Brian Ector: Okay, thanks, Eric. A couple of questions have come in around the production volumes we reported during Q1, Eric. Can you explain maybe the difference between what we realized in Q1 from a production standpoint relative to Q4 and how that sets us up for the year?
Eric Greager: Yes, thanks, Brian. So, Q4 was strong. So, above the high end of our guidance range at the exit and on less capital in Q4 than we anticipated. So, that was a very strong kind of operational outcome for Q4. The thing that’s important to keep in mind is the 151, I’ll call it, for Q1 was also, well within our outlined full year guidance plan. So, 150 to 156 was our plan, our guidance plan. And the 151 or 150.6 is what we expected in line with our expectations. Now, the difference between the 160 and the 151, it’s important to understand there was 4,000 BOE a day in the Viking, 100% oil sold, and the proceeds from that were put to debt in Q4. And so, that accounts for 4,000 of the 9,000. The other part of that drop between 160 and 151 is really related to seasonality and in particular related to our marathon non-op activity in our non-op Eagle Ford, the Karnes Trough, Eagle Ford.
Marathon had been working very diligently throughout the year and in particular throughout the summers, Q2 and Q3. But by the end of Q3, it essentially spent the capital they had allocated to the project. And so, in all of Q4, there was no stimulation, no wells turned to sales. And so, naturally, between Q3 and Q1, all the production, particularly the newest production with the highest pressures, released in late Q3 declined off into Q1. And so, that is the other part of the gap. But none of this comes as a surprise, Brian, and this. This was all within our guidance range, and we continue to reiterate not only our 150 to 156 guidance range, but also the continued growth throughout the quarters of our production. So, let me stop there.
Brian Ector: Thanks, Eric. Okay, I want to shift. We’ve had a number of inbound questions on the webcast related to our operations. I’ll start with Chad Lundberg. As an opening question, Chad, how many wells are planned to be drilled in 2024?
Chad Kalmakoff: Thanks, Brian. So, yes, total quantum of wells drilled this year will be 250. If you reference the investor pack online, that’s page 7 of the slide deck, roughly 60 of those are being allocated into the United States, and they’d be for properties both on an operative basis. A hundred of those are in the Canadian side, our light oil business, and then approximately 90 would be the balance of the 250 through our heavy properties. The other thing I would note is just the efficiencies we’re seeing as we, levelize our ego forward and think about the big machine that we call our assets today. Just the efficiency, you see it in the pressure leaks. We saw a 21% improvement on drill days through the Durban A. That translated and flowed through a 10% cost increase.
We’re seeing that in the United States with 8% reduction in EUFAR costs. Largely synergistic with each other, and we’re just excited to be able to share across both sides of the border as we think about improving.
Brian Ector: And, Chad, just an investor asking us to confirm our 2024 plans at Peavine. The well count, I believe we’re looking at for a total of 35 wells this year.
Chad Kalmakoff: Yes, I mean, Peavine has been, a tremendous story, obviously, for those who have followed us since we started back in 2021 with our first exploration and discovery well. This year we’ve ramped to two rig steady pace program that would be approximately 35 wells. Twelve of those are down in Q1. We’re looking at an option to, maybe drop that back to one rig and attempt to drill through break up here. It would still achieve close to the same well count, the 35, but we’re excited, again, about the efficiency that we can drive out of the program by just really continuing to think about operating this equipment on a very steady basis. And the crew, the equipment, the efficiency we can drive out of that.
Brian Ector: And, Chad, with recent flooding around the Texas area last week, any of our production affected?
Chad Kalmakoff: No, the short answer is nothing was affected last week. Definitely heavy rains in the greater Houston area. I think, when I think about that production team, they’re very good at managing and operating, obviously, in their own acute conditions. No different than in Canada in our coal conditions that permeate themselves through the Q1 time period. But no flooding effects last week.
Brian Ector: Maybe a question back to you, Eric, operationally. Production levels that could, we talked about our heavy oil plays. You mentioned earlier, referred to the Rex, the Waseca, Grizzly, even the Duvernay. What production levels could be expected in these heavy oil plays as we move forward?
Eric Greager: Yes, so these are, in terms of moving the needle on a base of 153,000 BOE a day, the midpoint of our range, they’re not going to be that meaningful. But having said that, the well performance really, really is quite strong. And the economics are really incredible because, these, generally speaking, these multilaterals in high quality, competent reservoir don’t require liners. They don’t require cementing. They don’t require any stimulation. These are just long, open hole multilaterals tied into a single well. And so the capital is very modest, I mean, compared to unconventional Duvernay and Eagle Ford, for example. So a couple hundred barrels a day out of each well, and we’ve got four wells on in Morinville, and I think we’ve got five wells on in the new Waseca play at Greater Cold Lake.
And both of those are in excess of 1,000 barrels a day today. And they’re very flat declines, flatter in Waseca than in Morinville because the Morinville reservoir is a little higher pressure. And when you have higher pressure, you generally have higher, early decline rates. But nevertheless, both of those will grow to a few thousand barrels a day each. And on the basis, of 153,000 BOE a day in growing, it’s modest. But, again, these things are so accretive in terms of economics and nav creation that they’re very, very attractive to us. And we will continue to deploy our geoscience teams and our intellectual property across our large heavy oil pipeline to find these where they are.
