Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv’s 2023 Third Quarter 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 third 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. 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. Our team delivered another quarter of impressive outperformance against our targets. We’ll get into the details in a minute. But first, I’d like to start with the steps we’ve taken to prosecute our durable returns strategy and ensure that Ovintiv is set up to create shareholder value. We believe a deep premium inventory is one of the three key ingredients to generating durable returns. Over two years ago, we recognized that the industry was likely to consume quality inventory at a rate much higher than it was replenishing. Fast forward to today, and that has definitely turned out to be the case. And the growing recognition of this deficit has been a motivator for the deal flow we’ve seen recently. We have moved against that broader industry tide and have both deepened our premium inventory and demonstrated our ability to generate superior operational and financial results to create value for our shareholders. We pioneered cube development to make the most out of the premium resource we have captured. We have continued to innovate to drive down costs and boost productivity. We have consistently converted upside locations to premium inventory by investing into organic appraisal and assessment on the acreage we already own. We closed over 200 highly accretive bolt-on transactions, and we made a significant step change with our Permian transaction earlier this year. Since 2021, we’ve added over 1,500 premium drilling locations to our inventory. We accomplished this by following a rigorous process to allocate our capital, and as a result, we accretively grew cash flow per share, free cash flow per share and maintained a strong balance sheet. Another area of intense focus for us has been consistent execution. Although much of the market’s focus this year has been on our Permian outperformance, each basin in our portfolio is contributing to our total outperformance. Across the Company, we continue to innovate and find efficiencies that reduce cycle times, lower costs and deliver leading well productivity. From production to capital to per unit cost, we once again beat our targets and enhanced the capital efficiency of our business. Our production beat in the quarter was driven by portfolio-wide well performance and excellent operational execution to efficiently turn in line our wells. I noted earlier that consistent execution is key to our story. And I’m proud to say the culture of innovation here at Ovintiv remains alive and well. Greg will touch more on this later, but our latest Trimulfrac innovation is unmatched in the industry today and setting the leading edge efficiency frontier in the Midland Basin. Our strong execution has accelerated our wells on line and is pushing 2023 production higher and stabilizing us at our 2024 run rate and free cash flow sweet spot sooner. We previously guided to a second half 2023 oil and condensate figure of 210,000 barrels a day. Using our Q3 actuals and the midpoint of our Q4 guide, our second half production will now come in at about 219,000 barrels a day or 9,000 barrels a day above our original guide. Finally, we’ve again raised our full year 2023 production guidance, our second raise since we closed the acquisition back in June. We have also narrowed the range and reiterated the midpoint of our 2023 capital guidance, despite bringing 15 to 20 more wells into 2023 from our program acceleration. Our third quarter results speak for themselves. Our team brought on 116 net wells, 16 more than planned, with 15 of those coming in the Permian. Our base production also outperformed, thanks to the work done by our teams to moderate decline rates. I’ll now turn the call over to Corey to cover our financial results.

Thanks, Brendan. Our operational success translated into strong financial results in the quarter with earnings per share of $1.47 and cash flow per share of $4.02, meeting consensus estimates. We generated free cash flow of $278 million and we returned approximately $127 million to our shareholders through share buybacks and our base dividend. Our share buyback this quarter was through participation in the EnCap secondary offering, which saw us purchase and retire 1 million shares. This buyback was an acceleration of our fourth quarter share repurchases, and as such, the $45 million we used to buy the shares will be subtracted from our planned buybacks in the fourth quarter, leaving us with $53 million of share repurchases to execute in the fourth quarter. We also saw strong per unit cost performance with operating expense, transportation and processing expense and production, mineral and other taxes coming in below the bottom end of the guidance on a combined basis. The third quarter was our peak capital and activity quarter. As our production crests and capital returns to our new run rate, we should start reducing debt more rapidly. With just over $6.1 billion of total debt at quarter end, our leverage ratio was 1.5 times. We remain committed to our mid-cycle leverage target of 1 times or about $4 billion of total debt, assuming mid-cycle prices. The maturity profile of our recently issued bonds will allow us to optimize our debt pay-down schedule as we work towards that target. And while debt reduction is a big area of focus for us in the near-term, our shareholder return framework remains consistent. We will continue to distribute at least 50% of post-dividend free cash flow to our shareholders with the remaining 50% going to the balance sheet.

