Q4 2022 Ovintiv Inc Earnings Call
Speaker 2: Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Oventives 2022, fourth quarter and year end results conference call.
Speaker 2: As a reminder, today's call is being recorded.
Speaker 2: At this time, all participants are in a listen-only mode.
Speaker 2: Following the presentation, we will conduct a question and answer session.
Speaker 2: Members of the investment community will have the opportunity to ask questions and can join the Q at any time by pressing star one.
Speaker 2: For members of the media attending in a listen only mode today, you may quote statements made by any of the OVENTIVE representatives.
Speaker 2: However, members of the media who wished to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent.
Speaker 2: Please be advised that this conference call may not be recorded or re-broadcast without the expressed consent of Oventiv. I would now like to turn the conference call over to Jason Verhast from Investor Relations. Please go ahead, Mr. Verhast. Thanks for showing. Welcome everyone to our fourth quarter and year in 22.
Speaker 3: be available to take your questions. Please limit your time to one question and one follow-up.
Speaker 3: I will now turn the call over to our president and CEO , Brendan McCracken.
Speaker 4: Good morning. Thank you for joining us. 2022 is a milestone year for O'Bintav. Our team generated a record free cash flow of $2.3 billion and net earnings of $3.6 billion.
Speaker 4: This achievement was underpinned by our leading capital efficiency.
Speaker 4: We return nearly a billion dollars to our shareholders, through our big base dividend and share buybacks.
Speaker 4: 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.
Speaker 4: These additions were mostly in the Permian and the acreage offsets are existing positions in Martin, Midmond, Upton and Howard counties.
Speaker 4: These inventory additions mean that we added more than twice the number of wells that we drilled last year.
Speaker 4: Our team successfully delivered 10% year-over-year capital efficiencies.
Speaker 4: which acted to offset significant inflationary pressures.
Speaker 4: Our team drilled and completed wealth 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.
Speaker 4: The combination of these efforts delivered total annual production of 510,000 BUEs per day, while holding the line on our capital guidance of 1.8 billion.
Speaker 4: 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.
Speaker 4: We've now reduced emissions intensity by more than 30 percent, and we are well on our way to meeting our goal of a 50 percent reduction.
Speaker 4: 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.
Speaker 4: These results demonstrate that our strategy is working and our execution is translating into increased value for our shareholders.
Speaker 4: 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.
Speaker 4: Our fourth quarter performance meant we ended the year with great momentum, with net earnings of 1.3 billion, adjusted eBedove $918 million, free cash low of $537 million, and cash low per share of $3.55, modestly ahead of consensus estimates. Our fourth quarter production came in at 524,000.
Speaker 4: volumes flowing safely and reliably with minimal interruption. We also delivered approximately $250 million to our shareholders through share-by-backs and base dividends.
Speaker 4: This will increase to $300 million in the first quarter as a result of the strong free cash flow we generated in Q4.
Speaker 4: We believe that long-term value creation in the EMP space will come from companies that can demonstrate durability in both their return on invested capital and their return of cash to shareholders.
Speaker 4: Generating durable returns requires a deep inventory of premium return drilling locations, disciplined capital allocation, and highly efficient conversion of resource to cashflow. We check all three boxes. Our capital efficiency is underpin by our multi-basin, multi-product portfolio. Our uniquely balanced portfolio provides operational and commodity diversification.
Speaker 4: Cross-base and learnings and premium inventory depth.
Speaker 4: Our ability to shift capital to maximize corporate returns as a competitive advantage.
Speaker 4: We did this in 2022 in response to the Monteney 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.
Speaker 4: Inter-business access to premium resource is another essential component to generating durable returns.
Speaker 4: We are continuously evaluating opportunities to extend our runway through both organic appraisal and assessment efforts as well as through bolt-ons.
Speaker 4: Over the course of the year, we made significant additions to our premium inventory across our ACES 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.
Speaker 4: where we added about 8,000 net acres to our core positions in Midman Martin, often in Howard.
The next biggest additions were condensate an oil locations in the money.
