Good morning, ladies and gentlemen, thank you for standing by. Welcome to Ovintiv's 2022 4th quarter and year-end results conference call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star one. Members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. 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. Welcome everyone to our fourth quarter and year-end 2022 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 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 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. 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 their 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 2 x 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 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 water flood 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. 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. 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. As a result, our leverage at year-end was 0.8 times. 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 $381 million of NOLs there. Assuming a $75 WTI price and a $3 NYMEX gas price, we would see CAD 200 million-CAD 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. We'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 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 and condensate-rich parts of our portfolio, as is evident 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 drilled 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. 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 cubes 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. 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. 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. 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 Treaty 8 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. 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 four-rig program of 70-80 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. 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. 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 ft 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. 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 40-50 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 activities levels in the BC Montney, we have chosen to allocate less capital to Bakken this year. As I mentioned, we are taking a flexible approach to our activity by sharing rigs and a c
At roughly 2/3 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. We're well-positioned for today's volatility. 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.
Thank you, sir. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing star one. We will now begin the question-and-answer session and go to the first caller. Your first question will come from Neal Dingmann at Truist Securities. Please go ahead.
Morning, guys. I'm just wondering, seems like your shareholders return plan seems to be now very stable. I'm just wondering, what would it take to cause you to either decide to ramp that payout and change the capital, the capital return? I'm just wondering how, maybe Corey for you or Brendan, how stable is that or is there things that could cause that to ramp even further?
Yeah, Neal. No, appreciate the question. You know, 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. We've really kind of followed our playbook there. If you remember, the foundation of that capital allocation model is our base dividend. You know, we've been pretty clear with our investors that we wanna continue to see that base dividend going up with time. We've still got some headroom on the kinda notional level that we set for that to be around, you know, $300 million-$350 million a year, which really floats back to the 10% of EBITDA at a mid-cycle price range.
That's probably the first place I'd start. The second place is the one that you're maybe pointing to, which is, you know, does that percentage of free cash flow march up with time? 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. That's the mode we're in today, but it's something we're always looking at to see, you know, what's gonna drive the valuation of the equity and be the right thing for the shareholder. Yeah, maybe I'll leave it there.
No, that's well said. Maybe just one last one for Greg. How different, you know, right now when you're seeing inflation out in the market versus your different plays when I'm looking at Uinta versus Perm versus Anadarko. I'm just wondering how different is inflation out there today for you? Thank you.
Thanks for the question, Neal. 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, and 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.
Your next question comes from Greg Pardy at RBC Capital Markets. Please go ahead.
Thanks. Good morning. Thanks for the rundown. Brendan, sorry. I'm catching my voice here. I wanted to come back to the reserve report a little bit just on the oil side. Pretty significant revisions and so forth that we saw. I'm just wondering where were they concentrated in any one play, and is there a little bit more that you could frame around those?
Yeah. Greg, no, appreciate it. 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 Uinta Waterflood. There's really a couple moving parts to talk to, and I'll get Corey to chime in here too. The two categories you wanna look at are the extensions and discoveries and then the revisions and improved recoveries categories. If you net the two 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 produced through the year, and that's how you get to flat year-over-year after adjusting for that Uinta sale.
Maybe, Corey, you wanna talk just a little bit about how the process works there and why those two categories net together?
Yeah. Hey, Greg, Corey here. Just on the details of how that works, and I'm sure you're familiar, but when we change our development plan, you actually have to do it by stick. If you have a stick that's in the original plan last year and you no longer plan to drill it, that comes out as a revision. Then when you rebook and put a different stick in, that comes in as an extension. Net-net, you could leave your development plan exactly the same and have a -1 in one category and a +1 in the other. 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. Wanted to shift gears, and it's really kind of a hedging question, and it's around the effectiveness of the three-ways, not so much when pricing is range-bound, but if we look at what's happened with the natural gas market over the last six months or so, the three-ways really aren't giving you much, you know, 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.
