Thanks, Michelle, and welcome, everyone, to our third quarter '22 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 prepared remarks, we will be available to take your questions.

Please limit your time to one question and 1 follow-up. I will now turn the call over to our CEO, Brendan McCracken.

Good morning. Thank you for joining us.

Our third quarter results demonstrate that our strategy to deliver superior, durable returns and substantial free cash flow is working. This strong financial performance is directly translating to increased cash returns to our shareholders.

In the quarter, we doubled shareholder returns to 50% of post-dividend free cash flow. As a result, we bought back 2.5% of our shares outstanding in the quarter.

We delivered these additional buybacks ahead of our original plan due to our significant debt reduction and strong business performance. We remain on track to deliver about $1 billion to our shareholders this year through the combination of share buybacks and base dividend.

And this amount is set to grow significantly in 2023 as our new hedging policy comes into effect. To put it in perspective, under our new hedging program, our third quarter free cash flow would have totaled approximately $1.3 billion or about $5 billion on an annualized basis.

This has us very excited about unleashing the free cash flow generating potential that we have built into our business. In addition to increasing cash returns, we continue to make progress reducing debt.

At the end of the quarter, our net debt to adjusted EBITDA ratio was below 1 turn. Our team delivered another quarter of strong operational results with outperformance from our new wells in our Montney, driving natural gas and NGL production to the high end of our guidance range, which in turn delivered total production levels also at the high end of our guidance range.

We are focused on maximizing free cash flow and returns in an inflationary environment. As a result, we've elected to preserve capital by slowing down some of our planned fourth quarter completions activity in our U.S.

basins. We chose to finish our Montney completions to have those wells online and exposed to higher gas prices through this winter season.

Greg will cover the specifics of our updated guidance. We're increasing total full year production by 5,000 BOEs per day and holding capital at $1.8 billion.

Our reservoir management and planning expertise is also paying off. We continue to see consistent well performance in the Permian, where we have been in cube development mode since 2015.

Our approach has not changed. As Greg will show, our well performance year-to-date is both generating strong return on invested capital, over 200% IRRs on strip pricing but also is generating very consistent year-over-year oil productivity per lateral foot.

I'll now turn the call over to Corey, who will cover our financial performance.

Thanks, Brendan. We delivered strong financial results in the third quarter with net earnings of $1.19 billion, EBITDA of $958 million, free cash flow of $437 million and cash flow per share of $3.70 beating consensus estimates.

Third quarter production came in at 516,000 BOE per day with each commodity within or above our guidance ranges. We were very pleased to deliver a significant increase in our direct returns to our shareholders this quarter.

We announced in early July that our return of free cash flow to shareholders would increase from 25% to 50%. With this jump to 50%, we delivered $387 million in share buybacks and base dividends.

We also maintained our commitment to reducing our absolute debt levels. We lowered net debt by almost $300 million, and we opportunistically repurchased about $500 million of our senior notes.

Over the long term, the most valuable E&Ps will be the companies that can demonstrate durability in their cash returns. We possess a premium, multi-basin portfolio that is uniquely balanced to exploit both crude and condensate, and natural gas opportunities across our North American asset base.

We possess a substantial inventory runway and our inventory counts are the result of a rigorous annual depletion plan process, which plots actual sticks on our acreage. The outcome is a well-balanced portfolio of premium drilling opportunities, more than 10 years of premium oil and condensate locations and more than 20 years of premium natural gas locations.

While having the resource under foot is a great starting point, efficiently converting the resource into cash flow is critical. This is why we are so focused on delivering top-notch capital efficiency and operational execution as this reflects our ability to extract value from our assets.

Finally, maintaining a thoughtful and disciplined capital allocation approach is key. If you're successful in finding and converting resource into cash flow but leak that cash by chasing the drill bit or dilutive M&A then the value captured never makes its way to the shareholder.

We are resolute in our focus on our return framework and remain committed to delivering substantial returns for our shareholders. When we combine our premium inventory and leading efficiency with this disciplined capital allocation, result is significant free cash flow generation.

Our 2022 free cash flow yield of about 16% is about 20% higher than our peers and more than 3x the average of the S&P 500. If we were unhedged this year, our free cash flow yield would more than double to almost 40%.

This is an amazing setup for our shareholders going into 2023, and it reinforces our desire to repurchase shares with free cash flow. Our substantial free cash flow profile is allowing us to return meaningful cash to our shareholders.