Thanks, Corey. The top priority since closing our Permian acquisition in June has been the rapid and efficient integration of the assets into our existing business, and I couldn’t be more pleased with how the team has performed. Not only did we complete the integration ahead of schedule, but we also accelerated the timeline of wells in progress that were inherited with the transaction. Along with strong well performance across the portfolio, this acceleration was a driving factor in our production beat and raise for the third and fourth quarters. As Brendan mentioned, this acceleration has brought forward the wave of peak production and will allow us to stabilize our run rate at 200,000 barrels of oil and condensate per day in the second quarter of 2024. We have completed all the outstanding DUCs and are running 5 rigs and 1 frac spread in the Permian today, which is reflective of our run rate activity level going forward. Our Permian well performance continues to be very strong. Our legacy footprint is seeing year-over-year oil productivity per foot increase of more than 20%. This is primarily driven by a combination of completions design, real-time monitoring and stage architecture optimization. It is also worth highlighting that our consistent cube development approach currently ranks first in year-to-date oil productivity per foot versus key peers in the Midland Basin. The wells on our recently acquired acreage are performing in line with our expectations and have an average oil IP30 exceeding the 2022 and 2023 Midland basin average. Of the wells we brought on line on the new acreage since close, approximately 20 individual wells have shown IP30 oil rates of more than 1,100 barrels per day. We are optimistic about the 250 high-potential locations we identified in the early days of the acquisition and are actively testing those areas in horizons today. Across the portfolio, we typically allocate about 10% of our D&C activity to testing upside locations, and we are taking the same approach here. As we’ve noted previously, we see opportunities to increase well performance and capital efficiency on the acquired assets as we apply Ovintiv’s drilling and completion approach. We expect to see our first end-to-end Ovintiv designed wells online late in the fourth quarter of this year. Our focus on efficiency and innovation has been key in delivering leading well performance in the Permian. While our cube development approach has stayed consistent, we are constantly looking for ways to make our wells more productive and less costly. Our enhanced completions have resulted in well performance exceeding type curve expectations, and we’ve been able to achieve this without an increase to well cost. The simplest path to mitigate higher costs is to increase efficiencies and reduce the amount of time spent on location, and that is exactly what we are doing. Over the last few years, we have realized significant savings utilizing local wet sand along with our Simulfrac operations, but our Permian team has taken this one step further. We are stockpiling wet sand on-site from our local mines and completing three wells with the same frac spread at the same time, a technique we’ve dubbed Trimulfrac frac. Trimulfrac is reducing cycle time and saving costs. About a quarter of our Permian wells in 2023 will be completed with this technology, and we expect to use it in more than half of our program next year. The results are impressive. For example, on our recent Driftwood pad, we saved an additional $125,000 per well when compared to Simulfrac. We were also able to bring the pad online sooner with our increased efficiencies, achieving almost 4,200 feet of completed lateral per day. With the pad online sooner, it will have an incremental 55 production days in 2023, directly increasing our capital efficiency. This step change in efficiency is easy to observe but difficult to replicate and is unmatched in the industry today. Highly sophisticated logistics management is essential to execute these more complex operations, and this is where our team excels. Our Montney performance continues to demonstrate the expertise of our team in maximizing value from the play. Once again, Ovintiv dominates the list of the most productive wells in the play with our results accounting for over two-thirds of the top wells in the basin and a clean sweep of the top 20. The Montney is one of the largest remaining oil plays in North America, and our 2023 program continues to target that oil and condensate-rich parts of our acreage, where we have over a decade of premium and drilling inventory. Western Canada is a net importer of condensate, and this means we generally receive prices near or above WTI for our product. Year-to-date, we’ve realized 97% of WTI, making the Montney competitive with the top oil basins in North America. In Uinta, our two-rig second half-weighted program is delivering exceptional well results. We recently brought online our nine-well Tomlin pad with an IP30 rate of 1,490 barrels of oil per day per well. This recent pad, along with the other wells brought online year-to-date, are set to outperform the Delaware. Another high-pressure oily basin by almost 10% through the first 365 days, pretty strong results for a play that is still emerging. Our large contiguous land base of approximately 130,000 net acres has multiple benches across about 1,000 feet of collective pay. It is 80% undeveloped, which translates into significant inventory runway. Our scalable rail capacity to the Gulf Coast, where we rail about 30% to 40% of our volumes, diversifies market exposure and supports our future development plans. Due to the high oil nature of this play, year-to-date, the Uinta has been competitive with our Permian asset for the highest operating margin in our portfolio. The Anadarko team has done a great job optimizing efficiencies in the play. After pulling back the program earlier this year due to weakness in natural gas and NGL prices, the team had the opportunity to be patient and opportunistic in securing a competitively priced frac crew to complete our remaining DUCs in the fourth quarter. This will see us bring on a total of 26 turned-in-lines for the year. The team has also managed our base production very effectively and has cut base declines in half to about 20% since 2021. The Anadarko continues to be a strong free cash flow generating asset in 2023 and is a premier multiproduct option in our portfolio. I’ll now turn the call back to Brendan.

