CA - Peyto Exploration & Development Corp. (PEYUF) Q4 2022 Earnings Call Transcript
2023-03-09 15:37:09 ET
Peyto Exploration & Development Corp. (PEYUF)
Q4 2022 Earnings Conference Call
March 9, 2023, 11:00 am ET
Company Participants
JP Lachance - President & CEO
Kathy Turgeon - CFO
Riley Frame - VP, Engineering
Tavis Carlson - VP, Finance
Todd Burdick - VP, Production
Derick Czember - VP, Land & Business Development
Lee Curran - VP, Drilling & Completions
Conference Call Participants
Mike Dunn - Stifel
Chris Thompson - CIBC
Presentation
Operator
Good day and thank you for standing by and welcome to Peyto's Year-End 2022 Financial Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions]. Please be advised that today's conference is being recorded.
I would now like to hand the conference over to your speaker today, JP Lachance, President and CEO. Please go ahead.
JP Lachance
Thanks, Justin. Good morning, folks, and thanks for joining Peyto's fourth quarter and year-end 2022 results conference call.
I'd like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory set forth in the company's news release issued yesterday.
In the room with me today, to answer any of your questions, we have the entire management team Kathy Turgeon, our Chief Financial Officer; Riley Frame, our VP of Engineering; Tavis Carlson, our VP of Finance; Todd Burdick, our VP of Production; Derick Czember, our VP of Land and Business Development; and Lee Curran, our VP of Drilling and Completions.
By all accounts, Q4 and 2022 as a whole was a very successful year for the company. The team grew annual production by 14% and PDP reserves by 8%, and that coupled with our higher commodity prices that we realized last year drove record cash flow and earnings for the company's entire 24 year history.
But before we get into some of those details, I'd like to acknowledge and thank the folks here in the office for their efforts in achieving the past quarters and year-end results. We have a small but dedicated team in our Calgary office, and that makes it all happen. Of course, an equal part -- an important part of our success, yes, as those folks in the field, the operators, the foreman, the maintenance crews, they keep our wells producing and our plants going.
We had a very cold snap just before Christmas where all the hands were needed to keep production on stream. It's always good to see that the percentage of Peyto's loss production during this period was only about half of that, of what the industry lost as a whole. And to me that's a testament of our field folk's dedication and focus in the field.
It's during these cold weather days when we as Canadians are reminded that not only is natural gas reliably heating our homes, but in many other places, especially here in Alberta, natural gas provides a reliable electric power generation too. In that sense natural gas is truly life saving energy and we are proud of Peyto to be the one of Canada's top suppliers of it.
Okay. Enough of soapbox here. 2022 was a very much -- was very much a consolidating interest year, a year where we consolidated interests and expanded our processing capacity, especially in the Brazeau area. Peyto did two very complementary acquisitions. One was an underutilized gas plant in Q1, and one was for undeveloped land in Q4. We might get Derick to expand upon these a little bit later and give us some more color on that.
But we also constructed the Chambers gas plant, which came on in Q2, and we've continued to optimize that facility up to a capacity now of 65 million cubic feet a day of gas and 2,500 barrels per day of liquids. We've also linked all those plants together in the Brazeau area to provide operational flexibility and total processing capacity now up to 250 million cubic feet a day.
We also spent capital to expand and debottleneck gathering systems in Sundance in 2022 to accommodate future growth. I think all told we spent about a $100 million, which was on major facilities and pipelines last year. That's a very large portion of our capital program relative to past years, and we don't expect to spend that this year. Perhaps we'll get Todd to expand upon our facility projects for 2023 later.
On our February 16 reserves released, you'll note that Peyto replaced 165% of production with new PDP reserves, and we did it for a filing development acquisition cost of $8.46 a barrel, or a $1.41 per Mcfe, where a gas company we'd like to quote things in Mcfe, which is high by Peyto standards, but still one of the most efficient amongst our peers given the inflationary pressures, the whole industry endured last year.
We also realized -- what we also realized much better prices, including our hedging losses and when you couple that with our industry-leading cash costs, it means we generated a cash netback of $3.74 per Mcfe or 2.7x more than it costs us to add those reserves, which is what we want.
