All righty. Next up, we have Saturn Oil & Gas, traded under the ticker SOIL on the Toronto Stock Exchange. Saturn is a Canadian oil and gas producer focused on developing high-quality assets across Saskatchewan and Alberta with a strong emphasis on operational execution and shareholder returns. Representing the company, we have Doug Deugo, Director, Exploitation and Engineering, and Cindy Gray, Vice President of Investor Relations.
Thanks so much, Errol, and thanks everyone for joining us this afternoon. A big thanks to Three Part for hosting this conference. Canadian energy is in a structural renaissance right now with what looks like the best backdrop we've seen in probably a decade.
We're pretty excited to be here and share the Saturn story with you. Just a reminder, all of the numbers that we state today are in CAD, unless we're talking about WTI prices, which are obviously in U.S. Saturn's a differentiated energy company. We have grown rapidly over the past five years, and our investment thesis is really centered around three key attributes. We've got a very diversified asset base that's weighted more than 80% to high-value oil and liquids.
We've got relatively shallow declines, meaning we don't have to replace production as quickly as some of our peer group does. We have 1.5 million net acres of land across Saskatchewan and Alberta. Our assets are midlife cycle, that means that we already have infrastructure in place so that the bulk of our capital can go towards drilling and production optimization, which are the activities that add immediate cash flow. Further, we have a demonstrated track record of outperforming on our well results. Saturn has protected the downside of our business.
We target lower cost, lower risk conventional wells, given our asset diversification, we don't have concentration risk. Saturn has one of the highest free cash flow yields among our peer group, despite our share price having nearly tripled since the beginning of 2026, our market value remains disconnected from our asset value.
To protect our debt, we use hedging, while our nimble and flexible capital program means we can rapidly and effectively ramp up spending or ramp down spending depending on commodity prices. All this leads to a compelling upside. Saturn continues to meet or beat analyst expectations as well as our internal guidance while being disciplined about our capital allocation. We're methodically reducing debt and buying back our own shares to improve per-share metrics, with this, we see opportunity for a re-rate. Quick snapshot on Saturn.
We've got a market cap of about CAD 1.3 billion and an enterprise value of CAD 2 billion. Our shares are owned largely by institutions. As you can see here, about three-quarters of our equity is held by U.S. and Canadian funds, with Atlanta-based GMT Capital and New York-based Libra Advisors holding just under 50% collectively.
Since closing our first major acquisition in 2021, we've delivered a compound annual growth rate of production of 193%, achieving current volumes today of over 43,000 BOE per day. We've used a combination of debt and equity to fund this growth. Our debt is comprised of publicly traded $650 million principal, senior notes having a coupon of nine and five-eighths, a five-year term, and a unique amortization feature that sees us paying down 2.5% of the principal each quarter.
In the past 12 months, we've delivered significant value per share on a debt-adjusted basis, as evidenced by 114% growth in production per debt adjusted share. Our strategy is based on a repeatable blueprint that's designed to increase per-share value. First, we acquire midlife cycle assets at attractive valuations, targeting assets within core areas where we can integrate them seamlessly and leverage our size and scale in the area.
Next, we look to optimize. We take those acquired assets, bring down costs, improve margins, which we also refer to as netbacks, and increase our free cash flow. This optimization includes streamlining infrastructure by consolidating facilities, improving blending, replacing pumps on wells, and really, we just watch every penny.
Repeatedly making small, incremental improvements across the asset base can really add up, as Doug will touch on later. From there, we develop to expand our reserves and increase the runway of drilling locations, further enhancing the long-term sustainability of the company. Finally, we reduce net debt, and we do that so that we can repeat the process, and we look to achieve a net debt to adjusted EBITDA multiple of 1x or less in the 12 - 18 months following an acquisition. This slide showcases this blueprint in action.
Since 2021, we've done four major acquisitions totaling CAD 1.4 billion, each of which has nearly doubled the size of the company at the time, and for acquisition metrics that are around 2x or below cash flow. The first two of these, Oxbow and Viking, were asset acquisitions in Saskatchewan, while the third was a CAD 500 million corporate acquisition of Ridgeback Resources, which was an Apollo-backed oil company.
That expanded our Saskatchewan portfolio and gave us an entry into Alberta. The fourth acquisition was another CAD 500 million transaction in Saskatchewan that closed in mid-2024. When we did this transaction, we reached into the U.S. credit markets, and that's when we issued the U.S. senior note and effectively lowered our borrowing costs. I'll now hand it over to Doug, who will talk about how this has resulted in our portfolio today.
Thanks, Cindy. We're 43,000 bpd , largely Canadian production, and most of that production is coming from Saskatchewan. Over half of our production from our Southeast Saskatchewan core area in the bottom right there, that was amassed over several deals there. We have a large high working interest position down there, an expansive infrastructure network, and it's a large focus area for us. Saskatchewan is a really good province to work in our mind.