Yeah. Thanks, Greg. You know, this is really related to the new hedging approach that we're now into. We've now got a book that reflects that new approach. If you remember, the principles of that approach were to provide downside protection to the business and essentially protect us so that we're gonna be free cash flow positive after the base dividend, even at the bottom of the cycle for a prolonged period of time. We kind of have notionally talked about that being something like $40 on oil and $2 on NYMEX for, like, a 12-month period. We'd wanna be able to drive through that period and be free cash flow neutral to positive after the base dividend. That's really what our book is designed to protect against.
It's not, you know, necessarily designed to capture a market view. It's more that risk management piece. 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. That protection level is there for the event of that, you know, 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, you know, now we're into thinking about the book for 2024, we'll adapt to the market conditions that are on the board today and, you know, 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. Please go ahead.
Good morning. Brendan, I wanted to maybe start with the portfolio renewal. You noted the ability of the company to add 450 sticks through less than $300 million in capital. Just want to get your thoughts on how you're able to add some of those locations when you think about, you know, today the market price of a premium stick is, you know, $2 million-$3 million , and you're able to add those, you know, well below that number. Just maybe just overall, your updated messaging on portfolio renewal as we've, you know, generally in our model, just earmarked about $300 million per annum in CapEx for portfolio renewal. Any change to that messaging?
Yeah. Arun, no, appreciate the call out here. I think, you know, look, I think we've been really clear. We think one of the keys to generating durable returns is having a deep premium inventory. You know, we drill a little over 200 wells a year is our 2023 plan. We need to be replacing that as we go, is our view. 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. You know, we think we've had, you know, very good success in 2022 on both of those fronts. You've seen the numbers. I won't quote them again here.
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 gonna keep following that strategy. I think we're very return 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. You know, I think for your 300, the one thing that we've said all the way along is that's not gonna be ratable because, of course, you know, we don't control the other side of these transactions, so we have to be opportunistic.
You know, that's the approach we're gonna take is that over time, it should kind of iron out to that level, but it's probably not gonna wind up being ratable, even though it relatively was about that number in 2022. It's gonna be one of these ones where we're just gonna have to watch and see how the market de-develops and how sellers look to optimize their portfolio with time.
Okay, great. My follow-up, Corey, I want to go back to the cash tax question. You know, in your previous commentary, you suggested that there'd be kind of a $5 gas price, where you thought that you wouldn't really have to be subject to Canadian cash taxes in 2023, and I think you provided that in the second quarter call. I wondered if you could help us kinda reconcile what changed and any forward thoughts on 2024 if you run a maintenance program at a, at a similar $75 and $3 deck in terms of cash taxes next year.
Arun, just I guess if you think about from that second quarter number, you know, at that point, we were probably seeing it closer to 100. If you took the CAD 5, that's where it got more material. This is all just to emphasize in case people missed the prepared comments. This is all Canadian tax.
The realized gas price is probably the biggest driver there. That's where we've got, you know, the full 1 Bcf/d out of the 1.5 roughly that we have total. Any market diversification benefits that we have accrue into that Canadian cost center. We saw a better performance in the back half of the year than we probably forecast at the time of the Q2 call. Just consume those Canadian NOLs a little bit faster than we thought. That's really the driver for why it's now CAD 200 million-CAD 250 million at the CAD 75 and CAD 3.
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 billion-dollar threshold this year to be, I don't want to say qualifying for that, but be subject to that next year.
Your next question comes from Gabe Daoud at TD Cowen. Please go ahead.
Thank you. Hey, everybody, thanks for the prepared remarks. Brendan, maybe could we just hit on CapEx a bit? Just curious. I know the 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 lowdowns 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.