Based on our third quarter free cash flow, we expect to return $250 million to our shareholders in the fourth quarter. This translates to an annualized cash return yield of 7%.

If we remove the $821 million impact of our hedges for the calculation, our cash return yield would more than double to about 19%. Even without the hedges removed, our 7% cash return yield is significantly higher than the broader market.

When looking at what our cash return yield would be on an unhedged basis, it is more than 4x the broader market. The roll-off of our 2022 hedging program is imminent.

And when we look ahead to 2023, the uplift to our cash flow generation is substantial and will result in incredible upside for our cash return profile. During the quarter, we continued to make significant progress in reducing debt and optimizing our capital structure.

We lowered net debt by $294 million to $3.6 billion. This represents almost $1 billion of net debt reduction so far this year.

In addition to lowering our net debt, we're taking a proactive approach to reducing our absolute debt and the interest costs that go with it. Over time, these permanent savings make room for further dividend increases.

We purchased over $500 million of our senior notes in the open market during the quarter, bringing our year-to-date total to $565 million of long-term debt retirement, the associated annual interest savings is significant at more than $32 million. We will continue to be opportunistic on this front going forward as higher interest rates lower the price of these bonds.

Our strong performance has generated a trailing 12-month adjusted EBITDA north of $4 billion, driving our current leverage ratio to 0.9x at the end of the quarter. The resiliency of our business and our ability to withstand market volatility over the long term remains a priority.

As such, we're committed to further debt reduction. Fortifying the balance sheet now during a period of strong commodity prices will allow us to be both resilient and opportunistic.

We're constantly looking for ways to maximize the value we receive for our products. When it comes to natural gas, we've been actively managing our pricing exposure, securing flow assurance and contracting access to diverse markets for decades.

We expect both the AECO and Waha gas markets have periods of tightness through the end of next year, where production comes close to or even exceeds in-basin demand and export capacity. We've been very proactive to ensure we can get our natural gas volumes to market and to minimize our exposure to local market pricing.

In Canada, we hold substantial capacity on 4 of the 5 major egress pipelines exiting AECO and this covers about 65% of our volumes. An additional 20% to 25% of our Montney price exposure is covered by basis hedges.

These convert our natural AECO exposure to NYMEX. So while the gas will be physically sold at AECO, we effectively receive a NYMEX base price for those sales.

The result is more than 90% of our Montney production is priced at markets outside of AECO from now through 2025, providing protection from potential price weakness there. We've implemented a similar strategy for natural gas volumes in the Permian.

About 75% of our volumes flow to the Gulf Coast markets via the Whistler and Gulf Coast Express pipelines. Another 20% is protected by Waha basis hedges leaving only 5% of our 2023 Permian gas volumes exposed to Waha pricing.

I'll now turn the call over to Greg, who will provide some operational highlights.

Thanks, Corey. Capital efficiency remains a primary focus for our asset teams across the organization.

And as Corey mentioned earlier, efficiently converting our resource into cash flow is a crucial aspect of our durable return approach. Our cube development method optimizes both the returns and the NPV of each acre we develop.

The result is that our capital efficiency ranks top tier among our peers and is creating exceptional value in today's volatile commodity and macroeconomic environment. No matter how you look at it, Ovintiv is delivering more barrels and BOEs for less capital than our peers.

This efficiency edge generates higher returns on invested capital and allows us to deliver higher cash returns to our shareholders. If we were to use the peer average for capital efficiency in our 2022 program, we would have had to invest another $350 million to deliver our targets.

Put another way, we are generating an incremental $350 million of free cash flow this year, value that we are returning to our shareholders. Ovintiv has long been an industry leader in resource stewardship and concurrent multi-zone development through our cube model.

We took a customized stacking and spacing approach in each multi-well pad to optimize recovery and deliver the highest NPV for every acre of land we develop. The benefits of our approach are very evident in the Permian Basin.

We've studied the play extensively over the last 8 years, delineating the asset by drilling across our entire acreage footprint and entering into extensive data trades with our peers in the Midland Basin. We are targeting up to 6 benches across the play, and we see further upside and additional prospective horizons.

The depth of our technical understanding and our ability to execute are demonstrated in our well results. Our 2022 program performance is right on top of our 2021 results.

