Ovintiv Inc. (NYSE:OVV) Q1 2024 Earnings Call Transcript

Ovintiv Inc. (NYSE:OVV) Q1 2024 Earnings Call Transcript May 8, 2024

Ovintiv Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv’s 2024 First Quarter Results Conference Call. As a reminder, today’s call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions]. Members of the media attending in a listen-only mode today, you may quote statements made by any of Ovintiv representatives or members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express 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 first 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 SEDAR+ and EDGAR. Following prepared remarks, we will be available to take your questions. I’ll now turn the call over to our President and CEO, Brendan McCracken.

Brendan McCracken: Good morning. Thank you for joining us. Our team has carried our momentum from last year into 2024 with every item at or ahead of our first quarter guidance midpoints. We delivered net earnings of $338 million, free cash flow of $444 million and cash flow per share of $3.80, beating consensus estimates. We’ve raised our full year production guidance, which will see us deliver oil and condensate volumes of about 206,000 barrels per day, while leaving our capital guide unchanged at $2.3 billion at the midpoint. Our 2024 oil and condensate capital efficiency now reflects a 19% gain compared to our original pre-acquisition 2023 guide. The combination of strong productivity across the portfolio, our leading capital efficiency and stronger oil price environment have raised our expectations for 2024 free cash flow from $1.6 billion to $1.9 billion, roughly $750 million more than last year with similar volumes and less capital spend.

This will allow us to deliver enhanced returns to our shareholders and accelerate debt repayment. As we highlighted in February, we also added 65 premium 10,000-foot equivalent locations in the Permian through three bolt-on transactions at an average cost of less than $3 million per location. These inventory additions are immediately competitive for capital, and are contiguous with our existing acreage in the core of the Midland Basin. Our multiyear disciplined strategy of both organic and inorganic inventory extension has added about 1,650 premium net 10,000-foot locations to our portfolio, delivering a huge boost to our full cycle returns and the durability of our business. We believe our 2024 program is highly repeatable in 2025 and beyond, reflecting our leading capital efficiency and the depth of our premium inventory.

As I mentioned, our strong execution enabled us to meet or beat all our first quarter guidance items. Production during the quarter came in above the midpoint of guidance on all products. Oil and condensate volumes averaged 211,000 barrels per day, with total volumes of 574,000 BOEs per day. We also came in below the midpoint on capital. We resolved the production disruptions we experienced during the quarter, largely due to refinery turnarounds in Salt Lake City as well as some downtime related maintenance that was largely in the Montney. We expect our oil and condensate volumes to stabilize through the second quarter with a more consistent profile in the second half of the year. I’ll now turn the call over to Corey.

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Q&A Session

Corey Code: Thanks, Brendan, and good morning. Our track record of shareholder returns continued through the quarter. We returned $328 million through share buybacks of $248 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, we have repurchased a total of 33 million shares and distributed approximately $700 million in base dividend payments for total shareholder returns of about $2.2 billion. In the second quarter, as per our shareholder returns framework, we will buy back 182 million in shares, and we expect to allocate $182 million to the balance sheet. We remain committed to lowering the overall debt level in our capital structure and the interest costs that go with it.

Our strong capital efficiency, combined with higher oil prices, will allow us to reach our $4 billion net debt target sooner. This bolsters the resiliency of our business and positions us to withstand market volatility over the long-term. Our focus in 2024 is to generate superior returns on our invested capital and maximize our free cash flow. Assuming full year average crude prices of $80 WTI oil and a NYMEX natural gas price of $2.25, we expect to generate about $1.9 billion of free cash flow. This is about $750 million or more than 60% higher than last year with similar production volumes. Second quarter production is set to average 560,000 to 575,000 BOEs per day, with oil and condensate volumes of about 207,000 barrels per day at the midpoint.

As Brendan mentioned, we expect to deliver a more consistent oil and condensate production profile for the remainder of the year. From a capital investment perspective, the second quarter will be our high point for the year. We added a sixth rig in the Permian at the start of April and we recently commenced our Anadarko drilling program. We expect capital spending to trend down through the second half of the year, and we remain very comfortable with the midpoint of our full year capital guide at $2.3 billion. Our full year TILs are expected to be roughly evenly split between the first and second half of the year. Capital efficiency remains a primary focus for our teams, as we work to efficiently convert our inventory into cash flow and generate consistent durable returns for our shareholders.

