Ovintiv Inc. (NYSE:OVV) Q2 2024 Earnings Call Transcript

Ovintiv Inc. (NYSE:OVV) Q2 2024 Earnings Call Transcript July 31, 2024

Operator: 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. [Operator Instructions]. 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.

Jason 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.

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 10 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.

Corey Code: 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.

Greg Givens: Thanks, Cory, and good morning. Our second quarter well performance was strong across the portfolio. In particular, we saw strong well productivity in the Permian where we produced oil and condensate volumes of 123,000 barrels per day. With the addition of our previously planned sixth rig in the play, our second quarter turn-in lines totaled 42 gross wells, approximately double the number of wells we brought on in the first quarter. As you can see in the chart on Slide 10, the wells are tracking above our 2024 type curve. The dash line on the chart shows all of the 122 wells we’ve brought online since the fourth quarter. As you can see, our well performance continues to paint the 2024 type curve, which is higher than our 2023 well results, incorporating all of the improved well productivity we achieved last year.

We remain fully confident in our ability to deliver our ’24 type curve in the Permian, which is unchanged from the start of the year. These gains are hard fought and the result of multiple stacked innovations. As our industry continues to mature, we expect to see a divergence in well performance between those operators who embrace innovation and technical complexities and those who continue to pursue the status quo. We continually push the boundaries of the efficiency frontier to execute our programs faster and with less capital, making the business more profitable. The same group of wells that exceeded our type curve for productivity also delivered some impressive pacesetter results on drilling and completions in addition to well cost. We drilled our fastest well in the quarter, a 10,500-foot lateral in less than 6 days.

When looking at our program average our Permian drilling speed in the first half of the year was roughly 10% faster than our 2023 program. On completions, our fastest second quarter pad average was about 4,800 feet per day. To put this in perspective that equates to pumping just over GBP 14 million of sand per day. Our year-to-date Trimulfrac wells were completed about 30% faster than our average speed in 2023 at an industry-leading 4,200 feet per day. On a total program basis, year-to-date we’ve completed roughly 20% more feet per day than our 2023 program average. These cycle time improvements mean that we continue to drive our well costs lower. Our pacesetting Permian well an 11,500-foot lateral had a D&C cost of about $600 per foot, in line with the lowest well cost in the basin.

Some of our longer laterals have delivered even better cost performance. Ovintiv remains an industry leader in the Midland Basin in several key categories including Trimulfrac, wet sand, drilling speed, supply chain and logistics management. Our outstanding performance is driving the strong capital efficiency you see in our business today. We also continue to see top drilling and completions metrics in the Montney where in the first half of the year we delivered an average of 1,750 feet drilled per day and over 4,275 feet completed per day, a speed similar to our Trimulfrac averages in the Permian. The Montney has the lowest well cost in the portfolio and our team delivered a pacesetter D&C well cost of less than 500 feet per quarter — sorry, $500 per foot in the quarter.

We are also bringing on some highly productive wells. During the quarter, our 11-well 15 of 28 Pipestone pad delivered initial rates well above expectations and is projected to exceed type curve by 8% over the first 12 months. Our low well cost, superior well productivity and strong price realizations for both condensate as well as natural gas meaning that the economics in our Montney wells remain outstanding. Assuming $75 WTI and $2.50 NYMEX gas, we expect our Montney to generate a program level IRR of more than 60%. Our Montney gas realized 129% of AECO and 72% of NYMEX in Q2 on an unhedged basis. This is thanks to our physical transportation arrangements to markets in Eastern Canada, Chicago, California and the Pacific Northwest. Our second quarter oil and condensate price realization was also robust at 94% of WTI.

As Corey mentioned, our second quarter production in the play exceeded our expectations. We brought on 33 net wells produced 34,000 barrels of oil and condensate and 1.2 Bcf per day of natural gas. On the condensate side, the outperformance was due to strong well productivity and some acceleration of turn-in lines. While on the natural gas side, we saw about 100 million cubic feet per day of outperformance due to well performance, post-maintenance flush production and a favorable royalty adjustment. The outperformance was specific to the second quarter and largely onetime in nature as we expect Montney condensate volumes to track closer to the 30,000 barrels per day in the back half of the year. Our performance in the Montney continues to demonstrate the expertise of our team and our leadership position in the play.

