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Good morning, ladies and gentlemen. Thank you for standing by. Welcome to Ovintiv's 2023 First Quarter Results Conference Call. As a reminder, today's call is being recorded. [Operator Instructions]. I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Thank you, operator, and welcome, everyone, to our first quarter '23 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. [Operator Instructions]. Following prepared remarks, we'll be available to take your questions. Please limit your time to 1 question and 1 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 speed. We also announced 2 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 more -- to this more in a minute, but the work our teams are doing to enhance completions 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, Dawn 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 first year -- excuse me, 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 a 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 this 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 and 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 3 years and tops the performance quoted by peers. Using the same time frame comparison, we now pump 65% more proppant 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, Ovintiv 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 players in North America that are capable of delivering multiproduct 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-above 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 2 rigs in the play and drilling a 9-well 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 cost 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 30 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. Now land position offsets our current acreage in Martin County. We have a deep understanding in the resource here, and we'll be able to leverage our existing operations. And 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 2 to 3 rigs on the acquired acreage for a total of 5 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, Simul-Frac, stage architecture, artificial lift and accelerated cycle times. We'll also be optimizing development and logistics across our combined Permian position versus the 3 separate operating companies that are planning and executing work on each of their individual footprints previously. We anticipate reduced offset frac hits as we significantly reduced 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 1 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 million to $630 million. We have provided our Q2 guidance under the assumption of a June 30 closing date. However, we have the potential to close a couple of 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 million 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, collars with floors in the mid-60s with upsides into the 80s and 3 ways with soft floors in the mid-60s and upside to 90 plus. 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 billion 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 the 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 disciplined capital allocation to make sure that value flows through to the bottom line. And we check all 3 boxes. Our leading capital efficiency is underpinned by our multi-basin, multiproduct 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 4 basins, the Permian, the Montney, and a quick cycle time and multiproduct 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.

[Operator Instructions]. Your first question will come from Doug Leggate at Bank of America.

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 30 close that the net cash outflow is actually going to be? Is that a material delta relative to the acquisition price?

Yes. Doug, I appreciate the question. As I said, 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. And just as a reminder, we expected these adjustments and we bake 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 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. That'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 the sustaining capital and the durability in terms of inventory depth of the combined portfolio?

Yes. I think the -- again, I 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 185,000 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, 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. And so recognize, it's a little bit early to start formally guiding to 2024 in 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 about $2.1 billion to $2.5 billion of capital.

Your next question comes from Josh Silverstein at UBS.

Maybe just on the sustaining capital number. You mentioned the $2.1 billion to the $2.5 billion for next year. Can you just talk about any sort of well costs in there, whether it's deflationary relative to what you're seeing now? And then you talked about the well cost not changing on the current completion design going forward into next year. Is that kind of a similar trend that you've seen? Are you factoring that into that guidance for next year as well?

Yes, 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. So I think it's early days. 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 refigure the completion design of the acquired assets, but you're acquiring 3 different assets. Can you just talk about how quickly you could implement your new designs there and maybe what the current well performance looks like versus what you might be able to see under the new completion designs?

Yes, Josh. I appreciate it. So again, we've not counted on a step change in well performance. Obviously, that's one of the upsides to the transaction here. We certainly look forward to getting the keys and getting in there and implementing the innovative approaches that our team takes. So it is -- there is a little process here. There's 120-odd wells in progress. So those have been drilled, cased and targeted with the prior management teams, and so 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 1 on that front. So once we work our way through those wells in progress, then we'll be into the full Ovintiv designs from there.

Your next question comes from Neal Dingmann at Truist Securities.

Brendan, 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 -- 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, stepping into buybacks and such. Just wondering any thoughts on potential changes on the shareholder return.

Yes. No, I appreciate it, Neal. 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 have 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 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 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 so 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.

No, that's great to hear. And then maybe my second one for Greg, just on the Uinta bit. You've got that Slide 8 that shows really the robust. I like that last table, it shows that you end up competing with the Delaware out of 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, again, I think obvious expectations are high for your Permian, like that sort of speaks for itself. I'm just wondering, how does Uinta compete against that when you're looking at returns?

Yes. Thanks for the question, Neal. I think the first thing I'd say on the Uinta is 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 2 rigs running there now. But we continue to be just really impressed with the results from the wells. This is an overpressured reservoir somewhere to the Delaware, so you're going to get high initial rates. But that does come with slightly higher cost. 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 what you 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 the industry. So look forward to having more news on that later in the year, but just I think that play really competes well and is a good fit in our portfolio.

Your next question comes from Gabe Daoud at TD Cowen.

I was hoping we could maybe just go back to the Midland acquisitions or just the 3 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, I guess, now until close or even just the first half of the year?

Yes, Gabe. So the activity level is consistent with where we were at the acquisition announcement date, so it's 7 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. Okay. That's helpful. And then I guess maybe for Greg, going back to 1Q results out of the Permian, you highlighted those 3 pads there. Could you maybe just talk a little bit about some of the differences you're doing on the -- 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 tweaking with the spacing of some of the existing zones?

Yes, thanks for that question. Yes, we're just 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 link slightly, working our perforating schemes, the perf clusters, how we -- how many perfs, where the perfs 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, so over time, we 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 improved efficiencies we've seen in the play in pumping faster has allowed us to pump a little bit more sand, a little bit more fluid and not improved -- or 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 is doing, generating great results and look forward to using these same techniques on the acquired assets when we take them over later in the year.

Okay. Gabe, I'd just add, 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. And so we've not been up spacing 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.

I was hoping you could talk a little bit more about the share repurchase kind of in light of credit facility being kind of 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.

Yes. 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, who 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, 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. As we think about the acquisition, we've got the bridge in place. Our intent is to put permanent financing in rather than drawing on that bridge. And we've spent a little bit of time describing the run rate, EBITDA of the new business. It has 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 time frame and beyond. If you look at our structure today, we got about $2.7 billion in that 2030 and beyond time frame. 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 that -- as it kind of stands now?

Yes. 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.

Your next question comes from Noel Parks at Tuohy Brothers Investment Research.

Of course, you're just on the verge of major transactions adjusting the portfolio. But one thing that we know there's a bit of a trend on some of the larger producers, multi-basin producers in the last 6 months or so is that there have been quite a few acquisitions where companies have slotted in properties sort of not under #1, maybe not even their #2 basins, but some of their smaller, less asset basin. And 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. So as you look at sort of beyond Montney, Permian, are you seeing things that could -- even though you got your hands for the short-term, that could be potentially compelling in your less active basin?

Noel, appreciate the question. I think you should expect us to be very focused on the portfolio that we have. And then what we 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. 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 as one of the few large operators on sort of both sides of the border, substantial U.S. 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 a 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 at our goals and objectives there holistically and haven't differentiated between the U.S. and Canadian assets. We've 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 JPMorgan.

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 what -- talk about your plans to kind of integrate the midstream and marketing of those assets as you move forward.

Yes. 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 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 3 of the EnCap operating companies had good relationships with mid streamers that we also work with and have long-standing relationship with. So working all of those details, and 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.

Yes. And I guess just -- I did give a little bit of the -- 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 will be sort of 5 years and in, we 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. Verhaest.

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