Thanks, Greg. Yesterday, we provided our fourth quarter guidance and updated our 2023 full year guide to reflect the improved well productivity across the portfolio and the accelerated turn-in-line timing in the Permian. The fourth quarter will be the high point for production this year. This reflects the impact of continued strong well results as well as the accelerated production momentum from the new Permian assets as we continue to bring the WIPs online ahead of schedule. If we compare back to our 2023 guidance at acquisition close, we have raised our expected total production by 4% while reducing our projected capital spend by about 2%, resulting in a capital efficiency improvement of about 6% since June. Our strong execution in 2023 is setting us up for continued success in 2024. We are again reaffirming our 2024 plan. Our plan maximizes return on invested capital and free cash generation. Our normalized and load-level program achieves this production level with $465 million less capital than 2023 and about 100 fewer net turn-in-lines. Our turn-in-line cadence in the fourth quarter will be front-end weighted with more than 90% of the total company wells coming online in October and November. As expected, our production will decline during the first quarter of 2024 before reaching our go-forward run rate of 200,000 barrels a day in the second quarter. In addition to the refinements to the 2024 scenario, we’ve included a preliminary cash tax outlook. We have mentioned previously that we expect to be subject to AMT next year. We recently completed an extensive project to identify and claim R&D credits. This was a multiyear study that resulted in $122 million of credits to reduce our 2024 tax in the United States. That savings is reflected in the estimates on slide 20 in our appendix. In summary, our durable returns strategy is working very well. I’d like to recognize our team for the outstanding operational and financial results we’ve delivered year-to-date and acknowledge their relentless drive for further innovation to make our business more valuable for our shareholders. We have significantly added to our inventory depth, successfully integrated the acquisition into our existing operations and have efficiently accelerated the inherited wells in progress inventory. We see opportunities for further upside going forward, and we are eager to bring our fully Ovintiv designed and executed wells online before the end of the year. We once again increased our full year 2023 production guidance, and we’ve tightened the range on our capital spending. And over the long term, we believe that value creation in the E&P space will come from companies that can demonstrate durability in both the return on invested capital and the return on cash to shareholders. We are positioned to deliver on this value proposition through our relentless focus on innovation, execution, disciplined capital allocation, responsible operations and leading capital efficiency. This concludes our prepared remarks. Operator, we’re now ready to open the line for questions.

The first question comes from Neal Dingmann from Truist Securities. Please go ahead.

