Ovintiv Inc. (NYSE:OVV) Q4 2022 Earnings Call Transcript

Ovintiv Inc. (NYSE:OVV) Q4 2022 Earnings Call Transcript February 28, 2023

Operator: Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv’s 2022 Fourth Quarter and Year-End Results Conference Call. 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 : Thanks, Michelle, and welcome, everyone, to our fourth quarter and year-end ’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 their slides and in the disclosure documents filed on SEDAR and EDGAR. Following prepared remarks, we’ll be available to take your questions. Please limit your time to 1 question and 1 follow-up. I will now turn the call over to our President and CEO, Brendan McCracken.

Brendan McCracken : Good morning. Thank you for joining us. 2022 as a milestone year for Ovintiv. Our team generated a record free cash flow of $2.3 billion and net earnings of $3.6 billion. This achievement was underpinned by our leading capital efficiency. We returned nearly $1 billion to our shareholders through our base dividend and share buybacks, and we reduced our long-term debt by $1.2 billion. We also expanded our future runway with the addition of approximately 450 new premium return locations. These additions were mostly in the Permian, and the acreage offsets our existing positions in Martin, Midland, Upton and Howard Counties. These inventory additions mean that we added more than twice the number of wells that we drilled last year.

Our team successfully delivered 10% year-over-year capital efficiencies, which acted to offset significant inflationary pressures. Our team drilled and completed wells faster than ever before and our cube development approach continued to deliver consistent well results while maximizing the value and returns from every acre we developed. The combination of these efforts delivered total annual production of 510,000 BOEs per day. While holding the line on our capital guidance of $1.8 billion. We also made significant gains elsewhere in our business. We were recently included in the Bloomberg Gender Equality Index. In addition, we made significant progress towards our GHG emissions reduction target. We’ve now reduced emissions intensity by more than 30%, and we are well on our way to meeting our goal of a 50% reduction.

In short, in 2022, we delivered tremendous profitability, increased direct returns to our shareholders, bolstered our financial strength, extended our future inventory runway and continued our strong social and emissions performance. These results demonstrate that our strategy is working and our execution is translating into increased value for our shareholders. We had a record-breaking year, and I’m confident our team will continue to deliver leading capital efficiency and durable returns for our shareholders in 2023 and beyond. Our fourth quarter performance meant we ended the year with great momentum, with net earnings of $1.3 billion, adjusted EBITDA of $918 million, free cash flow of $537 million and cash flow per share of $3.55, modestly ahead of consensus estimates.

Our fourth quarter production came in at 524,000 BOEs per day. Strong well performance across our portfolio drove us to the top end of guidance on oil, gas and NGL. This was despite extreme winter weather across North Dakota, Oklahoma and Western Canada. Kudos to our team, where the weatherization efforts made by our experienced field staff kept our volumes flowing safely and reliably with minimal interruption. We also delivered approximately $250 million to our shareholders through share buybacks and base dividends. And this will increase to $300 million in the first quarter as a result of the strong free cash flow we generated in Q4. We believe that long-term value creation in the E&P space will come from companies that can demonstrate durability in both their return on invested capital and the return of cash to shareholders, generating durable returns requires a deep inventory of premium return drilling locations, disciplined capital allocation and highly efficient conversion of resource to cash flow.

We check all 3 boxes. Our capital efficiency is underpinned by our multi-basin multiproduct portfolio. Our uniquely balanced portfolio provides operational and commodity diversification, cross-basin learnings and premium inventory depth. Our ability to shift capital to maximize corporate returns is a competitive advantage. We did this in 2022 in response to the Montney permitting slowdown, which is now behind us, and we are making use of this option again in 2023 in response to weaker short-term North American natural gas fundamentals. In our business, access to premium resource is another essential component to generating durable returns. We are continuously evaluating opportunities to extend our runway through both organic appraisal and assessment efforts as well as through bolt-ons.

Over the course of the year, we made significant additions to our premium inventory across our asset base. Through organic appraisal and more than 90 transactions, we cost effectively added approximately 450 inventory locations. The biggest focus of this program was in the Permian and where we added about 8,000 net acres to our core positions in Midland, Martin, Upton and Howard. The next biggest additions were condensate in oil locations in the Montney. All told, we replaced 2x the number of wells we drilled last year. We’re committed to staying disciplined and opportunistic in our bolt-on efforts, and only transacting when we can generate strong full cycle return at mid-cycle pricing. Our inventory renewal efforts make our business more sustainable and help us extend our premium inventory runway across the portfolio.