It is important to note that these 2022 results reflect all of our wells online year-to-date and a representative of full development stacking. At current strip prices, our Permian wells deliver a greater than 200% rate of return and payout in less than 10 months.

Just a few weeks ago, we highlighted our Montney asset to the investment community as we believe it is undervalued by the market. Our Montney webcast is still available on our website, but as a quick recap we are expecting over $2 billion of upstream operating free cash flow this year, the highest among all of our assets.

This is driven by our leading capital efficiency and outstanding well results. At strip, both our gas and oil and condensate wells generate returns north of 200%.

We also hold a premier acreage position with multiple phase windows and substantial product optionality. We have a premium inventory runway of more than 10 years in the oil and condensate window and more than 30 years in the gas window.

Importantly, we have secured market access and strong price realizations for our products. Our condensate production trades in line with WTI and more than 90% of our natural gas volumes are priced outside of AECO going forward.

Finally, and I will cover this further in a minute, our proven culture of innovation has driven unmatched operations in the basin. As you can see, we are the clear industry leader across multiple key efficiency and operational metrics.

These results are not by accident. We take great pride in our team's ability to innovate and push the efficiency frontier.

In the third quarter, we brought online a 15-well Montney pad that stacked multiple innovations together to deliver record results. On the drilling side, our redesigned drill bits and optimized motors set an Ovintiv Montney drilling record of over 2,400 feet per day.

Not to be outdone, our completions team utilized real-time frac optimization and simul-frac operations to set an Ovintiv Montney completions record of 10,375 feet per day and a proppant record of over 19 million pounds per day. Finally, we use multiple coiled tubing units and integrated service rigs to seamlessly tie in 15 wells and set an Ovintiv Montney pad production record of 12,000 barrels per day of condensate.

This case study clearly shows the power of our culture of innovation, and I want to reinforce how proud I am of the team and their delivery of these results. Our operational execution in the quarter was not limited to just the Montney.

In the Permian, our efforts across the entire development process, drilling, completions, facilities, production and tie-in resulted in a 20% faster spud to first sales cycle time versus our 2021 average. A similar effort in the Anadarko focused on our simultaneous operations and alleviating bottlenecks, delivering a 25% faster spud-to-first sales cycle time versus our 2021 average.

Finally, in the Bakken, we achieved record completions performance of more than 6,300 feet per day. We are also seeing strong well performance from our recent 10-well [cramer] development with an initial 30-day average oil production of 1,900 barrels per day per well.

It is no secret the operating environment remains challenged but we are responding with innovative solutions. We are confident in our ability to generate superior asset level returns and maximize capital efficiency.

That said, our teams have had to be very agile this year and responded in real time to inflationary pressures and supply chain bottlenecks. These challenges still persist.

We have made a number of changes to our fourth quarter program to optimize our operations and set us up for continued success in 2023. We've updated our fourth quarter and full year 2022 guidance to reflect these changes.

First, capital discipline remains a priority for us. We've maintained the high end of our full year capital range at about $1.8 billion but this will mean slowing down activity levels in some of our operating areas as we approach the end of the year.

Inflationary pressures continue to persist throughout the industry, but they are more acute in our U.S. assets.

In response, we are leveraging the optionality of our portfolio by slowing down fourth quarter completions activity, primarily in the Anadarko and Bakken, while maintaining our planned activity levels in the Montney. We will build an incremental DUC inventory of about 15 to 20 wells.

This is beyond what we consider normal operational DUCs and we'll see us exiting the year with about 35 to 40 total drilled but uncompleted wells. We will take a methodical approach to bringing these wells on production throughout the first half of next year.

We also made the decision to change out our frac crews in the Permian and Anadarko. Our new crews are set to begin working for us in the coming weeks, and we are confident in their ability to deliver industry-leading performance.

We also expect this will help us deliver a more ratable program in 2023. Additionally, we've seen a delayed return of oil volumes in the Anadarko following line pressure issues that persisted throughout the third quarter.

These issues have been largely resolved with the installation of additional infield compression, and the team is working to unload these wells through the fourth quarter. The combination of lower-than-expected fourth quarter production in the Anadarko and the slowdown of completions activity in the oilier plays will result in lower fourth quarter oil and condensate volumes.

Despite these headwinds, our full year total production guide has increased by about 5,000 BOE per day as a result of strong outperformance from our Montney asset. To be clear, the increased natural gas volumes we are expecting from the Montney this quarter are not the result of lower royalties, rather, they are driven by the exceptionally strong well performance.

