Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2023 Fourth Quarter and Year End Results Conference Call. As a reminder, today's call is being recorded. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Thank you, Joana, and welcome, everyone, to our fourth quarter and year end '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 EDGAR and SEDAR+. Following our 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. 2023 marked another year of execution against our durable return strategy. We beat and reset our targets twice over the course of the year, and this trend continued into the fourth quarter in every aspect of our business. We converted our operational success into bottom line financial results with full year net earnings of $2.1 billion and cash flow of $3.9 billion. With capital investment totaling $2.7 billion, we generated free cash flow of approximately $1.2 billion, of which $733 million or 63% was returned directly to our shareholders. We continued to lead the industry by delivering efficiency gains in each of our assets. Completion design innovations, record-setting execution performance, leading well productivity per lateral foot, and base decline management are a few of the areas contributing to our excellent return on invested capital. In June, we more than doubled our premium drilling inventory in the Permian with a set of three highly accretive acquisitions. Our team has seamlessly integrated the new assets, and we are very pleased to report on the excellent results from our first end-to-end wells in the former EnCap acreage. These Permian acquisitions, combined with our strategic bolt-on additions and our organic assessment and appraisal programs, have added 1,650 premium drilling locations to our portfolio in the last three years. We identified the importance of this inventory renewal years before others and prosecuted a multi-year disciplined strategy of both organic and inorganic investment. The result is a huge boost to our full cycle returns and the durability of our business. We made great progress against our 50% greenhouse gas emissions intensity reduction target. For 2023, we achieved a 42% reduction from our 2019 baseline. Over the course of the year, we repurchased approximately 10 million shares and increased our base dividend by 20%. This reflects our commitment to maintaining financial strength, generating superior returns on capital investment, and returning significant cash to our shareholders. Our strong execution in 2023 has set us up for continued success in 2024. We will cover more of the details later in the call, but year over year we are set to deliver 40% more free cash flow at lower commodity prices. Our strong execution momentum continued through the fourth quarter, at 240,000 barrels per day; our oil and condensate volumes significantly exceeded expectations, coming in 7% above the midpoint of guidance. This outperformance was driven by faster drilling and completions and strong well results from both our legacy and newly acquired Permian assets, as well as excellent base production performance across our portfolio. Our seamless asset integration in the Permian allowed us to accelerate our expected turn-in-line schedule, meaning that the vast majority of our fourth quarter turn-in-lines came on in October and November. This, along with strong well performance, drove our fourth quarter oil volumes, which peaked in November. The higher volumes were achieved with lower capital, which came in at the low end of our guide driven by operational efficiencies. Our per unit cost performance for both TMP and operating expense came in well below the midpoints of our guide by margins of 15% and 4%, respectively. And finally, we reduced our total debt by $426 million, further strengthening our balance sheet. Our message in 2024 is simple: We will continue to focus on maximizing returns on our invested capital and maximizing our free cash flow to enhance shareholder returns and further reduce our leverage. In 2024, we expect to generate about $1.6 billion of free cash flow. This is $450 million more than in 2023, with flat production, assuming lower commodity prices. Our 2024 oil and condensate capital efficiency reflects an 18% gain compared to our original pre-acquisition 2023 guide. This is driven by disciplined capital allocation and operational efficiencies. I'll now turn the call over to Corey, who will cover the 2024 plan in more detail.