It’s worth noting that these inventory adds did not result in incremental proved reserves, both because of the timing of the ads late in the year and the SEC booking rules. It’s also worth pointing out that our U.S. oil reserves were flat year-over-year after accounting for the sale of our high-cost mature waterflood in the Uinta Basin in the third quarter. I’ll now turn the call over to Corey to discuss our 2023 outlook.

Corey Code : Thanks, Brendan. Our 2023 capital plan provides continued strong shareholder returns while keeping our production volumes flat year-over-year. Greg will speak more to the details of the plan later in the call. But at a high level, we intend to execute a resilient, load leveled program, which we’ve optimized to generate significant free cash flow, maximize capital efficiency and maintain balance sheet strength. We are leveraging our multi-basin multiproduct portfolio and focusing 100% of our investment in oil and condensate ridge areas. But as always, we have the optionality to shift capital to other parts of our portfolio. If economic factors dictate over the course of the year. With 25% of our 2023 oil and gas volumes covered by WTI and NYMEX benchmark contracts, our greatly reduced hedge position allows us to participate in commodity price upside up to $110 a barrel for oil and $8 per MMBtu for natural gas.

This is a huge tailwind for us compared to last year. We are well underway today on our first quarter buyback program of $238 million. Collectively, we will return approximately $300 million to shareholders in the first quarter across our base dividend and share repurchases. Our first quarter cash return yield of approximately 11% is very competitive in today’s market across both industry peers and the broader economy. We remain committed to delivering substantial returns to our shareholders. Since implementing our capital allocation framework in the fall of 2021, we’ve returned more than $1.4 billion to shareholders. We see this momentum continuing in 2023 and beyond as we continue delivering a highly efficient development program and removing legacy costs from the business.

We also reduced long-term debt by $1.2 billion, and as a result, our leverage at year-end was 0.8x. As expected, we continue to see our U.S. business being cash taxable starting in 2024, as we expect to be subject to the corporate alternative minimum tax at current prices. Our cash tax included in our guidance relates to our Canadian business. It is likely to attract cash tax this year based on stronger-than-expected performance in 2022 that consume more tax pools than initially expected. We ended the year with a $381 million of NOLs there. Assuming a $75 WTI price and a $3 NYMEX gas price, we would see $200 million to $250 million of cash tax in Canada. This cash tax will not be payable until early 2024 and will be working capital rather than actual cash used in 2023.

I’ll now turn the call over to Greg to talk more about our 2023 plan and provide some operational highlights.

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Greg Givens : Thanks, Corey. The development program we implemented last year has strategically positioned Ovintiv for success in 2023. Capital efficiency remains a primary focus for our teams as we work to efficiently convert our inventory into cash flow and generate durable returns for our shareholders. Our 2023 10-rig program delivers annual total production volumes of 513,000 BOE per day, split evenly between liquids and natural gas. This production profile is flat versus 2022 despite selling some noncore assets last year. As Corey mentioned, given the weak outlook for natural gas and NGL prices this year, we have chosen to allocate our capital to the oil condensate rich parts of our portfolio as is evidenced by the lower activity in the Anadarko Basin.

As we expected, our first quarter production is set to be the low point for the year, at about 500,000 BOE per day. This profile is driven by a couple of factors. First, and as we outlined in our third quarter call, we intentionally built a drill but uncompleted or DUC well inventory in the fourth quarter. We are limiting our usage of spot crews and taking a methodical approach to bringing these wells online through the first half of 2023. Second, the wells that were brought online at the end of last year were weighted towards the front end of the fourth quarter. This affected production in January and February as we ramped activity back to levels normalized with the rest of 2023. Our Q1 guide also includes the impact of known weather events.

We have been thoughtful in our approach to increasingly load level our development programs. And in 2023, we expect to see less variation in turn-in-line cadence setting us up for a more ratable production profile in the second half of the year and going forward. Permian well performance continues to be topical. So I’d like to take a moment to discuss what we’ve been seeing in the play. We’ve been active in the Permian for over 8 years and have studied the basin extensively. We’ve drilled across our entire acreage footprint to delineate the play, and we’ve entered into numerous data trades with our peers. We led the industry to cube development, which maximizes both recovery and returns. Our approach to stacking and spacing has been very consistent through time.

