Ovintiv Inc. (DE)

Welcome to OVINTIV's 2023 First Quarter Results Conference Call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question and answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star 1. For members of the media attending in a listen-only mode today, you may quote statements made by any of the OVINTIV representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of OVINTIV. I would now like to turn the conference call over to Jason Verhest from Investor Relations. Please go ahead, Mr. Verhest.

Thank you, Operator, and welcome everyone to our first quarter 23 conference call. This call is being webcast and slides are available on our website at ovento.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and in our disclosure documents filed on CDAR and EDGAR. Following prepared remarks, we will be available to take your questions. Please limit your time to one question and one follow-up. I will now turn the call over to our President and CEO, Brendan McCracken.

Good morning. Thank you for joining us. We've kicked the year off with great momentum. We delivered net earnings of $487 million, cash from operating activities of $1.1 billion, free cash flow of $241 million, and cash flow per share of $3.44, beating consensus estimates. We also returned approximately $300 million to our shareholders through share buybacks and base dividends. This represents a cash return yield of nearly 15%, which is very competitive in today's market across both industry peers and the broader economy. Production during the quarter came in at 511,000 BOEs per day. We exceeded guidance on oil, gas, and NGL while coming in at the low end of guidance for capital. This result was driven by strong well performance across our portfolio and combined with some impressive capital savings from our innovation and efficiency focus that saw us once again push the leading edge for industry on drilling and completion speeds. We also announced two compelling transactions that enhance our capital efficiency, grow our margins, simplify our portfolio, and extend our premium inventory depth. First, we entered into an agreement to acquire core Midland acreage and added over 1,000 locations to our inventory. And second, we entered into a separate agreement to sell all our assets in the Bakken for $825 million. The combined transactions are immediately and sustainably accretive on all key metrics including cash flow per share, free cash flow per share, shareholder returns, NAV, and inventory life. In conjunction with the transactions, we also announced a 20% per share increase to our base dividend. I'll speak more to the transactions later in the call, but we are reiterating the projections we made at the announcement and remain on track to close both deals before the end of June. I want to thank our team for delivering an impressive quarter in all aspects across every asset. These results demonstrate that our strategy is working and our execution is translating into value for our shareholders. Our team is focused on execution and delivery. Our 2023 program is designed to maximize free cash flow while load leveling our activity through the year. The beat in our first quarter production volumes reflect the intense focus of our teams on executing that plan and delivering strong well performance. We saw great results across the portfolio with especially strong productivity in the Permian. Greg will speak to this more in a minute, but the work our teams are doing to enhance completion design is clearly showing up in our well results. Our culture of innovation amplifies these operational successes as learnings are quickly transferred across the portfolio. In addition to strong volumes, we also saw significant margin enhancement from our market access strategy. We continue to successfully manage our gas flow assurance and price risk across the portfolio. With over 90% of our Montney gas priced outside the basin and 65% of our production physically accessing downstream markets, We were once again positioned to benefit from premium pricing at Malin, Sumas, Don, and Chicago. This diversification allowed us to capture some of the high West Coast gas prices we saw in the quarter, resulted in a pre-hedged natural gas price realizations of more than 140% of NYMEX for our Canadian gas. Across the whole portfolio, we realized 111% of NYMEX after hedges. I'll now turn the call over to Greg to discuss the operational highlights from the quarter.