All told, we replaced two times the number of wells we drilled last year. We're committed to staying disciplined and opportunistic in our Bullton 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 ads did not result in incremental proof to 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 US oil reserves were flat year-over-year after accounting for the sale of our high-cost mature water flood in the UN to base and in the third quarter.
I'll now turn the call over to Cory 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.
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 return 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 your end was 0.8 times.
As expected, we continue to see our US 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.
consume more tax pools than initially expected.
We ended the year with 381 million dollars of NOLs there.
Assuming a $75 W2L price and a $3.9 ex-gast price, we would see 200 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.
We'll now turn the call over to Greg to talk more about our 2023 plan and provide some operational highlights. Thanks, Cory. The development program we implemented last year has strategically positioned of creative Ab options and if there is an additional Ident Adjuncts??ing as carpet advanced care options are the same allows us to have doors exposure to daily information about future staffs in the province, willing to work together foruo and dangers bevoraudience engagement.
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 BUE 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 Cory mentioned, given the week outlook for natural gas and NGO 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 Anodarco basin. As we expected, our first quarter production is set to be the low point for the year.
at about 500,000 B.O.E. 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 duck 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 on our approach to increasingly low-level our development programs. And in 2023, we expect to see less variation in turn-in-line cadence, setting us up for a more radical 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 keep 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, 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, seeing them a 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-based and learning approach. Moving north to the Montany, we are very excited to get back to a more normalized level of activity in the BC part of our acreage.
With a recent resolution of the legal dispute between the BC government and the 38 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 open to disposition and 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, Oventiv has brought online 17 of the top 20 wells in the Montenegro 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 liquid 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 vehicle market. Are you into basing this been generating some top-tier well results? And we are excited to continue development in the play this year. 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 a highly competitive, both within our portfolio and among the top shell 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 1000 feet of collective pay.
This translates into a significant inventory runway.
Our UNTA 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 take away capacity out of the basin to the local Salt Lake City refining complex, and we recently secured additional scalable rail capacities of the Gulf Coast.
As a result, our UNTIT will receive an average price of about 85% of WTI and generates impressive margins. In 2022, the UNTIT matched the Permian for the highest operating margin in our portfolio.
This year we plan to share two rigs between the EO and the Boccan 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 Inwinta and 40% in the blocking.
We continue to be very pleased with the results from our Bach and Play. Our recent tin well-cramer pad vastly outperformed our expectations and produced an outstanding 2 million barrels of oil in just 200 days.
Our Boccan 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, and the BC Montany, we have chosen to allocate less capital to the Bach in this year.
But as I mentioned, we are taking a flexible approach to our activity by sharing our exhibit at Yualenta. Deborah, thank you.
At roughly two-thirds natural gas and associated in GLs, our Anodarco asset provides great product optionality and provides stable-based 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 for
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 percent, further bolstering the cash generation capabilities of the asset. I'll now turn the call back over to Brendan.
Thanks Greg. We're delivering outstanding results. We're well-positioned for today's volatility and with our balanced portfolio, we're 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 Discipline 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, discipline, capital allocation, responsible operations, and leading capital efficiency have positioned our business to thrive on the road ahead.
This concludes our prepared remarks. An operator will now please take questions.
Thank you, sir. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing to strikes by pressing simple kneel button or pass out the elevator to the puppy and
We will now begin the question and answer session and go to the first caller.
Your first question will come from Neil Dingman at Truist Securities. Please go ahead.
Morning guys, I'm just wondering, seems like your shareholder's certain planet seems to be now very stable. I just wonder what would it take to cause you to either decide to ramp that pay out and change the capital return? I just wanted to help maybe Corey for your ran-in house stable is that or is there things that could cause that to ramp even further?
Yeah, Neil, no appreciate the question. You know, we've been very consistent with that Caffel 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, you know, 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, you know, 300 to 350 million a year, which really floats back.
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 yeah, we'll leave it there. Thank you.