We take a customized concurrent multi-zone development approach in each of our tubes to optimize resource recovery and deliver the highest NPV for every acre of land we develop. The chart on the right shows a tight dispersion of full field development results. Our Permian program, like all development programs, has a statistical variance across wells. But on average, the program delivers consistent performance year in and year out. In the early part of 2022, we had a few pads that performed towards the lower end of the distribution. But as expected, those wells are offset by outperformance seen in the latter part of the year. Heading into 2023, we expect to see consistent performance across our program. And as always, we are actively working to increase resource recovery through our culture of innovation and our cross-basin learning approach.

Moving north to the Montney. We’re very excited to get back to a more normalized level of activity in the BC part of our acreage. With the recent resolution of the legal dispute between the BC government and the First Nations, we are well positioned to execute a highly optimized program in the play this year. We have in hand all of the permits required for our 2023 program, and we continue to build our bank of permits for 2024. As a reminder, the vast majority of Ovintiv’s position in all our 2023 activity is on freehold lands and therefore, will not be subject to the restrictions that were announced as part of the new consultation agreement. We are continuing to deliver industry-leading results in the play. Over the last 12 months, Ovintiv has brought online 17 of the top 20 wells in the Montney on a BOE basis.

We hold a premier acreage position with substantial product optionality. Our premium inventory runway is more than 10 years in the oil and condensate window and more than 30 years in the natural gas window. This year’s 4-rig program of 70 to 80 net turn in lines will be largely balanced between our BC and Alberta acreage with a focus on our more liquids-rich areas. The economics on these wells remain outstanding. Even with current strip pricing, we expect to generate well level returns of more than 100%. These great returns are driven by our superior well results, low drilling and completion costs and strong price realizations. As a reminder, our condensate trades in line with WTI and more than 90% of our natural gas volumes are priced outside of the AECO market.

Our Uinta Basin has been generating some top-tier well results, and we are excited to continue development in the play this year. When we look at our resource in the basin, it has all the right characteristics to be to be highly competitive, both within our portfolio and among the top shale plays in North America. Our large contiguous land base of approximately 130,000 net acres is primed for cube development. It has multiple horizontal intervals with about 1,000 feet of collective pay. This translates into a significant inventory runway. Our Uinta team has delivered impressive well results recently, outpacing the peer average by about 50% and going toe-to-toe with core Delaware Basin results. We have long-term takeaway capacity out of the basin to the local Salt Lake City refining complex, and we recently secured additional scalable rail capacity to the Gulf Coast.

As a result, our Uinta oil receives an average price of about 85% of WTI and generates impressive margins. In 2022, the Uinta match the Permian for the highest operating margin in our portfolio. This year, we plan to share 2 rigs between the Uinta and the Bakken to bring on a combined total of 40 to 50 net wells. We’ve reserved some flexibility around the timing of rig moves between the assets. But at a high level, we currently expect to execute about 60% of our activity in the Uinta and 40% in the Bakken. We continue to be very pleased with the results from our Bakken play. Our recent 10-well vastly outperformed our expectations and produced an outstanding 2 million barrels of oil in just 200 days. Our Bakken team also did a great job in responding to extreme weather over the last few months and successfully kept our operations running with minimal downtime while bringing on 3 separate pad development projects.

We also continue to see strong well results in the play with our recent Kramer development projected to outperform our initial outlook by 25% through 360 days. With the resumption of normalized activity levels in the BC Montney, we have chosen to allocate less capital in the Bakken this year. But as I mentioned, we are taking a flexible approach to our activity by sharing rigs and a frac crew with the Uinta. At roughly 2/3 natural gas and associated NGLs, our Anadarko asset provides great product optionality and provide stable base production with ample market access and strong price realizations. As mentioned earlier, we’ve chosen to reduce our activity in the play and focus on optimizing asset level free cash flow and operational efficiencies, given the weaker outlook for gas and NGLs in 2023.

That said, I’m incredibly proud of the actions taken by the Anadarko team to reduce cycle time. During the fourth quarter, we achieved our best cycle time yet at 94 days, a 30% reduction compared to our 2021 average. They’ve also done a great job in shallowing out the base decline rate in the play to about 20%, further bolstering the cash generation capabilities of the asset. I will now turn the call back over to Brendan.

