on track to generate about $1.9 billion of free cash flow. This is about $750 million more than last year. Third quarter production is set to average between 565,000 and 580,000 BOEs per day, with oil and condensate volumes of about 206,000 barrels per day at the midpoint. We expect third quarter capital investment to come in around $550 million at the midpoint and we remain very comfortable with the midpoint of our full year guide at $2.3 billion. We also updated our cash tax guidance for the year with expectations of lower cash taxes. In the U.S., this is driven by greater certainty around certain tax attributes from last year's Permian acquisition. In Canada, lower natural gas prices resulted in a lower cash tax outlook. Additionally, as we mentioned last quarter, the resolution of a legacy legal matter will result in one-time recovery of approximately $150 million that we plan to allocate to debt reduction. We expect to receive the cash in late 3Q and 4Q with minimal cash tax impact. Between this and the roll-off of our REX pipeline commitment in May, we will realize about $250 million of cash savings this year from the cleanup of legacy items. I'll now turn the call over to Greg, who will speak to our operational highlights.

Thank you, Cory, and good morning. Our second quarter well performance was strong across the portfolio. Notably, we experienced robust well productivity in the Permian, achieving oil and condensate production volumes of 123,000 barrels per day. With our previously planned addition of a sixth rig, we completed 42 gross wells in the second quarter, nearly double the count from the first quarter. As illustrated in the chart, the wells are performing above our 2024 type curve. The chart also shows all 122 wells we've brought online since the fourth quarter. Our performance continues to align with the 2024 type curve, which surpasses our results from 2023, reflecting improved well productivity from last year. We are fully confident in our ability to achieve our 2024 type curve in the Permian, unchanged from earlier this year. These advancements result from multiple innovations. As the industry matures, we expect to see differences in well performance between operators who embrace innovation and those who maintain the status quo. We are constantly pushing the efficiency frontier to execute our programs more quickly and at lower costs, enhancing profitability. The same group of wells that exceeded our type curve for productivity also yielded impressive results in drilling and completions as well as in well cost. We drilled our fastest well in the quarter, a 10,500-foot lateral in less than six days. Our average drilling speed in the Permian's first half of the year was about 10% quicker than our 2023 program. In completions, our fastest second-quarter pad average reached roughly 4,800 feet per day, which translates to pumping over $14 million of sand each day. Year-to-date, our Trimulfrac wells were completed approximately 30% faster than our 2023 average at an industry-leading 4,200 feet per day. Overall, we've completed about 20% more feet per day than our 2023 program average. These cycle time enhancements are helping us drive down well costs. Our standout Permian well, an 11,500-foot lateral, had a drilling and completion cost of approximately $600 per foot, matching the lowest well costs in the basin, with some longer laterals even yielding better cost performance. Ovintiv remains a leader in the Midland Basin across several key categories like Trimulfrac, wet sand, drilling speed, and supply chain management. Our strong performance is driving superior capital efficiency for our business. We are also achieving top drilling and completion metrics in the Montney, where we averaged 1,750 feet drilled per day and over 4,275 feet completed per day in the first half of the year, comparable to our Trimulfrac averages in the Permian. The Montney possesses the lowest well cost in our portfolio, with our team delivering a standout D&C well cost of less than $500 per foot this quarter. We are also bringing highly productive wells online. During the quarter, our 11-well 15 of 28 Pipestone pad significantly exceeded initial rate expectations and is projected to be 8% above type curve over the first 12 months. Our low well costs, superior productivity, and strong price realizations for condensate and natural gas yield excellent economics for our Montney wells. Assuming $75 WTI and $2.50 NYMEX gas, we anticipate our Montney to generate a program-level IRR of over 60%. In Q2, our Montney gas realized 129% of AECO and 72% of NYMEX on an unhedged basis, due to our effective transportation arrangements to markets in Eastern Canada, Chicago, California, and the Pacific Northwest. Our second quarter oil and condensate price realization was robust at 94% of WTI. As Corey mentioned, our second quarter production exceeded expectations, bringing on 33 net wells with production of 34,000 barrels of oil and condensate, and 1.2 Bcf per day of natural gas. The strong performance in condensate resulted from exceptional well productivity and some acceleration in turn-in lines, while natural gas outperformed by about 100 million cubic feet per day due to well performance, post-maintenance flush production, and a favorable royalty adjustment. This outperformance was primarily specific to the second quarter and is largely one-time, as we expect Montney condensate volumes to align more closely with 30,000 barrels per day in the second half of the year. Our Montney performance showcases our team's expertise and our leadership position in the play. Across several key metrics, Ovintiv consistently ranks at the top of the peer group. Our capital efficiency is 50% to 60% better both on a BOE basis and an oil and condensate basis compared to peers. Our spud to rig release time is 50% faster, we are drilling 20% longer laterals, and we have drilled 13 of the top 15 wells in the play since 2023. We are confident in our ability to continue delivering outstanding well results, generating superior asset-level returns, and unmatched capital efficiency. Regarding the Uinta, our significant scale and running room in the play set it apart from local peers. With over a decade of well inventory and sufficient takeaway capacity, along with margins similar to those in our Permian operations, the Uinta is a unique and highly competitive part of our portfolio. The refinery turnarounds in Salt Lake City were completed at the end of the first quarter, allowing us to resume constrained production throughout the second quarter. Our oil and condensate volumes reached 28,000 barrels per day. We brought on seven net wells and now have over half of our 2024 turn-in lines operational. Our drilling program in the Anadarko commenced in April and is progressing well. We plan to begin bringing those wells online in the third and fourth quarters, focusing on the oiliest parts of our acreage. The wells have demonstrated first-year oil cuts exceeding 55%, with about 85% of first-year revenue derived from oil. Our oil and condensate volumes totaled 27,000 barrels per day in the quarter. With the lowest base decline rate and a modest development program this year, the Anadarko continues to generate significant free cash flow.

