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 speaker's presentation, there'll be a question-and-answer session. To ask a question during the session, you'll need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, to JP Lachance, President and CEO. Please go ahead.
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 & Business Development, and Lee Curran, our VP of Drilling & 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%. 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. 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 quarter's and year-end results. We have a small but dedicated team in our Calgary office, and that makes it all happen. Of course, an important part of our success is those folks in the field, the operators, the foremen, the maintenance crews, they keep our wells producing and our plants going. We had a very cold snap just before Christmas, where all hands were needed to keep production on stream.
It's always good to see that the percentage of Peyto's lost production during this period was only about half of that of what the industry lost as a whole. To me, that's a testament of our field folks' 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 reliable electric power generation too. In that sense, natural gas is truly life-saving energy, and we are proud at Peyto to be one of Canada's top suppliers of it. Okay, enough of soapbox here. 2022 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, 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. 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 develop gathering systems in Sundance in 2022 to accommodate future growth. I think all total, we spent about CAD 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. From our February 16th reserves release, you'll note that Peyto replaced 165% of production with new PDP reserves. We did it for a finding, development and acquisition cost of CAD 8.46 a barrel or CAD 1.41 per Mcfe, we're a gas company, we 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, you know, much better prices, including our hedging losses. When you couple that with our industry-leading cash costs, it means we generated a cash netback of CAD 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 $6.38 per MMBtu, up from $3.84 in 2021. 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 dropped towards zero. 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.
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. Late this year, we'll have about 10% of our volumes flowing to 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 contango, and we are continuing with our systematic hedging program. We're up to about 60% hedge now on average for 2023 at prices near $4 in Mcf, which helps 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. Before we open up to questions, I just like to point out one more, you know, 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 takeaway capacity from the Gulf. Should be a pull on prices there. There will always be a seasonal supply and demand swing, as, you know, the commodity is really dependent. We should expect to see price volatility to remain. 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. Enough out of me. Let's turn the call over to questions. Before we go to the phone lines, I just have one question that came in overnight, that comes in it right off the top, and maybe we should just address because it's a recurring theme.
The question that came in from email, 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? 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 contango. Should 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, you know, smart, good returns with the money that we're spending.
As I mentioned already, we've already, you know, done that. We're guiding to the lower end of our guidance. We're targeting the lower end of our guidance to pull back and to hydrate our projects, so we're deferring the longer payout wells on the facility projects. We expect that if prices do remain low, service costs will realign accordingly as well. We still have plans to reduce our debt, and strengthening the balance sheets is also still a priority. To answer this question in short, you know, no, we don't currently have, don't currently expect to change the dividend. With that, let's open it up to the phone lines. If there are questions for folks who wanna answer, the whole team is here to answer them.
Thank you. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. One moment for our first question. Our first question comes from Karthik Rathod from Bloomberg. Your line is now open. Karthik, your line is now open. If your line's on mute, please unmute. Bear with me one moment, please for our next question. One moment. Our next question comes from Gerald Macey . Your line is now open.
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. When I pose the question, I'm really most interested in reconciling that gap in order to understand how that gap might affect 2023. 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. In February, on each occasion, you showed the production in the table.
The table showed it at 105, which was clearly below the 110. You know, high marks on transparency about not achieving the target. Then in March, we're at 103, and again, high marks on transparency. You know, 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. 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. All these numbers are from the letter. That is despite spending CAD 335 million since Q2, and that's net of acquisitions.
I've taken the acquisitions out. That's a pretty big gap, and I know that there's some inflation in there, and I know there's some in the CAD 335, and I know that there's some cold weather in there at the end of the year. Five rigs were going pretty much until the end of the year, and the money was spent. I 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. You did touch on it, you know, maybe more on facilities and all the rest of it. I just was interested in if you could shed some light on the gap. Again, I think you did a great job last year. I just have this topic that I don't understand.
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, you know, a lot of money on debottlenecking or facilities. Are we looking out over the next year, and is that gonna be less of a factor? You did touch on it in your remarks earlier, I'd just like you to be a little more in-depth on this. Thank you. I'm very interested in the answer.