Thanks, Brendan. As Brendan noted, capital efficiency remains a key focus for our operating teams as we work to efficiently convert our inventory into cash flow and generate durable returns for our shareholders. Our efforts on completion design, and particularly on stage architecture, delivered stellar well performance across our Permian acreage this quarter. This continues the well performance momentum we generated in the second half of last year. The chart on the right shows our results across 2022, the first quarter of this year, and our full year 2023 performance expectations. We are actively working to increase resource recovery through our culture of innovation and our cross-basin learning approach. The Permian wells we turned online in the quarter had an impressive IP30 rate of 1,165 barrels of oil per day on a 10,000-foot normalized basis. This level of oil production per foot of lateral is in line with our strong fourth quarter results and is among the highest we've ever delivered in the Permian. It's important to stress that we continue to utilize our cube development approach to achieve these results. It's also important to note that these results are spread out across our acreage footprint and we have pumped these completions without added well costs above our budget. We are very encouraged by the year-to-date results we're seeing in the play. However, we recognize it's early, and we have not yet underwritten this performance in our guidance numbers for the rest of the year. We continue to set the efficient frontier in operational performance in the Permian. Our track record of continuous improvement has resulted in both cost efficiencies and productivity improvements. After navigating a challenging operating environment in 2022, Our team has put us back on track in 2023 with some significant completions milestones. For example, our year-to-date average completion speed at well over 3,000 feet per day is about 25% faster than our average speed over the last three years and tops the performance quoted by peers. Using the same timeframe comparison, we now pump 65% more profit and 35% more fluid. Our enhanced performance efficiency means that these higher intensity completions are not resulting in higher well costs. We are also demonstrating industry-leading drilling efficiency, ranking second in an independent Midland Basin peer review of drilling feet per day over the last 12 months. In our business, time is money, and these achievements mean we spend fewer days on location with less downtime, improving our capital efficiency and reducing our costs. Our strong performance in the quarter was not limited to the Permian. We are continuing to deliver impressive results across our portfolio. Nowhere is this more evident than in the Montney. Over the last 12 months, Oventive has dominated the list of most productive wells in the play on a total BOE basis. One of our recent lower Montney wells posted a 30-day IP rate of more than 5,300 BOE per day, comprised of 1,150 barrels per day of condensate and $25 million a day of natural gas. There are very few plays in North America that are capable of delivering multi-product yields like this from a single well. The economics in the Montney remain extremely robust. Even with the current strip pricing, we expect to generate well-level returns of more than 100% across the 2023 program. These great returns are driven by our superior well productivity, low D&C costs, and strong price realizations. During the quarter, our Montney condensate realized price was greater than 100% of WTI, and as Brendan mentioned earlier, our Montney gas realized prices were more than 140% of NYMEX on a pre-hedge basis. The Anadarko is also outperforming our expectations. Our reduced activity levels in the play this year enabled the team to innovate and refine our completion design, improve well-targeting, and optimize base production. Our activity has been focused on the oiliest, highest margin parts of the acreage. They've also done a great job in shallowing out the base decline rate in the play to about 20%, further improving the cash flow generation of the asset. The Anadarko continues to provide great product optionality and stable base production with ample market access and strong price realizations. In the Uinta, we are gearing up for an active program in the second half of the year. We are currently running two rigs in the play and drilling a nine-wheel pad, which we expect to bring on production in the third quarter. Our Uinta land base of approximately 130,000 net acres is about 80% undeveloped and is primed for cube development. It has multiple stacked horizons with about 1,000 feet of collective pay. This translates into a significant inventory runway. We continue to generate industry-leading well results comparable to those in the Delaware Basin and outpacing our peers by about 50%. So overall, we are very pleased with the operational performance across the asset base, and we remain intensely focused on delivering our targets for the remainder of the year. I'll now turn the call back to Brendan. Thanks, Greg.