I mentioned gas prices were up. Last year, NYMEX natural gas prices averaged to $6.38 per MMBtu, up from $3.84 in 2021. But there was also incredible volatility last year ranging where prices ranged from lows near $3.50 to highs over $9. AECO prices were also volatile but with the added challenge of the market disconnection that happens during the summer maintenance season, where once again prices drop towards zero. And it's for these very reasons that Peyto has an active hedging strategy to smooth out the volatility so we can plan our capital programs, commit to paying dividends and continue to strengthen the balance sheet. It's also the reason why the company has a market diversification program with volumes pointed at various markets like Malin, Ventura, Dawn, Emerson, and Henry Hub, all through the use of various marketing or transportation or basis deals.
So what we don't have is essentially any AECO exposure this summer as we expect to see a repeat of last summer's maintenance program.
And late this year, we'll have about 10% of our volumes flowing to the newly -- sorry, the newly constructed highly efficient Cascade Power plant, which is pretty much close to completion near Edson, Alberta, and that's part of a 15-year gas supply agreement. We're building that pipeline now, and we're excited about setting up some gas later this year.
As we move forward in 2023, we are taking a cautious approach to our capital spending in light of the fall of natural gas prices. We've built a flexible program that focuses drilling in core areas only, and we've deferred the higher cost Whitehorse/Minehead program for now.
Starting out a little slower, allows us to make the call to wrap up later in the year depending on prices. Future prices are in tangle, and we are continuing with our systematic hedging program, we're up to -- about 60% hedge now on average for 2023. Prices near $4 in Mcf, which helps give us -- gives us that confidence to spend within that capital guidance and sustain that dividend. We also have 25% of our forecasted gas volumes fixed for 2024. So we're continuing to secure future revenues beyond this year.
So before we get to -- before we open up to questions, I just -- I'd just like to point out one more important thing here. The global demand for natural gas continues to grow, and it's never been more important for energy security than it is today. I read last night that Freeport LNG has approved the startup of their final liquefaction train. So that's good news on take away capacity from the Gulf, should pull -- should be a pull on prices there, but there will always be a seasonal supply and demand swing. As you know, the commodity is well dependent. And so we should expect to see price volatility to remain, but Peyto is well equipped with our low cost structure, our price risk management, and our disciplined approach to shareholder returns to thrive in this environment as we go-forward.
Okay. So enough out of me, let's turn the call over to questions.
But before we go to the phone lines, I just have one question coming in overnight. That comes in right off the top and maybe we should just address, because it's a recurring theme, the question that came in from e-mail and it's similar to some others, gas prices have dropped in half since you guys set the dividend level last November. Are you going to have to cut the dividend?
So we do not forecast -- just to be clear, we do not forecast having to change the dividend from this level at this time. Our dividend is still far less than our projected earnings. We have ample protection from our hedge book and we continue to add hedges in the future that are higher than the prices we have today. Because of course, the forward curve is in tangle. Prices roll back, or, sorry, roll forward, we will first look at our capital program and then we'll make adjustments to ensure we're still making smart good returns with the money that we're spending.
And as I mentioned already -- we've already done that. We are guiding to the lower end of our guidance. We're targeting the lower end of our guidance to pullback into high grade of our projects. So we're deferring the longer Peyto wells and the facility projects. And we expect that if prices do remain low, service costs will realign accordingly as well. So we still have plans to reduce our debt and strengthening the balance sheets is also still a priority.
So to answer, but this question in short, no, we don't currently have -- don't currently expect to change the dividend.
So with that, let's open it up to the phone lines. If there are questions for folks who want to answer, the whole team is here to answer them.
Question-and-Answer Session
Operator
And thank you. [Operator Instructions].
And our first question comes from Karthik Roger from Bloomberg. Your line is now open. Karthik, your line is now open. If your line's on mute, please unmute. Okay. [Operator Instructions].
And our next question comes from Jeremy [indiscernible]. Your line is now open.