As a reminder, an additional feature supporting our strong free cash flow this year is the expiry of our REX pipeline commitment here in May, which represents about $100 million in savings versus 2023. Additionally, the recent resolution of a legacy legal matter will result in a onetime recovery of approximately $150 million that will go straight to the balance sheet to reduce debt. Between this and the REX roll off, we’ll realize an additional $250 million in the cleanup costs from the legacy business. I’ll now turn the call over to Greg, who will speak to our operational highlights.

Greg Givens: Thanks, Corey. Across our acreage footprint, our Permian well performance continues to deliver. As planned, Q1 was a relatively lighter quarter for new wells on stream in the Permian with only 17% of our full year turned in lines. On Slide 8, the chart on the right shows our result across the last two quarters. The dash line shows all 80 of the wells we brought online over that period. These wells demonstrate the performance of our new completions design across our asset footprint. The green line is our 2024 Permian type curve, unchanged from its introduction in February. As you can see, our performance continues to match the type curve, which incorporates all of the improved well productivity we achieved last year and demonstrates how our team is continuing to innovate to drive returns.

We only turned in line 21 wells in the first quarter, but have already turned in line 14 wells in Q2. The performance from these 35 wells as well as our continued solid base performance gave us the confidence to increase our oil and condensate guide for the year to 206,000 barrels per day at the midpoint. Our execution across drilling and completions in the Permian continued to deliver improvements in cycle time, which will ultimately reduce the number of days on looking and lower costs. On the drilling side, our average drilling speed in the first quarter was roughly 5% faster than our 2023 program. As Corey mentioned, we recently added a sixth rig in the Permian. With respect to completions, our year-to-date Trimulfrac wells were completed 30% faster than our average speed in 2023 at an industry-leading 4,200 feet per day.

We expect to utilize Trimulfrac on more than half of our program this year. This approach yields a 15% savings in completions cost per foot and essentially doubles the completed feet per day versus a traditional zipper frac. We have deep experience with Trimulfrac, having completed nearly 70 wells in more than 3,400 stages since we began deploying the technique over two years ago. We are also seeing industry-leading drilling and completion metrics in the Montney, where in the first quarter, we delivered an average of 1,750 feet drilled per day and over 4,100 feet completed per day. These results are in line with our Permian pacesetters and demonstrate the value of our culture of innovation and multi-basin portfolio to deliver learnings and transfer learnings in real-time.

Despite the current weakness in gas prices, the economics on 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%. These returns are driven by our superior well productivity, low well costs and strong price realizations for both condensate, which generate — which generally trades in line with WTI as well as natural gas. In fact, our Montney gas realized 103% of NYMEX in Q1 on an unhedged basis. This is the result of our physical transportation arrangements to markets in Eastern Canada Chicago, California and the Pacific Northwest. Our Montney program remains robust in both BC and Alberta as we have in hand, all of the permits needed to execute our 2024 plan and 100% of our water needs secured.

Our performance in the play continues to demonstrate the expertise of our team and maximizing value from this incredible resource. In the Uinta, our continued focus on well cost reductions makes the play highly competitive in our portfolio as it generates a margin similar to our Permian operations. Our large contiguous land base of approximately 137,000 net acres has multiple benches across 1,000 feet of collective pay. It is greater than 80% undeveloped, which translates into a significant inventory runway. As Brendan mentioned earlier, the refinery turnarounds in Salt Lake City were completed at the end of the first quarter, allowing us to bring constrained production back online and return the local refining complex at our typical rates.

Furthermore, our rail capacity to the Gulf Coast diversifies market exposure and supports future growth in the play. With our first quarter drilling program complete, we will continue to on getting the majority of our 2024 wells online through the second quarter. Moving to the Anadarko. Our 2024 drilling program commenced at the beginning of April. 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. We plan to run one rig in the play for the remainder of the year and expect to see our first wells come online in the third quarter. The team has also managed our base production very effectively and we expect our 2024 Anadarko base decline rate to average an impressive 17%.

I’ll now turn the call back to Brendan.

Brendan McCracken: Thanks, Greg. Our team delivered another strong quarter, meeting or beating all our targets, and delivering cash flow per share and free cash flow above consensus. Our focus remains on maximizing capital efficiency, generating significant free cash flow, reducing debt and continuing to bolster our premium return drilling inventory. We are well positioned to deliver consistent durable returns to our shareholders through our focus on operational excellence, disciplined capital and responsible operations. This concludes our prepared remarks. Operator, we’re now ready to open the line for questions.