The Permian acquisition we announced last month checks all the boxes for our durable return strategy. It extends our future inventory runway in a core area and is immediately accretive across all key financial metrics. It will also enhance our capital efficiency, lower our cash costs per BOE. Importantly, we maintain our strong investment grade rated balance sheet. Although commodities have been volatile since we announced the transaction, it's important to note that the original accretion metrics were calculated before the OPEC supply cut announcement using March 30th strip pricing. which was actually a few dollars below today's WTI strip. The metrics we highlighted remain as robust or even slightly better today. Located in some of the best rock in the Permian, these assets have demonstrated leading well performance and are a natural fit with our existing Martin County acreage. The blocked-up acreage sits in the core of the northern Midland Basin and is about 85% undeveloped. It is also well delineated with more than 180 horizontal wells producing today. That is an ideal setup for our team. The transaction will add 1,050 net well locations to our Permian inventory. The land position offsets our current acreage in Martin County. We have a deep understanding of the resource here and will be able to leverage our existing operations. At close, we will nearly double our Permian oil and condensate production. The acquired assets immediately compete for capital across our program, and we expect to run two to three rigs on the acquired acreage for a total of five rigs in the Permian. While the performance of the acquired assets stands on its own, we do see several potential upsides. We will apply full-scale cube development across the acreage. We'll be deploying our proven optimization techniques around completion design, simulfrac, stage architecture, artificial lift, and accelerated cycle times. We'll also be optimizing development and logistics across our combined Permian position versus the three separate operating companies that were planning and executing work on each of their individual footprints previously. We anticipate reduced offset frackets as we significantly reduce activity across the position. As I noted earlier, the transaction is progressing as planned. We are targeting a mid-June closing date if we get regulatory approval in a timely manner. With an effective date of January 1st for both the Permian acquisition and the Bakken sale, there will be typical purchase price adjustments, which are typical for these types of transactions. The acquired assets are expected to be free cash flow negative in the first half of the year, while the Bakken assets will be free cash flow positive. As a result, we'll pay an adjustment for both deals. These anticipated price adjustments were baked into our valuation of the assets and our purchase price, and were also incorporated into our accretion metrics. Teams have been focused on seamless integration, and we look forward to closing. Yesterday, we provided our second quarter guidance and updated our 2023 full-year guide. In the second quarter, we expect to see production grow to roughly 515,000 to 535,000 BOEs per day, with associated capital spending of $590 to $630 million. We have provided our Q2 guidance under the assumption of a June 30th closing date. However, we have the potential to close a couple weeks earlier, in mid-June, and we've provided a guidance sensitivity for that scenario. Assuming we close both transactions in mid-June, we would expect to add on a net basis roughly 5,000 to 6,000 barrels of oil and condensate to our second quarter production guidance, and we would expect to add capital of about $70 to $90 million to our second quarter capital guidance. Our full year guidance remains unchanged from the update we provided in April when we announced the transaction. In the Permian, we expect to shift from a 10-rig program at the time the acquisition closes to a 5-rig program by the fourth quarter, with most of the transition happening in Q3. As a result, Q3 will be our highest quarter of capital spend. In addition to increased capital efficiency, The transaction will also drive increased cash cost savings. We are divesting a relatively higher operating and T&P cost asset in the Bakken and adding a relatively lower cost asset in the Permian. We anticipate company-level savings of 3% to 5% for both OPEX and T&P in the second half of the year. While our hedging philosophy has not changed, we have layered in additional WTI and NYMEX protection to reflect the additional scale and the debt of the company post-transaction. We now have about 50% of our pro forma WTI exposure hedged using a combination of swaps in the mid to high 70s, callers with floors in the mid 60s with upsides into the 80s, and three-ways with soft floors in the mid 60s and upside to 90+. On the gas side, we have layered in production through a mix of structures, again, many with attractive upside. Next year, we expect to run a low-level development program, producing more than 200,000 barrels of oil and condensate per day, with a capital range of $2.1 to $2.5 billion. To put that into context, next year we will spend roughly the same amount of capital at the midpoint as our original 2023 guide, but that capex will produce an additional 30,000 barrels per day of oil and condensate. We believe that long-term value creation in the E&P space will come from companies that can demonstrate durability in both their return on invested capital and their return of cash to shareholders. Generating durable returns requires a deep inventory of premium return drilling locations. the culture and expertise to convert that resource to free cash flow at a superior rate of return, and discipline capital allocation to make sure that value flows through to the bottom line. We check all three boxes. Our leading capital efficiency is underpinned by our multi-basin, multi-product portfolio, which provides operational and commodity diversification, cross-basin learnings, and premium inventory depth. Following the close of the transactions, we will have anchor positions in four basins, the Permian, the Montanine, and a quick cycle time and multi-product asset in the Anadarko, and a high margin, high return emerging oil play in the Uinta. We're delivering outstanding results. We're well positioned for today's volatility. We take great pride at producing safe, affordable, reliable, and secure energy while delivering superior returns to our shareholders. That concludes our prepared remarks. Operator, we're now pleased to take questions.