Unidentified Analyst
Hello, congratulations on the results. I know there's lots of hard work and I wanted to thank you for that. The topic that I wanted to inquire about is a gap that I think it would be helpful to reconcile the gap. And when I pose the question I'm really most interested in reconciling that gap in order to understand how that gap might affect 2023. So the question is, the target for the firm was 110,000 barrels a day for year-end. In December, the President's letter confirmed that. In January, the President's letter didn't quite confirm it, but basically said that we were on track. There was a little bit of hedging and little bit of concern expressed about timing. Then in February, and on each occasion, you showed the production in the table. In February, the table showed it at 105, which was clearly below the 110 so high marks on transparency about not achieving the target. Then in March we're at 103 and again, high marks on transparency. And I know there's been some issues about deferring production. However, what that leads one to look at is a very strong declaration of the 110 being intact as of December. And then when we look at where we are today, we are now 1,000 barrels a day as per the March letter. We are 1,000 barrels a day below the Q2 2022 level. And that's all these numbers are from the letter. That is despite spending $335 million since Q2 and that's net of acquisitions. I've taken the acquisitions out. So that's a pretty big gap. And I know that there's some inflation in there, and I know there's some in the $335 million, and I know that there's some cold weather in there at the end of the year, but five rigs were going pretty much until the end of the year and the money was spent. So I've racked my brain and looked through everything to try to figure out why we would have this big gap when all that money was spent. And you did touch on it maybe more on facilities and all the rest of it, but I just was interested and if you could shed some light on the gap. And again, I think you did a great job last year. I just have this topic that I don't understand. And what I'm really looking for is for you to look out over the next year and tell us whether or not -- whatever it was that interfered with production increase over the last three quarters, a lot of money on bottlenecking or facilities are we looking out over the next year? And is that going to be less of a factor? And you did touch on it in your remarks earlier, but I'd just like you to be a little more in-depth on this. Thank you. And I'll -- I'm very interested in the answer.
JP Lachance
Okay. Thanks, Jeremy. Yes. So one of the things we put in our reserve release there was the decline rate that we actually experienced. I think part of the reason for the miss in 2022, or at least at the end of the year was the declines were higher than we thought. And so that was -- or then we forecasted certainly. So that was one of the issues you touched on the cold weather, obviously added to that as well, delayed us for a full two weeks at year-end.
We actually dropped the rig, the four -- the -- we did not have five rigs running right to the end of the year. We only had four. We dropped the fifth rig midway through the quarter. So that's part of the reason why production wasn't quite as high as we expected it should or wanted it, or expected it to be. And the decline is a big part of that coming into the year. So that's one of the reasons why we're behind at the very beginning.
So as we move forward into Q1 now, and the rest of the year in 2023, we have four rigs running. One of those rigs is dedicated to the -- is more or less dedicated to the Minehead and area doing basically drilling, earning well. So we don't get quite the same effectiveness from that rig as we would on production because it's earning at a disproportionate rate. In other words, we spend capital, but we don't get the same net results from it. So that's one of the other reasons.
And the 110 just as a reminder is, was just a -- it was a target and we did expect to meet that, and we failed to meet that, and the team recognizes that. Notwithstanding that, we were able to grow production annually by 14% over the year, as you point out. So strong results just the same, but that target was missed.
And as we go forward, we are not in any hurry here to bring on a bunch of extra production with prices the way they are. So we are being cautious and careful on how we're spending our money and how -- and whether we bring on production and with -- and we've talked about this in February, how we've also looked at doing some optimization and maintenance projects and have accelerated those into this first quarter because it doesn't make sense for us to bring -- I don't think shareholders want us to blow this -- the top off is the gas -- initial gas production at a time when prices are relatively poor. We have hedged a lot of volumes, but we don't have them all hedged, right? So that's the other part of the story.
I think I touched on most of what you said. The decline probably is the most significant difference, and that's why we're behind coming into the year. Does that help answer your question there, Jeremy?
Unidentified Analyst
Hello? Hello?
Operator
Hello. Jeremy, are you still there?
Unidentified Analyst
Yes. Yes. That's very helpful to answer my question. I just -- on the decline, I would just be interested if you could explore that a little more because again does that mean that if the wells were at target initial production and then they decline more rapidly, how does that affect the economics overall and what do you expect of the decline rate in the future? So that, that would be -- would I think round it out very nicely.
JP Lachance
Yes. So we -- yes, Jeremy. So we actually look at the economics of all of our projects on an ongoing basis. We adjust our type curves all the time. So we make sure that what we're doing out there, spending capital effectively is making us money, right? Including the current environment that we're in today, right?
So we have budgeted, or we have planned for a steeper decline in 2023, right? We've said it was -- it should be closer to 29% based on GLJ. So it's going to be in a range that's around 29% for year-over-year, 29%, 30%, let's say. So we have already budgeted for that, and that's part of our model. And just because the wells declined a little quicker at the front end doesn't necessarily mean that their reserves aren't there. And so it's just a profile that we have to better manage here as we go forward. But certainly the economics of these projects are still great even in today's price environment.
Operator
And thank you. And one moment for our next question. And our next question comes from Mike Dunn from Stifel. Your line is now open.