Brendan McCracken : Thanks, Greg. We’re delivering outstanding results, and we’re well positioned for today’s volatility. And with our balanced portfolio, we are also well positioned for the long-term needs of the global energy market. We take great pride in producing safe, affordable, reliable and secure energy while delivering superior returns to our shareholders. In 2023, we’ll continue to focus on the following key priorities. Safe work always, executing a disciplined development program focused on maximizing capital efficiency, generating significant free cash flow to enhance returns to shareholders maintaining our strong balance sheet and continuing to enhance our premium return drilling inventory. Our focus on execution, disciplined capital allocation, responsible operations and leading capital efficiency have positioned our business to thrive on the road ahead. This concludes our prepared remarks. Now operator, we’re now pleased to take questions.

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Q&A Session

Operator: Your first question will come from Neal Dingmann at Truist Securities.

Neal Dingmann: I’m just wondering, it seems like your shareholder’s plan seems to be not very stable. I’m just wondering what would it take to cause you to either decide to ramp that payout and change the capital return? I’m just wondering how maybe Corey, for you or Brendan, how stable is that is there things that could cause that to ramp even further?

Brendan McCracken: Yes, Neil. I appreciate the question. We’ve been very consistent with that capital allocation plan and the resulting shareholder returns since we launched it all the way back in the third quarter of 2021. And so we’ve really kind of followed our playbook there. If you remember, the foundation of that capital allocation model is our base dividend. And we’ve been pretty clear with our investors that we want to continue to see that base dividend going up with time. We’ve still got some headroom on the kind of notional level that we set for that to be around $300 million to $350 million a year, which really floats back to the 10% of EBITDA to mid-cycle price range. And so that’s probably the first place I’d start and then the second place is the one that you’re maybe pointing to, which is does that percentage of free cash flow march up with time?

And really, the plan we’ve been following there is to both be reducing debt and paying back 50% of that free cash flow to shareholders. And so that’s the mode we’re in today, but it’s something we’re always looking at to see what’s going to drive the valuation of the equity and be the right thing for the shareholders. So yes, maybe I’ll leave it there.

Neal Dingmann: No, that’s well said. And then maybe just 1 last 1 for Greg. How different than when you’re seeing inflation out in the market versus your different plays when I’m looking at Uinta versus firm versus Anadarko. I’m just wondering how different is inflation out there today for you?

Greg Givens: Thanks for the question, Neal. And so we saw quite a bit of inflation throughout the year in 2022. As we ended the year and started into the fourth quarter — sorry, first quarter, it feels like the rate of change is really subsided, and we’re seeing a leveling off. As far as how that affects us across our different plays. We are seeing less inflation in Canada as compared to the U.S. And so we’re — that’s one of the reasons why we really like the play there, as I noted in my prepared remarks.

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

Greg Pardy : I wanted to — Brendan, sorry, I’m catching my voice here. want to come back to the reserve report a little bit, just on the oil side. So pretty significant revisions and so forth that we saw. I’m just wondering where did they — were they concentrated in any one plan? Is there a little bit more that you could frame around those?

Brendan McCracken: Yes, Greg. No, I appreciate it. So the first place to start is on the U.S. oil reserves, total proved year-over-year, it’s flat after you adjust for the sale of that you went to waterflood. And there’s really a couple of moving parts to talk to, and I’ll get Corey to chime in here, too. But the 2 categories you want to look at are the extensions and discoveries and then the revisions and improved recoveries categories. And if you net the 2 of those together, our approved reserves actually go up by 30 million barrels year-over-year and then you take off the production that we produce through the year, and that’s how you get to flat year-over-year after adjusting for that, you into sale. So maybe, Corey, you want to talk just a little bit about how the process works there and why those 2 categories net together?

Corey Code: Greg, Corey here. Just on the details of how that works, and I’m sure you’re familiar, but when we changed our development plan, you actually have to do it by stick. So if you have a stick that’s in the original plan last year, you no longer plan to drill it, that comes out as a revision. And then when you rebook and put a different stick in, that comes in as an extension. So net-net, you could leave your development plan exactly the same and have a minus 1 in 1 category and a plus 1 in the other. So you really do have to look at it on a net basis, even though you have to record them separately.

Greg Pardy : Okay. That’s really helpful. And then I want to shift gears and it’s really kind of a hedging question, and it’s around the effectiveness of the 3 ways, not so much when pricing is range down. But if we look at what’s happened with the natural gas market over the last 6 months or so, the 3 ways really aren’t giving you much, much protection given the drop. I’m just wondering what your perspective is there and how you sort of think about 3 ways on a go-forward basis.