Across numerous key metrics, Ovintiv screens is the top of the peer group. We have the best capital efficiency on both a BOE basis and on oil and condensate basis, coming in 50% to 60% better than the peer average. 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 place since 2023. We are confident in our ability to continue delivering well results in the play, generating superior asset level returns and unmatched capital efficiency. Moving to the Uinta. Our significant scale and running room in the play continue to differentiate Uinta from our in-basin peers. With over a decade of well inventory, ample takeaway capacity and margins similar to that of 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 bring constrained production back online for the duration of the second quarter. Our oil and condensate volumes totalled 28,000 barrels per day. We brought on 7 net wells and now have more than half of our 2024 turn-in lines online. Our drilling program in the Anadarko began in April which is now well underway. We expect to begin bringing those wells on through the third and fourth quarters. We are targeting the oiliest parts of our acreage to leverage the strong oil performance we saw in 2023, where the wells displayed first year oil cuts of more than 55% with about 85% of first year revenue coming from oil. Our oil and condensate volumes totalled 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. I’ll now turn the call back to Brendan.

Brendan McCracken: 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.

Q&A Session

Operator: 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.

Neal Dingmann: My first question for you, Greg, really on Slide 10 and on like that on the Permian performance specifically. Could you just talk about those 42 second quarter wells? Obviously, it held up very, very well. Just wondering anything different that — on the D&C side there. And then can you remind me just sort of generally where those wells were drilled versus kind of where plans are for the remainder of the year?

Brendan McCracken: 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.

Greg Givens: Yes. Thanks for the question, Neal. And 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 quarter 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.

Neal Dingmann: Greg, and maybe my follow-up for you as well. Just one on you or even Brendan, if you want to jump in, just on completions now not just the Permian, but maybe top overall. Just wondering what percent is broader side is used in Trimulfrac. And also what — are you fully going to I guess you call it sort of that the sand binder sand conveyor when we were out there seeing it on site. Is that what you’re using on every pad now. So I’m just wondering from sort of the completion side. Have you gone to — is that more of the standard out to you all?

Greg Givens: 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 the well cost and the results we’re getting are industry leading. And that’s just our focus on innovation and continuous improvement and just really proud of the teams and how well they’re executing right now.

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

Arun Jayaram: Yes. Good morning. I have a follow-up on Slide 11, maybe to Brendan and Greg. I was wondering if you could give us a sense of what you’re baking in, in terms of drilling and completion efficiency gains and if you came to the decision where cycle times continue to maybe outperform your expectations, Brendan, would you be in the camp of producing more at the same level of CapEx or trending CapEx down and to — not to increase production even above what you raised this morning.

Brendan McCracken: Yes. I would 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. And so what we 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 baked in everything we’ve got. And 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.

Arun Jayaram: 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?

Brendan McCracken: Yes, for sure, Arun. So look, I think reflect in 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. And the result is we’ve created a business that’s really a proven free cash generator. And we’ve been using that free cash to both return cash to shareholders through buybacks but also importantly, through reducing our leverage. And that puts 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 think that’s really an important feature for us.

And you look at what we’ve done, 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. And 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 the way along and so that leaves us in a place where prosecuting our strategy means really focused on getting better, not just on getting bigger.

Arun Jayaram: Great. Thanks a lot.

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

Josh Silverstein: Good morning guys. Bren, just sticking with the improving the 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 we’re addressing that impact the current shareholder return profile of 50% post base dividend?

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

Corey Code: 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. So 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.

Brendan McCracken: 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 the way 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.

Josh Silverstein: 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 guys positioning for the improving outlook in both Will you want to open up some more exposure to AECO, allocates 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?

Brendan McCracken: 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. And you mentioned the startup of Trans Mountain being an incremental tailwind to those fundamentals. And we continue to see the need for significant condensate imports into Western Canada to supply that diluent demand from the oil sands producers. And so we see that premium pricing staying intact. On the condensate side and then on the AECO side, we’re probably in the cautious camp. So 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, I gas resource in Canada. And so 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. And so our strategy continues to be to price diversify on the gas side and get market access to multiple downstream markets for our Canadian gas. And 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 in and that’s great as well. But I think long term, we continue to believe in diversifying away from the Western Canadian market.

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

Neil Mehta: Yes very 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?

Brendan McCracken: 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. And so we’re probably in the mid-30s on a decline rate across the whole portfolio. And 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.

Greg Givens: 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. And that’s allowed us to flatten that decline. But 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.

Neil Mehta: 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?