Thanks, and good morning. As Brendan mentioned, we entered the year with strong momentum from 2023, which sets us up to deliver a highly-efficient development program and a substantial increase in free cash flow. We are currently producing about 20% more oil and condensate than we were just one year ago, and our 2024 plan is focused on exploiting the most oil-rich areas in each of our plays. Additional catalysts supporting strong free cash flow include the expiry of our REX pipeline commitment, which represents about $100 million in savings year-over-year. We also expect about $100 million less in current tax expense year-over-year. As a reminder, we'll pay our 2023 current tax in the first quarter. This will not affect free cash flow, but it will result in a cash outflow of about $250 million. We are currently well underway on our first quarter buyback program of $248 million. Collectively, we will return $330 million to shareholders in Q1 between our base dividend and share repurchases. We are well-protected against potentially weak natural gas prices, as we have hedged about 50% of our 2024 gas volumes. More than three-quarters of our gas hedges have hard protection at prices exceeding $3, paired with upside participation to the mid-$4 range. For a $0.25 drop from our base assumption NYMEX price of $2.50, the impact to our full-year cash flow would be limited to about $50 million. 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. Our 2024 capital plan reflects a resilient, level-loaded program. We are leveraging our multi-basin, multi-product flexibility and focusing 100% of our investment on oil and condensate across the portfolio. As always, we have the optionality to shift capital, if economic factors dictate over the course of the year. Our 2024 program will deliver annual total production volumes of about 560,000 BOEs per day, essentially flat with 2023 volumes for about $450 million less capital. The savings will translate directly into increased free cash flow. As expected, our first quarter production is set to be the high point for the year at a midpoint of about 568,000 BOEs per day, including about 210,000 barrels per day of oil and condensate. This includes the impact of refinery turnarounds at Salt Lake City, weather, and planned maintenance that total about 8,000 barrels per day in the first quarter. From an activity and capital investment perspective, 2024 will be relatively low-leveled and ratable. Our development program will see less variation in turn-in-line cadence, setting us up for a more consistent production profile starting in the second quarter and going forward. Annual oil and condensate volumes are expected to average about 205,000 barrels per day, with production exceeding 200,000 barrels per day in every quarter. This is about 5,000 barrels per day higher than our previous 2024 guidance for the same amount of capital and is a credit to the strong capital efficiency delivered by our teams. Importantly, our development program is highly repeatable beyond 2024. I'll turn the call over to Greg. He'll speak to our operational highlights.