Thanks for the time, everyone. It was a great quarter. My first question is about the Permian. Could you discuss the future potential for changes in project size there? Also, are you able to continue expanding the lateral length in most areas? I'm curious about those two aspects of the play.

Yes, Neal, we appreciate it, and I’ll get Greg to weigh in on some of the details here. But broadly speaking for us in the Permian, you should expect consistent lateral lengths year-over-year. And then, as far as occupation size, again, very consistent. In fact, if you go back over our last several years of Permian programs, they’ve been very consistent from an occupation size and also a well spacing perspective. In fact, 2023 and 2022 were the exact same wells per section, actually up a little bit on wells per section from 2021. So, ‘23 and ‘22 are up about 15% on wells per section, but very consistent. And so, we’re seeing that strong well performance without any upspacing in our go-forward programs. But Greg, maybe you want to comment on Neal’s thoughts on the program.

Yes. I guess the first thing you’ll see that will be a little different going forward, we always try to do things in multiples before because that fit very well to our Simulfrac technique. Going to Trimulfrac, you’ll see things in multiple of 6. That’s the way Trimulfrac works. As you frac three wells at a time while you prep the other three wells. So some slight shifts there, but you should see very similar overall occupation size and similar lateral length, as Brendan alluded to.

Brendan, I would like to follow up on the shareholder return. You are making remarkable progress on debt repayment while also providing a solid return to shareholders. I’m curious about your thoughts on possibly accelerating the shareholder payout, considering what some companies have done, perhaps even before reaching your debt target of around $4 billion. Could you also share your overall perspective on this plan?

Yes, no, appreciate it, Neal. I think we’re going to stay consistent with the shareholder return framework that we’ve been following, and we think that is a great balance of allowing us to create value for our equity shareholders, both through the cash return, but also by reducing debt and converting that enterprise value to the equity holders from the debt holders. So, I think for us, it makes sense to stay in that 50-50 mode and be consistent there. And really, what we’re excited about is accelerating into that free cash flow sweet spot and just overall generating more free cash flow for both debt reduction and cash returns.

The next question comes from Gabe Daoud from TD Cowen. Please go ahead.

Hey, thanks. Good morning, everyone. Thanks for taking the time and thanks for all the prepared remarks. Brendan, was hoping we could maybe talk a bit about ‘24. Just curious how much of your recent productivity and efficiency gains have you embedded in the program, the capital figure, and the production figures. Just trying to get a sense if there’s maybe downside risk to capital given Trimulfrac and then upside risk to production volumes.

Hey Gabe. Yes, I appreciate the question. So, we’ve been very consistent with our projection on 2024 that we’ll stabilize at that 200,000 barrels a day and at that capital range. So really, we hadn’t changed any of that in the projection that you saw today. I would say sitting here now, we feel highly confident in that projection. And to be clear, we expect to be at least 200,000 barrels a day in every quarter next year. And so, so far, we haven’t changed the basis that we used to prepare that projection. We’re, of course, very encouraged by the outperformance that we’ve been seeing all year on productivity. And also the performance that we’re seeing on capital execution and what that means for cost savings. We just think it makes sense to get all of the long-dated production data from as many wells as possible before we update or change that 2024 projections. So, I think the results this quarter and all year speak for themselves, and we’re excited to continue that through the fourth quarter here and into next year when we update that ‘24 guide.

I would like to know if you have any updated thoughts on industry consolidation. The integration with EnCap is going exceptionally well, but I'm interested in hearing your views on consolidation in the Permian region and the industry as a whole. Thank you.

Yes, no, I appreciate it. Gabe, it’s obviously been an area of focus for the industry. I think for us, we’ve been very focused on execution and the digestion and integration of the transaction that we undertook earlier this year and the bolt-ons that we had undertaken in the two years prior. So, we think our durable returns strategy has been very effective here. And we’ve done a lot in this space. And I alluded to in the prepared remarks, over 1,500 premium locations added over the last couple of years. And you can see that showing up in our results. So, I think for us, really focused on executing and creating value off the platform that we’ve created.