Operator: [Operator Instructions] We will now begin the question-and-answer session and call the first caller. Question comes from Neil Mehta at Goldman Sachs. Please go ahead.

Neil Mehta: Good morning, Brendan and team. A couple of questions for you. First, I would love your perspective, we spent a lot of time talking about the Permian over the last couple of quarters. But on the Montney specifically, and the progress you’re making in the oil window. So if you could just spend some time talking about your plans for that over the course of the year, and what do you think that investors should be focused on from a strategic perspective there?

Brendan McCracken: Yes. Thanks, Neil. Really appreciate it. And where I’ll start first is just with the resource itself. And I think this is a place that’s getting more attention from our investors, but one of the things we’ve been flagging for a little while now is the — everybody knows the Permian is the largest remaining premium oil resource in North America. And I think what a lot of people haven’t realized until recently is the second largest remaining oil resource in North America is in the Montney, and it’s sort of largely been thought of as more of a gas play. But where we’ve been focusing our capital and focusing our attention in the play has been on our acreage that’s in the condensate window, which for us sells as a premium product and really prices just like our oil price in the U.S. And so that’s been the strategic focus for us.

And look, we’re really pleased with the results. I think it’s very consistent with our durable return strategy where we’ve built a culture and expertise that lets us lead on innovation and that showing up in both our cost and our productivity performance in the play. And as we run the business at a maintenance level as a company, that’s the role that the Montney is playing within the portfolio. So investors should expect it to run relatively flat through the year and deliver free cash flow off the back of that.

Neil Mehta: Okay. That’s helpful. And then just a follow-up. We’ve got some questions this morning on just 2Q capital. It is a little bit higher than what would be implied for the full-year. I’m guessing that’s just lumpiness with the sixth rig coming up and the Anadarko kicking off, but just any perspective on just timing of CapEx in Q2?

Brendan McCracken: Yes, you got it, for sure, Neil. The sixth rig is part of that. And then we highlighted the TIL cadence, the turn-in-line cadence across the portfolio being a little lighter in 1Q and a little stronger in 2Q. And so where that will set us up is, if you look at it on a first half, second half basis as a company would be almost balanced on that capital and turn-in-line cadence, but a little bit shaded towards Q2 relative to Q1.

Neil Mehta: Okay.

Brendan McCracken: Yes, thank you, Neil.

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

Arun Jayaram: Yes, good morning. Corey, I’m wondering if you could just maybe elaborate on the $150 million expected cash inflow, it looks like you resolved a previous asset sale dispute, but maybe some details on that and maybe perhaps timing and any tax implications from that inflow?

Corey Code: Yes. Good morning, Arun. Just based on the agreement, we’re not allowed to say a whole bunch more about it other than I can confirm it’s a very old transaction. We should have minimal cash tax with it. And then maybe the only other clarifying point would be it’s not going to show up in cash flow. So the full amount of it’s going to go to reduce debt in the second half of the year.

Brendan McCracken: And Arun, the only thing I’d add to it, we’re very pleased to get this one resolved. As Corey said, it’s an older item, not a recent one. And think generally, what that should reflect is the relentlessness that our team has to get value for our shareholders. And when you think about the $150 million from this settlement, combined with the work to roll off the REX payment this year, which actually is this month is our final REX payment owing that’s almost $300 million or maybe call it, closer to $250 million of incremental value to the shareholders. And our team is just relentless about trying to unearth those opportunities and bring them all the way to the bottom line.

Arun Jayaram: Yes. Just to clarify, do you have a sense of timing? Is that a 2Q item, or is that second half of the year?

Corey Code: It will be second half. It’s right around third, fourth quarter.

Arun Jayaram: Okay. Fair enough. My follow-up is just on the Trimulfrac completion scheme. Greg, I think you mentioned you participated now in 70 completions, but one of the questions we’ve got from investors is if you could give us a sense of the well productivity on the Trimulfrac completions versus the wells you’re doing, either Simulfrac or zipper. And is there any trade-off before some of the — that you’re experiencing from some of the efficiency gains versus just overall performance or well productivity?

Greg Givens: Thanks for the question. And we’ve been very pleased that all along over the past two years, as we’ve instituted these Trimulfrac’s, we’re seeing no degradation of well performance really at all. What we’re seeing is lower treating pressures and the ability to pump these jobs faster, which should generates cost savings, which will flow straight to the bottom line. It also allows us to execute these jobs faster, which allows us to be more capital efficient. But the performance from these wells are very much in line with the other wells in the field. If you recall, we were doing this for a bit of time prior to even divulging that we were doing Trimulfrac and the results weren’t showing up any differently during that time, and that continues to be the case today.