Thanks, Greg. So our team continues to build on our track record of execution. We once again met or beat all our targets, generated cash flow per share and free cash flow per share above consensus. Maximizing the capital efficiency and the profitability of our business continue to be key areas of focus across our organization. Our industry-leading efficiencies and our strong culture of innovation are truly differentiating against a maturing resource backdrop. We are well positioned to deliver superior durable returns to our shareholders through our focus on operational excellence, disciplined capital allocation and responsible operations. This concludes our prepared remarks. Joanna, we're now ready to open the line for questions.

Thank you. We will now begin the question and answer session and go to the first caller. First question comes from Neal Dingmann at Truist Securities. Please go ahead.

My first question for you, Greg, is regarding Slide 10 and the performance in the Permian specifically. Can you elaborate on the 42 wells from the second quarter? They performed exceptionally well. I'm curious if there’s anything different on the drilling and completion side. Additionally, could you remind me where those wells were drilled compared to the plans for the remainder of the year?

Yes. That's great, Neal. I appreciate that question. I'll turn it over to Greg here. We brought on over twice as many wells in the second quarter versus the first quarter. So that really kind of gives now a statistical data set to look at year-to-date and really what you're seeing is a consistent D&C approach with the wells, both geographically, but also just how we've been completing them and drilling. But I'll turn that over to Greg to fill in some of the details there.

Yes. Thanks for the question, Neal. And we really didn't do anything different in the second quarter than we did in the first. We're completing the wells the same way. As Brendan mentioned, we do have wells both in the first and second quarters scattered throughout the whole of our acreage position, both on our legacy acreage and on the acquired incap acreage. So we're just seeing the results of what we would expect to see with an average type curve. Some of the wells come in slightly above the curve. Some of them come in slightly below curve. But on average, we're very confident in our ability to deliver that type curve and we feel very comfortable that we're going to deliver on it for not only the rest of this year but years to come, as we think it's a great way to talk about how our program is going to deliver going forward.

Greg, I have a follow-up question for you, or maybe Brendan wants to chime in. I'm curious about completions, not just in the Permian but overall. What percentage of the broader side is being utilized in Trimulfrac? Additionally, are you fully using the sand binder and sand conveyor at every pad now? I'm trying to understand if this has become your standard approach for completions.