Thank you, sir. Ladies and gentlemen, we will now begin the question and answer session. If you would like to ask a question, please press star followed by the number one on your telephone keypad. If your question has been answered and you would like to withdraw from the queue, please press star followed by the number two. And if you are using a speakerphone, please lift your handset before entering any keys. In order to ensure we get to everyone, we do ask that you limit yourself to one question and one follow-up. Your first question will come from Doug Leggett at Bank of America. Please go ahead.

Thanks. Good morning, everybody. I appreciate you taking my questions, Brendan. Two quick ones, if I may. I want to pick up on your comments about the effective date and the cash outflow and the acquisitions in the first half of the year. Can you just clarify, what are you anticipating, assuming June 30th close, that the net cash outflow is actually going to be? Is that a material delta relative to the acquisition price?

Yeah. Hey, Doug, appreciate the question. So, you know, as I said, it We're seeing customary closing adjustments here, but a bit different than some other situations since we're simultaneously selling one asset and buying another. So based on today's commodity prices and assuming the June close and our expectation of activity pre-close here, we'd estimate the closing adjustment on the Permian acquisition to be under $100 million. And that is a net outflow from us since the asset's running free cash flow negative during the interim period as a whole. And it's important to note there's some potential here for working capital to swing that number around a bit. And, of course, the closing timing will have a little bit of an impact, but that's our best estimate today. And then on the Bakken side, since we're the operator there, we know those numbers a little more tightly. And again, with today's commodity prices, we'd expect the closing adjustment there to be a little over $100 million. And again, that's an outflow for us since the Bakken's been free cash flow positive during the interim period. As a reminder, we expected these adjustments, and we baked them into how we priced the transaction, and so they don't impact the economics of the overall transaction, and we also accounted for those closing adjustments in the accretion metrics that we've reported.

Got it. Thanks for the clarification. I guess my follow-up is I want to revisit something we've asked you about many, many times in the past, Brendan, so apologies for that, but You've talked about durable cash returns. It's straight out of our playbook on how we think about valuation, which is durable or sustainable free cash flow. When you look at your portfolio today post-deal on a run rate basis, what do you see as a sustaining capital and the durability in terms of inventory depth of the combined portfolio?

Yeah, I think, again, appreciate the question, Doug. The Maybe what I'll do here is focus a little bit on how we see the scale of crude and condensate unfolding, and that's probably the way to back into your sort of maintenance-level question, pro forma. So with the deal announcement there, we gave some steering on the pro forma numbers for both 2023 and then for full year 2024, and we've reiterated those same numbers with this Q1 release, so no change there. We see 2023 pro forma averaging 185 to 195,000 barrels a day. And so if you look at our Q1 actuals and then now our Q2 guide, that lines up with us producing 210,000 barrels a day in the third and fourth quarters of this year. And then looking out into 2024, you know, I think we want to provide some context for how we see the combined business shaping up. and so we expect to produce over 200 000 barrels a day for the full year and we're targeting an activity plan that would see us start 2024 a little higher than that and then reach a stable production level for the second half of 24. uh and so recognize it's a little bit early to start formally guiding to 2024 and exit rates and there are a bunch of moving parts here but For big round numbers, we see the pro forma business setting up into a new stay flat level of about 200,000 barrels a day of crude and condensate, and that would translate through to that $2.1 to $2.5 billion of capital.

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

Yeah, thanks. Good morning, guys. Maybe just on the sustaining capital number, you mentioned the 2.1 to the 2.5 for next year. Can you just talk about any sort of, you know, well costs in there, whether it's deflationary relative to what you're seeing now? And then you talked about, you know, the well costs not changing on the current completion design going forward into next year. Is that kind of a similar trend that you would see? And are you factoring that into that guidance for next year as well?

Yeah, that's right, Josh. So we've not built any deflationary assumptions into that, either into our 2023 guide yet or obviously down the road yet. You know, I think it's early days. You know, I think like others, we've seen the service pricing plateau and in a few places start to retreat a bit, but quite early. So we've not counted on any of that deflationary pressure coming into the market in our forward-looking steering or guidance.