The Montney also benefits from less cost inflation than our U.S. assets and has a strong outlook for natural gas prices through the winter months.

Finally, our total cost guidance for the year is unchanged. I'll now turn the call back to Brendan.

Thanks, Greg. Before we move to Q&A, I'd like to sum up the key takeaways from today's call.

First, our team delivered another strong quarter of financial and operational results. We're increasing full year production guidance and maintaining capital.

We're one of the most capital efficient operators in the industry. Our team is meeting the challenges of cost inflation and supply chain disruptions with agility and innovation, and we are optimizing our development plans to create value for our shareholders.

We're actively delivering on our durable return strategy. We're investing to earn superior return on invested capital that fuels our free cash flow.

Our cash return yield from our base dividend and buybacks is market leading. It exceeds that of the S&P 500, and it is poised to more than double in 2023.

Finally, we're resolute in our determination to close the valuation gap between us and peers. We're doing that today by buying back our shares and ensuring we can deliver those durable returns over the long run.

Operator, we're now prepared to take questions.

This is John Abbott on for Doug Leggate. Our first question is just given the fourth quarter guide, for oil and condensate, how do you see sustainable production for oil and condensate just sort of going forward?

And now look, are you in that sort of 175,000 barrel per day range to get back to 180,000 barrels per day. How do you sort of think about that?

John, yes. So one of the objectives that we have coming into '23 is to create a more ratable production profile for our business.

And so that's sort of connected through to our choices that we made with capital in the fourth quarter here. And so what we've been leaning into, and this is consistent with what we've been saying really all year is in this macro environment with the opportunity we have on buybacks, it continues to make sense to us to be in maintenance mode.

And so what you should expect from us is to be holding activity flat year-over-year, which will translate through to production that's going to be flat after correcting for divestitures on a year-over-year basis. And obviously, we're still working the details of that '23 program now, and we'll give more of an update in time.

But really, that's the game plan that we're operating under here. And the year-over-year flat after divestitures is the way to think about it.

Appreciate it. And then for our second question related to the Anadarko line pressure issues.

It sounds like you're moving past those issues, those wells -- those issues are being resolved. But what steps have you taken or how -- what steps are you taking in the future so that this does not arise potentially again?

Yes. No, great question, John, and that has been an area of focus for us really since the early months of the summer when we realized that this was going to be a challenge for our midstream provider there.

So I'm going to maybe just turn it over to Greg to comment on the steps the team has been taking to make sure that this isn't a recurrent problem for us when we get into the warmer weather next summer.

Thanks, Brendan. And yes, just to build on that a little.

As we went through the summer, we had two issues that were impacting us in Anadarko. We were bringing on our new wells that were adding volume to the system and that was combining with high temperatures that just caused the system to fill up.

What we've done since and working with our midstream provider as it's their system, we've added additional -- they've added additional compression to draw down the line pressure. They've added some coolers to cool the gas and handle the hotter temperatures and overall just work to debottleneck the system.

And we feel like those efforts will be resilient and help us not only during the current time, but also when weather gets warm again next summer. The impacts to our production were throughout the third quarter, but we've got the issues behind us.

And now we're working to unload the wells. The wells in the Anadarko were predominantly on gas-assisted plungers as an artificial lift form.

And so it's taking a little time to line those back out and adjust to the new current operating conditions. But we feel like throughout the quarter, we'll be getting back to regular production levels from the asset.

This is Jeanine Wai. Our first question is related to just inflation in the Montney.

The prior plan was to have Montney activity, we believe, increasing next year since 2022 was a bit low due to some permitting things earlier in this year. But is there a case to be made that potentially next year, you could skew a little even more to the Montney given that it seems like there's significantly less inflation there, and you have really, really strong well performance or -- is there some kind of, say, natural governor on activity based on how much direct price exposure you want to echo.

Yes, Jeanine, great appreciate the question. Absolutely, we're going to see the capital program in the Montney go up year-over-year because we've now got the permitting challenge behind us and the returns there are very strong.

I think what you should expect, though, is we're not making some strategic shift to the commodity mix in the company. We're not making a strategic shift to gas here.

We did elect to complete out those Montney gas wells in the fourth quarter here and have them on stream for what we expect to be a higher winter price than summer, but that was really more of a tactical call than a strategic call. And so what you should expect is our Montney program is still going to be pretty dominated by investment into the condensate window and driving the production and returns from that conde window.