Yes. Thanks for that, Neal. And yes, in the Permian, we are continuing to execute on Trimulfrac. It will make up just over half of our completions this year. We're using the wet sand from the local sand mines being delivered to location and using the sand piles that we pioneered in the Permian over the last few years. So all of that is what's allowing us to have these industry-leading results. It's just our focus on efficiency, logistics, and our supply chain management as well as partnering with some really solid industry players to help us deliver these fracs. As we think about the other plays in the portfolio, they're also seeing very good completion cycle times in the Montney, while it's a different play. So we have a different stage architecture there. The focus on efficiency and innovation is the same as we have in the Permian. In the Permian, we're leaning on completing multiple wells at the same time to improve our cycle time. While in the Montney, we're looking at a real-time frac optimization to tailor the treating schedules to each well to optimize our efficiency there. But in all cases, we feel like our cycle times, well cost, and the results we're getting are industry leading. That's just our focus on innovation and continuous improvement, and I'm really proud of the teams and how well they're executing right now.

Thank you. Next question comes from Arun Jayaram at JPMorgan. Please go ahead.

Good morning. I have a follow-up question regarding Slide 11, perhaps for Brendan and Greg. Could you provide insight into the drilling and completion efficiency gains you are considering? If cycle times continue to exceed your expectations, Brendan, would you prefer to maintain production at the same level of capital expenditure, or would you consider reducing capital expenditure without increasing production beyond what you mentioned earlier today?

Yes. I'd love the question, Arun, and love the momentum that the team is creating here. Really with our guidance for the rest of this year and the outlook that we've given for '25 and beyond, what they reflect is all the known efficiency gains that we've captured to this point. And really what the pacesetters reflect is what's the future potential. What we've baked in is the knowns. And where we'd love to do is continue to see the efficiency gains that we've seen over the last several years continue to show up, and so we'll address that in future guidance and annual plans as we roll them out. But to date, we've baked in everything we've got. What we're highlighting with the pacesetters is that it's physically possible to do even better than the leading efficiencies that we've captured so far.

Great. And my follow-up, Brendan, is just on the M&A climate continue to see a pretty active A&D market in the Permian Basin. Specific question there is, as you are aware, a large Midland Basin trade that apparently is coming with Double Eagle I think OVV and others have been kind of mentioned in the press. But I was wondering if you could comment about how you think about future A&D in the Permian post the uncap transactions and just any thoughts. Is there any credibility to some of these reports?

Yes, for sure, Arun. So look, I think reflecting on how we've been prosecuting this durable return strategy, it's really let us get ahead of the competition and deepen our inventory ahead of some of the price escalation that we've seen in the market. The result is we've created a business that's really a proven free cash generator. We've been using that free cash to both return cash to shareholders through buybacks and also importantly, through reducing our leverage. That puts us in a place today where we can be really disciplined and really just focused on executing the portfolio that we've got. One of the things we're really pleased to see in this quarter is leverage moving in the right direction. We've highlighted the 1,650 inventory locations since 2021 through a whole series of actions, including the organic renewal to do that. Really shows that we've got a track record to build that portfolio and make our company better. The now 20% capital efficiency gain that we're seeing year-over-year, I think is a great proof point of that. To your question, lots of consolidation speculation. One thing I'd highlight, it's maybe more of a hidden trend, but it's something we think is actually really important over time, what we're seeing is that the leading operators really continue to get more technically sophisticated. The way that's happening, the sort of avenues that are driving that, it's really hard to catch up if you haven't been stacking these innovations across your business all along and so that leaves us in a place where prosecuting our strategy means really focusing on getting better, not just getting bigger.

Great. Thanks a lot.

Thank you. Your next question comes from Josh Silverstein at UBS. Please go ahead.

Good morning, guys. Bren, just sticking with the improving balance sheet outlook. You do have a $600 million maturity coming up next year. Just curious what the latest thinking is to address that and whether it's going to impact the current shareholder return profile of 50% post-base dividend?

Yes. Josh, yes, thanks for the question. I'll kick it to Corey to talk about that maturity in '25.

Yes, good morning Josh. I think the outlook we have for free cash flow puts us in a good spot where we can handle it within our existing framework. That's a main maturity. So we've got a fair amount of time before that. We're not committing to whether we have to refinance it or put it on our credit facility, but we do have enough free cash flow, we can make a pretty significant dent in that just organically.

And then on the capital allocation framework, Josh, what I'd say there is we've been really clear, we're using free cash to drive down that leverage towards the 1x target at mid-cycle prices. And I think sitting here today, as we make that progress, it makes sense to stay in that 50-50 model. And then once we get to that is probably a good time to take a look at what should it change? Is it anything different? And I would just highlight, we've always said it's been in the program all along. It's at least 50% of free cash flow going back to shareholders. So I think as we approach and get to that 1x leverage, that will be the time to take a look at that.