Thanks, Corey. 2023 was an exceptional year for our Permian team. Efficiency records, seamless asset integration, and strong well performance were consistent themes throughout the year. Our execution across drilling and completions continued to redefine the efficient frontier and operational performance in the basin. Our enhanced completions have resulted in well performance exceeding type curve expectations, and that performance has been included in our 2024 guide. While our cube development approach has stayed consistent, we are constantly looking for ways to improve cycle time and reduce the number of days on location. For example, our average completion speed at well over 4,000 feet per day for our Trimulfrac wells was about 9% faster than our average speed in 2022 and tops the performance quoted by our peers. We pumped 29% more slurry and increased our equipment utilization by 14% for an average of 18 pumping hours per day. We continue to demonstrate industry-leading drilling efficiency with an average of 12 days per release, which is 5% faster year over year. We expect to utilize Trimulfrac on more than half of our program this year. This approach yields a 15% savings in completion costs per foot and essentially doubles the completed feet per day versus a traditional zipper frac. Importantly, the results from our Trimulfrac wells are in line with the rest of our program, meaning there will be no degradation in well performance. So what does all this mean? It means we're able to more efficiently convert resources to cash flow and enhance shareholder returns. As a result, in 2023, the Permian generated an incremental $150 million in free cash flow due to our unique innovative approach. Across our acreage, our Permian well performance continues to be very strong. The chart on the right shows our results across 2023. The orange line includes all wells on our legacy acreage and all the EnCap wells since the start of the year. The dashed line shows the 19 Ovintiv design end-to-end wells we brought online on the EnCap acreage during the fourth quarter. Finally, the green line is our 2024 Permian type curve. The initial results from the 19 fully Ovintiv design wells on the EnCap acreage are impressive, showing a 10% productivity uplift compared to prior operators. These cubes were designed and used the same well stacking and spacing that we use across our Permian position. Our efforts on completion design and particularly on stage architecture delivered stellar well performance in 2023, and we expect this to continue in 2024. Our well results have been consistent across our legacy acreage and the acquired acreage position, and our new type curve was used to generate our 2024 plan. This improved well performance and faster cycle time are the major drivers behind our increased oil guide to a midpoint of 205,000 barrels per day for the year versus the previous guidance of 200,000 barrels per day. Our 2023 actual oil production per foot of lateral is in line with the best we've ever delivered in the Permian and is among the best in the basin. In fact, when you compare our 2023 legacy wells combined with the EnCap wells we controlled from end to end, our well productivity per foot ranks second versus our peers in the Midland basin. We expect these results to be highly repeatable in 2024, and this expansion and type curve has been baked into our full-year guide. In 2024, we plan to run an average of five to six rigs throughout the year with 1 to 1.5 frac spreads to bring on 120 to 130 net wells. The Montney is one of the largest remaining oil plays in North America. Our performance in the play continues to demonstrate the expertise of our team in maximizing value from this incredible resource. In both BC and Alberta, we have unleashed cross-basin learnings and innovation to drill some highly prolific oil and condensate wells. Since the third quarter of 2023, our 10 best Montney wells averaged more than 1,000 barrels per day on an IP30 basis. Supported by our oil and condensate productivity, the economics of our Montney wells remain outstanding. Even with the low natural gas prices reflected in the current strip, we expect to generate a program-level IRR of more than 60%. These strong returns are driven by our superior well productivity, low D&C costs, and strong price realizations. As a reminder, our condensate trades in line with WTI. In 2023, we realized 96% of WTI, making the Montney competitive with the top oil basins in North America. With our portfolio of fixed transportation outside of AECO, we realized 106% of NYMEX for our 2023 natural gas volumes on an unhedged basis. Despite weaker natural gas prices, we are continuing to deliver exceptionally robust returns in this play. This year, we plan to run three to four rigs to turn in line 60 to 70 net wells. In the Uinta, we continue to deliver leading well results. A recent third-party report noted that our six-well pad is yielding a higher per-acre oil EUR than over 75% of the developed DSUs in the Delaware Basin. With a similar cost structure, our wells are outpacing one of the top basins in North America. This strong well performance combined with our continued progress on cost reductions continues to make the Uinta competitive in our portfolio, generating a margin similar to our Permian operations. Our large contiguous land base of approximately 137,000 net acres has multiple benches across about 1,000 feet of collective pay. It is greater than 80% undeveloped, which translates into a significant inventory runway. Our scalable rail capacity to the Gulf Coast diversifies market exposure and supports our future development plans. In 2024, we plan to average one rig in the Uinta to turn in line 25 to 30 net wells. Our 2024 program in the Anadarko is designed to target the oiliest parts of our acreage to leverage the strong performance we've seen from our most recent wells. The early production from these wells has displayed first-year oil cuts of more than 55%, with about 85% of first-year revenue coming from oil. This combined with year-over-year D&C cost reductions of $1 million per well significantly enhances the economics of the program, which we expect to deliver highly competitive returns in 2024. The team has also managed our base production very effectively and has cut base declines in half to less than 20% since 2021. Our planned one-rig program will bring on 7 to 10 net wells. I'll now turn the call back to Brendan.

Thanks, Greg. Access to premium resources is an essential component to generating durable returns. In total, since 2021, we've cost-effectively added about 1,650 locations, about two-thirds of which were in the Permian. Since the beginning of this year, we've added 65 premium 10,000 foot equivalent locations in the Permian through three bolt-on transactions, averaging 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. We've continued to invest in assessment and appraisal to convert our inventory into the premium bucket. This generally represents about 10% of our total capital spend. Appraisal wells are often included in our cube developments to prove up prospective zones, and this is something we are currently advancing in our new Permian acreage, where we're testing up to six zones in some parts of that position. We're seeing promising results, which could add significant potential upside to our inventory. At the time we acquired the assets, our acquisition case was underwritten with only three development zones. We are committed to staying disciplined and opportunistic in our bolt-on efforts and only transacting when we can generate strong full cycle returns at mid-cycle pricing. In closing, as a leading operator with more than a decade of high-quality drilling locations and a deep commitment to capital efficiency, we are positioned to deliver consistent, durable returns to our shareholders through our focus on operational excellence, disciplined capital allocation, and responsible operations. In 2024, we're focused on maximizing capital efficiency and margins, generating significant free cash flow, reducing debt, maintaining our strong balance sheet, all while continuing to bolster our premium return drilling inventory. I'd like to thank our team for their safe work, their dedication, and for delivering these outstanding results. This concludes our prepared remarks. Joana, we're now ready to open the line for questions.