Brendan McCracken: Yes. Thanks, Greg. This is really related to the new hedging approach that we’re now into. So we’ve now got a book that reflects that new approach. And if you remember the principles of that approach were to provide downside protection to the business and essentially protect us so that we’re going to be free cash flow positive after the base dividend even at the bottom of the cycle for a prolonged period of time. And we we kind of have notionally talked about that being something like $40 on oil and $2 on NYMEX for like a 12-month period. And we’d want to be able to drive through that period and be free cash flow neutral to positive after the base dividend. And that’s really what our book is designed to protect against.

So it’s not necessarily designed to capture a market view. It’s more of that risk management piece. And the reason that we chose to put 3 ways on as the vehicle for 2023 was because we were able to get a really wide put spread in those 3 ways. And so that protection level is there for the event of that sort of severe bottom of the market, but not necessarily there to take upside off the table, which is really why we chose the 3 ways. I think as we look forward and now we’re into thinking about the book for 2024, we’ll adapt to the market conditions that are on the board today. And choose amongst the different structures, whether that’s fixed price swaps or collars or puts to again put that risk management in place for 2024.

Operator: Your next question comes from Arun Jayaram of JP Morgan.

Arun Jayaram: Brendan, I wanted to maybe start with the portfolio renewal. You noted the ability of the company to add 450 sticks to less than $300 million of capital. So I just want to get your thoughts on how you’re able to add some of those locations when you think about today, the market price of a premium stick is $2 million to $3 million, and you’re able to add those well below that number. And just — maybe just overall, your updated messaging on portfolio renewals we’ve — generally, in our model, just earmarked about $300 million per annum in CapEx for portfolio renewal. Any change to that messaging?

Brendan McCracken: Yes, Arun, I appreciate the call out here. I think — look, I think we’ve been really clear, we think one of the keys to generating durable returns is having a deep premium inventory. And we drill a little over 200 wells a year as our ’23 plan. So we need to be replacing that as we go is our view. And our strategy is to do that with a combination of both the organic effort to get more locations on the acres we already control, but also the bolt-on approach that you’ve seen us be following in. And we think we’ve had very good success in ’22 on both of those fronts, and you’ve seen the numbers. I won’t quote them again here. And so that’s been the place that we’ve seen the most accretive to do that work. To your question on the go forward, I think we’re just going to keep following that strategy.

I think we’re very returned and value-focused and we have to do like the numbers said, we had to do over 90 transactions to make that happen. So we obviously are very familiar with the market is. And I think for your 300, the one thing that we’ve said all the way along is that’s not going to be ratable because, of course, we don’t control the other side of these transactions. So we have to be opportunistic, but that’s the approach we’re going to take is that over time, it should kind of iron out to that level, but it’s probably not going to wind up being ratable, even though it relatively was about that number in 2022. So it’s going to be one of these ones where we’re just going to have to watch and see how the market develops and how sellers look to optimize their portfolio with time.

Arun Jayaram: Great. And my follow-up, Corey, I wanted to go back to the cash tax question. In your previous commentary, you suggested that, call it, there’d be kind of a $5 gas price where you thought that you wouldn’t really be subject to Canadian cash taxes in 2023. And I think you provided that in the second quarter call. I was wondering if you could help us kind of reconcile what changed, and any forward thoughts on 2024, if you run a maintenance program at a similar $75 and $3 deck in terms of cash taxes next year?

Corey Code: Yes, Arun, just I guess, if you think about from that second quarter number, at that point, we were probably seeing it closer to 100. If you took the $5, that’s where it got more material. This is all just to emphasize it in case people missed the prepared comments, it’s all Canadian tax. And so the realized gas price is probably the biggest driver there. That’s where we’ve got the full 1 Bcf a day out of the 1.5 roughly that we have total. So any market diversification benefits that we have accrued into that Canadian cost center. And so we saw a better performance in the back half of the year than we probably forecast at the time of the Q2 call. So just consume those Canadian NOLs a little bit faster than we thought.

So that’s really the driver for why it’s now $200 million to $250 million at the $75 million. And then going forward, the bigger step change is really the cash tax in the U.S. from the AMT that we could likely trigger at these prices. tripping over that $1 billion threshold this year to be — I don’t want to say qualifying for that, but be subject to that next year.

Operator: Your next question comes from Gabe Daoud at Cowen.