Brian Ector: A two-part question on the Duvernay for you. Any ability to acquire additional land beyond the Crownland purchase from Q1? And part two, what level of production in wells per year could we see from the Duvernay? And what type of growth profile?
Eric Greager: Yes, so there’s always more you can buy. We’re very intentional about where we spend the money. It’s got to be, as good as what we’ve got already or better. And, of course, the 31 net section acquisition we made in Q1 in the Duvernay met that criteria and is immediately executable. That’s the other thing. You don’t necessarily want to, find yourself in a position where you’ve bought high-quality resource that you can’t execute on quickly. And so next year, because we’ve already finished the drilling, casing, and cementing of our 2024 program, next year we’ll actually be deploying capital against not only our existing Pemina-Duvernay position but our new extension to better understand it, continue to inform our technical models, and bring, obviously, value forward on that land acquisition. And now in terms of how fast we can grow it, we’ve steadily ramped activity in our Pemina-Duvernay, two wells per year, four wells per year, six wells per year last year, seven wells per year this year.
We’re expecting north of seven next year. I’m going to say nine or ten if we’re just kind of broad brush strokes here. But it’ll certainly be seven to ten. It’ll be more than what we’ve done this year. And we’re going to continue growing that. Our LRP contemplates a max of 12 wells per year, but that was before our new acquisition. And so we think we’ll be north of that as well. And we think this, as we continue to ramp this and on good results potentially accelerate, because the capital efficiency is very strong and accretive to our portfolio, we would grow this thing, to we think north of 20,000 BOE a day over, perhaps a five-year period, perhaps a year or two longer. Some of this is still in the works in our current LRP, but it’s a meaningful addition.
In fact, with most of the rest of our portfolio running flat, this is where our growth engine is, and we’re very excited about that. It’s high-quality contiguous position with lots of control, and we’re excited about the opportunity to continue deploying capital there, growing the asset, and doing so at incrementally accretive capital efficiencies, which will improve our overall business over time.
Brian Ector: At a high level, Eric, acquisitions and dispositions, what are we thinking about as it relates to that? What areas would you consider core? And maybe part of that, given the diversity of the asset base, would we consider pursuing asset sales?
Eric Greager: Yes, so we sold a portion of the Viking last year. It’s a good place to start in this answer because we call those assets 4 again in PLATO, and it was 4,000 BOE a day, and we got $160 million out of that. Now, the challenge was, and the reason those assets were carved out of the portfolio is because they could not compete for capital within our portfolio, and so given that fact, we were left with two choices. We were left with deploying capital against assets that didn’t compete in the portfolio, and that capital then, of course, punches below its weight because you’ve taken it away from an allocation to a higher-performing asset, so that’s diluted to your performance. Or you don’t allocate capital, and we know that fracture-stimulated reservoirs over time, like 4 again in PLATO and Viking, starved of capital would decline to no value over a couple of years.
And so you don’t want to starve an asset of capital and allow it to decline to no value. You also don’t want to allocate capital to something that doesn’t compete, and so you’re left with, if it’s worth more to the outside world than it is in our portfolio, we should sell it. And so we set a retention value on that basis, and the proceeds were clearly worth more than it was inside our portfolio, so we sold it. We think that’s disciplined portfolio management, and we revisit our portfolio every single quarter because market conditions change, differentials change, quality and performance, the quality pricing and so on changes. So we revisit that frequently and continue to reallocate our capital to the highest-returning portions of our business within our portfolio.
If something doesn’t compete, then it gets considered for disposition. Right now, everything in our portfolio is funded and competes for capital, but should that change, we will run a disciplined discounted cash flow analysis, and we’ll set a retention value, and we will test the market. And if it’s worth more on the open market than it is within our portfolio, we’ll sell it. We think that’s disciplined. We think that’s the right economic basis upon which to sell assets, and the proceeds of any sale would be applied today to our debt.
Brian Ector: Okay, thanks, Eric. Let’s revisit really quickly our free cash flow profile for the year. Q1 free cash flow is zero. We talked about that. We say full-year free cash flow at the current strip is $700 million. Why the disconnect between Q1 and the balance of the year, Eric, and maybe a second part of that, is there any reduction in E&D spending to improve the free cash flow profile?
Eric Greager: Well, it’s a great question. We talked earlier about the 2% top-line production growth year-over-year as being set essentially as close to flat as we feel comfortable because the seasonality of our assets and our portfolio, require us to be a little north of flat to avoid things that we think wouldn’t be very constructive. So we like 2% per year top-line production growth, and if we reduce E&D capital further, of course, that would have lagging, knock-on production impacts. And these are all very profitable investments. So, everything we’re investing in, have IRRs that are substantially north of our threshold, crochets that are substantially north of our thresholds, and are all very economic. And so these are economic investments, and we’ve set the E&D capital to be as low as it can be, which corollary to that essentially suggests that we’re maximizing free cash flow generation.