Great. And then maybe looking at the Montney, there's some changing pricing dynamics up in Canada for condensate and AECO with the start-up of TMX and LNG Canada. How are you positioning for the improving outlook in both? Will you want to open up some more exposure to AECO, allocate more capital to the condensate window? How are you thinking about the plan for, I guess, maybe back half of this year and into next year?

Yes. Thanks, Josh. Really unchanged on the allocation front. So we're going to continue to allocate our capital to the condensate window. And really what's underneath that is, we believe strongly the fundamentals for condensate to remain a premium product in Canada are very much intact. You mentioned the startup of Trans Mountain being an incremental tailwind to those fundamentals. We continue to see the need for significant condensate imports into Western Canada to supply that diluent demand from the oil sands producers. So we see that premium pricing staying intact. On the condensate side. On the AECO side, we're probably in the cautious camp. We're very excited and looking forward to seeing LNG Canada start up. We think that is going to be a real positive for Canada and Montney gas producers, but it's probably not a structural game changer to AECO pricing relative to NYMEX. And that's just because there's a lot of gas resources in Canada. Even taking that incremental 2 Bcf a day offshore to international markets is going to be helpful, but probably not a long-term rerate of AECO. Our strategy continues to be to price diversify on the gas side and get market access to multiple downstream markets for our Canadian gas. Right now, we're in a really great position there with substantially all or close to all of our Canadian gas being priced outside of AECO. That's clearly a good thing in the current market, and we think long term, the right move. There might be transient periods where AECO tightens, and that's great as well. But I think long term, we continue to believe in diversifying away from the Western Canadian market.

Thank you. Next question comes from Neil Mehta at Goldman Sachs. Please go ahead.

Yes. Good morning, team Brendan. Just want to talk about the base decline rates in the portfolio. You talked about that in the context of the Anadarko. But in general, we've seen them continue to move lower on a BOE basis. So can you talk about what you're seeing across the portfolio that's enabling that and the sustainability thereof, across the four different spaces you operate?

Yes, maybe I'll kick it to Greg to talk about some of the great things that our team has been doing to drive that. But this is a combination of both active base production management by our team, but also as we have stayed in this maintenance level mode over time, you get a declining decline rate, a drop in decline rate just as that production base matures and you get further out on the type curves for more wells in the mix. We're probably in the mid-30s on a decline rate across the whole portfolio. Then the notable exception, which you highlighted, was the Anadarko, which is actually now well under 20% on the base decline. But over to Greg on some of the specifics of how we're getting that.

Yes. Just thanks for your question. I really just want to complement the teams on what a great job they've done just doing the daily blocking and tackling that it takes to keep these wells on and minimize decline as well as minimizing things like frac interference. That was one of the big we benefited from with our in-cap transaction. We were able to spread out the activity across that acreage footprint, which the previous operators were not able to do. That's allowed us to flatten that decline. It's also the actions of the team things like routine break fix, optimizing artificial lift, avoiding downtime and just really planning and executing their business well and doing that across the portfolio, all of the assets, we're seeing a flatter base decline year-over-year and just anticipate those guys continuing to work to flatten those base declines.

Thanks. The follow-up is just on '25. I recognize it's early. But if I think about CapEx, you're at $2.25 billion to $2.35 billion this year, call it $2.3 at the midpoint. What are the puts and takes as you think about 2025 capital that we should be keeping in the back of our minds?

Yes. I think obviously, the one that's live right now, Neil, that we're in the midst of doing is our price discovery from the service sector. That will be a really important next couple of months here as we get all of that in place and really understand how pricing is shaping up for '25. That could be a big driver one way or the other. Our view here is probably fairly consensus, which is given the activity levels that we're seeing across the industry, there's some potential for deflation bias probably rather than inflation given the market dynamics. We got to get through that work and really understand that before we make anything declarative. The other is continued efficiency capture. Can we continue to drive some of the gains that we've seen over the last several years that have resulted in a pretty substantial enhancement to our capital efficiency? When we put all of that in the basket today, net-net, what we're steering people to is this outlook of $2.3 billion, holding the 205,000 barrels a day of crude and condensate flat year-over-year. And that's the best way to be thinking about the business as we work through the next several months.

Thanks, Brendan.

Next question comes from Doug Leggate at Wolfe Research. Please go ahead.