Brendan McCracken: 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. And so 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. And so that could be a big driver one way or the other. And I would say, generally, our view here is probably fairly consensus, which is given the activity levels that we’re seeing across industry, there’s some potential for deflation bias probably rather than inflation given the market dynamics. But look, we got to get through that work and really understand that before we make anything declarative. And then really, the other is continued efficiency capture.

And 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. So 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.

Neil Mehta: Thanks, Brendan.

Brendan McCracken: Yes. Thanks, Neil.

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

Douglas Leggate: Hi, guys. Thanks for taking my question. Brendan, I know there’s no precision here, and we 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?

Brendan McCracken: Yes, I really appreciate the question, Doug, and it’s quite an insightful question. The — 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. And remember, the premium designation we use is a well that can deliver a rate of return higher than 35% and at a price deck of $55 WTI and 275 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. And so that is the sort of 10 to 15 in cutoff that you’re talking about. And 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. And so buried in those two things that I just told you is that we’re delivering a higher program return and 35% today. And so the question or the transparency that we’re trying to answer for our investors is, hi, how long can the business continue to deliver that return that you’re generating today? And so 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.

Douglas Leggate: 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.

Brendan McCracken: Yes. Thanks, Doug. Yes, I really appreciate that one as well. That 15 to 28 pad is tracking above our 24 program type curve. And just like what you saw in the Permian, we’ll see statistical distribution around that type curve mean in the Montney. And so what we’re really trying to highlight there is, hi, why was your Q2 production so strong relative to plan and relative to 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. And so we would expect, I think best way to plan the business is for us to continue to perform at that type curve over the rest of the year. And 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. .

Douglas Leggate: Terrific. Thanks so much, guys

Brendan McCracken: Yes. Thanks Doug.

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

Gabe Daoud: 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?

Brendan McCracken: Yes. I’ll flip that to Greg to fill in.

Greg Givens: 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. And so 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. So, we’re pretty close to our run rate there in the Permian, but we feel like somewhere there just under 120 is probably a rate that we’re going to flatten out at over time for this type of activity rate.

Brendan McCracken: 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. And then 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.

Gabe Daoud: 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 pacesetters representing the new go-forward D&C figures for those two plays? Thanks guys.

Brendan McCracken: Yes. I think the perspective we’ve been taking on this we like to live in the world of — this is what we’re delivering today and you don’t have to believe in some future story, but these are the results you’re seeing today. And then I think the relentless drive we have is to try and always be converting those pacesetters into averages over time. And we like the track record of what we’ve been able to do on that front. And I think it’s more of a stay tuned as we proceed through the rest of this year and into next. But excited about what the team is delivering there on the leading edge.

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

Greg Pardy: Yes. Thanks, good morning. And 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?

Brendan McCracken: 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. And it’s also very undeveloped. So over 80% of our acreage position in the core of the play is undeveloped. And really what the team has done, the teams really delivered that it’s pretty impressive what they’ve accomplished on both market access, but also well productivity and well cost. And 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.

So 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 in the maintenance level, so this outlook of 205,000 barrels a day we would see the Uinta stay pretty flat in that. And so 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. So I would expect it to stay pretty stable as we head through the back of this year and into ’25.

Greg Pardy: Okay. All right. That makes a lot of sense. And then maybe just follow-up. I thought — I heard Greg say that there was a onetime royalty adjustment in Montney in 2Q. And I’m just wondering how much of a volumetric impact that would have had.

Brendan McCracken: Yes. It’s probably — I’ll just give the headline and then Greg can fill in on the nature of the adjustment. But it’s probably about 3/4 of the gas outperformance in 2Q, which was about 100 million a day extra. But maybe Greg can just give a little more color on what drove that royalty adjustment.

Greg Givens: Yes. Thanks, Brendan. And that’s spot on. Of the 100 million a day, about 75% of that was the royalty adjustment. And there’s two things that go into that. One, as we see lower commodity price, the we were on a sliding scale royalty system in Canada. So with lower commodity price, we actually pay lower royalty to the crown and that means that we get to keep of the net production for ourselves. So 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 proceed by the average producer in the basin in previous quarters, and that was lower than we had projected. And so that caused a onetime adjustment there. So 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.

Brendan McCracken: And 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. And then the other thing to just 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.

Greg Pardy: Understood. Thanks very much.

Brendan McCracken: Thanks, Greg.

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

Roger Read: 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?

Brendan McCracken: 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. But kick you to Greg on some of the things the team is doing on LOE.