Got it. And then you mentioned being able to rejigger the completion design of the acquired assets. You're acquiring three different assets. Can you just talk about how quickly you can implement your new designs there and maybe what the current world performance looks like versus what you might be able to see under the new completion designs?

Yeah, Josh, I appreciate it. So, again, we've not counted on a step change in well performance. You know, obviously, that's one of the upsides to the transaction here. And we certainly look forward to getting the keys and getting in there and implementing the innovative approaches that our team takes. You know, there is a little process here. There's 120-odd wells in progress. So, you know, those have been drilled, cased, and targeted with the prior management teams. And so we know we'll be working with those well designs initially. But As far as the rigs, we'll be jumping right into our well design and targeting basically from day one on that front. So once we work our way through those wells in progress, then we'll be into the full event of designs from there.

Your next question comes from Neil Dingman at Truist Securities. Please go ahead.

Morning, guys. Thanks for the time. Brandon, my first question just on the shareholder return program specifically, could you talk about your thoughts on sticking with the formulaic plan, which I like, versus, you know, I know some others more recently, I'm just, we've seen here in the last, I guess, for earnings, others taking a more opportunistic approach, you know, stepping into buybacks and such. Just wondering, you know, any thoughts on potential changes on the shareholder return program?

Yeah, no, appreciate it, Neil. And you're quite right. We've left the shareholder return framework exactly as is, so no changes to that. And if we kind of call back to when we initially put that in place, one of the designing principles that we felt was really important was to have a transparent program that shareholders could understand and therefore value, but also have one that would be durable and not be sort of swinging around. So I think we accomplished that. I think the program has some flexibility in it in terms of how we return the cash to shareholders and you know, just for the sake of restating the obvious, we've been firmly in the buyback world because our view has been that's the best value available to us in allocating that return of cash. And so, you know, we see the current equity valuation well below the intrinsic value of the business at a mid-cycle price. And so buybacks continue to screen very favorably in our minds. And And so, you know, we think that shareholder return framework has worked well and looks to continue to work well for us. So you should expect us to be consistent with that.

Yeah, that's good to hear. And then maybe my second one for Greg, just on the Uinta bit, you know, you've got that slide eight that shows really the real best. I like that last table. It shows that the Uinta competing with the Delaware, the core Delaware. I'm just wondering maybe if Greg could talk about maybe just thoughts on how that does compare from a return perspective to, you know, again, I think obviously expectations are high for your Permian. That sort of speaks for itself. I'm just wondering, how does the UNTEP compete against that when you're looking at returns?

Yeah, thanks for the question, Neil. And I think the first thing I'd say on the U.S. is, you know, we're really just getting ramped up here on that program. As I said in my prepared remarks, we drilled a few wells in the first quarter. We have two rigs running there now. But we continue to be just really impressed with the results from the wells. This is an overpressured reservoir, similar to the Delaware, so you're going to get high initial rates. But that does come with slightly higher costs. We think as we continue to optimize our program, get the services we need going in the basin, we feel like it's going to compete cost-wise with the Permian, maybe slightly higher, but not where you'd see in the Delaware. And so putting all that together with the takeaway that we've secured, we're seeing really good success moving barrels both to Salt Lake City and on rail down to the Gulf Coast. We think the returns here are going to be incredibly competitive in our portfolio, which would put them up there with anybody in industry. So look forward to having more news on that later in the year, but just think the play really competes well and is a good fit in our portfolio.

Your next question comes from Gabe Dowd at TD Cowan. Please go ahead.

Thanks. Hey, morning, everybody. Thanks for the prepared remarks and the time. I was hoping we could maybe just go back to the Midland acquisitions or just the three assets. Could you maybe just give us a sense of where production is currently given the target of 75,000 BOE a day by close? And I guess is that 75,000 BOE a day, is that a number exiting the quarter or is that a quarterly average? And what does activity look like from you know, I guess now it's so closed or even just the first half of the year.

Yeah, Gabe, so the activity level is consistent with where we were at the acquisition announcement date, so it's seven rigs. And we get weekly production updates, and those are all tracking rate against plan relative to that 75,000 BOEs a day at close. And that was at close, so it's the exit of the quarter because there is a ramp up through the quarter for sure with that activity level.