Thank you. The next question comes from Doug Leggate from Bank of America. Please go ahead.

Brendan, I'd like to ask you to elaborate on two things you mentioned. First, your CapEx guide for next year is between $2.1 billion and $2.5 billion, which is still quite broad. Given the increase in Trimulfracs from 25% to 50% and the cost savings, it seems to me that you should be leaning toward the lower end of that range, or even below it. What can you share about that? Secondly, I'd like to clarify if any of the 20% improvements in legacy wells or the application of the Ovintiv design to legacy EnCap assets are included in that 200 base, which has been established for quite some time.

Yes, Doug, I’ll address them in reverse order. We haven’t altered the foundation of the 200,000 barrel a day projection, which has been in place since late Q1 when we announced the transaction to provide some insight into 2024. There are no changes to that projection. We’ll incorporate the results we’ve seen and provide a forward update in February, as we typically do for '24. Regarding capital expenditures, the sentiment around inflation and deflation has fluctuated in recent months. It’s reasonable to say we’re still observing the potential for some overall deflation. Additionally, as you mentioned with Trimulfrac, we’re seeing opportunities for capital efficiencies that will factor into our guidance for '24. We're enthusiastic about the momentum our team is building and are optimistic about the potential for some deflation, primarily driven by OCTG prices, which have shown the most potential for deflation in recent months.

I appreciate that. Can I go for a clarification just on one point? The fact that you’ve not changed the base when you and I traveled earlier this year, you suggested that you don’t feel ready yet to declare if you’ve improved recovery or just accelerated production. Are you at a point now where you think you’ve got the answer?

I think that’s an answer that will come with time. I don’t think there’s a magical light switch moment where all of a sudden you’ve got precisely 90 days or 180 days of data. I think this is going to be a place we evolve into and derisk as we get more wells that are performing at that level. And as those wells have more data that convinces us on that. So yes, no light bulb moment to announce today, but I think, like I said, the results that we’re seeing year-to-date are piling up and giving us confidence as we go forward.

The next question comes from Scott Gruber from Citigroup. Please go ahead.

I want to continue on that line of inquiry. I realize the 200,000 plateau next year may move higher as you incorporate learnings from your second half program, hopefully, it does. But if your inputs kind of still indicate that the 200,000 is reasonable, which is a decent decline from your exit rate here in ‘23. Would you look at raising the well count to raise that plateau? Is that something you consider? I just think about backward dated oil curve and decent inventory in the play. I would think the NPV mass suggests that something higher is better. So just some additional thoughts there.

Our decision will focus on maximizing returns and free cash flow. Currently, we don't anticipate significant demand for additional production, and there are various market factors at play that suggest we should be patient and wait for clearer signals. We are actively working to enhance efficiencies, which provides us with flexibility. For example, we decided to complete four drilled but uncompleted wells in the Anadarko this quarter. This decision was influenced by the performance of nearby wells, a better NGL and gas market than we initially expected for the summer, and the availability of competitively priced frac crews this quarter. We will continue to evaluate our decisions based on return on invested capital and free cash flow optimization.

The next question comes from Umang Choudhary from Goldman Sachs. Please go ahead.

The strong operational results are obviously notable. Can you walk us through the evolution of Simulfrac to Trimulfrac? And can you also help us understand what is critical for its success and how is Ovintiv unique in its ability to deploy this technology?

I appreciate it, Umang. I’ll have Greg add to this, but I want to highlight that there are no significant trade secrets or intellectual property in our industry. Much of the value we generate through innovation relies on our culture and expertise. Over many years, we have observed that our learning has a strong dependency on past experiences and impacts our ability to execute initiatives like Trimulfrac. Now, I’ll hand it over to Greg.