Gabe, no, appreciate it. Nothing in there around the deflation or the DUC build. It is just literally the consuming those carryover DUCs in the first half of the year. 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. Essentially, it works out to about 50-60 wells a quarter, and it's gonna be pretty smooth month- to-m onth as well. That is a huge step change for us year-over-year to get more load-leveled. That is gonna wind up greatly benefiting 2024. We thought it was just really important to get that shift made this year. That's why you're seeing that done.
Thanks, Brendan. That's helpful. 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? Thanks, guys.
Thanks, Gabe.
No, thanks for the question, Gabe. 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. 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. This is just a continuation of that effort, continuing to delineate that asset and move forward there. It'll 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 and to get an optimal result out of the Uinta going forward.
So encouraged, but a measured approach.
Yeah, 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. You know, the acreage position we have is right in the center of the basin, so it's right in the best part of the resource. We're getting more confidence in the productivity and cost structure of the play. You know, 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.
You know, the only other thing I'd say is part of the reason that margin has enhanced is we sold that high-cost water flood last year, which took quite a bit of the operating cost out of the asset.
Your next question comes from Lloyd Byrne at Jefferies. Please go ahead.
Hey, good morning, guys. 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 looked better than the first and second. What changed there and how does 2023 look? Then I have a quick follow-up to Gabe's question, I think.
Yeah, I'll flip it to Greg here. Type curve is largely stable year-over-year. You can see that from 2021 to 2022 to our projected 2023. We got real high confidence in that 2023 curve. You know, Greg, you can talk about some of the things you're excited about that the team's doing on completions there to drive that productivity.
Yeah. Yeah. 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. 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's really been working most recently on their stage architecture, the amount of, you know, 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 those fourth quarter results we showed on the slide. 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 to use the same cube development approach across the asset position, continue to optimize our completions on every pad. 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'll translate into good performance in 2023.
The one thing Greg mentioned that I'll just highlight a little bit that I'm excited about is what the team's doing with real-time frac monitoring. We've been able to, you know, make adjustments on the fly because we've got a lot more live telemetry, both in the well that we're fracking and then in the wells around them. That's really helping us, both from a productivity perspective but also we think from a cost perspective. That, that's an exciting one to keep watching as we go through 2023 here.
Okay, great. 2023 looks more like the fourth quarter. On the cost structure, is that just scale in the Uinta going forward? Maybe just give us an idea of how much acreage you guys have there?
Yeah. I'll let Greg hit on the acreage, but the cost structure is just scale. We've been, you know, drilling a pretty small program through the last several years to really delineate and get the confidence that we now have. We know for sure that as we bring, you know, that load leveled rigs and spread between the Bakken and the Uinta, that's gonna help drive those costs down. We've seen that 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 gonna be able to drive these costs down with a bit more scale in the program. Greg, you can talk about the acreage.
Yeah. On the acreage side, we have 130,000 net acres in the play. That's with multiple development horizons across that acreage position. 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. Please go ahead.
Good morning. I'm on for Doug Leggate. Our first question, and 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's now about two-thirds complete. Just wondering if you could give us an update of where current oil and condensate production may be at, and have we already seen the lows on oil and condensate production for the quarter?
Yeah. You know, John, appreciate the question. The best guidance we give you is we're on track for the guidance we're issuing today. What was the second part of your question?
Yeah. What we're trying to understand is, you know, the quarter's 2/3 complete, right? I mean, its guidance is 160,000 barrels per day. 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 to slow down an activity in 4Q that drove, you know, the guidance for this quarter, but are you already on an upward trajectory at this point in time?
Yeah, that's a reasonable way to think about it, John. You bet.
All right. 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?
You know, I think we've done a fair bit of that over time, when you look at how we're allocating capital today, every asset in the portfolio is competing for capital, and delivering free cash flow for the corporation. You know, we're always gonna look at that and think about is there a way we can enhance the value of the company for our shareholders. A lot of the cleanup that we've been doing is, has been done here, so.
Your next question comes from Jeoffrey Lambujon of Tudor, Pickering, and Holt. Please go ahead.