No, that's well said. And then maybe just one last one for Greg. How different, you know, right now when you're seeing inflation out the market versus your different plays, when I'm looking at you in versus firm versus anecdote, just wondering how different is inflation out there today for you. Thank you.
Thanks for the question, Neil. So we saw quite a bit of inflation throughout the year in 2022. As we ended the year and started into the first 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. So we're seeing less inflation in Canada.
and is compared to the US. And so 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 Party at RBC Capital Markets. Please go ahead.
Thanks, good morning. Thanks for the rundown. I wanted to do Brendan, sorry, I'm catching my voice here. I wanted to come back to the reserve report a little bit just on the new- else side. So pretty significant revisions and so forth that we saw. I'm just wondering where did they...
Were they concentrated in anyone playing, is there a little bit more that you could frame around those? Yeah, Greg, no, appreciate it. So the first place to start is on the US 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 Cory 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 you into sales. So maybe Corey, you want to talk just a little bit about how the process works there and why those two categories net together.
Yeah, hey Greg, Cory 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. So 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 and then when you rebook and put a different stick in that comes in as an extension. So...
NetNAT, you could leave your development plan exactly the same and have a minus one and one category and a plus one and 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 one to shift gears, and it's really kind of a hedging question. It's around the effectiveness of the three ways, not so much when pricing is range-bound, but if we look at what happened with the natural gas market over the last six months or so, the three ways really aren't giving you much protection given the...
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, free cash, low 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 9x for like a 12 month.
And the reason that we chose to put three ways on as the vehicle for 2023 was because we're 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.
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.
choose amongst the different structures, whether that's fixed price swaps or callers or puts, to again put that risk management in place for 2024.
Your next question comes from Arun Jairam 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 to less than 300 million in a capital. So, let me 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, two to three million bucks, and you're able to add those, you know, well below that number. And just maybe just overall, you're updated messaging on portfolio renewal as we've, you know, generally in our model, just earmarked about 300 million per annum and capex for portfolio renewal. And you.
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. 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 return and value focused. And we have to do, like the number said, we have to do over 90 transactions to make that happen.
these transactions. So we have to be opportunistic, but you know that 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 rateable 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.
Okay, great. And my follow-up, Corey, I wanted to go back to the cash tax question. In your previous commentary, you suggested that there would 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 same quarter call. I wondered if you could help us kind of...
If you took the $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.
And so the realized gas price is probably the biggest driver there. That's where we've got, you know, the full one BCF a day out of the one and a half roughly that we have total. So any market diversification benefits that we have accrued into that Canadian cost center. And so we saw better performance in the back half of the year than we probably forecast at the time of the Q2 call. So just can see in those.
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 Doubt at Callin. Please go ahead. Thank you, everybody. Thanks for the prepared remarks.
Brennan, 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 duck load-downs 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 ducts being built again in the second half of the year just trying to reconcile it. Yeah, I gave no appreciate it. Nothing nothing in there around the deflation or the duct build so it is just literally the consuming those carry over ducts in the first half of the year. And then I think.
to get more low level than 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. Thanks, Brian , that's helpful. Maybe it was a follow up for Greg, could you maybe just give us a little more color around what's going on in the UNTA?
with the results for getting in the UNTO, we're seeing some strong individual well results there. But we've also been working on that to take away 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 QB 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 unit to go in forward. So, encourage but a measured approach.
Yeah, I think Gabe, if I just added to that, we now got over 100 horizontal wells of our own into the play as well as some third party wells around us. 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, you know, as Greg kind of mentioned in the prepared remarks, it's actually a pretty critical point. The UNTO 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 Jeffries. Please go ahead.
Hey, good morning, guys. Uh, 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 in 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.
Yeah, I'll flip it to Greg here. But Ted grows 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. 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. 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's 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.
And 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 frack monitoring. So we've been able to make adjustments on the fly because we've got a lot more live telemetry, both in the well over fracking and then in the wells around them. And that's really helping us both from a productivity perspective.
Is that just scale in the UNTA going forward and then maybe just give us an idea of how much acreage you guys have there?