First question comes from Neal Dingmann from Truist.

Brendan, my first question is just maybe for you, Greg, on the notable capital efficiency specifically; could one of you discuss what's driving, I think you all talked about this year's 18% year-over-year improvement from the original ‘23 guide. I'm just wondering how repeatable are these drivers and what maybe is driving the bulk of this?

Look, this has been a multi-year effort where we use the culture and the expertise of our team through innovation to really drive those capital efficiencies. And so, I think that's great to see the 18%. If you remember when we transacted on the EnCap, we had programmed or guided to a 15%. So we've even outperformed that already, and so we're excited about that and thank the team for that, and I guess I would tell our investors we're hungry for more. But I'll turn it over to Greg to comment on the specifics of those efficiency gains.

Before I start, I do just want to say quickly, congratulations and thank you to our team for this year. They had an excellent performance in 2023, and especially in the fourth quarter. I think they exceeded all of our expectations including ours. But as far as the efficiencies and what's allowing us to improve that, it's about half production improvement and about half capital efficiency or just doing the wells faster and less expensively. I mean, everything we do is driven around trying to drill and complete our wells faster and more efficiently quarter over quarter and year over year. And you've seen that improvement over the last several quarters on both the drilling and completion side. On the drilling side, it's about more effective BHAs and minimizing trip times on the stage architecture. On the completion side, it's stage architecture, really focusing on our completion designs to try to get the most production out of each foot of lateral that we complete. We've done a lot of work on the surface, on the efficiency of how we handle our sand. Some of you came out and saw our field tour earlier this year and saw how we're able to move significant amounts of sand very efficiently to stockpile on location, so we can stay ahead of our very efficient frac crews. We're working really hard to be able to handle the recycled water we need to keep up with our frac rates. All of that allows us to try to frac at what we think are some of the most efficient rates and efficient costs anywhere you're going to see in the industry. On top of that, we're using real-time optimization of these frac jobs to make sure that we're putting the sand in the water where we need to. All of that is just resulting in a much more efficient operation. It's not any one little thing that we're doing; it's the stacked innovations. One of these things by themselves wouldn't move the needle, but when you stack them all together, it makes a really big impact. Without doing all the pieces, you can't do the whole. The reason why we're able to try and frac and execute the way we are is just the results of years' worth of a bunch of small innovations stacked on each other, and that's what's leading to the better efficiency year-over-year.

Greg, maybe just I'll take my second, maybe just a little bit of a follow on that. I'm just wondering my second is really around that Slide 8 where you all lay out kind of your '24 programs. I'm just wondering if you continue to have these efficiencies like let's say the Permian continues to trend in this direction and you're able to bring on even more wells because of these efficiencies. Would you continue to do so in that area and lessen the amount of activity in another area? Or maybe Brendan, even for you, would you think about— I guess my point is, would you continue to have more production in these areas or would you stay with the same production and just return more to shareholders?