Okay. Thanks, Jerry. Yeah. 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 or than we forecast, certainly. 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. 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.
That's part of the reason why, you know, production wasn't quite as high as we expected it should or wanted it or expected it to be. The decline's a big part of that coming into the year. That's part of the reasons why we're behind at the very beginning. 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 more or less dedicated to the Minehead area doing basically drilling earning wells. 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. That's one of the other reasons. The 110, just as a reminder, it was a target, and we did expect to meet that, and we failed to meet that, and the team recognizes that. Notwithstanding that, you know, we were able to grow production annually by 14% over the year, as you point out, strong results just the same, but that target was missed. As we go forward, we're not in any hurry here to bring on a bunch of extra production with prices the way they are. We are being cautious and careful on how we're spending our money and whether we bring on production.
We talked about this in February, how we've also looked at doing some optimization and maintenance projects and accelerated those into this first quarter because it doesn't make sense for us to bring. You know, I don't think Cheryl wants to blow the top off this initial gas production in a time when prices are relatively poor. We have hedged a lot of volumes, but we don't have them all hedged, right? 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. That help answer your question there, Jerry?
Hello?
Yeah.
Hello?
Hello. Jerry, are you still there?
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, you know, if the wells were, at, you know, target initial production and then they decline more rapidly, you know, how does that affect the economics, overall? What do you expect of the decline rate in the future? That would, I think, round it out very nicely.
Yeah, Gary, we actually look at the economics of all of our projects on an ongoing basis. We adjust our type curves all the time. 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? We have budgeted or we have planned for a steeper decline in 2023, right? We've said it should be closer to 29% based on GLJ. It's gonna be in a range that's around 29% for year-over-year, 29%, 30%, let's say. We have already budgeted for that, and that's part of our model.
You know, just because the wells decline a little quicker at the front end doesn't necessarily mean that their reserves aren't there. It's just a profile that we have to better manage here as we go forward. Certainly, the economics of these projects are still great even in today's price environment.
Thank you.
Thank you. One moment for our next question. Our next question comes from Mike Dunn from Stifel. Your line is now open.
Thanks. Can you hear me?
We can. Go ahead, Mike.
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, you know, 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.
Yeah. We expect 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. That'll depend on the weather, to be honest. Every year we've gone in with a plan, and it depends on how spring unfolds, to be honest. You know, we expect we're gonna 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. We'll wrap up on the back end. Of course, the degree in which we wrap up on the back end will depend on prices.
That's why we built this flexibility in there.
Okay, thanks, JP. Another one from me, if I may. Your note talked about the Falher extended reach wells at Sundance. Maybe just explain for me, you know, how many of these you maybe did last year and how many you're thinking of doing this year.
Sure. I'm gonna ask Riley to maybe comment on these for us. Riley, you want-
Yeah, you bet. Yeah, we drilled a handful of these wells last year. There's a couple of different features, you know, typically kind of underdeveloped horizontally, in the past. 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 is has kind of proved up the concept that these, you know, these tighter channels really do work, and they're giving us some great results. 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. Pretty good program.
You know, as we mentioned, the results that we're getting out of those are really favorable at this point in time. You know, it's another benefit of the deal we did two years ago in Cecilia, by and large, with, you know, just another zone that we've been able to extract value out of there. Yeah, they're looking very positive, so.
All right. Well, thanks for that. That's all for me.
Thank you. If you'd like to ask a question, that is star one one. Again, if you'd like to ask a question, that is star one one. One moment for our next question. Our next question comes from Chris Thompson from CIBC. Your line is now open.
Hey, everyone. Thanks for taking my question. First one here on cash taxes. How should we think about that for 2023?
Hey, Chris. It's Tavis Carlson here. Using current strip prices and our planned CapEx spending for the year, we're estimating that an effective tax rate would be around 10% of pretax cash flow. We did end the year with over CAD 1 billion of tax pools. That's gonna help minimize that tax rate. The annual deductions on those aren't gonna be enough to fully shelter tax looking forward.
On strip pricing, you know, what's your level of cash taxability in 2023?
It'd be around 10%.
Of our pretax.
Yeah, of our pretax cash flow, yeah.
