Ovintiv Inc. (NYSE:OVV) Q3 2023 Earnings Call Transcript

Ovintiv Inc. (NYSE:OVV) Q3 2023 Earnings Call Transcript November 8, 2023

Operator: 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. [Operator Instructions] 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.

Jason 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.

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 ensured 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 turned 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 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.

Corey Code: 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. I’ll now turn the call over to Greg.

Greg Givens: 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 time line 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 on line 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 cost 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 single 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 on line 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 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 on line 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 on line 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 and 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.

Brendan McCracken: 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 turned 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 on line 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 turned in lines. Our turned in line cadence in the fourth quarter will be front-end weighted with more than 90% of the total company wells coming on line 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 act 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 on line 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.

Operator: [Operator Instructions] First question comes from Neal Dingmann from Truist Securities. Please go ahead.

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Q&A Session

Neal Dingmann: Thanks for the time, guys. Very nice quarter. My first question for the team is on the Permian specifically. Sort of like the — just the expansion of the operation. I’m just wondering, could you speak to the future potential project size changes there? And are you able to continue to expand the lateral length in most of the areas. So just wondering on those two aspects of the play.

Brendan McCracken: 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 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.

Greg Givens: 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.

Neal Dingmann: And then just, Brendan, a follow-up on the shareholder return, you guys are making just tremendous progress on the debt repayment in addition to having that solid shareholder return. So I’m just wondering — I know you’ve got that debt target of around $4 billion. Just wondering, thoughts about potentially accelerating the shareholder payout given what some others have done, maybe even before you get to that $4 billion, or maybe just talk about how you’re thinking about that overall plan.

Brendan McCracken: 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.

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

Gabe Daoud: 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.

Brendan McCracken: Hey Gabe. Yes, I appreciate the question. So, we’ve been very consistent with our projection on 2024 that will 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.

Gabe Daoud: And then, I guess, just as a follow-up, I’d love to get maybe some updated thoughts around industry consolidation. Obviously, the 3 for — with EnCap and integration is obviously going incredibly well, but just curious to hear your updated thoughts on Permian consolidation and just general industry consolidation. Thanks, guys.

Brendan McCracken: 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 undertook 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.

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

Doug Leggate: Brendan, I wonder if I could just ask you to maybe push you a little bit on two things you just mentioned. The first one is your CapEx guide for next year is $2.1 billion to $2.5 billion, still pretty wide. But this step-up in Trimulfracs, if I’m pronouncing that correctly, to 50% from 25% and the cost savings. It seems to me that you’re — you got to be pointed towards at least the lower end of that range, if not below. What can you tell us about that? And then, my second question, which is related is I just want a clarification really. Has any of the 20% legacy improvement — legacy well improvements or the application of the Ovintiv design to the legacy EnCap assets, are any of those included in that 200 base? Because that 200 base has been in place for quite a while.

Brendan McCracken: Yes. Doug, I mean, I’ll take them in reverse order here. So no, we haven’t changed the basis upon which we prepared that 200,000 barrel a day projection. You remember, right, it’s actually been in place since late Q1 when we announced the transaction and felt like we needed to give some color to 2024. So yes, no change to that. So we’ll obviously be incorporating the results that we’ve seen and putting them into a go-forward update in February when we traditionally would guide for ‘24. And then on the CapEx side, look, I think the — at any given moment over the last few months, the sentiment on inflation, deflation has moved around a fair bit. I think it’s fair to say. I think we’re still seeing the potential for some overall deflation.

And then, as you alluded to with things like Trimulfrac, we’re seeing the potential for some capital efficiencies to assist on that go-forward. So we’ll, again, take that into account as we prepare detailed guidance for ‘24. But we’re excited about the momentum that the team is creating and I think seeing the potential for a little bit of deflation, which I think no surprise has been led by OCTG prices as the category that’s created the most deflation potential that we’ve seen over the last few months.

Doug Leggate: 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?

Brendan McCracken: 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.

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

Scott Gruber: 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.

Brendan McCracken: I think for us, that decision will be driven by returns and free cash maximization. And you alluded to — today, we don’t see the world calling for additional barrels of growth. There’s enough cross currents out there that I think it makes sense to be patient and wait for those signals. But I think we continue to unlock efficiencies and that creates optionality for us. And if you look at one small example, I think it’s a little bit in the rounding, but we did elect to complete those four drilled and uncompleted wells in the Anadarko this quarter. Combination of the earlier well performance that we’re seeing from neighboring locations with an improved NGL and gas environment, relative to what we were expecting this summer and then the ability to get really competitively priced frac crews on it this quarter.