Mike Dunn
Thanks. Can you hear me?
JP Lachance
You can go ahead, Mike.
Mike Dunn
Great. Hey just thought I'd ask here if you could maybe flesh out a bit for us, how you expect the production to look I guess through the quarters of this year based on I guess your updated outlook to maybe targeting towards the lower end of that CapEx guidance range.
JP Lachance
Yes. So we expect that -- we'll -- we could fall a little bit here first half of the year, depending on what we do through breakup. We do plan to run rigs through breakup at this point in time it's likely three rigs and -- but we'll -- that'll depend on the weather to be honest. We've all -- every year we've gone in with the right, with the plan and it depends on how spring unfolds to be honest. So we expect that we'll be some -- we're going to fall a little bit here, we always do in Q2, just because of the nature of the fact that we don't get as much activity done. And then -- but then we'll wrap up on the back end. Of course, the degree in which we ramp up on the back end will depend on prices. That's why we built this flexibility in there.
Mike Dunn
Okay. Thanks, JP, and then another one from me, if I may. Your note talked about the Falher extended reach wells at Sundance. Maybe just explain for me, how many of these you maybe did last year and how many you're thinking of doing this year.
JP Lachance
Sure. I'm going to ask Riley to maybe comment on these for us. Riley, why don't --
Riley Frame
Yes, you bet. So yes, so we drilled a handful of these wells last year. There's a couple of different features typically kind of underdeveloped horizontally in the past. So being able to go back in and drill these with some longer laterals on the heels of some land deals that were done here to connect some sections. And all that stuff has kind of proved up the concept that these tighter channels really do work. And they're giving us some great results.
So we drilled four wells last year, and we've already got two wells down or three wells down this year, and we've got another 17 to go this year so pretty good program. And as we mentioned, the results that we're getting out of those are really favorable at this point in time. So it's another benefit of the deal we did a couple years ago in Cecilia, by and large with just another zone that we've been able to extract value out of there. So yes, they're looking very positive, so.
Mike Dunn
All right. Well, thanks for that. That's all from me.
Operator
And thank you. [Operator Instructions].
And our next question comes from Chris Thompson from CIBC. Your line is now open.
Chris Thompson
Hey everyone thanks for taking my question. First one here on cash taxes, how should we think about that for 2023?
Tavis Carlson
Hey Chris, it's Tavis Carlson here. So you think current strip prices and our planned CapEx spending for the year, we're estimating that an effective tax rate would be around 10% of for tax cash flow. We did end the year with over $1 billion of tax goals. That's going to help minimize that, that tax rate. But the annual deductions on those aren't going to be enough to fully shelter tax looking forward.
Chris Thompson
So on strip pricing then what's your level of cash taxability in 2023?
Tavis Carlson
It'd be around 10% before tax cash flow. Yes.
Chris Thompson
Okay. All right. Okay. And then next question, what are you planning to do with the excess Empress service that you have subscribed, if anything? Maybe you just tell us a bit more about that.
JP Lachance
Sure. So that's I think if you look at our marketing slides, you'll see there's a bar on there that, that shows the excess Empress service that we have or that we are supposed to get here by the end of this month. We still haven't officially got that yet. It's tranche five it's called. So -- but result it's coming. So when we get that we basically will then look at ways to monetize that.
And last year I think we saw times when disconnection of AECO was quite large and so the plan would be that service is relatively cheap, it could cost us around $0.19 to hold it. And so anything that in the market, the difference between AECO and/or Empress throughout the summer that is greater than $0.19 is going to basically add additional funds for us, right, income. So it should be a real advantage to have that service, but we need to get it first.
Chris Thompson
Got it. Okay. Okay. And then on the service cost side, have you seen any level of reduction in service costs just given where prices have gone in those conversations?
JP Lachance
I might have Lee answer that directly, but directionally Q1 is the busiest -- it's always the busiest time of the year, right. And I think all the rigs every year you look at the history that, that's when the rig count is the most of any given year. So that is one of the reasons why we pulled back that, that that rig last year because we anticipated this. But maybe Lee, do you want to comment anything?
Lee Curran
Yes, sure. Nothing yet, unfortunately as JP alluded to Q1 is high time for activity, activity hit a high watermark this year that I think outpaced a lot of people's expectations. We hit the 250 rig back to rig count in Western Canada. So between that shortage of personnel still working through some supply chain issues, I think some of the most -- I think for the most part that's been sorted out.