So we’re very pleased with Trimulfrac. We pump a third of our jobs last year using that technique, this year will be a little over half. And I see no reason why we couldn’t continue to push that up even higher in the future as we continue to use the technology.

Brendan McCracken: Yes. I’d just add Arun. I’d just add Arun, in the rock doesn’t know it’s being Trimulfraced. So the way we design these completions, the rate of slurry sand and water that’s going through each cluster is exactly the same in either a zipper, a Simul or a Trimulfrac. And so really, this is all about an aboveground efficiency gain and the reservoir feels the exact same frac it would otherwise. So that’s why the result that Greg is describing on the well performance makes total sense that the wells would produce exactly the same because the completion downhole is exactly the same.

Arun Jayaram: Great, thanks Brendan.

Brendan McCracken: Yes, thanks Arun.

Operator: Thank you. The next question comes from Neal Dingmann at Truist Securities. Please go ahead.

Neal Dingmann: Good morning guys. Thanks for the time. My first question is on the D&C plan. Specifically, looking at your — I guess, the second quarter guide, you all talked about adding that sixth Permian rig is — I know you’d — I already said suggested and started up the Anadarko program. I’m just wondering assuming you’re maybe — I don’t know, Brendan question for you or Greg, if the operational efficiencies continue at this current pace, would you all continue with the same rigs, the six same rigs or which I think is about 60% the overall program? Or would you let maybe a Permian rig, or another rig go earlier than expected in the program this year?

Brendan McCracken: Yes, Neal, I think the way to think about that is based on what we’re seeing today in terms of supply and demand fundamentals and the service price environment that we’re working in, we’re biased towards keeping that low-level program going with that sixth rig through the end of the year. And so that’s what’s reflected in the guidance that we issued today and additional asset level guidance in the material also shows that — with that 60% of the TILs in the Permian coming in the second half.

Neal Dingmann: Got it. Got it. Okay. And then just a quick — do you have some, Greg.

Greg Givens: No, go ahead, Neal.

Neal Dingmann: Okay. Then just a quick second one, just on capital allocation. Is it fair to say — I don’t know, Brendan, for your record, just when you look at the free cash flow, and we have that continuing to ramp up pretty nicely this year. Will that likely continue to consist of just — continue to lean — leaning into buybacks of the stocks or — I’m just wondering, I guess, that versus variables or something else or if I could ask maybe one other second part of there. I mean do you all think of the stock value is based on a mid-cycle level, or what would cause you to continue leaning into this as you have?

Brendan McCracken: Yes. Great question, Neal. The approach we’ve taken, I think, will continue to be consistent with. And our view there has been to stay in this 50:50 allocation of free cash, where we’re putting half of it to the debt reduction and then half of it to the incremental shareholder returns. And then on your question around how to do that incremental shareholder return, we continue to see buybacks as the right value choice and the way we get to it is exactly how you implied. So we look at what we think the intrinsic value of the business is, and we look at that through a mid-cycle lens. And for us, that’s been $55 on TI and $2.75 on NYMEX. And so we look at the business through that price lens, which sitting here today feels reasonably conservative on the oil side and probably balanced on the gas side.

And so we like that as a discipline tactic to really manage that decision between staying in buybacks or shifting into something like a variable dividend. And so when we do that math and analysis, today, we’re still very comfortable that the buybacks are the right return mechanism to choose for that incremental return to our shareholders.

Neal Dingmann: Absolutely agreed. Thanks, Brendan.

Brendan McCracken: Thanks, Neal.

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

Gabriel Daoud: Hey, thank you. It’s Gabe here from Cowen. Hey guys. Brendan, I was hoping maybe you could just provide a little bit more on the trajectory from here? You assume you get 8 KBD back in the Uinta and Permian tills, kind of accelerating from here with 60% in the back half. You’re starting a rig in the Anadarko. Is Montney, I guess, declining still on the condensate basis? How do we think about that, I guess? And just some of the puts and takes at the asset level versus the corporate level guide that kind of assumes or implies maybe flattish to down in the second half on oil and condensate.