Hi, guys. Thanks for taking my question. Brendan, I know there's no precision here, and I like to pretend that the risk, but I want to hit your comment about the 7 to 10 years, $2.3 billion I seem to recall at the time of the EnCap deal, we were talking about, we've addressed the inventory issues we've got in front of it. Timing, obviously, the deal was fantastic, given everything that was going on. But the 7 to 10 years, I thought it was probably a 15 plus. Can you help reconcile the gap from?

Yes, I really appreciate the question, Doug, and it's quite an insightful question. What we're trying to draw a distinction there too is from a total premium inventory we've definitely shifted ourselves into that ideal window of 10 to 15. Remember, the premium designation we use is a well that can deliver a rate of return higher than 35% at a price deck of $55 WTI and $2.75 NYMEX. So it's a pretty high bar to be able to do that. We deliberately hold, call it, a conservative view of that mid-cycle price just to create a discipline in how we think about that inventory depth. The sort of 10 to 15 in cutoff that you're talking about. Then what we're highlighting with the 7 to 10 million is if you take our current capital efficiency, this idea of can you hold 205,000 barrels a day for $2.3 billion of capital. With our current cost structure, current capital efficiencies, what we're seeing is we have an inventory that would be able to do that for 7 to 10 years. Buried in those two things is that we're delivering a higher program return and 35% today. The transparency we're trying to illustrate for our investors is how long can the business continue to deliver that return that you're generating today? When we compare that across the industry, that screens really well compared to how we see peers setting up from an inventory quality and current capital efficiency perspective. So that's the transparency we're trying to illustrate for our investors.

Very clear. Thanks for that answer, Brendan. My follow-up is a quick one. It's Slide 12. I'm just curious if you can you don't really talk much about the well performance and the improvements you've seen in the Montney. I'm wondering if this was just an isolated area or if there is any read through to the broader portfolio quality, if you like, as this type curve seems to be outperforming your legacy wells in Montney. I'll leave it there.

Yes. Thanks, Doug. Yes, I really appreciate that one as well. That 15 to 28 pad is tracking above our 24 program type curve. Just like what you saw in the Permian, we'll see statistical distribution around that type curve mean in the Montney. What we're really trying to highlight there is, why was your Q2 production so strong relative to plan and guidance and on the back of two things, the 15 to 28 pad performance as well as accelerating some of the onstreams in the Montney in the quarter. We would expect, I think the best way to plan the business is for us to continue to perform at that type curve over the rest of the year. I would just say this is part of the relentless drive to keep making the business better. If the team can continue to find ways to drive completion design that gives us a better type curve, we'll bake that into future guides. But for now, the type curve we've got there is the right one for the full year.

Terrific. Thanks so much, guys.

Yes. Thanks, Doug.

Thank you. Next question comes from Gabe Daoud at TD Cowen. Please go ahead.

Thanks. Morning, everyone. And thanks for taking my question. I was maybe hoping to get a little more color around the Permian and whether or not the current equipment level and just call it, 130 net tools a year, if that holds current volumes of 123,000 barrels a day of crude and conde flat more or less from here?

Yes. I'll flip that to Greg to fill in.

So yes, we're on track for the same number of TILs that we've been guiding to. But as you recall, as we came off the EnCap transaction, our rate was quite a bit higher than our long-term run rate. The first quarter, I believe it was around 130 in the Permian, 123 this quarter. It will continue to down slightly as it levels out in that 115 to 120 range. We're pretty close to our run rate there in the Permian, but we feel like somewhere just under 120 is probably a rate that we're going to flatten out at over time for this type of activity rate.

Maybe, Gabe, just to fill in across the portfolio there, what we'd expect to see through the back half of the year is the Montney sit around 30,000 barrels a day, the Uinta and the Anadarko both sit in the high 20s, respectively. The balance coming out of the Permian, which, as Greg said, probably just underneath 120 to get to that second half guidance that we've put out.

Thanks, Brendan. Thanks, Greg. That's helpful. And then maybe as a follow-up, you talked about the 2.3 billion capital number, obviously, but just curious, at the asset level, you did highlight some pretty attractive pace setters from a D&C standpoint in Midland and the Montney. Just curious, can you talk a little bit about confidence levels in those pace setters representing the new go-forward D&C figures for those two plays? Thanks, guys.