One of the barriers to I guess, deflation is it's a bit bittersweet, but is the impact from FX, the Canadian dollar keeps to -- keeps continuing to devalue and so we're competing with our American counterparts for a lot of commodities, so that's not helping us in any way. We are -- yes, we're working on it. We're hopeful that a lot of our services are recognizing kind of this hotspot in gas prices right now. And it's about a third of the activity out there, so we're hopeful that come middle of Q2, Q3 will see some impact, but nothing material yet, unfortunately.
Chris Thompson
Got it. Okay. Okay. And then on your capital spending plans for this year, how much of that is non-productive capital spending in the budget?
JP Lachance
So I would argue that everything we're doing is productive in some way it's going to add value to the company. So -- but as far as what's not directed directly -- sorry, is not directly on wells and sorry, just on other things like facilities and whatnot, that that average is probably around 20%. I mean, Todd can allude to the fact here; maybe it's a good time to talk about what we have in the facility side. Todd, you want to -- what's the stuff that we're doing that isn't related to drilling wells?
Todd Burdick
Sure. So obviously last year we had the Chambers plant and that that was a big part of like, I guess a abnormally high facility and project budget. But this year, obviously JP mentioned that we're working on the cascade connection. So that's been going really well. No major issues. We expect to have the pipeline done here probably in the next two weeks to three weeks with the final connections. Some facility work that still has to happen should happen in Q2 so we'll be ready there. So that's a fairly good piece of the facility or project side. A little bit of plant optimization is planned to happen at Oldman and just some of the Sundance plants and then our regular maintenance.
And really other than that we've got some pretty robust production optimization projects that that from a cost per Mcf or per BOE are pretty I guess advantageous versus what you get when you drill a well. So not only we get extra production out of that as well, so -- and that'll help bring up production on the base and stabilize it a little bit. So that's the key things that we're working on that should bear fruit through the year.
JP Lachance
Thanks, Todd. That's good. Yes. Any other questions, Chris?
Chris Thompson
Yes, sorry, one more from me, if you don't mind. So just on the third-party outages coming up this summer, where are you guys seeing that -- the highest pain points for per pricing through the summer?
JP Lachance
When you say third-party outages, what do you mean? Sorry.
Chris Thompson
Well, so that'd be like maintenance on NGTL pipeline or other facilities that'll impact you guys.
Todd Burdick
Yes. There'd be a -- there is a small outage I believe at plants that may affect our NGL volumes. We'll just warm up. That's the beauty of us operating our production. And we can change the conditions of how we operate. So that's a smaller one that's happening. I think that's happening in --
JP Lachance
That's in May.
Todd Burdick
May. So we'll warm up a little bit. So we'll put the liquids back in the gas base and sell the heat content instead. Hopeful the gas prices will be better then. But NGTL wise, we have excess capacity on the system, so we should be able to absorb any kind of maintenance changes if there's FTR cuts, but there's -- if there's foreign transportation cuts to that system. And -- but that depends on how NGTL operates the system here this summer, whether they do that or they cut IT to deliveries and restrict storage. So it really depends on how they manage their maintenance schedule or how it may affect us, but we're protected in all ways.
Operator
And thank you. [Operator Instructions].
And one moment, we do have a follow-up question. And we have Jeremy [indiscernible]. Your line is now open.
Unidentified Analyst
Hi again, JP, the last year one of the headwinds that was pretty obvious was the hedging was at prices that when AECO spiked it led to quite a negative impact, which you absorbed well because of the great results. Quite a negative impact on the royalty costs. The fact that our hedges are now above AECO or very near AECO is pretty transparent and obvious. And so I think that's well understood. The part that is less well understood at least by me, I know it exists, but I don't quite know the dimensions of it. Is the favorable impact that, that this has looking out over the 2023 year when AECO is near our hedges or indeed, AECO is below our hedges there's a quite an adjustment, I think to the projected royalty costs, which is a favorable tailwind this year compared to last year. I was just wondering if you could shed a little light on the dimensions of that and the mechanics.
JP Lachance
Sure. Yes. So just a reminder that when we pay royalties, we pay them on the AECO price, right? The par price or the AECO price that, that, that basically, so when we have all this diversification away from AECO and the fact that we have hedges, I would say are unfortunately in the money in some cases, as we look forward and I say unfortunately, because ideally we're not -- that's not why we're doing it, right? We're doing it to secure revenues, not necessarily to beat the market, but obviously hedge -- royalties are going to be lower with lower prices. And so that, that will be much better than last year. So that will be helpful. It'll be accretive.