So I think we’ll manage those decisions as they come and make the right call from a return on invested capital and free cash maximization lens.

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

Umang Choudhary: The strong operational results is 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 Ovintiv unique in its ability to deploy this technology?

Brendan McCracken: Yes. I appreciate it, Umang. And what I would — I’ll get Greg to chime in here, but what I’d sort of set him up for is, there’s no trade secrets or intellectual property in our industry of any real meaningful node. And so, a lot of how we create value through innovation is with culture and expertise. And what we’ve seen over a long period of years here is that there’s a real path dependency to that learning and the ability to execute on things like Trimulfrac. But I’ll turn that over to Greg to chime in.

Greg Givens: 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 onetime 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.

Brendan McCracken: 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.

Umang Choudhary: 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.

Brendan McCracken: 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 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 go-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.

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

Greg Pardy: Thanks for the rundown. I was going to ask about LNG, but I think that sits where it does. With all of the calls the last couple of years, the Uinta has sort of gone from testing with potential now. I’m trying to get a better sense as to how you’d frame the size of that asset. And do you — and I think it competes already. So, what would be the limiting factors? Or maybe what are the parameters you’re looking at to really grow that business?

Brendan McCracken: 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.

Greg Pardy: And then maybe just shifting back to the Anadarko. What caught my ears, I guess, in listening to the commentary was cutting base decline rates in half. I’m just wondering if maybe Greg can touch on that a little bit as well as just where D&C costs are sitting these days versus, say, pre-pandemic.

Brendan McCracken: Yes. Terrific. Over to Greg.

Greg Givens: Yes. Thanks for the question, Greg. And first on the base decline, it’s just a series of just aggressive blocking and tackling by the team. We focused really hard on our artificial lift, installing plungers, keeping wells on line longer, worked on compressor downtime. I worked with the midstream operator there in the area, making sure that we’re able to handle all the gas from the field as we go forward. So just a lot of really consistent blocking and tackling effort. Obviously, as you slow down production, you eliminate — or excuse me, slow down drilling activity, you eliminate OFI as well. So a lot of pieces there, but just really great effort from the team to flatten that base decline. And we feel like they’re not done yet.

So they’re in a really good place. As we think about cost there, that’s a basin that has got great access to services. So, while the rig count is down in the basin, it is very easy to reactivate and get rigs and frac crews back to the basin as we just demonstrated with this frac crew we picked up for a short-term assignment. And so, the cost there will be similar to where we were prior to the pandemic, minus the tubulars. The tubulars are still — while they’re coming down, they’re a little higher than they were pre pandemic. But I think on a cost per foot, it’s going to be in line or below where the Permian is.

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

Roger Read: I’d like to follow up a little bit on what the — bringing the wells forward, and I guess just a little bit will tie into the Simulfrac, Trimulfrac kind of changes. But what else that means for you, right? So, you’re bringing wells on quicker, you’re bringing production on a little quicker. You get a little more capital efficient, but you’re also pulling some inventory forward. So, I just want to understand how you think about that within this overall logistics discussion we’ve been having on here about above ground versus below ground, but tying back to the belowground as you accelerate how that looks within the overall inventory picture.

Brendan McCracken: Yes. Roger, I appreciate it. And really, if you wind back to how we wanted to prosecute the business, we wanted to get to a load leveled activity across each of the assets and really create the capital efficiencies that that load leveling can offer. And we want to run the business to maximize free cash flow. And we knew that as inheriting that wells in progress inventory in the Permian that we got from the acquisition, we were going to have to slow down activity and feather that back to the load leveled program that we want to run. And we were able to accomplish that early because of great work by the team on the integration, but also, as you pointed out, just drilling and completing wells faster. And so really, we’re going to sit at that 5-rig level.

We’re already at that level here today, have been for a little while. And so that will — if we continue to drill and complete faster, that will bring more and more wells into each year’s program. But that’s where we get to Scott’s question earlier, which is, hey, do you pocket those capital savings or do you let that increased activity grow production modestly. And that’s really going to — that decision is going to come back to the free cash flow and return optimization that we talked about. So, it’s all very linked, as you’re pointing out. And as far as accelerating the subsurface and consuming more inventory, I think would just refer you back to my comments about why that’s been so important to swim against that industry tide and deepen the inventory and create a trajectory for Ovintiv, where we’ve got a very long-dated premium inventory to work with, and that’s going to generate the durable returns that we think are going to be valuable.

Roger Read: 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.

Brendan McCracken: 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.

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

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

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