Yes. I think that comes down to really a return on invested capital question and a value question. We'd look at that point at what's the macro telling us from the— is the world asking for more barrels and more BTUs? Clearly, the dynamic we have today is the world doesn't need any more BTUs. That's why all of our capital is focused on oil targets this year. I think your question around whether to save the capital and maximize free cash flow or whether to let production creep up and grow cash flow per share over time, I think really is a fundamental question, and we'd take that in turn. Today, we're running the business at that maintenance level. Really what that's saying is, today we don't think the market is asking for more barrels and more BTUs. It makes sense for us to maximize that free cash flow and stay in the maintenance mode. Really the last thing I'd leave you with and I think it was Corey that addressed this in his earlier comments is, this '24 run rate where you're seeing us at $2.3 billion and 202 to 208 on the oil and condensate, we see that as very repeatable again in '25 and beyond.

The next question comes from Arun Jayaram from JPMorgan.

Good morning. Brendan, a lot has been written and analyzed around your completion optimization program in the Permian Basin. We did see that you've tweaked up your type curves. If we're going to compare and contrast the productivity per foot that you expect to deliver in 2024 and compare that to your pre-2023 completions, give us a sense of what type of productivity benefits you're generating with the new completion design?

It's over 10% from those pre-2023 results, Arun. And just as a reminder there, we've stayed consistent in the cube development mode and have not shifted into upspacing or skipping benches. In fact, we've added benches as we've been pointing to with our assessment and appraisal work. And the reason that's important is we're delivering that inflection, and enhanced— and really, as Greg pointed out— leading productivity per foot without sacrificing those zones and destroying inventory for the future, which, when you combine that with the amount of premium inventory we've added to the company over the last several years, and then having preserved and added organically as well, I think is a distinguishing story.

I'm switching gears. I want to talk a little bit about the Montney. Let's talk about the 2024 program, 60 to 70 wells, $450 million of capital. Brendan, can you discuss just your general inventory depth in the play? Would love to hear about the free cash flow potential relative to the $1.6 billion corporate guidance for the year? Pardon me, at the deck that you've highlighted, and maybe just discuss the A&D landscape in the Montney.

For sure. But from an inventory perspective in the Montney, we're blessed. So we've had a historic position in that play, and that's important for two reasons. One, the acreage there—we can hold that without the continuous drilling programs that folks are maybe used to in the U.S. So we've had a massive acreage footprint in the play for a long time. And so that sets us up with a deep premium inventory on both the oil side, where we're over 10 years of inventory on the oil side, and then on the gas side—decades of inventory is probably the way to describe that. I mean, we're not currently drilling any gas wells, but deep inventory on the gas side of the play as well, which we think becomes real value on the road ahead. Obviously, today doesn't look like a great return from competitiveness in our portfolio, and that's why we're not putting capital there. So that's the inventory side of things. I'd say from a competitiveness perspective, look, we've got that big position. There is an incumbency advantage in the Montney where the historic producers in the play have got access to market, which is really the big differentiator. I think everybody recognizes the rock is globally unique and competitive. But it's the access to market that really unlocks the returns. And again, because of our historic position in the play, we've been able to deliver really high return on invested capital by having great market access. And again, I just remind you, we have almost no AECO exposure out through the end of 2025, and the condensate, which is the oil we're producing in the play, and targeting the play trades today just $2 or $3 back from TI.

The next question comes from Gabe Daoud from TD Cowen.

Thanks for taking my questions. Brendan, was hoping we could maybe just start with 1Q, that 8 KBD impact that you all noted. As we're now just about in March, is that like fully in the rearview or is that also impacting the rest of the quarter through March?

Gabe, thanks for the question. Obviously, the weather is in the rearview here, and then the piece that's still active is the refinery turnaround. There are a number of refiners in that Salt Lake City market, and they all run on a four to five-year maintenance turnaround schedule. As it happens, we've got two of those five refiners currently down for their routine, planned maintenance, and that will persist into March here. Obviously, we are dialoguing with them closely and understanding their schedule to be back up and then using our rail access to try and move barrels that way. But otherwise, the other pieces of the planned maintenances and weather are in the rearview.