All right. Okay. Next question. What are you planning to do with the excess Empress service that you have subscribed, if anything? Maybe you could just tell us a bit more about that.
Sure. That's, I think, if you look at our marketing slides, you'll see there's a bar on there 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. But we've been told it's coming. When we get that, we basically will then look at ways to monetize that. You know, last year, I think we saw times when the disconnection to AECO was quite large. The plan would be, you know, that service is relatively cheap.
It could cost us around CAD 0.19 to hold it. You know, anything that in the market, the difference between AECO and/or Empress, throughout the summer that is greater than CAD 0.19 is gonna basically add additional funds for us, right? Income. It should be a real advantage to have that service, but we need to get it first.
Got it. Okay. Okay. On the service cost side, have you seen any level of reduction in service costs just given where prices have gone in those conversations?
I might have Lee answer that directly, you know, directionally Q1 is the busiest. You know, it's always the busiest time of the year, right? I think all the rigs every year, if you look at the history, that's when the rig count is the most of any given year. That is one of the reasons why we pulled back that rig last year, 'cause we anticipated this. Maybe Lee, do you wanna comment anything?
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, active rig count in Western Canada. So, between that shortage of personnel, still working through some supply chain issues, I think some of those, I think for the most part, that's been sorted out. One of the, one of the barriers to, I guess, deflation is, it's a, it's a, it's a bit bittersweet, but, is the impact from FX. You know, the Canadian dollar keeps continuing to devalue, and so we're competing with our American counterparts for a lot of commodities. That's not helping us in any way.
We are, yeah, 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. You know, it's about a third of the activity out there. We're hopeful that come middle of Q2, Q3, we'll see some impact, but nothing material yet, unfortunately.
Got it. Okay. Okay. On your capital spending plans for this year, how much of that is non-productive capital spending in the budget?
I argue that everything we're doing is productive in some way, and it's gonna add value to the company. As far as what's not directed directly, sorry, it is not directly on wells and Sorry, just on other things like facilities and whatnot. That averages 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 wanna... What's the stuff that we're doing that isn't related to drilling wells?
Sure. You know, obviously last year, we had the Chambers plant and, you know, that was a big part of, like, I guess, abnormally high facility and project budget. You know, this year, obviously, JP mentioned that we're working on the Cascade connection, that's been going really well. No major issues. We expect to have the pipeline done here probably in the next two-three weeks with the, you know, final connections, some facility work that still has to happen, should happen in Q2, so we'll be ready there. You know, that's a fairly good piece of the facility or project side.
You know, a little bit of plant optimization is planned to happen at Oldman and some of the Sundance plants and then our regular maintenance. You know, really other than that, we've got some pretty robust production optimization projects that from a cost per MCF or per BOE are pretty, you know, I guess advantageous versus what you get when you drill a well. Not only we get extra production out of that as well. That'll help bring up production on the base and stabilize it a little bit. That's the key things that we're working on that should bear fruit through the year.
Thanks, Todd. That's good. Yeah. Any other questions, Chris?
Yeah. Sorry, one more from me, if you don't mind. Just on the third-party outages coming up this summer, where are you guys seeing the highest pain points for pricing through the summer?
When you say third-party outages, what do you mean? Sorry.
So that'd be like, maintenance on an NGTL pipeline or other facilities that'll impact you guys.
Yeah, there is a small outage, I believe, at Plains 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. That's, that's a smaller one that's happening. I think that's happening in-
That's in May. Yeah.
May. We'll warm up a little bit, so we'll put the liquids back in the gas phase and sell the heat content instead. Hopefully, gas prices will be better then. NGTL-wise, we have excess capacity on the system, so we should be able to absorb any kind of maintenance changes if there's FGR cuts, if there's firm transportation cuts to that system. That depends on how NGTL operates the system here this summer, whether they do that or they cut IT capacity to deliveries and restrict storage. It really depends on how they manage their maintenance schedule, how it may affect us. We are protected in all ways.
Got it. Okay. Thank you very much. I'll hand it back.
Thank you. If you have a question, that is star one one. Again, if you have a question, that is star one one. One moment, we do have a follow-up question. We have Gerald MacKaye. Your line is now open.