Gabe Daoud: Brendan, maybe could we just hit on CapEx a bit. Just curious, another program is heading towards being more level loaded, but — is there anything else in the back half of the year that’s driving the step down in CapEx? I understand the DUC blowdown will occur in the first half. But as I think about the second half, is there service cost deflation may be being baked in? Or is there intentional DUCs being built again in the second half of the year? Just trying to reconcile that.

Brendan McCracken: Yes, Gabe. I appreciate it. Nothing in there around the deflation or the DUC build. So it is just literally the consuming those carryover DUCs in the first half of the year. And then I think you can see on one of the slides, I’m not sure which number it is here just off the top of my head, but we show the monthly turn in line and essentially works out to about 50 to 60 wells a quarter, and it’s going to be pretty smooth month-to-month as well. So that is a huge step change for us year-over-year to get more low leveled and that is going to wind up greatly benefiting 2024, and we thought it was just really important to get that shift made this year. So that’s why you’re seeing that done.

Gabe Daoud: That’s helpful. Then maybe as a follow-up for Greg. Could you maybe just give us a little more color around what’s going on in the Uinta? Just curious, I guess, what are some of the expectations or goals with the program this year? And as you maybe even think about adding more capital to that moving forward?

Greg Givens: Thanks for the question, Gabe. And really, as we’ve said for a few quarters now, we’ve been pleased with the results we’re getting in the Uinta. We’re seeing some strong individual well results there. But we’ve also been working on the takeaway capacity to make sure that we have the ability to get those barrels to market and get paid a fair price for them. And so this is just a continuation of that effort continuing to delineate that asset and move forward there. But it will continue to be a balanced approach as we continue to evaluate that and use our cube development strategy there and use all of the things that we’ve learned from all of the other plays that we participated in get an optimal result out of the unit to going forward. So encouraged but a measured approach.

Brendan McCracken: Yes. I think, Gabe, if I just added to that, we’ve now got over 100 horizontal wells of our own into the play as well as some third-party wells around us. And the acreage position we have is right in the center of the basin. So it’s right in the best part of the resource, and we’re getting more confidence in the productivity and cost structure of the play. And then as Greg kind of mentioned in the prepared remarks, it’s actually a pretty critical point. the Uinta is our highest margin play alongside the Permian in 2022, which is a huge step change for the play from a margin perspective, and that all adds up to better returns there. And — the only other thing I’d say is part of the reason that margin has enhanced as we sold that high-cost waterflood last year, which took quite a bit of the operating cost out of the asset.

Operator: Your next question comes from Lloyd Byrne at Jefferies.

Lloyd Byrne : Brendan, or maybe, Greg, can you guys just talk a little bit more about what’s happened with the type curves in the Permian? I mean the third and fourth quarter to date look better than the first and second. So what changed there? And how does ’23 look? And then I have a quick follow-up to Gabe’s question, I think.

Brendan McCracken: Yes, I’ll flip it to Greg here. But type curve is largely stable year-over-year. You can see that from ’21 to ’22 to our projected ’23. We got real high confidence in that ’23 curve. And Greg, you can talk about some of the things you’re excited about that the team is doing on completions there to drive that productivity.

Greg Givens: Yes. I think one of the first things I’d point to is we continue to develop our cubes in the Permian. It’s a co-development approach that we’ve had since we’ve entered the play. So we overall get very consistent results in aggregate, but there is some variation in the individual well results as you move around the play. The team has really been working most recently on their stage architecture. The amount of spacing between stages, the amount of sand we put in each well and continuing to drive efficiencies there and seeing really positive results, as you saw in the fourth quarter results we showed on the slide. So really, the thing I would point back to is that unlike maybe some other operators, we’ve not changed our approach over time.

We continue the same cube development approach across the asset position, continue to optimize our completions on every pad. And despite some variability early in the year, we were really encouraged later in the year with how the results came out, and we feel like that will translate into good performance in ’23.

Brendan McCracken: One thing Greg mentioned that I’ll just highlight a little bit that I’m excited about is what the team is doing with real-time frac monitoring. So we’ve been able to make adjustments on the fly because we’ve got a lot more live telemetry both in the wallet were fracking and then in the wells around them. And that’s really helping us both from a productivity perspective, but also we think from a cost perspective. So that’s an exciting one to keep watching as we go through ’23 here.

Lloyd Byrne : Okay. Great. So ’23 looks more like the fourth quarter? And then — on the cost structure, is that just scale in the Uinta going forward? And then maybe just give us an idea of how much acreage you guys have there?