And then my follow-up would just be on '24 capital. If I just look at Slide 8 and do the tow math of build times lateral fleet or average lateral foot times D&C, you get a CapEx number that's maybe $200 million to $300 million or so below the full-year range. I think I know the answer, but just kind of want to confirm: Is that maybe like infrastructure spend or that appraisal bucket that you had noted? Maybe just a little bit of help with that delta would be helpful.

For sure, Gabe. The biggest piece of that bucket is our capitalized G&A. If you recall, we have some of that capitalized G&A that's traditionally been done that way for years. That's the biggest piece of that. And then really the last little bits of it are some land and some facility capital, but they're pretty minor.

The next question comes from Neil Mehta from Goldman Sachs.

Good morning, Brendan and team. Couple of capital allocation questions. Just your perspective on continuing to shrink the share count here, especially as the balance sheet is now in good shape; how should we think about the priority around share repurchases?

Thanks, Neil. Great to have you back on the name. Really, our thinking here has been consistent. With our cash return to shareholders, we've been using buybacks, and I would expect us to continue to use buybacks at current market conditions. Really, what we look at there is just a straight value question. What's the best allocation of capital? Today, we trade at still a very significant intrinsic value discount at mid-cycle prices. Because of that, we believe the best use is to buy back and to create cash flow per share and free cash flow per share growth through buying those shares back.

Thanks, Brendan. It's great to be back. The follow-up is just in terms of your M&A commentary. I think you used the language of you want to be disciplined and opportunistic, and you also highlighted you have over a decade of inventory. Maybe you could just step back, make picture and think about how you think about the strategy around M&A in terms of bolt-ons from here?

Neil, I think, if we take that step back, we formed this durable return strategy three years ago. And that really has led us to get ahead of the competition on deepening our premium inventory. And what we see is we've added more premium inventory depth at a lower cost than just about anybody over that period. The great part of that is that means we're in a place today where we can be very disciplined and really focus on execution. Just a reminder on the numbers, we've added 1,650 premium inventory locations since ‘21. And that's not just the EnCap transaction; obviously, that was the biggest single mover of the needle, but we also did over 200 bolt-on transactions through that period and have also had great success with our organic conversions to premium as well. And then I would add, we've also integrated the assets that we acquired seamlessly, and that's really demonstrated by the performance of the business that you're seeing. So, I think it exactly as you prompted, we're going to remain very disciplined. But also, as you saw in 1Q ‘24 here already, we've added 65 locations at a cost that delivers really excellent full cycle returns. So, we like that.

The next question comes from Scott Gruber from Citigroup.

Wanted to ask about the potential additional locations in the Permian as you test new zones. When do you think you'll be in a position to make a call on whether those 250 additional zones qualify as Permian and get included in the account?

I think you should expect us to keep updating on that through the year here, Scott, in a bit of an internal process. But we usually, in the spring, is where we really round up our view and look at it on a year-over-year basis. So, I think as we go through the year, we're going to obviously be getting more data and results on those tests, and we'll keep the market updated. But I don't think this is something you have to wait until next year on. I think we'll keep updating as we go through the year.

And then another question on the Permian, you mentioned improving cycle times, and I imagine on the uncapped acreage, your learnings there will continue throughout the year. But then when I look at the activity set in the slide on ‘24 activity by basin, it looks like the rig count is up maybe a half a rig. So, as we think about the drilling cadence relative to that till cadence, is the drilling cadence going to be a bit faster than the till cadence in the Permian this year? You set up for a few more fill-ins in the basin in ‘25.

So we're not in this plan building any ducts, Scott, so we'll just have our normal operational run rate of ducts where you just have wells in between drilling and completions. But we're not deliberately investing to build those ducts up in this plan. So, I think what you'll see is, if we continue to catch a gear on drilling speed and completion speed, that'll just show up as wells coming on stream earlier. And that kind of takes us back to Neil's question on do you save the capital or do you let the production volumes grow? I think we'll have to answer that as we go through the year and just keep our eye on the fundamentals of the market.