Yes, we believe in focusing on what we are currently delivering, and you can see the results today without having to rely on future projections. Our goal is to consistently turn those top performers into averages over time, and we are proud of our track record in this area. I encourage you to stay tuned as we move through the rest of this year and into next year. We are excited about what our team is achieving at the forefront.

Next question comes from Greg Pardy at RBC Capital Markets. Please go ahead.

Yes. Thanks, good morning. I'd really echo the strong execution again in this quarter. I wanted to come back just to the intent. I guess my question is, is it core? And can you perhaps give us a sense as to how large that segment becomes maybe from a production standpoint over the next few years?

Yes. Greg, thank you. Yes, look, we really like the Uinta. It's been on an incredible trajectory over the last year where we've doubled production and just a couple of things that are really important about the Uinta is very oily. So over 80% oil on a BOE basis. It's also very undeveloped. Over 80% of our acreage position in the core of the play is undeveloped. The teams have really delivered it. It's pretty impressive what they've accomplished on both market access, but also well productivity and well cost. Where that's put us is where the returns and the margins that we're generating in the Uinta are really competitive with the Permian, so competitive with one of the best plays in North America from a return and margin perspective. Pretty excited about what's going on. I think the way to expect from a trajectory perspective is for us if we keep the company at maintenance level, so this outlook of 205,000 barrels a day we would see the Uinta stay pretty flat in that. That would be in the high 20s for barrels a day, and we think that's the right place to settle that one in. We have the ability to grow it if we choose. But if we're not growing the total company production, there's not a motive to be growing into the expense of any of the other assets. I'd expect it to stay pretty stable as we head through the back of this year and into '25.

Okay. That makes a lot of sense. I have a follow-up question. I thought I heard Greg mention there was a one-time royalty adjustment in Montney in the second quarter. I'm curious about the volumetric impact that might have had.

Yes. I will provide the main point first, and then Greg can elaborate on the nature of the adjustment. It is likely about three-quarters of the gas outperformance in the second quarter, which amounted to approximately 100 million extra per day. Perhaps Greg can offer more details on what influenced that royalty adjustment.

Yes. Thanks, Brendan. That's spot on. Of the 100 million a day, about 75% of that was the royalty adjustment. There are two things that go into that. As we see lower commodity prices, the we were on a sliding scale royalty system in Canada. With lower commodity prices, we actually pay lower royalty to the crown and that means that we get to keep of the net production for ourselves. That caused a good portion of the beat, but we also had a prior period adjustment where we went back and looked at the actual prices being received by the average producer in the basin in previous quarters, and that was lower than we had projected. So that caused a one-time adjustment there. I'd say probably 1/3 of the adjustment was due to low prices in the quarter and then the PPA made up the rest.

Just to close that out, Greg, what that effectively means is there weren't more gross BTUs produced. We just got to keep more of them as a result of the split between us and the royalty owner. Another thing to recall back is that we've not allocated capital to growing gas production. That's just an associated gas stream that's coming out of our condensate investments.

Understood. Thanks very much.

Thanks, Greg.

Thank you. Next question comes from Roger Read at Wells Fargo.

Good morning. How are you? I just wanted to come back on some of the LOE guidance. I mean, understandable that volumes probably come down here in the second half of the year. So some of the LOE increase on a per unit of production going up makes sense. But I was just curious, is there anything else we should be watching? Or as you think about the range of LOE, how much is controllable and how much is just going to be volume driven?

Yes. Thanks, Roger. I'll kick it to Greg to talk about some of the specifics here that we're some of the things we've been doing to make cost control on the LOE really show up in the results. But you've hit on the big feature, which is a little bit of the per unit effect on the production. Kick you to Greg on some of the things the team is doing on LOE.

Yes. Thanks for the question. And again, just really proud of the job the teams have done to push back on. We've seen general deflation on the capital side of our business. But on the expense side, the costs have been really pretty sticky due to high labor costs and labor is a big factor there on the LOE side. The teams have done a great job just minimizing the break/fix work, keeping their wells up and online more and doing a great job with automation. We've got our operations control centers. That we use to monitor the wells to predict when they're going to come offline and then respond quickly when they do come offline. Those things together allow us to keep the wells up more and generate more production. While keeping the absolute cost flat, if you're able to generate more production, as you observed, then you get a lower unit metric. Just a great job of blocking and tackling from all the teams across all four of the plays.