Yeah, 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 bockin and the UN to 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 pay setter basis and we've got real good indications on the pay setter front that we're going to be able to drive these costs down with a bit more scale in the program.
Greg, you can talk about the acreage. 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 I 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 Leggett. Our first question, Greg, goes to you.
Understandably, it's lower, given the slowdown of activity in the fourth quarter.
The quarter is 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 are we on? Have we already seen the lows on oil and condensate production for the quarter? Here Parchment.
You know, the port is two thirds complete, right? I mean, it's a guy that's 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 had to slow down an activity in 4Q that drove, you know, look 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. And then for our second question is, I mean, congratulations on the additions to your invitations. What is your thoughts on potential portfolio cleanup in the current environment? Thank you.
You know, 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, you know, we're always going to look at that and think about as our way we can enhance the
of tutor, pickering and hope, please go ahead.
Thank you, everyone. Thanks for taking my questions. My first one is just some is you can elaborate more on the capital efficiencies that you spoke about over 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? What's embedded?
and local wet sand and those, I think we're 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 in well-signed facility and short tie-in operations, which is where all of our capital goes to. So.
I think it's just a continuation year over year.
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 ducks that we carried over from the fourth quarter, that we fill those in to our schedules so we would have a very level loaded fracks scheduled.
I appreciate that detail. And then just from my second one, I wanted to ask more on some of the moving pieces from a original 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's kind of the primary driver of the year-to-year increase there on spending, just given it will look to be similarities and activity and lateral length plans. But
Can you talk about how the contracts that are set up on pricing and how quickly inflation, flattening or subsiding could flow through? And then maybe separately as you 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 as other key factors that you might consider there? Yeah, I'll start Greg and chime in here too, but we're a little over a third.
walked 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, 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.
And you know that the you know maybe turn over to a Greg to add anything you want to there. Yeah 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...
Your next question comes from Roger Reed at Wells Fargo. Please go ahead.
Yeah, thank you. Good morning. I just like to ask Canada with the LNG expansion coming on the west coast how that might have an impact on you know what you're doing up in the BC area and you know any thoughts on timing or capital allocation for something like that.
Yeah, Roger, appreciate the question. So, you know, the Canadian LNG project continues to progress towards a mid-decade start-up. That's an additional 2.1 BC FAD of take-way. There's the potential for more projects to FID to add to that in the back half of the decade here.
So 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 echo just 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 bases, hedges that we've got in place. So we really are well insulated and basically have a 9-Mex 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 ACO market. That's helpful, thanks. And then I just wanted to come back some of the comments earlier about decline rates in the antidarko base and kind of leveling out here. Can you provide us a, you know, company-wide?
first year decline rate indicator. Yeah, we're in the kind of 30 to 35% total corporate decline.
Okay, so not much different than what you're seeing in the Antarctic. The Antarctic is shallowed out below that, so the Antarctic is the shallower of the portfolio today. Sorry, I meant like what you saw in 21, it's declined out. Sure. And you said flood, that's not. Thank you.
not much different than what you're seeing in the Antarctic. The Antarctic is shallowed out below that, so the the Antarctic is the shallower of the portfolio today. Yep. Sorry, I meant like what you saw in 21, it's declined out. Sure. And you said flood, that's not. Thank you. Thank you.
Your next question comes from Eumeng Chowdery 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 routine program and sounds like you expect that to be more level loaded, both on spending and on production.
starting in the back half of the seared. You talked about the benefit of completing ducks 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 might be mindful of what it means for 2024 and beyond.
understand that there are a lot of things at play here including potentially some lower service costs. I appreciate the question. You got it nailed on the progressing to the low-babbled program this year and the extra duck capital in the first half of the year is about $80 million. So it's spread between the first two quarters.
Gotcha, that's really helpful. And then one other housekeeping question for us and thanks so much for the update on the UNTA. Can you remind us on the inventory you have left in the UNTA basin for this high quality locations which you have highlighted in a deck?
Yes, it's kind of an interesting one 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 would 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.
and for your continued support and interest in the event of 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 lines.