But at least relative to the second half of last year, I mean it looks like there's a little bit more drilling in the Permian, a little less in the Montney. Is that fair?

You're absolutely right there. We're going to be adding a sixth rig later in the first half of the year to the Permian. Year-over-year, capital is down in the Permian, but really that's a function of us absorbing all those wells in progress from EnCap. And so, you'll see us shifting into a six rig run rate in the Permian later in the second half of this year. You're right about that.

The next question comes from Greg Pardy at RBC.

Yes, thanks. What does the unit look like in three to five years? I'm trying to get a better sense as to what kind of role it's going to play in the portfolio. I mean, you've set the table pretty nicely with the acreage margins you've got and how much you've done. I wonder how big this is going to be coming over that timeframe.

Yes, Greg. I would just highlight, it's obviously gotten a lot bigger just in the last 12 months, having basically doubled oil production in the play over the last 12 months. That's not going to be the continued trajectory. I think what you're going to see is, it will level out here in 2024, maybe some growth over the year, but leveling out generally compared to that more aggressive or more significant ramp-up. Really, the multiyear look on the Uinta is really again back to a fundamental decision. What we've built here alongside our other assets is another asset that can compete for capital and create modest growth for the company over time. We've got the ability to continue to scale the takeaway to the Gulf Coast through rail, and we're seeing the well performance and returns that could compete for capital and be part of growth. We have that option, and the decision around how to allocate capital there is going to rest on the fundamentals for the company and the larger macro really more than any constraint at a play level.

That's great context. I wanted to come back to the strategic decision, the M&A decision more as it relates to the backdrop and what we've seen in trends and just the tidal wave of M&A in the U.S. and then obviously the replenishing that you guys did last year in terms of bulking up on the portfolio. With where you sit now with the three big plays within the company, is there any inherent advantage for you from a cost of capital or portfolio diversification standpoint or what have you where it would make sense to get bigger? Or is it really just a case that you're very content with the portfolio at this juncture? I'm just trying to get a sense as to where your head's at.

Greg, thanks for the question. We are entirely motivated about better as opposed to bigger. The focus for us is on capital efficiency and margin expansion in order to drive free cash flow and return on invested capital. I think the reality is we've got the sophistication and the capability to do that with the portfolio that we have today. That's really what we're excited about, making that business better. I think the track record shows we've been able to inorganically add to that and make ourselves better. I think the 18% capital efficiency is a great proof point of that just in the last 12 months. But we're really focused on better rather than necessarily bigger.

The next question comes from Jeoffrey Lambujon from TPH & Company.

My first one's a follow-up on the location ads and the Permian and the success you've had with that program, which has obviously continued here into Q1 with what you've done year to date. And I realize it may be complicated to speak to expectations for the pace of these things, but maybe I could ask if you could frame the opportunity set or what the market looks like over the near term as you see it, or even just what you all would like to get done in general as you continue that initiative.

I think, look, the ability to do these very attractive bolt-ons, it's not getting easier, and I think that's been true for some time. It's not just a recent phenomenon, but look, the team's been really creative. What we look for is those situations where we've got a differential advantage, where it's either a natural owner situation or I think in a lot of these opportunities, we're bringing something to the table that the seller can benefit from that nobody else does. I would highlight our combination of cube development, the density that we attack this acreage at, with the leading well results that we garner. I think that is a relatively unique proposition. We use those to try and create a differential advantage for us in a competitive market. So, I think you nailed it. It's really hard to be predictive about what those look like over time, but I think it's safe to say it's not getting easier to find those opportunities where the full-cycle return really makes sense for the strategy that we've laid out.

And then for my follow-up, just maybe a nuanced one on the guidance for oil and condensate, if we should think about the midpoint of the range there for the years, kind of a P50 type outcome, what are the factors that you consider that move you around within that range or even beyond it? Would the low end be the result of items similar to the Q1 factors like the maintenance or turnarounds for example, if those were to extend beyond what's been planned, and then on the high end would that mainly be continued capital efficiencies that you mentioned, maybe more trim potentially coming in the program? Just trying to get a sense for what kind of risking is baked in, just thinking of the track record throughout last year, and especially in Q4 in terms of the operational beats on results compared to guidance and expectations.