Brendan McCracken: Yes. I’ll let Greg hit on the acreage, but the cost structure is just scale. So we’ve been drilling a pretty small program through the last several years to really delineate and get the confidence that we now have. And so we know for sure that as we bring that load-leveled rigs and spread between the Bakken and the Uinta, that’s going to help drive those costs down. And we’ve seen that when you look at — you remember, we tend to look at these things on the pacesetter basis, and we’ve got real good indications on the pacesetter front that we’re going to be able to drive these costs down with a bit more scale on the program. And Greg, you can talk about the acreage.

Greg Givens: Yes. On the acreage side, we have 130,000 net acres in the play, and that’s with multiple development horizons across that acreage position. And it’s still about 80% undeveloped. As Brendan mentioned, we have now around 100 horizontal wells in the play, but have significant running room left there as we go forward and execute on our plans.

Operator: Your next question comes from John Abbott at Bank of America.

John Abbott : Our first question, Greg goes to you. It’s on the condensate oil and condensate guidance for the first quarter. Understandably, it’s lower given the slowdown of activity in the fourth quarter. The quarter is now about 2/3 complete. Just wondering if you could give us an update of where current oil and condensate production may be at. And are we — have we already seen the lows on oil and condensate production for the quarter.

Brendan McCracken: Yes. John, appreciate the question. The best guidance we give you is we’re on track for the guidance we’re issuing today. So — and what was the second part of your question?

John Abbott : Yes. So what we’re trying to understand is it’s — again, it’s — the quarter’s 2/3 is complete, right? I mean the guidance is 160,000 barrels per day. And so we’re trying to see whether or not we’ve already seen the lows of production for oil and condensate for the quarter. Are you already moving higher at this point in time? I mean you’ve had the slowdown in activity in 4Q that drove outlook guidance for this quarter, but are you already on an upward trajectory at this point in time?

Brendan McCracken: Yes, that’s a reasonable way to think about it, John. You bet.

John Abbott : All right. And then for our second question is — I mean, congratulations on the additions to your inventories. What is your thoughts on potential portfolio cleanup in the current environment?

Brendan McCracken: I think we’ve done a fair bit of that over time. And so when you look at how we’re allocating capital today, every asset and the portfolio is competing for capital, and delivering free cash flow for the corporation. So we’re always going to look at that and think about it is there a way we can enhance the value of the company for our shareholders. But a lot of the cleanup that we’ve been doing has been done here, so.

Operator: Your next question comes from Jeoffrey Lambujon of Tudor, Pickering and Holt.

Jeoffrey Lambujon: My first one is just if you could elaborate more on the capital efficiencies that you spoke about on what were the most impactful factors there in 2022? How those contributed to that 10% improvement year-to-year last year? And then looking forward, how do you view the repeatability there and then also incremental improvements to be captured this year and what’s embedded in the outlook here?

Brendan McCracken: Yes, Jeff, appreciate it. I think on the backward-looking capital efficiencies, it was all about just being faster. So drilling faster and completing faster was the big thing as we really embedded frac into the portfolio and local wet sand and those, I think, were good winners for us last year. And as you transition and take a more forward-looking view that’s the order of the day again this year is to keep finding those efficiencies and technical breakthroughs on our drilling and completions and well site facility in short time in operations, which is where all of our capital goes to. So I think it’s just a continuation year-over-year. And we’ve taken a modest approach to our expectations in terms of how we set that guidance for 2023.

Greg Givens: And maybe just to build real quickly on the efficiencies for ’23. We felt it was really important for the DUCs that we carried over from the fourth quarter that we fill those in to our schedule. So we would have a very level loaded frac schedule this year which doesn’t expose us to spot crew pricing but also just makes the best, most efficient use of the equipment that we have under contract today. So efficiencies are only going to improve in ’23 over what we want.

Brendan McCracken: Some of the moving pieces from a regional perspective within the capital program for the year, just how to think about Flex points across the assets, pieces from a regional perspective within the capital program for the year, just how to think about points across the assets. Maybe starting with the Permian, it looks like inflation is kind of the primary driver of the year-to-year increase there on spending just given will look to be similarities in activity and lateral length plans. But can you talk about how the contracts there set up on pricing and how quickly inflation flattening or subsiding could flow through? And then maybe separately as we think about flexibility across the other parts of the portfolio, how do you view the option to add or drop activity outside of the Permian in response to commodity prices or inflation or just other key factors that you might consider there?