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. 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 this has looking out over the 2023 year, when, you know, 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.
Sure. Yeah. Just a reminder that when we pay royalties, we pay them on the AECO price, right? The par price or the AECO price. When we have all this diversification away from AECO, and the fact that we have hedges, you know, I would say are unfortunately in the money in some cases as we look forward. I say unfortunately, because ideally, we're not, you know, that's not why we're doing it, right? We're doing it to secure revenues, not necessarily to beat the market. Obviously, hedge royalties are going to be lower with lower prices, that will be much better than last year. That will be helpful. It'll be accretive.
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. That has an added compound effect to our cash flows because we won't be paying as much royalties either. I think, as you pointed out, last year, royalties were quite a bit higher as a percent. You know, we also had realized prices that were lower than the, than the AECO at that time. It is, it's gonna be very accretive, I think, this year.
Any, any dimension you can put on that? Because I know in the worst quarter, you know, we had a $0.95 royalty and it's eased back to $0.75. I'm really trying to get at the dimension of the tailwind, meaning, you know, if AECO's going down and we're experiencing the decline and the fact the royalties go down, well, we're not better off. 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 grinds out a certain non-proportionate tailwind. You know, it looks like it's, you know, well in excess of $0.10, but I don't really know how to model it.
I'm just, you know, back of the envelope, you know, CAD 0.10-CAD 0.20 is the disproportionate improvement in royalties. I. Do you have anything on that or, we can take it offline?
We can take it offline maybe, but we're estimating our royalties for this year, we're 9%. About 9% based on the current strip. You know, when you roll it all in for... Right, 9%? Yeah, I'm just confirming.
It was 11% in 2022.
The average for 2022 was 11. That puts some perspective on the royalty %. We can take this offline, Jerry, if that's okay.
Thank you.
Okay.
Thank you.
I have one more question from email I'd like to get to that we never addressed here, Justin. I'm gonna ask a question for Derick here. We had we spent CAD 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, you know, 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 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.
Yeah. No, for sure. We're definitely happy with the acquisitions we were able to close in 2022. You know, we typically don't do big flashy deals, our goal is to do deals that make sense and are profitable. The acquisitions are very similar to the Cecilia acquisition you mentioned, in that they provide immediate results and opportunities. Complementary nature of the assets. The corporate acquisition added an underutilized 45 million a day, newer Aurora gas plant, 73 net sections of land and approximately 900 BOE a day from 20 net wells. On the property and acquisition side, we picked up 42 net highly prospective sections that came with approximately 600 BOE a day, from 12 net wells.
That also came with 59 kilometers of pipe and a 15 million a day compressor. We were able to grow this property to over 5,000 BOE at year-end, and we closed the deal on September 13th. We are continuing to drill the wells. I believe we're now pushing past 6,000 BOE. You know, we are able to do this because of the incredible fit to our existing land base and infrastructure. Also, the technical ability team did an excellent job of planning and executing prior to and after closing. Yeah, if you haven't done so, I recommend checking out our corporate presentations to the exceptional fit that these acquisitions provided 2023.
You know, on the farm-in side of things, you know, we're in early days in our Minehead farm-in, we've also started going on the Ansell farm-in that has created some excitement over here. We currently have the ability to earn 35 sections gross through these farm-ins. As for 2023, you know, we continue evaluating new opportunities and remain opportunistic if the right deal presents itself. We always try to have some irons in the fire to hopefully we can transact on some of those opportunities here this year. Also on the asset team front, in addition to being very active in crown sales and evaluating them, we're also very active doing smaller farm-in swaps and pooling to enable growth of the existing land base.
You know, this activity has been ongoing already in 2023, and we'll continue throughout the year.
Thanks. Yeah, we've been very effective with those smaller deals. They're not big splashy things, but we certainly have been effective with those smaller back-end type acquisitions as an organization.
That's great.
Okay. Is there any more questions?
I am showing no further questions over the phone.
Thank you very much for attending the call, and we'll talk again soon.
This concludes today's conference call. Thank you for participating. You may now disconnect.