We'll definitely do some gas drilling as well, but not a big shift from what you've seen from us in the past. So it's really '22 is sort of the anomaly year where investment in the Montney was down because of the permitting delay, and this is kind of getting back on track in the play for us, because we definitely are going to pay attention to the broader gas macro at NYMEX since that's going to be where the bulk of our price exposure is going to be over 90%.

But we'll also be sensitive too on the margins, additional gas production for us in Canada will be AECO exposed. So that's definitely something we're thinking about as we're allocating capital within the portfolio.

Okay. Great.

Our second question, I just wanted to go back to something we just heard in the prepared remarks. It sounds like you said you just switched out your frac crews in the Permian and the Anadarko.

So just wondering really how much of your 2023 service activity do you already have secured. I think the prior commentary was that many of your service contracts were rolling off maybe this quarter or early next and so that was kind of driving some of the inflation out to next year.

So how does this kind of change over in the frac crews and everything? How does that factor into your decision to build the 15 to 20 DUCs.

Yes, for sure, Jeanine. The change out of the frac providers really is not connected to the DUC decision at all.

The choice to not complete those wells was really driven by our strategy on free cash generation and using that free cash to drive buybacks at the valuation that we sit at today. So that was really that calculus.

And then -- but you are correct, the service contracts for us are rolling at year-end. And so what we've done is run an RFP process to determine who the best provider for us will be for '23.

We've made those choices, and we're now in the midst of making that cut over to those new providers. And maybe, Greg, if you want to comment on any specifics there.

No. Thanks, Brendan.

Yes, we -- just as Brendan said, as those contracts roll off, we went to our large pool of providers that we've worked with for many years and selected that we think we'll be the best provider for next year, and we've got that work secured and look forward to getting a running start into 2023. We're all set up and have our services we need to deliver on our program for next year.

My first question really let's just -- is on probably what I'd still say is the topic to zero, and that’s capital allocation. And Brendan, I'm just wondering specifically, would you all consider -- obviously are doing a great job on the buybacks, but I'm just wondering would you even consider lean in harder into these in the coming quarters, especially if your free cash flow, I mean, we see it well, we're still 20%, one of the better out there.

Would that still be kind of your primary shareholder return?

Yes, Neal, on the buybacks, absolutely. I think at these valuations, it continues to be the clear winner in terms of how to return cash to the shareholders.

We obviously also have at the foundation of our capital allocation model a sustainable and growing base dividend, and that will be something that we'll be looking at through the year as well. But today, the buybacks are quite attractive.

Really, if the macro stays where it's been recently, we’ll see significant cash returns and debt reductions next year, which could be a point at which we contemplate going above the 50%. But as you pointed out, even at the 50% our free cash flow yield is well above peer average and 3x the broader market.

So it's set up to be in a pretty good place.

Yes, I would agree. Okay.

And then second question, just on operational activity. Specifically, on the press release, you all did a good job highlighting just what I see, call it, still certainly upside from the Permian, Montney and Anadarko.

And what I'm curious is, could you just maybe discuss a little bit? I know you've got some interesting acreage, if you could discuss current activity, potential upside potentially in your Bakken and Uinta plays, haven't heard as much on them recently.

Yes. I'll tee this up for Greg because it's both the Bakken and the Uinta have been particularly highlights this year on just some monster well performance.

So I'm going to turn it over to Greg to comment there.

Yes. Thanks, Brendan.

Yes, as I mentioned in the prepared remarks, we've seen some really strong performance from the Bakken this year. We had high expectations for the asset and what those wells could deliver, and they haven't disappointed that 10-well [cramer pad] at IP30s of over 1,900 barrels per day per well.

We're really glad to see that. And really, that's the result of our multi-basin strategy of taking learnings from one basin and applying them across the portfolio.

So we were able to really apply industry-leading technology to these completions, leaned in a little bit on completion intensity, which is something that hasn't really been done much historically in the Bakken and really saw great results. So very happy with what we're seeing in the Bakken.

Again, it's always been very competitive with our other assets. It's just the inventory life there.

It's not quite the same as our others. Shifting to the Uinta, we've got some really positive results there recently as well.

