Ovintiv Inc. Q4 FY2022 Earnings Call

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.

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 one question and one follow-up. I will now turn the call over to our President and CEO, Brendan McCracken.

Good morning. Thank you for joining us. 2022 was 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 three boxes. Our capital efficiency is underpinned by our multi-basin, multi-product 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, where we added about 8,000 net acres to our core positions in Midland, Martin, Upton, and Howard. The next biggest additions were condensate and oil locations in the Montney. All told, we replaced two times 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 returns 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 adds 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.

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, multi-product portfolio and focusing 100% of our investment in oil and condensate-rich 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 consumed more tax pools than initially expected. We ended the year with $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.

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 non-core 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 eight 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 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 competing closely 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 matched the Permian for the highest operating margin in our portfolio. This year, we plan to share two 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 Kramer pad 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 three 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 two-thirds natural gas and associated NGLs, our Anadarko asset provides great product optionality and provides 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.

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.

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

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 anything that could cause that to ramp even further?

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.

No, that's well said. And then maybe just one last one for Greg. How different is what you're seeing in inflation out in the market versus your different plays, when I'm looking at Uinta versus Permian versus Anadarko? I'm just wondering how different is inflation out there today for you?

Thank you for the question, Neal. We experienced significant inflation throughout 2022. As we concluded the year and moved into the first quarter, it seems that the rate of change has really diminished, and we are observing a stabilization. In terms of its impact on our various operations, we are encountering less inflation in Canada compared to the U.S. This is one of the reasons why we have a strong preference for our operations there, as I mentioned in my earlier comments.

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

I wanted to ask about the reserve report, particularly regarding the oil side. We observed some significant revisions, and I'm curious if they were concentrated in any specific area. Could you provide more context on that?

Yes, Greg. No, I appreciate it. So the first place to start is on the U.S. oil reserves; total proved year-over-year is flat after you adjust for the sale of the Uinta 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 two categories you want to look at are the extensions and discoveries and then the revisions and improved recoveries categories. And if you net the two of those together, our proved 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 Uinta sale. So maybe, Corey, you want to talk just a little bit about how the process works there and why those two categories net together?

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 one in one category and a plus one in the other. So you really do have to look at it on a net basis, even though you have to record them separately.

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 six months or so, the 3 ways really aren't giving you much protection given the drop. I'm just wondering what your perspective is there and how you sort of think about three ways on a go-forward basis.

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 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 three ways on as the vehicle for 2023 was because we were able to get a really wide put spread in those three 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 three 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.

Your next question comes from Arun Jayaram of JP Morgan.

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?

I appreciate your question, Arun. We've been clear that a key to generating lasting returns is having a strong premium inventory. Our plan for 2023 includes drilling over 200 wells, so we need to continuously replace those wells. Our strategy involves both increasing the number of locations on the acres we control and pursuing additional acquisitions. We've had success in both areas last year, as indicated by our results. Moving forward, we will continue with this strategy, maintaining a focus on returns and value. It required over 90 transactions to achieve this, so we have a solid understanding of the market. Regarding the $300 million, we’ve mentioned that it won't be consistent because we can’t control the other side of these transactions, making it necessary for us to be opportunistic. Over time, we expect it to average out to that level, but it may not be consistent despite being around that figure in 2022. We'll need to observe how the market evolves and how sellers manage their portfolios over time.

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?

Yes, Arun. If we look at the second quarter figure, we were estimating it closer to 100. When considering the $5 mark, it became more significant. I want to stress that this is solely related to Canadian tax. The realized gas price is likely the main factor driving this. We've utilized 1 Bcf a day out of the approximately 1.5 we have in total. Any market diversification benefits have been incorporated into that Canadian cost center. As a result, the latter half of the year performed better than we had anticipated during the Q2 call. We consumed those Canadian NOLs a bit faster than we expected. This explains why the figure is now between $200 million and $250 million at the $75 level. Looking ahead, a significant shift will be the cash tax in the U.S. due to the AMT, which we may trigger at these prices, potentially exceeding the $1 billion threshold this year, making us subject to it next year.

Your next question comes from Gabe Daoud at Cowen.

Brendan, maybe could we just hit on CapEx a bit. Just curious, your 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 maybe being baked in? Or is there intentional DUCs being built again in the second half of the year? Just trying to reconcile that.

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.

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 think about adding more capital to that moving forward?

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 to get an optimal result out of the Uinta going forward. So encouraged but a measured approach.

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 is that we sold that high-cost waterflood last year, which took quite a bit of the operating cost out of the asset.

Your next question comes from Lloyd Byrne at Jefferies.

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 2023 look? And then I have a quick follow-up to Gabe's question, I think.

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.

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.

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 wells we're 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.

Okay, great. Does 2023 look more like the fourth quarter? Regarding the cost structure, will that just be due to scaling in the Uinta going forward? Could you also provide us with an idea of how much acreage you have there?

Yes. I'll let Greg discuss the acreage, but the cost structure is primarily influenced by scale. Over the past few years, we've been executing a relatively small drilling program to delineate and build the confidence we now have. We are certain that bringing our load-levelled rigs between the Bakken and the Uinta will help reduce those costs. Our analysis indicates that with increased scale in our program, we will be able to drive these costs down effectively. Greg, you can elaborate on the acreage.

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.

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

Our first question is for Greg regarding the condensate oil and condensate guidance for the first quarter. We recognize it’s lower due to the activity slowdown in the fourth quarter. The quarter is now about two-thirds complete. Could you provide an update on the current oil and condensate production levels? Have we already reached the low point for oil and condensate production this quarter?

Yes, I appreciate the question. The best guidance we can provide is that we are on track with the guidance we issued today. What was the second part of your question?

Yes. We are trying to determine if we have reached the lowest points of production for oil and condensate this quarter, considering that the quarter is about two-thirds complete and our guidance is 160,000 barrels per day. Have you started to see production increase at this time? There was a slowdown in activity in the fourth quarter that affected our outlook for this quarter, but are you now on an upward trend?

Yes, that's a reasonable way to think about it, John. You bet.

All right. For our second question, congratulations on the additions to your inventories. What are your thoughts on potential portfolio cleanup in the current environment?

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.

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

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?

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 SIM 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.

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 into 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.

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. 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?

Yes, I'll start, and Greg can add any insights as well. Currently, we have a little over one-third of our capital program pricing locked in for this year. The pricing is slightly higher for rigs, spreads, and pipe. This gives you an idea that if we experience any deflation throughout the year, we would see some of that impact, although it's likely to be more evident in the latter half of the year, given the pricing trends from the first two months. I’ll hand it over to Greg now for any additional comments.

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 service costs of one basin versus another.

Your next question comes from Roger Read at Wells Fargo.

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?

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.

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?

Yes. We're in the kind of 30% to 35% total corporate decline.

Okay. So not much different than what you're seeing in the Anadarko.

The Anadarko is shallower than the other areas in the portfolio today. Yes, I meant that it has declined since what you observed in 2021, as you noted, and is now relatively flat.

Your next question comes from Umang Choudhary at Goldman Sachs.

My first question was on your program. I mean, one of the focuses was to set up a ratable program and it sounds like you expect that to be more level loaded both on spending and 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 one-time 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.

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 two quarters.

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?

Yes. It's interesting because the activity level is still relatively modest. Therefore, the inventory will be quite long, extending decades out. This is something we can continue to discuss with investors as we gather more data and results in the play. But for now, it remains very long.

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.

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.

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.