The government is very friendly to oil and gas, really open to collaboration with oil and gas companies. They actually have a provincial target to double their output, and they offer some very low royalty rates. The balance of our production comes from our Alberta assets, where we have our oil-driven Montney and Cardium plays there.
Cindy touched on it, the nature of our assets is really flexible and strategic, allowing us to ramp up and ramp down production based on those external factors. Most of our wells do take one week or around one week to drill, we can really move around our capital as we see fit. At Saturn, we pride ourselves on being really good operators.
We work hard to find those opportunities to raise our margins where we can. As evidenced here, we've seen a 27% reduction in our OpEx from 2021, a 28% reduction in our royalties down to 11%. That, coupled with our high liquids weighting as well as our hedging strategies, really shows in the margins. You can see there from 2024 to 2025, fairly flat netbacks, all while WTI took a 15% haircut.
On the Op cost front there's a lot of information here. I'm not going to go through it all, but basically, we've driven CAD 8.40 out of our OpEx there. Where we see our biggest wins, though, is really leveraging that infrastructure footprint, where we get in there, use that infrastructure footprint to consolidate fields and facilities, as well as reduce redundancies.
The other thing we do is use our size for strategic procurement initiatives on high-dollar items like chemicals. The less intuitive level of this would be through our production optimization program. Basically, when we add barrels on existing wells, it comes with a marginal increase in OpEx that disproportionately lowers our OpEx on a BOE basis. We're willing to spend a lot of time and effort focusing on our existing land base to really do better on the wells that we already have.
Looking at our development, we're really proud of the success we've had with our drilling program. Last year in 2025, we saw a 23% outperformance relative to our budgeted production expectation. We refer to that as our type curves. Looking at that far left there with our Frobisher Mississippian and Spearfish development, those are our conventional wells, some of our highest return development opportunities.
We actually saw a 50% outperformance on those wells, and they also represent a significant portion of our future inventory that we do have. If I get your attention on the right here, this is an independent review of payout periods for North American plays. Saturn plays being in green. You'll see that we have positions in three of the top four plays by payout in there.
Our Frobisher Mississippian and Saskatchewan open- hole multi-leg Bakken stuff is some of the best payouts and best values you have in all of North America. On that open- hole multi-leg position there, sorry. We're quickly becoming a leading developer using this technology in Saskatchewan.
Basically, for those of you who might not know, an open- hole multilateral is where you have one main well bore drilling down to your formation, then when you get there, you split off into several horizontals targeting the same zone. We routinely drill eight to 10 legs in a single well, this really ramps up the efficiencies that you can get with your reservoir exposure for these wells. Ultimately at this point, this technology has really taken off. This was the catalyst for the Clearwater development in Northern Alberta.
I don't know if anybody is familiar with that. Basically, we're taking that Clearwater style of drilling that has really ramped up over the last couple of years and employing it down in Southeast Saskatchewan. With that, we are doubling down on our Saskatchewan open- hole program. We are increasing our open- hole count by 60% in 2026 to 2025.
We're throwing a third of our development budget towards this technology. With that, actually on that leg, when we bought Ridgeback back in 2023, we had ascribed zero value to open- hole multilaterals in that deal. In that deal, we bought that without this technology. On the acreage that we got from Ridgeback today with our Bakken open hole multilateral inventory, we would ascribe CAD 350 million worth of value to there at this point. Really proud of that. We're not done there.
The efficiencies that we've garnered in deploying this technology, we've taken 30% increase in our drill rate in our meters per day drilling from 2025 to 2024. That's equated to a 20% reduction in our cost per meter of drilling those wells. That's further enhancing our value. The difference between these and, say, frack plays, frack plays have a lot of tangibles in their cost structure. You have casings, stages, frack fluids, that kind of thing. This is a lot of time.
Those efficiencies that we gain through drilling equate very directly with cost reductions on our well expectations. On our conventional program, again, these are some of our most impactful from a return basis. At our budget expectation there, so at our base expectation, these are our highest profitability wells, let alone with the 50% outperformance we did see last year.
Really, really strong there. 23 wells of these this year, definitely very, very strong. The beauty of these is with that infrastructure position that we do have, we have the ability to more effectively than our peers bring these wells online. All oil wells make a little bit of water. If you can't manage that water effectively at surface, it comes with a cost that can really eat into your margins.
Because we bought these assets with that infrastructure position in place already, we're able to bring these wells online and keep more of that netback in our margins. In addition to our drilling program, we're also looking at our base wells for enhanced opportunities here. One such being waterflood.
In waterflooding, it's a tried-and-true method used for a long time, where basically you push water back into the reservoir to increase the pressure of the reservoir, as well as sweep more of that oil out. We're doing that. The advantages of that are lowering declines, maximizing well utilization, reducing liabilities, as well as in the case of our Creelman area here, it's going to enhance the value of the infill inventory that we do have in that area.