One of the things I'll just highlight, and we've mentioned it before, but we did remove a lot of the summertime risk to high power prices in the Permian, which we identified as a risk factor coming into this year. We've got about 80% of our summer power needs in the Permian there at firm prices, so forward prices that are advantaged relative to the current market. That's another feature. The team did a nice job of getting out in front of and managing the potential for some cost inflation in our LOE structure.

I appreciate that. And the other question I had was just sort of a follow-up in the Permian. With the Matterhorn pipeline kicking off this quarter, any sort of immediate impacts that you would expect out of that?

I mean the most immediate impact will be the impact of Waha pricing, where we have a small amount of exposure. It doesn't have a huge revenue influence when you think about it from the corporate perspective. We do have a little bit of Waha gas exposure that we inherited with the uncap assets that we acquired last year. So that's probably the most immediate effect, Roger. But otherwise, just good to see another piece of pipe infrastructure built out of the Permian. I don't think there's any spoiler alert here that there will need to be more in the future. We're well insulated on the gas takeaway side at the moment but helpful to have more infrastructure in the basin for sure.

Great. Thank you.

Thank you.

Thank you. Next question comes from Kalei Akamine from Bank of America.

Hi, guys. Good morning. My first question is on the Anadarko. Brandon, you had mentioned that the '24 program is repeatable going forward in that program this year, the Anadarko declines, granted with an improving base. But wondering when that assay plateau is at the current activity set. Whether this asset, which isn't consuming a lot of capital, is actually a core use of your portfolio.

Yes. Great question. Yes, really pleased to see the Anadarko performance. We're really at that point now where it's stabilized out in that high 20s on the crude and condensate rate, and that would be the kind of going in starting point for our '25 program. We've got a relatively small capital program but maintaining a big free cash flow base. That's the tremendous role that the Anadarko asset is playing in our portfolio today, very capital efficient. The returns compete heads up with each of the other three assets in the portfolio. We'll do the work here over the next several months to figure out exactly the right activity level in '25, but we think it's probably going to be in a maintenance level just like what we described earlier on the Uinta where now that we've got those two programs pretty balanced on scale and performing very well on returns. It probably makes sense to just have them stay pretty stable in the portfolio over time.

I appreciate that. My next question is also on the 2025 program, which is going to be repeated this year. In the Permian, you guys recently added a six rig, and I suppose you'll keep that running for '25. So wondering if we're setting up for a more capital-efficient program because there looks to be some room for non-D&C capital to sort of roll on '25.

Yes. Sitting here today with the efficiency gains that we've captured, I mentioned earlier the sort of basis of the forward look captures all the known efficiency gains that we've got in hand today. We probably can back off of that sixth rig pace and hold the Permian flat in '25. I don't want to get too far over our skis on the '25 program because that's really a work in progress internally at the moment. But that's where the numbers would shake out today if we looked at the TILs, just the sort of thousands of feet we need to bring on stream in '25, you wouldn't need six full rigs all year. So that could be sometime in '25, we make that pivot back from six to five.

I appreciate it. Thanks, McCracken.

Yes. Thank you.

Thank you. Your next question comes from Nitin Kumar at Mizuho. Please go ahead.

Hi, good morning, Brendan and team. Thanks for taking my questions. Brendan, I wanted to circle back on something you said about addressing M&A about getting better and not bigger. You alluded to some technologies wondering if you could maybe give us a little bit more color on are you talking about expanding recovery, expanding zones or other technologies? And what's the timeline look like on some of those?

Yes. I appreciate it. If there's any danger here, it's that we're going to talk your ear off on this stuff for too long. I'll try and be concise. I would highlight a couple things. One has been the approach we've been taking on data and really being focused on building out a private data set that is quite unique, both in scope and specificity for some problems and challenges that we're trying to get after with our innovations. We've set ourselves up to work using that private data set and get some really unique inferences into what's going to drive cost reductions but also what's going to drive well productivity over time. That's the first one. The other features that we've talked a bit about before, particularly on the completion design front, the things we're doing in the stage architecture, the things we're doing with frac fluids to drive oil recovery. On the real-time optimization that Greg mentioned earlier, I think those continue to be the three channels that we're seeing great returns on our efforts. When you look at how these innovations unspool over time, the feature that we think is maybe a bit new in the last few years is how these things are stacking together. How things that we can do today with Trimulfrac are really rooted in things we figured out how to do a couple of years ago, with wet sand and sand piles in the real-time optimization stuff and how that pairs with the fluid chemistry and the rock fabric work that we're doing in the labs. All this stuff is kind of really feeding together into an understanding of an entire system and how to optimize that entire system. That's great because what it means is there's a real sense of momentum that can be built. It also, I think, is a way for companies like ours to see differentiation where you can drive relative return performance that's differentiated from competitors. That's my most concise version of that discussion.