And since our diversification to all these other markets, as you described, actually puts us in a better position, puts us above -- should put us above the realized price. Our realized price should be better than the AECO -- than the AECO price. And so that has added a compound effect to our cash flows because we won't be paying as much royalties either because I think, as you pointed out last year, royalties were quite a bit higher as a percent. And we also had realized prices that were lower than AECO at that time. So it is -- it's going to be very accretive I think this year.
Unidentified Analyst
Any dimension you can put on that because I know in the worst quarter, we had a $0.95 royalty and it's eased back to $0.75. But the -- and I'm really trying to get at the dimension of the tailwind meaning if AECO is going down and we're experiencing the decline and the fact that royalties go down, well, we're not better off. But if in the forward quarters, the impact on our revenues is only a third of our production, but the impact on the royalties is on 100% of our production with favorability skewed to the hedged portion, that that grinds out a certain non-proportionate tailwind. And it looks like it's well in excess of $0.10. But I don't really know how to model it. So I'm just back of the envelope, $0.10 to $0.20 is the disproportionate improvement in royalties. So do you have anything on that or we can take it offline?
JP Lachance
We can take it offline maybe, but we were estimating royalties for this year are 9%, about 9% based on the current strip based when you roll it all in for right 9%. Yes. I'm just confirming.
Kathy Turgeon
It was 11% in 2022.
JP Lachance
And the average for 2022 was 11%. So that puts some perspective on the royalty percentage. We can take this offline, Jeremy, if that's okay.
Unidentified Analyst
Thank you.
JP Lachance
Okay.
Operator
And thank you.
JP Lachance
I have one more question from the e-mail I would like to get to that we never addressed here, Justin. So I was going to turn -- I'm going to ask questions for Derick here. We had -- we spent 90 -- $55 million last year on acquisitions and that includes Crown land sales. We bought 28 sections last year. Maybe Derick, you can expand a bit about how we've -- what we've done with those assets? We had a great year in 2021 where we bought an asset in Cecilia area where we turned it, say into gold, but we certainly exploited it very well and grew the production in that area. How have we done with the assets that we just bought last year? I know one was at the end of the year.
Derick Czember
Yes. No, for sure, we're definitely happy with the acquisition. We're able to close in 2022. We typically don't do big flash of deals. But our goal is to do deals that make sense and are profitable. The acquisitions are very similar to the acquisition in connection in that they provide immediate results and opportunity the complementary nature of the assets.
The corporate acquisition added an underutilized 45 million a day new Aurora gas plant, 73 net sections of land, approximately 900 BOE a day from 20 net wells. On the property acquisition side, we picked up 42 net highly perspective sections that came with approximately 600 BOE a day from 12 net wells that also came with 50 million kilometer pipe, 50 million a day capacitor. We were able to grow this property to over 5,000 BOE at year-end and close the deal on September 13. We are continuing to drill the land. I believe we're now pushing past 6,000 BOE. We are able to do this because of the incredible fit for existing land based infrastructure. Also, the technical support did an excellent job hiring and executing prior to and after closing. And if you haven't done so, I recommend checking out our corporate presentations to the exceptional fit that these acquisitions provided hail [ph].
And then on the farming side of things, we're in early days in our Minehead farming and we've also started going on the Ansell farming. That has created some excitement over here. We currently have the ability to earn 35 sections across through these departments. And then, as for 2023, we continue evaluating new opportunities and remain opportunistic if the right yield presents itself. We also try to have some irons in the fire, so hopefully we can track on those opportunities this year.
Also on the asset team front in addition to being very active in Crown sales evaluating them, but we're also very active doing smaller farm swaps and cooling to enable growth of existing body. This activity has been ongoing already at 2023 and we'll continue to be working here.
JP Lachance
Thanks. So, yes, we've been very effective with those smaller deals. They're not big flashy things, but we certainly have been effective with those smaller tuck-in type acquisitions as organization. Yes. I don't -- is there any more questions?
Operator
I'm showing no further questions over the phone.
JP Lachance
Okay. Well, thank you very much for attending the call and we'll talk again soon.
Operator
This concludes today's conference call. Thank you for participating. You may now disconnect.
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Peyto Exploration & Development Corp. (PEYUF) Q4 2022 Earnings Call Transcript