Yes. Thanks, Brendan. And thanks for your question. Our teams have had a really great track record of always finding these new innovations and implementing them in a way to help improve returns in the Permian and across the portfolio. But in the Permian specifically, if you go back in time, we’ve been doing cube development here for a long time. Initially, it was through SIMOPS. We had multiple rigs and multiple frac spreads on each location. And we really focused on logistics to make sure we kept everything running smoothly and we were able to execute on those larger developments. And we saw the opportunity with Simulfrac that if we could start fracing two wells at the same time, that would really speed up the process and help us reduce cost and improve returns. And then, that kind of evolved into us pumping larger and larger amounts of sand. And so, as we put more sand, we realize we need to have a cheaper way to get that proppant. And that led us to get local sand mines to use wet sand and bring it to location. And then, as we continue to execute and pump faster, we said, well, gosh, we don’t need to have supply chain be a limitation on our ability to continue to frac wells faster. And that led us to the sand pile. And that allows us to keep inventory on location to make sure that sand doesn’t keep us from executing. As you see all these innovations, they kind of build on each other. You can’t just immediately jump to the last step in the process. You’ve got to build as you go. And really, the latest step in that process is Trimulfrac for us. And a little bit about how Trimulfrac works, it’s really simple. It’s the same process as Simulfrac. It’s the same equipment. We’re using one frac spread, to be clear. It’s just one spread with one blender. The only thing that’s different from a Simulfrac spread is we add a few more pumps so we can get some more rate and then we adjust the plumbing so that we’ve got pipe running to three wells. So we can pump down all three wells at the same time, stimulate three wells at the same time. And by doing that, we’re able to actually trim 3 to 4 days off of the time for each well, which saves us about $125,000 a well. And it’s been working really well for us. To be clear, this is not just an idea. This is something we’ve been executing on for some time now. We’ve done five pads already this year, executed really well. And that’s what gives us the confidence to start incorporating that into our future plans. So, as I said before, this is not just a new one-time thing for us. This is an evolution over time of all of these innovations building on each other. And that’s what I think gives us a unique advantage in the basin. It’s just where we’ve been is allowing us to go where we’re going today.

And I’d just add, Umang, like the whole point of all of this innovation is to create a more capital efficient business and have higher return on invested capital. And that’s the standard that we hold ourselves to. And we spend a lot of time looking at how we compete in that space and pretty consistently rank at the top of capital efficiency amongst a pretty high-quality peer group. And I think as Greg outlined, this isn’t a secret, but it’s really hard to imitate. And that’s where the value is for our business.

And maybe I’ll ask another longer term question, I guess. You had a spotlight event on the Montney assets last year, and you indicated the potential to unlock value through the build-out of midstream infrastructure. Can you give us an update on this? And as we head into this up-cycle in ‘25, ‘26, potentially on natural gas, how should we think about the capital allocation from a long-term perspective between Permian and Montney? It’s a little bit more of a long-term question, but would help your response here.

Yes, no, I’d love it. We’re obviously very excited about our Montney asset, and it’s really two assets in one. We’ve been trying to make sure the market understands that we have a Montney oil asset with a deep premium oil inventory, and then we have a Montney gas asset with an extremely deep premium inventory on the gas side. And in 2024, I think we’ll see around 20% of our capital deployed in the Montney, and that’s all going to be deployed into the oil window. So, we make a lot of gas in the Montney because of the legacy base production but where our capital has been focused going forward in ‘24 is going to be in the oil window. But definitely, down the road, we see the opportunity for the Montney gas to create a lot of value for our shareholders. And that’s something, of course, we’ve been exploring to get market access to better price environments for the Montney. We’re set up to access all ex AECO environments for the next three years. And then, we’ve got a deep transportation portfolio that persists even out past that ‘25 time line that lets us stay outside of the AECO environment. And of course, we’re exploring the potential for LNG exposure down the road.

The next question comes from Greg Pardy from RBC Capital Markets.

Thanks for the overview. I was going to ask about LNG, but I believe that situation remains stable. Over the past couple of years, the Uinta has shifted from testing to showing potential. I'm trying to understand how you assess the size of that asset. I believe it already competes in the market. What do you see as the limiting factors, or what parameters are you considering to grow that business?