Okay, thanks, Brandon. That's helpful. And then I guess maybe for Greg, going back to 1Q results out of the Permian, you highlighted those three pads there. Could you maybe just talk a little bit about some of the differences you're doing or tweaks that you're doing on the completion side? And then also have any of the cubes changed at all, whether it's adding new zones or maybe tinkering with the spacing of some of the existing zones? Thanks, guys.

You bet. Thanks for that question. Really proud of what our team has accomplished here in the Permian over the last few quarters. We remain committed to our cube strategy there because we firmly believe that co-development is the best way to optimize our recovery and returns from our acreage. But we have made some changes to our completion designs and a little tweaking to the well targeting. We're really focused on our stage architecture, and what that means is we're just adjusting the stage length slightly, working our perforating schemes, the perf clusters, how we – and how many perps, where the perps are placed. And we're also adjusting our sand and water mix. And what that's resulting in, as we said in the prepared remarks, over time we've started pumping a little more sand which is really very economic for us because of our wet sand supply we have there local in the basin, but also our unique on-location sand storage system that allows us to pump really large volumes of sand with very minimal downtime. And so the approved efficiencies we've seen in the play of pumping faster has allowed us to pump a little bit more sand, a little bit more fluid, and not increased our cost. On the targeting piece, we're not really adjusting our spacing there. It's really just slightly tweaking where the wells are located to help improve drilling performance, but also help well performance. So it's just a lot of little things that add up to really strong results. But again, every cube is custom designed to optimize the output from that section of land and get the best return from the well. So, overall, just really proud of what the team's doing, generating great results, and I look forward to using these same techniques on the acquired assets when we take them over later in the year.

Yeah, Gabe, I'd just add, you know, because I think this is really important because there's been a lot of moving parts in industry on attacking the stacking and spacing in the Permian and how that interplays with well performance. And so... I think this is the reason we've been in cube development mode for as long as we have is we feel like this is absolutely the right way to target the resource for value and returns. So we've not been upspacing or widening out spacing here. As Greg says, what we've been doing is just finding better ways to land the wells within the benches to both drill faster but also boost productivity.

So really, like Greg says, happy with how things are going.

Your next question comes from Nicholas Pope at Seaport Research Partners. Please go ahead.

Morning, everyone. Morning. I was hoping we could talk a little bit more about the share repurchase. In light of credit facility being increased as you're repurchasing shares and as you look at that balance right now, trying to understand a little bit about where that credit facility, what that interest rate looks like right now, and as you look at kind of progressing through the acquisition divestiture period, if you're thinking about where that gap might be funded, what the expectation is for credit facility versus the bridge financing, kind of what those rates look like and how you're thinking about that relative to the share repurchase right now.

Yeah, Nicholas, I appreciate the question. So I think kind of that's really a financing question on the transaction. So I'll flip it over to Corey. He can kind of walk you through where we're at on that front and how we see that coming together.

Sure. Thanks, Brendan. So on that front, you know, just to be clear, the framework that Brendan walked through earlier on the Share buybacks, that's kind of our method of returning capital to shareholders. So it comes on the trailing basis of the free cash flow in the prior quarter. But as we think about the acquisition, we've got that bridge in place. Our intent is to put permanent financing in rather than drawing on that bridge. We've spent a little bit of time describing the run rate EBITDA of the new business as about $4 billion at mid-cycle pricing. If you look at our debt structure today, that long-term debt number we've talked about being $4 billion. We think about that being kind of like the 2030 timeframe and beyond. If you look at our structure today, we've got about $2.7 billion in that 2030 and beyond timeframe. So it leaves us about $1.3 billion of space in there to have a long-term number we like. And the shorter end of that would be stuff that we could repay rather quickly with free cash flow as we generate that through the business. So that's kind of how we're thinking about putting permanent financing in place.

Got it. And what kind of rates are you looking at right now with your credit facility as it kind of stands now?

Yeah, I mean, obviously short rates are higher right now, so it's probably in the 6% range on the credit facility. But we do have a commercial paper program as well that we mix between the two, trying to optimize the shorter-term cost.

All right, I appreciate the color. Thank you. Thank you.