Brendan McCracken: Yes. Maybe I can talk a little bit about the shape within the assets there, Gabe. So remember, the kind of the biggest factor for production shape for us this year has been really finishing off the integration of that acquisition in the Permian last year. And just as a reminder, I think everybody knows this, but just as a reminder, there was quite a number of wells in progress that we inherited there as we shifted from that asset being run for growth under the prior management to being run for free cash flow under our strategy. And so really, the shape that you’re seeing through ’24 is just finishing off that stabilization and integration. And so what you should expect is the Permian will stabilize in the back half of the year at a little under where it was in 1Q.

Montney will be fairly flat through the year. Uinta grows a little bit more and Anadarko fairly flat to slightly down through the year until we start to bring on those wells in the second half.

Gabriel Daoud: Okay. Okay. Great. Thanks, Brendan. That’s helpful. And then I guess as a follow-up, you did $190 million or so, I guess, in bolt-ons in 1Q. Just curious what the sites like for continued bolt-ons and if we should expect maybe that similar level of spend the rest of the year? Or do you think the $190 million is kind of it for this year? Thanks guys.

Brendan McCracken: Yes. I think the thing to think about there is we’ve done a lot in this space over the last several years, and we’ve updated that outcome with the 1,650 net premium inventory additions that we’ve made over that time. And it was a combination of the smaller bolt-ons, like the ones that you referenced that we did earlier in 1Q, and then the larger transaction in the Permian last year and our organic efforts, right, converting nonpremium locations to premium on our existing acreage. And so look, I think that puts in a spot today where — we’re keeping it very opportunistic. We’re not driven to have to transact in order to extend our inventory. We’ve got that in place. And so it lets us be very value-oriented and disciplined in the market that we’re seeing today.

And I think we’ll stay opportunistic though. And when we see opportunities like we saw in 1Q to go grab some really high-quality inventory that bolts rate on to our existing acreage, we’ll continue to do that, but we’ll balance that with our ambitions on debt reduction and we’ll be disciplined about value creation.

Gabriel Daoud: Great, thanks Brendan. Thanks for the time.

Brendan McCracken: Yes, thanks Gabe.

Operator: Thank you. The next question comes from Scott Gruber of Citigroup. Please go ahead.

Scott Gruber: Yes, good morning. Just following up on the Permian rig count question. Given the efficiency gains, I’m curious, the Permian rig count of six equivalent with a modest level of growth out of the asset relative to where it’s going to stabilize in the second half?

Brendan McCracken: Well, I think that will be a ’25 question, really, Scott, because today, what we’re doing is, like I said, integrating that higher WIP activity that we inherited and whether that’s leaving us is with the guidance that you’ve got there for both the company and the asset. And really the question around is five or six the maintenance level, that will be a ’25 question that will come to as we get through the year. And really, what we’re honoring there is the rate of change that the team is continuing to drive like as we just drill faster and complete faster. So we’ll get a read on that as we get through the rest of the year and update that view for ’25 when we get there.

Scott Gruber: Okay. And then just circling back on the $150 million gain on the resolution. Just checking, you guys will receive $150 million in cash in the second half. Is that correct? And how do we think about that in terms of cash distributions or that cash going to the balance sheet?

Brendan McCracken: Yes, Scott, really appreciate the clarification. That is correct. So that’s $150 million in cash coming to us. It will not be a cash flow item. And so our intention is to put that directly to debt reduction.

Scott Gruber: Okay. Appreciate it. Thank you.

Brendan McCracken: Yes, great. Thank you.

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

Greg Pardy: Yes, thanks. Good morning. I want to maybe just build a little on the balance sheet question. So that’s — the $150 million paydown is helpful. Corey, you had what — I think a working capital headwind of $376 million or so in the first quarter bits. Do you expect some of that to unwind through the year. The bigger question is where is most of the progress made in the deleveraging getting to the $4 billion? Is that really — is that predominantly going to be 2025 as you look at it?

Brendan McCracken: Yes. I’ll let Corey chime in here, Greg. But really, the progress is the free cash generation from the business, driving debt down. But I’ll turn it to Corey.

Corey Code: Yes, Greg. We’ll start to see progress even as we get through the first quarter, because we put that debt bridge in the appendix as to help people see some of these onetime items in the first quarter. So those included the bolt-ons here that were previously mentioned plus the actual cash payment of the 2023 tax bill for us. So our business will generate more free cash flow really starting in April after the first quarter and the debt starts to come down, and obviously accelerates as oil’s 80-plus. So we’ll start to see progress this year we don’t know, we have to wait until 2025 to see that.