If you look back, and you can see this in the public data, the last 10 wells we've drilled there have averaged just over 1, 900 barrels per day in their first month and the 3 most recent wells are actually over 2,000 barrels a day. So seeing really strong well results from our cube development there in the Uinta and also seeing really, really strong margins.

The team has done a great job moving our barrels. We're now assuming a number of barrels via rail down to the Gulf Coast.

And so our margins there in the third quarter were right in line with the Permian, so some of the strongest in the company. And just as a reminder, in the Uinta, we did have the asset sales that closed in the quarter, but that was the legacy waterflood that we divested.

We still have our -- approximately 130,000 net acres there in the core of the shale play. And as I just mentioned, the results there are looking quite promising.

Most of my questions have been answered. But Brendan, you talked about more ratable program next year and still sort of flat, I guess, year-over-year ex the dispositions.

How should we think about CapEx maybe from 2 fronts. One is maybe just on a -- like would you expect it to be relatively stable on a quarterly sequential basis, and then what about inflation, especially now that you've got some of your other services locked in?

Yes, Greg, that's what we're working towards is a more ratable production profile, but that will also come with a more ratable capital profile. The big objective, of course, is to be highly efficient with the capital and maximize free cash flow, and this is consistent with the remarks I think we made even last quarter.

Sitting here today, the inflation pressures we've been saying feel like a 10% to 20% range year-over-year, and it's really kind of pointing more towards the high end of that range. And so that's where you should expect us to be on capital next year.

And then the 15 to 20 DUCs that we're carrying into will be completed through the front half of the year. So we're not going to bring on spot crews to go ahead and undertake that work.

We'll do it with the existing ratable activity level. So they'll get completed through the front half of the year.

Okay. Perfect.

And then maybe just the second 1 is to match up the change in production mix, the alteration and production guidance. How much capital did those decisions save you in the fourth quarter?

Yes. If you just do the completion cost on those 15 to 25 wells, Greg, it's on the order of $70 million to $85 million.

I'll start with a follow-up on shareholder capital returns. And Brendan, you talked about contemplating I think, was the word, an increase beyond the current 50% on achievement of $3 billion of net debt, which on our math is just around the corner.

But more generally, what are the factors that will ultimately drive the decision to either stick with 50% or take that commitment higher?

Yes. I think, Menno, it's really going to be a quarter-to-quarter choice that we're going to look at.

So I don't think there's a particular set of circumstances. And really, if you remember, the $3 billion trigger was really all about shifting to the 50%.

So I don't really see that as a governor on our choices going forward. So in a lot of ways, what we're going to look is to see how the macro is shaping up for the year.

Obviously, there's uncertainties in that picture as we sit here today that we're learning more on every day. And that will just really drive how we think about the balancing act between continued debt reduction and more cash returns.

And as we look at it today, we're poised at the 50% level to have an outsized cash return yield. And so we know the buybacks are the tool that we have in the quiver to drive that valuation increase.

And so we'll kind of manage it quarter-by-quarter as we go.

Perfect. And then just moving on to the Montney and with the understanding that you've already locked in the majority of permits -- BC permits for 2023.

Is there any update on the status of bilateral talks between Blueberry First Nation and the government? And is it possible that we see resolution before the end of the year?

That's certainly the objective that we're being told by the BC government to have a resolution imminently. But that's why we've gone ahead and made sure we're in good shape to be able to execute on the '23 program.

And so really anything from this point forward is kind of upside for us. And I think you know this, Menno, but for the benefit of everyone, the acreage position we have in the Montney is all on the lower-risk permitting part of the play here.

And so that's what's been able to unlock our ability to have that confidence in the program and have those permits in hand as we're just in a part of the play where we don't have that exposure to the more challenging permitting acreage. So feeling good about it, and we'll just sort of see and I think it's helpful generally to have a specific resolution, but pleased with where we sit.

Most of my questions have been asked, hopefully, 2 quick ones for you. You talked about lower 4Q oil and condensate production due to lower sales in the quarter.

Can you remind us when these wells are coming online? And any thoughts on exit 2022 production and implication for production cadence next year, early next year?

Yes, Umang, appreciate the question. So the DUCs that we're not turning in line this year, they're going to be spread throughout the front half of next year.

And then the question on where does that leave us for exit, we are seeing our fourth quarter TILs come down as a result. So we were almost 70 turn in lines in the third quarter.

That's going to be more in the low 40s in the fourth quarter. And so I think we'll be in the guidance range on exit as well as for the quarter, and that will set up the 2023 and we'll give some more color on the shape of 2023 in due time here.