Got it. I guess what I was trying to get at is at some level, and it's been asked in different ways on the call, it's a matter of scale as well. And this certainly makes you better and helps you drive more margin out of the barrel, but how does it make you get more reserves, I guess, what I was trying to get at. Just as my second question, I wanted to understand, we saw you add some hedges in the quarter. I want to talk about the long-term hedging as you approach that 1x net debt-to-EBITDA target, do you expect to see fewer hedges being in place? Or is this just part of the DNA of Ovintiv? How do you think about long term?

Yes. Let me come to the hedges in a sec, but I just want to circle back to your earlier point, and perhaps that was too wonkish in my explanation. What you're seeing is type curves are higher year-over-year and costs are lower, and free cash generation is up 60% per share. That's how you're seeing all that cumulative effect of all of that flow through to the bottom line for our shareholders. That's the relentless pursuit that we're after with those innovations. To your hedge question, I think what we've always maintained, and I think it continues to be our perspective, is we're hedging to manage against the risk of a protracted period of very low prices. As our debt comes down as you're seeing it do, our need for those hedges goes down as well. I would expect us to be in a place where we can sort of ratchet those hedges back as we approach that leverage objective with time. Today, we're managing it with a hedge program that's plus or minus 20% to 25% of volumes and using 3-way structures that give us that price floor that we're looking for, but also retain exposure to the upside. That hedge program should dial back as we approach that leverage target.

Great. Well, thanks for the patience in answering my questions.

Yes, you bet. Thank you.

Thank you. Next question comes from Geoff Jay at Daniel Energy. Please go ahead.

Hey, guys, real quick one for me. In terms of the difference, I guess, between sort of the average to date D&C cost by basin and the pacesetter D&C costs. Is there service cost deflation in those figures or is that pure efficiency?

Those are just pure efficiency. Yes. So they're side-by-side on service costs, apples-to-apples there.

Okay, great. Thanks. That's helpful. I appreciate it.

Yes, thanks, Geoff.

Thank you. And the next question comes from Dennis Fong at CIBC. Please go ahead.

Hi. Good morning, and thanks for taking my question. Most of the other questions I had came from other analysts, but I did have one that kind of jogged my memory with one of the previous questions asked. Can you talk towards some of the understanding that you have of the basins you operate in, especially with a focus on data? How does that potentially kind of further inform or revise the way that you adopt best practices, either in operations, cost savings, well productivity, or even lands that you target either from acquisition or swaps?

Yes. Thanks, Dennis. Yes, I love that question. I think we try and really harness the advantage of being in several of these really high-quality basins. The saying we have around here is the only infinite rate of return project we are aware of is learning from somebody else's capital. When one of our offsetting peers tries something new and it either works or doesn't, we work really hard to learn from what those peers are learning because it's their risk dollars that went into that learning. It's an infinite rate of return, whether it worked or didn't. Because we're in multiple basins, we could do that across an even bigger peer set. The other feature that we work really hard on is transporting ideas across each of those basins and asset teams. We've really created an internal environment where those ideas are flowing really easily and naturally across the teams. That lets us do things like achieve basin-leading frac performance in the Permian, up to 4,800 feet per day. Do the exact same thing in the Montney and really rapidly within several quarters, get to that efficient frontier in both places. Really excited about that skill that we've built. We do see quite a bit of innovation difference across the basins. It's remarkable how much idea trapping happens across these basin boundaries. That just gives us an advantage because we showed that with the Montney slide where you can see pretty large differences in outcomes across a relatively small group of concentrated peers. We really think that is related to this culture of sharing and innovation that we've built across the asset teams.

Great. Thanks, and appreciate the context. I'll turn it back.

Thanks, Dennis.

Thank you. At this time, we have completed the question-and-answer session. I will turn the call back over to Mr. Verhaest.

Thanks, Joanna, and thanks 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.