Greg Givens: 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 cost and labor is a big there on the LOE side. So 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. And those things together allow us to keep the wells up more and generate more production. And that while keeping the absolute cost flat, if you’re able to generate more production as you observe, then you get a lower unit metric. But really just a great job of blocking and tackling from all the teams across all four of the place.

Brendan McCracken: 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. And so — we’ve got about 80% of our summer power needs in the Permian there at firm prices, so forward price that are advantaged relative to current market. And so 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.

Roger Read: 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.

Brendan McCracken: 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. But 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, they’re I don’t think there’s any spoiler alert here that there will need to be more in the future, but good to see this one coming. And I think for us, just we’re well insulated on the gas takeaway side at the moment and — but helpful to have more infrastructure in the basin for sure.

Roger Read: Great. Thank you.

Brendan McCracken: Thank you.

Operator: Next question comes from Kalei Akamine from Bank of America.

Kalei Akamine: 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. And whether this asset, which isn’t consuming a lot of capital is actually a core use of your portfolio.

Brendan McCracken: Yes. Great question. Yes, really pleased to see the Anadarko performance. And 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. And so we’ve got a relatively small capital program, but maintaining a big free cash flow base. And 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. And so 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 probably makes sense to just have them stay pretty stable in the portfolio over time.

Kalei Akamine: I appreciate that. My next question is also on the 25 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.

Brendan McCracken: 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. So 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.

Kalei Akamine: I appreciate it. Thanks, McCracken.

Brendan McCracken: Yes. Thank you.

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

Nitin Kumar: 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. And 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 time line look like on some of those?

Brendan McCracken: Yes. Appreciate it. And then I mean, us that your danger here is that we’re going to talk your ear off on this stuff for too, too long. So I’ll try and be concise. But I think I would sort of highlight a couple of 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. And so we’ve really set ourselves up to be able 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. So that’s the first one.

And then 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. And then 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. And so 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. So 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 and all of 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. And 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. So that’s really the — like I said, I could go on and on, but that’s my most concise version of that discussion.

Nitin Kumar: 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. And I just want to talk about the long-term hedging as you approach that 1x net debt-to-EBITDA target, do you expect to see less hedges being in place? Or is this just something part of the DNA of Ovintiv? And how do you think about long term?

Brendan McCracken: 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. But I think how you’re seeing this show up and making the company better 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. And so that’s the relentless pursuit that we’re after with those innovations. So yes, hopefully, I didn’t cloud that with my engineering details. But to your hedge question, I think what we’ve always maintained, and I think it continues to be our perspective on it is we’re hedging to manage against the risk of a protracted period of very low prices.

And as our debt comes down as you’re seeing it do, our need for those hedges goes down as well. And so I would expect us to be in a place where we can kind of ratchet those hedges back as we approach that leverage objective with time. But 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 as well. But in general, that hedge program should dial back as we approach that leverage target.

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

Brendan McCracken: Yes, you bet. And thank you.

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

Geoff Jay: 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?

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

Geoff Jay: Okay, great. Thanks. That’s helpful. I appreciate it.

Brendan McCracken: Yes, thanks, Geoff.

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

Dennis Fong: 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? And then 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 land that you target either from acquisition or swaps?

Brendan McCracken: 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. And 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. So when one of our offsetting peers try something new and it either works or doesn’t work. We work really hard to learn from what those peers are learning because it’s their risk dollars that went into that learning and like I said, it’s an infinite rate of return, whether it worked or didn’t. And so because we’re in multiple basins, we could do that across an even bigger peer set. And then the other feature that we work really hard on is transporting ideas across each of those basins and asset teams and we’ve really created an internal environment where those ideas are flowing really easily and naturally across the teams.

And that lets us do things like achieve basin-leading frac performance in the Permian, up to 4,800 feet per day. And do the exact same thing in the Montney and really rapidly within several quarters, get to that efficient frontier in both places. And so really excited about that skill that we’ve built. And then we do see quite a bit of innovation difference across the basins. It’s remarkable, actually, how much idea trapping happens across these basin boundaries. And that’s just advantage us 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. And we really think that is related to this culture of sharing and innovation that we’ve built across the asset teams.

Dennis Fong: Great. Thanks, and appreciate the context. I’ll turn it back.

Brendan McCracken: Thanks, Dennis.

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

Jason Verhaest: Thanks, Joanna, and thanks everyone for joining us today. Our call is now complete.

Operator: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.