But that lower turn in line, obviously, is going to have a flow-through effect to the first quarter in '23.

Great. And then my next question and hopefully a quick one.

On Permian productivity, Slide 12 highlights that you have kept your productivity at this well flat this year. Would love your updated thoughts on how long can you keep the productivity of those wells flat going forward given that you have been early in shifting to cube development.

And then as you think about the bolt-on opportunities, especially in the Permian, how is the market today?

Yes. So the first question there on the productivity piece, I mean, this is just really important.

So we've been in the cube development mode all the way back to really when we entered the play. And so this has no change to our development strategy.

We've been developing the full stack at density since that time. And so I think the answer to your question is the premium inventory runway that we talk about is over a decade in the Permian.

And so it's our job to ensure that productivity stays at that level through that whole runway, and that's the approach we're taking. And feel pretty confident because we're seeing that show up in our results.

And then Umang, just remind me the second part of your question there?

Just on the bolt-on opportunities in the Permian, how is the market right now?

How is the market. Yes.

This has been a space where we've been really pleased at the progress we've been making. We've added a considerable number of locations in the last year through this bolt-on program at really accretive values.

We're now on track to replace all of this year's drilling consumption, both in the Permian but across the whole portfolio. So some 230 locations between our -- both our organic as well as our bolt-on program so pleased with how that's making progress.

And the market, I think, has probably, if anything, improved a bit as we've gone through the year, I think seller expectations have gotten a little more reasonable as commodity prices have stabilized and the backwardation in the market has continued. And you've seen that with some of the larger transactions that have appeared recently, and we've seen that as well in the smaller bolt-on space.

First, just a clarification on the earlier question around '23 CapEx. As you said, Brendan, you've been messaging sort of 10% to 20% higher -- the possible bias towards the upper end of that range, so call it around 2.1 billion or so.

I just wanted to clarify, that's still a good number, even with the $75 million to $80 million of CapEx associated with the DUCs getting pushed out into the first half of next year.

Yes, Philip. So I appreciate the clarification.

So obviously, a bit early to get super specific on the detailed guidance here, but we would see that DUC capital on top of the prior steering.

Okay. And then just wanted to ask about the base dividend.

I think you guys have said in the past that the Board typically targets a base dividend that represents about 10% of cash flow at mid-cycle pricing, which would probably put you somewhere in sort of the $300 million to $350 million range and well above sort of the current annualized number. Obviously, you guys have raised the dividend 3 times in the past several quarters.

And I guess in your prepared remarks, you sort of implied that another increase is likely in the card. So the question here is mainly just on timing.

Are you mostly waiting for the hedges to roll off in January? Do you want to see a bit more debt reduction?

Or is it something else?

Yes. Philips, you've got it nailed in terms of how we're thinking about the base dividend.

I think on timing, obviously, hard for me to front run the Board on that here. But it's something we'll look at every quarter and sort of a way is this the right time to make that increase.

And that will be the approach we take with it. But you've got the sort of aiming point nailed down there, $300 million to $350 million is kind of the place we have in mind.

Can you hear me? I was hoping you guys could talk a little bit about the kind of broader balance sheet debt plan right now.

Obviously, a big quarter of debt repurchases in the third quarter across a lot of different issuances. So kind of curious what the thoughts are?

And what maybe the kind of rate is right now on the credit facility because obviously, you built a little bit on the credit facility to repurchase some of that debt in the quarter. So just hoping you could expand a little bit on the broader plan for those notes and maybe what's available in the next year.

Yes, Nicolas, I appreciate the question. I'm going to turn it over to Corey here.

But what we've talked about is we do want to continue to drag net debt down, and we've kind of said less than $3 billion is sort of directionally where we're headed. And I'll let Corey kind of talk about the specifics of some of the open market repurchases we've done and how we thought about those.

Yes. Thanks for your question.

So if we look at it, you rewind the tape a bit the $3 billion target, ideally, we had hoped to get that as an actual $3 billion debt and not have a $3 billion net debt. And if you think about where rates have gone, it's really opened up the opportunity for us to buy back much of bad debt either at or near par that would have been priced in the $130 range not that long ago.

So the higher interest rate environment has made some of that available. When we did our Montney release, we had updated the open market repurchases and some of that makes it known to people publicly that, that's an option we're looking at.