Your next question comes from Noel Parks at Toy Brothers Investment Research. Please go ahead.

Hi, good morning.

Hey, good morning.

You know, of course, you're just on the verge of major transaction suggestions in the portfolio. But one thing that we noticed is a bit of a trend on some of the larger producers, multi-basin producers, in the last six months or so is that there have been quite a few acquisitions where companies have slotted in properties, not on their number one, maybe not even their number two basins, but some of their smaller, less active basins. Presumably because there aren't a lot of bids out there and they can offer scale and get a good price. Some of those look like they've been really successful as far as upgrading technology and so forth. As you look at sort of beyond Monte Permian, are you seeing things that, you know, could, even though you definitely got your hands full short term, that could be potentially compelling in your less active basin?

You know, Noel, I appreciate the question. You know, I think you should expect us to be very focused on the portfolio that we have and then what we've said is in the near to medium term, we're going to be pretty focused on allocating free cash flow to debt reduction and shareholder returns. You know, obviously need to stay opportunistic and always looking for value, but I think the near-term focus is going to be on debt reduction and shareholder returns.

Great. Fair enough. And, you know, as one of the few folks large operators on sort of both sides of the border, substantial US and Canadian operations. I just wonder, as far as ESG mandates, projects, goals, initiatives, is on the Canadian side, are there any particular higher priorities that you need to address there, like I said, even through mandate or just through your own plans? And... Just wondering if there's any difference sort of in relative spend you see, for instance, between the Permian and the Montney.

No, I think for a long time now we've worked that, our goals and objectives there holistically and haven't differentiated between those. The U.S. and Canadian assets have taken a similar approach in both places. Obviously, there's specific regulatory differences between the two, but if we took you to a well site and a facility in Canada and a well site and facility into the U.S., Aside from the different pressure, temperature, and fluids, you really wouldn't notice a difference in terms of the design philosophy and operating philosophy. So I don't think we see an appreciable difference in either the approach we're taking nor the cost of any emission mitigation, which I'll just use this opportunity to remind folks that for us, we've been delivering... pretty significant greenhouse gas emissions reductions synergistically or at least at very low cost. So this has not been a burden on our business, and we don't see it becoming a meaningful burden, at least in the near to medium term.

Your next question comes from Arun Jayaram at J.P. Morgan. Please go ahead.

Yeah, good morning, Brendan. I wanted to see if you could highlight some of the integration work that you're doing on the newly acquired assets. Obviously, it hasn't closed yet, but talk about your plans to kind of integrate the midstream and marketing of those assets as you move forward.

Yeah, that's all in motion, Arun. Obviously, a whole number of processes at work there, but our team is working this pretty intensely across a whole number of categories, everything from the drilling and completion plan, sort of the obvious stuff, to how do we integrate this into our IT systems and our operations. operational control centers to the back office, financial accounting, and so forth. So all of that is moving well, including the midstream and marketing. I expect the transition on the marketing is going to be pretty snap acting. And we're well set up on the midstream side too, both or all three of the NCAP operating companies had good relationships with midstreamers that we also work with and have a long-standing relationship with. So, you know, working all of those details in the team is for sure on top of it, but don't see it as an area of concern sitting here today.

Great. And then, Corey, for you, thoughts on free cash flow generation this year, next year, and as you look to target debt reduction down to that $4 billion number?

Yeah, and I guess I do give a little bit of how we're thinking about that. permanent structure of the financing, really that's just to give us the flexibility to use that free cash flow to pay the debt down to $4 billion. So between our commercial paper credit facility and the term debt that'll be sort of five years and in, we'll have lots of opportunity to repay it with minimal to low cost. So we think it's a good structure. It balances the long-term capital structure of having long-term debt, but also getting closer to $4 billion quicker when there's excess free cash flow.

At this time, ladies and gentlemen, we have completed the question and answer session, and I will turn the call back to Mr. Verhest.

Thank you, operator, and thanks, everyone, for joining us today. Our call is now complete.

Ladies and gentlemen, this does conclude your conference call for this morning. We would like to thank you all for participating and ask you to please disconnect your phones.