Corey Code: Yes, I’ll start. Greg can chime in here, too. But we’re a little over 1/3 locked in pricing for our capital program this year. It’s a little higher than that on rigs and spreads and pipe. So that kind of gives you a sense for if we do see some deflation through the year, we would see some of that flow through, although it’s probably more of a back half feature, just knowing how the first 2 months of things have been priced. And the — maybe turn it over to Greg to add anything you want to there.

Greg Givens: Yes. I think the first thing to point out is we have all of the rigs and crews we need to execute on the program currently working for us today, and we’re going to be using those throughout the year. I think as you compare the different plays, we’re going to be open to some movement in the back half of the year if that does occur. But the most important thing for us is to focus on efficiency and getting most out of the crews and the rigs that we have. So we feel pretty good about where that’s headed, and we’ll be able to move capital if we need to in response to lower — or lower service costs of 1 basin versus another.

Operator: Your next question comes from Roger Read at Wells Fargo.

Roger Read : I just would like to ask, Canada with the LNG expansions coming on the West Coast, how that might have an impact on what you’re doing up in the area? And any thoughts on timing or capital allocation or something like that?

Brendan McCracken: Yes. Roger, appreciate the question. So the Canadian LNG project continues to progress towards a mid-decade startup. That’s an additional 2.1 Bcf a day of takeaway. There’s the potential for more projects to FID to add to that in the back half of the decade here. So we’re watching that closely. As you’ve heard us remark in prior calls, we do think the next logical step of price diversification would be to get some LNG exposure in the portfolio. So that’s something we continue to evaluate and I think my earlier comments were that nothing particularly imminent on that, but it is definitely something we continue to monitor and look at actively. Remember that the way we’ve set up our Western Canadian gas price exposure here is we essentially have very minimal AECO exposure all the way through 2025.

And so that’s a combination of our physical transport into the West Coast and into the Midwest and into Ontario as well as some basis hedges that we’ve got in place. So we really are well insulated and basically have a NYMEX exposed gas portfolio here through the mid-decade when those LNG projects should begin to turn on in Canada and help enhance the sort of structural fundamentals of the AECO market.

Roger Read : That’s helpful. And then I just wanted to come back to some of the comments earlier about decline rates in the Anadarko basin kind of leveling out here. Can you provide us a company-wide first year decline rate indicator?

Brendan McCracken: Yes. We’re in the kind of 30% to 35% total corporate decline.

Roger Read : Okay. So not much different than what you’re seeing in the Anadarko.

Brendan McCracken: The Anadarko is shallowed out below that. So it’s — the Anadarko is the shallower of the portfolio today. Yes. Sorry, I meant like what you saw in ’21, yes, it’s declined out as you said, flat in that.

Operator: Your next question comes from Umang Choudhary at Goldman Sachs.

Umang Choudhary : My first question was on your program. I mean, one of the focus was to set up a ratable program and it sounds like you expect that to be more level loaded both on spending on production starting in the back half of this year. You talked about the benefit of completing DUCs in the first half. Can you provide any color in terms of what the dollar amount looks like? And is this a onetime benefit, which we should expect in 2023. Just so that we are mindful of what it means for 2024 and beyond. I understand that there are a lot of things at play here, including potentially some lower service costs.

Brendan McCracken: Yes, Umang, I appreciate the question. You got it nailed on the progressing to the low-level program this year. And the extra DUC capital in the first half of the year is about $80 million. So it’s spread between the first 2 quarters.

Umang Choudhary : Got you. That’s really helpful. And then one other housekeeping question for us, and thanks so much for the update on the Uinta. Can you remind us on the inventory you have left in the Uinta Basin for these high-quality locations, which you’ve highlighted in our deck?

Brendan McCracken: Yes. It’s kind of an interesting because, of course, the activity level is still relatively modest there. So the inventory is going to be quite long. So it’s sort of decades out there right now. And — so that will be something we can continue to talk to investors about as we get more data and results in the play. But right now, it’s very long.

Operator: At this time, we have completed the question-and-answer session. So I will turn the call back to Mr. Verhaest for any closing remarks.

Jason Verhaest: Yes. Thank you, operator, and thank you, everyone, for joining us today and for your continued support and interest in Ovintiv. Our call is now complete.

Operator: Ladies and gentlemen, this does conclude your conference call for this morning. We’d like to thank you all for participating and ask you to please disconnect your lines.