Greg Pardy: Okay. And then thanks for that. And then maybe just related, how are you thinking about your hedging program, particularly as the balance sheet continues to deleverage, is hedging something that you could see really moving away from? Or is that something you’d want to stay involved with no matter what?

Brendan McCracken: Yes. I think — so the — maybe I’ll talk about the current state and then talk about the future. So really, what we’ve been doing with our hedging program is protecting the business against a long period of very low prices. And so with that has resulted in is us hedging on a quarterly basis about a year out in time, and hedging a brown a quarter of production on both the gas and oil fronts. And with that will let us do is withstand a period of pricing as low as 40 on the oil and two on the gas, and still be free cash flow neutral or better after the base dividend. That’s been kind of the principle of what we’ve been doing. And so as the debt comes down, I think there’s kind of two things that happened. One, the interest expense comes down and so that balancing point on free cash flow neutrality is enhanced.

And then the other is kind of your question, which is do you even feel the need to hedge at all. And I think that’s something that we’ll just continue to address as we work towards that debt reduction. But the direction of travel is as you suggested, which is as the business de-levers the need hedge goes down.

Greg Pardy: Okay. Thanks very much, Brendan.

Brendan McCracken: Yes. Thanks, Greg.

Operator: Thank you. The next question comes from Roger Read at Wells Fargo. Please go ahead.

Roger Read: Yes, thanks. Good morning. Just really wanted to follow-up on, I guess, kind of thinking about it in the portfolio side. You’ve got a nice collection of assets here. You’ve obviously done some modest acquisitions. Is there anything at this point that it makes more sense to kind of put on the back burner potentially monetize as a way to accelerate debt repayment?

Brendan McCracken: Yes, Roger, I appreciate the question. Look, what we’ve done is built a portfolio that can be competitive for capital in every asset that we have. And so you can see from the capital allocation across the portfolio, the two biggest places where we’re allocating capital are our two biggest assets, so this is kind of no surprise, the Permian and the Montney. But our returns that we’re generating in the other two assets that Uinta and the Anadarko are very competitive for capital. And so we could move a rig around the portfolio and not have a change in corporate return. And that’s been how we’ve designed and sort of trimmed the portfolio over the years is to have exactly that multi-basin portfolio where everything is competitive for capital.

So I think that’s what you should continue to expect. I think we’re excited about each of the assets in the portfolio and what our teams are doing to generate free cash flow and capital efficiency gains in each of them.

Roger Read: Okay, well that is my only question. Appreciate it. Thank you.

Brendan McCracken: Yes, thanks Roger.

Operator: Thank you. And the next question comes from Geoff Jay at Daniel Energy Partners. Please go ahead.

Brendan McCracken: Go ahead, Geoff, if you’re there. I think we might have lost him, operator.

Geoff Jay: Hi, can you hear me? Sorry about that.

Brendan McCracken: Hi, there we go.

Geoff Jay: Yes, sorry about that. My question is really about the multiyear outlook for the Montney. I guess, given the Trans Mountain expansion, obviously, conde is tight right now, and I wonder kind of how you sort of think about the incremental pool for condensate going forward and what the opportunity set is for you to either grow that asset or at least get maybe even better pricing up there?

Brendan McCracken: Yes, Geoff, I appreciate the question. And this has been a dynamic that our teams follow very closely for quite a number of years, and our view has always been that the Montney condensate will stay a premium product and that view is really just informed by how the marginal pricing is being set. So today, the Canadian market is about 50% domestic short on condensate. So around half of the demand is actually being imported into the basin. And that’s the price setting mechanism that creates the premium pricing that you’re referring to. And so as the oil sands producers expand brownfield projects and get more market access, that just exacerbates that net shortage of domestic condensate supply. And so we see the fundamentals continuing to be strong there for years and years to come.

And that’s been the strategy of how we’ve deployed capital into the play is to chase that premium priced barrels. So — and then to your question on growth, really, our Montney plan as it stands is maintenance level because as a company, we’re a maintenance level. And so that’s the role that, that asset has been fulfilling in the portfolio. But as we’ve highlighted over the recent years, we have the ability to modestly grow that if there is a market call for that growth.

Geoff Jay: That’s super helpful. That is all for me. Thanks guys.

Brendan McCracken: Yes, thanks Geoff.

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 on our call today. This call is now complete.

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