Hey, good morning, everyone. Thanks for taking my questions. My first one is just wondering if you could elaborate more on the capital efficiencies that you spoke about on, you know, what were the most impactful factors there in 2022, and how those contributed to that 10% improvement year-over-year last year. 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?
Yeah, Jeff, appreciate it. You know, I think on the backward-looking capital efficiencies, it was all about just being faster. Drilling faster and completing faster was the big thing as we, you know, really embedded simul-frac into the portfolio and local wet sand and those I think were good winners for us last year. 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 and short tie-in operations, which is, you know, where all of our capital goes to. I think it's just a continuation year-over-year. You know, we've taken a modest approach to our expectations in terms of how we set that guidance for 2023.
Maybe just to build real quickly on the efficiencies for 2023. 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. We feel like the efficiencies are only gonna improve in 2023 over what we delivered in 2022.
Perfect. Appreciate that detail. Just for my second one, I wanted to ask more on 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, you know, inflation's kind of the primary driver of the year-to-year increase there on spending, just given what look to be similarities in activity and lateral length plans. Can you talk about how the contracts there are set up on pricing and how quickly inflation flattening or subsiding could flow through?
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?
I'll start. Greg can chime in here too. You know, we're a little over a third on locked-in pricing for our capital program this year. It's a little higher than that on rigs and spreads and pipe. That kind of gives you a sense for, you know, 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 two months of things have been priced. Maybe turn it over to Greg to add anything you want to there.
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 gonna be open to some movement in the back half of the year if that does occur. The most important thing for us is to focus on the efficiency and getting most out of the crews and the rigs that we have. 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 in one basin versus another.
Your next question comes from Roger Read at Wells Fargo. Please go ahead.
Yeah. Thank you. Good morning. I guess I'd like to ask Canada, with the LNG expansions coming on the West Coast, how that might have an impact on, you know, what you're doing up in the BC area, you know, any thoughts on timing or capital allocation for something like that?
Yeah. Roger, appreciate the question. You know, the Canadian LNG project continues to progress towards a mid-decade startup. That's an additional 2.1 Bcf/d of takeaway. There's the potential for more projects to FID to add to that in the back half of the decade here. We're watching that closely. You know, as you've heard us remark in prior calls, you know, we do think the next logical step of a price diversification would be to get some LNG exposure in the portfolio, so that's something we continue to evaluate. I think my earlier comments were that, you know, 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. 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. We really are well-insulated and basically have a NYMEX-exposed gas portfolio here through to 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. Thanks. Just wanted to come back to some of the comments earlier about decline rates in the Anadarko Basin kinda leveling out here. Can you provide us a, you know, company-wide, first-year decline rate, indicator?
Yeah. We're in the kinda 30%-35% total corporate decline.
Okay. Not much different than what you're seeing in the Anadarko.
The Anadarko is shallowed out below that, so the Anadarko is the shallower of the portfolio today. Yeah.
Sorry. I meant like what you saw in 2021. Yeah, it's declined.
Sure.
As you said, flattened out. Thank you.
Thank you.
Your next question comes from Umang Choudhary at Goldman Sachs. Please go ahead.
Hi. Good morning, and thank you for taking my questions. 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 and 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? 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.
Yeah. Umang, appreciate the question. You got it nailed on the, on the progressing to the low-level program this year. The extra DUC capital in the first half of the year is about $80 million. It's spread between the first two quarters.
Gotcha. That's really helpful. One other housekeeping question for us. 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 highlighted in the deck?
Yeah. It's kind of an interesting one because, of course, the activity level is still relatively modest there, so the inventory is gonna be quite long. You know, it's sort of decades out there right now. We'll, you know, that'll be something we can continue to talk to investors about, as we get more data and results in the play. Right now it's very long.
Thank you.
Thank you.
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.
Yeah. Thank you, operator. 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 would like to thank you all for participating and ask you to please disconnect your-