So it does tend to unlock some of those opportunities that maybe would have been tucked away and held for the long term. So we do look at it more opportunistically and try and take down the debt.

If you think about where rates are today, the front end of the rate curve is pretty high. So we'll be focused at least in the short term on generating cash and paying some of that down but still looking to be opportunistic if there's repurchases to be made in the future.

Got it. That's helpful.

And as you look at kind of the increase in the borrowings under the credit facility during the quarter, I think it seems like it was just a timing issue, but what kind of rates are you seeing right now on the credit facility with the $440 million you got on par at quarter end?

Yes. I mean short rates are close to almost 4%.

So if you look at what we're buying back is in the 6% range. So like I said, it's relatively flat across the curve.

So the old days of getting sub-1% and taking out high coupon notes, there's not as much interest savings there. But long term having inflation, increase your commodity price and taking out notes that you thought were locked in for a long time is a good opportunity still for us.

Just a quick 1 for me. It looks like Permian oil declined quarter-over-quarter despite an uptick in turnarounds.

I was just wondering if there were any one-off events that impacted production for the quarter or if it was just timing of the wells.

No, Fernando, yes, good question, but it's just timing of when the wells came on in the quarter. So that's why we showed the well performance chart of the year-to-date and very pleased with how the wells are coming in for the year there.

Just had a couple of things. I just want to hear about the increased frac intensity you've been doing in the Bakken, how well that has played out.

Has that been, listening to other operators across various basins, discussing their optimization, it seems like in some areas, there is a bit of a pendulum swing back to somewhat lower frac intensity. And some of that has development pattern implications and the parent-child considerations and so forth.

But just wondering, across the other basins, maybe directionally, how’s sort of the completion intensity pattern tracking?

Yes. I'll turn it over to Greg.

But the completion intensity outside of the Bakken, so in places like the Permian and the Montney, in the Anadarko has been pretty stable. But Greg, I don't know if you want to comment on any detail there?

Yes. I think the first thing, just to remind everyone, I appreciate the question is that -- we use a customized approach for every cube that we develop.

So we'll look at the spacing and stacking, taking into account parent-child impacts, the timing of when wells are being completed versus the previous wells in the area. We look at all of those things on every well and look to use all of the knowledge we've gained across all of our basins to try to use the most current up-to-date innovative technologies and approaches.

And so what we saw in the Bakken was really just a result of we've seen some success in some other basins that hadn't been deployed in the Bakken, and we tried that there and it worked very well. But just generally, as Brendan mentioned, there's not a bulk shift to more intensity or less intensity across the board.

It's just tweaking things around the edges and trying to use what works. We found that most of these plays are more alike than they are different.

And that's where our multi-basin strategy really pays off. So we're just using those learnings to make everything a little better.

Great. And sort of more on a macro question.

It does seem which of course this project does in a lot of ways, the Russia-Ukraine situation doesn't seem to be near-term headed towards any sort of resolution. But in the event that things should change or turn around there, are you in the camp more of seeing the price increases, higher European gas demand and so on as being more durable changes to the markets going forward?

Or do you see them more as in the event things got better in the region, sort of like we're enjoying more of a temporary bump in commodity prices that if sanction lifted market got sort of back more to normal business would kind of reverse itself and we might be looking at prices more like the prior couple of years.

Yes. Thanks, Noel.

I think really, this is a durable fundamental call on North American gas that preceded the Russian invasion of Ukraine. And I think it's pretty easily forgotten because of the importance of that invasion, but it's -- if you look back into the -- what was happening in Europe for gas prices, pre-invasion, there was already a dramatic shortage underway.

And so really what we see unfolding is a call on North American gas to supply that global LNG demand, whether it's in Europe or Asia or other parts of the developing world. And so that's a durable price signal that we see unfolding over decades.

But of course, North America also has a lot of gas resource. And so I think that's where fundamentally we're going to watch closely how that supply and demand balance plays itself out as North America expands its LNG export capacity, but supply grows strongly into those expansions.

And you can see that underway even today where North American gas supply has ticked up just in the last 2 quarters, and we're still waiting on a full return to LNG exports this winter. So that's something that we're certainly taking a close fundamental look at and will play into how we choose to allocate capital in our '23 program.

Thanks, Michelle, and thanks, everybody, for joining us today and for your continued interest in Ovintiv. Today's call is now complete.

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