Yes. I appreciate it, Greg. The Uinta really has been unlocked in two ways. One, we unlocked it with a demonstrated cube development. And then, we also unlocked it with market access. So we’ve shifted that basin from being solely only able to access the Salt Lake City refinery market to now we are moving about 40% of our oil production to the Gulf Coast. And so, what that’s done is really enhanced the margin in the play and in particular, enhanced the margin stability in the play. So, it’s taking the volatility out of realized prices there. And so, today, our Uinta basin margin is consistent with our Permian basin margin at the top of the portfolio. So, both the well performance and the market access unlock have been important. To get to your question around like where are some of the natural limits there, I think we can continue to see Uinta production grow pretty robustly from where it is today for us because we have those market access options. And so, I think we’ll continue to be pretty disciplined on capital allocation there and just continue to step into the play, but we’re excited about the trajectory that it’s on.

Thank you for the question, Greg. Regarding the base decline, it results from the team's diligent efforts. We have focused intensely on our artificial lift, installing plungers, extending the production life of wells, and minimizing compressor downtime. I collaborated with the midstream operator in the area to ensure we can manage all the gas from the field moving forward. There has been a consistent effort to address these challenges. Naturally, as we reduce production, a decrease in drilling activity also impacts OFI. There are many components to consider, but the team's strong effort has been key in stabilizing the base decline, and we believe they still have more to achieve. They are in a favorable position. In terms of costs, this basin has excellent access to services. Although the rig count is currently lower, reactivating rigs and frac crews is straightforward, as shown by our recent short-term frac crew assignment. Consequently, costs should align closely with pre-pandemic levels, excluding tubulars, which are still slightly elevated compared to pre-pandemic prices but are decreasing. Overall, the cost per foot is expected to be comparable to or lower than the Permian.

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

I’d like to follow up on the acceleration of bringing wells online, which relates to the changes in Simulfrac and Trimulfrac. What does this mean for you? By bringing wells online and production sooner, you're becoming more capital efficient, but you're also advancing some inventory. I'm interested in how you view this in terms of our overall logistics discussion about above ground versus below ground, particularly how this acceleration fits into the broader inventory context.

Yes, I appreciate it. If you think back to our strategy, we aimed to achieve a balanced level of activity across all our assets to enhance capital efficiency. Our goal is to operate the business in a way that maximizes free cash flow. With the wells in progress inventory we acquired in the Permian, we expected to slow down activity to align with our load-leveled program. We managed to transition to that program efficiently, thanks to the team's excellent integration work and our ability to drill and complete wells more quickly. Currently, we're operating with 5 drilling rigs and plan to maintain that level. If we continue to improve our drilling and completion times, we can bring more wells into our yearly plan. This ties back to Scott's earlier question about whether to save capital or allow increased activity to modestly boost production. Ultimately, this decision will hinge on our focus on free cash flow and optimizing returns. Additionally, regarding our subsurface efforts and inventory management, I want to emphasize the importance of building a strong inventory that positions Ovintiv for sustainable returns over the long term.

No, agreed. I’m not advocating for acceleration. Just trying to understand where it all fits. And then, the only other question I have, everybody is focused on M&A. You’ve obviously been involved in some of it yourself. But what about on the disposition side? Is there anything we should be watching on that front? As you think about it from a high-grading perspective, something you know that isn’t anywhere near front burner, anything like that we should be watching for? Thinking also as a way to accelerate debt reduction. Thank you.

Yes, Roger, I appreciate the question and certainly something we think about, but we’re pretty happy with the portfolio that we’ve created. It’s highly focused. Each asset is contributing free cash flow and each asset is competing for capital. So pretty happy with the portfolio we have, but always seeking to understand how we could create value and bring it forward for our shareholders.

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

Thanks, Joana, and thank you all for joining us today and for your continued interest in Ovintiv. Our call is now complete.

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