I recognize that's a really fair question, given how much we've outperformed here in recent quarters. I would just highlight that if you look at the fourth quarter, we really had everything come together, which is great to see, and I'm particularly pleased about how that flowed all the way through to the bottom line to free cash flow generation. I think you've nailed it. I think there's a range of risk factors that we have to consider when setting guidance, and we're very thoughtful about how we do that and give our investors the best picture for what we think that we're going to deliver in the coming period, whether it's the coming quarter or the full year. We really are confident in the guidance range that we've provided here today and look forward to executing against that as we go through the year.

The next question comes from Roger Read at Wells Fargo.

Good morning. I wanted to come to two items. One, Slide 10, the end-to-end OVV pads on the results. And then what's the right way to think about that particular structure as we look into 2024, right? I mean, a handful of wells in this pad in the fourth quarter, good results, but what's the right way to extrapolate that as we look at '24 and it sounds like '25 kind of looks similar. What's the right way to think about it over the next, say, 24 months?

Yes, really appreciate you digging into this one, Roger. I think it's a really important update. It's obviously been one that we've been talking about since we announced the deal. The end-to-end wells, we now have 19 wells on stream with a meaningful amount of production data that were designed and drilled and completed by Ovintiv. It's across three different pads that are spread out across the acreage position. Those collective 19 wells are delivering at a level consistent with our legacy 2023 wells. I mean, that's just a tremendous outcome. I know that was one of the questions that the market had for us is how is this acreage going to compete within our portfolio. There you go, right out of the gate, 19 wells, three pads spread across our rate-in-line. That's given us the confidence to be able to underwrite that 2024 curve, which you can see is actually a little bit up from the '23 overall average. Really, that's what's baking in is the full end-to-end Ovintiv design in 2024 across the combined EnCap and legacy acreage.

Thanks for that. And then to follow up on the 65 locations you've acquired year-to-date, how much of that is brand new location? How much of that is in a sense the ability to drill the longer laterals? In other words, you're acquiring additional acreage that improves a location that might not have previously been on the list. I'm just trying to understand what bolt-ons are really providing.

It's a mix of both of those things, Roger. It's both the extending longer laterals and getting that across existing acres that we control, and onto new acres, as well as just pure, as you put it, pure new locations where we're adding acreage adjacent to our existing position. It's a mix of both of those things.

The next question comes from John Abbott from Bank of America.

Thank you for taking our questions. First question is on M&A. You have the advantage of bringing both in the U.S. and in Canada. We've seen a lot of industry deals in the U.S. What are your thoughts about industry consolidation in Canada at this point in time?

Yes, I don't think any different, John. I think, again, because of the actions that we've taken to get out ahead of the crowd, so to speak, I think that leads us in a place where we can be really disciplined and just focus on executing within the portfolio that we've got. As you've seen in the 1Q update here, we continue to be pretty focused on adding in the Permian. I would say out of the 1650, the biggest two-thirds of it was Permian, and then the next biggest place where we did bolt-ons was in the Montney. I don't think our view is any different in Canada versus the U.S.

And then for the follow-up question, if you make the decision to maintain production, even if you achieve efficiency gains and return capital to shareholders, where do you see long-term maintenance CapEx for the trend?

So we really see this guide that we've laid out here in '24 as repeatable for 2025. So obviously we're not guiding to '25 and beyond, but as we look out in the business, that's what we're seeing is the rateable activity program that we put in place this year. We can just roll that rate into next year again, and barring some big change inflation or deflation, we'd just see the same guide numbers that we rolled out today.

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

Thanks, Joana, and thank you everyone for joining us today. Our call is now completed.

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