We initiated this flood last year. In this particular area, we have 18 sections of land. Again, when we come back and drill those wells into the repressurized reservoir, we're expecting a threefold increase in the amount of recovery that we'll get out of those. From there, we have another 100 sections that we could deploy this to around that Viewfield Bakken area.
Our Alberta team, really strong technically. They're breathing new life into the Cardium here. We're having a lot of success with that. We're pushing to longer laterals and pad-style drilling here, and overcoming some technical challenges to be able to do that. In doing so, we've already set a couple of records.
To date, we have the fastest extended reach horizontal well in the Cardium and the longest extended reach Cardium well ever, with over 3 mi of lateral in zone. The beauty of these extended reach horizontals is that the costs don't scale linearly with the length of the well. Going to a 2-mi well over a 1-mi well only adds 30% more cost with 2 x the reservoir exposure. A 3-mi well is only 60% more than a 1-mi well, getting 3 x the reservoir exposure.
We're really leaning into these extended reach wells. On the other side there, too, within our Alberta inventory, if we do start seeing better strength in gas markets, we do have gas year inventory in here that we can tap on from that balanced portfolio to add more gas if it starts to make more sense to do that. Looking forward, this is a snapshot of our reserves.
We have a long runway ahead of us. Currently, we have 1,200 locations booked in our reserve database for a total of 220 million barrels of reserves, with over half of that being ascribed to currently producing wells and 95 million barrels of that in the lowest risk proved developed producing category. Looking at the reserve life indices here, that's a ratio of your future reserves to your current rate.
With the 2P reserves of 14 years, that again really demonstrates the sustainability that we do have. We had a really good year on the reserve standpoint. We were able to add 31% PDP reserves per share year-over-year growth. Also saw our largest ever technical revision of 11 million barrels on the success of those drilling programs, the implementation of those waterfloods, and our OpEx initiatives.
Really proud of that. If you look at the bottom left here, you can see where we trade relative to our peers and our reserve value. We trade at 90% of our total proved reserved value. If we were to trade at even the average of our peers, which is nearly 2x , we would be approaching a CAD 13 share price. We're CAD 7 today.
If we started getting up to the upper end of that spectrum, we'd be nearing a CAD 20 share price. The growth story is real. That with also no credence given to the additional 1,400 locations we do have that aren't currently booked as well. Going further down that road, if you were to take basically back into a share price from our current booked reserves, you'd see that top table there.
That was what we disclosed at the end of the year. I'll point to you that at the end of the year, the independent evaluators were using a price deck that had $60 WTI for 2026. Obviously, that's not the world we're in today. Taking that same exact reserve database, using a $75 WTI price deck in the bottom left here, you can see what we're worth at those categories.
Approaching CAD 9 on that lowest risk proved developed producing category. Our 1P category total proved over CAD 12 there, knowing that most of our peers trade in and around here, if not a premium to that 2P category. Everything in there all together for 2P, over CAD 18. Really, really strong value proposition for what we have. Again, with no value ascribed to all those future inventory locations that we do have. With that, I will let Cindy take you through how those technical successes have translated into our financials.
Thank you, Doug. Just taking a look at Saturn's first quarter, it really showcases the strength of this execution, and we've highlighted a few stats here, which I will not go through in detail, but I did want to point out that across pretty much all of these metrics, we came in ahead of guidance and ahead of analyst expectations, despite having the benefit of only one month of that stronger WTI price.
Consistently exceeding expectations has helped Saturn drive robust cash flow, CAD 440 million over the past four quarters, and we also generate healthy free cash flow. From a capital allocation perspective of that free cash flow, we continue to target opportunities that offer the best returns for our shareholders. That includes share buybacks.
It has included buying back our own bonds in the open market when they traded in the mid-80s because of the Trump tariff talk. We have also continued to look for small tuck-in acquisition opportunities that help drive increases in per-share metrics. Since our share buyback commenced in August of 2024, we have returned over CAD 60 million to Saturn shareholders, reduced our shares outstanding by about 11%, and today we continue to be active with that buyback.
Even though we have seen a significant increase in our share price, we still believe that Saturn shares represent the best value barrels on the market. Thinking about another element of our free cash flow allocation, we consistently repay debt with nearly CAD 180 million of debt repaid over the last seven quarters, and we maintain ample liquidity.
We have got a CAD 150 million reserve-based credit facility and a CAD 100 million associated accordion feature, giving us about CAD 250 million of liquidity. We protect this by hedging. Our robust hedge book shields us against volatility. It ensures we can always meet our debt obligations. As the size and scale of our business has expanded, we truly believe there may be opportunities to further lower Saturn's cost of capital.
This chart just basically outlines our budget and guidance at 2026 or the beginning of 2026, which was again set at that $60 WTI price. We incorporated a lower capital spending budget for this year, simply reflecting the fact that we want to keep the value of those reserves in the ground. It is CAD 185 million of capital this year, down from about CAD 240 million last year.
The second quarter of each year, which we are in currently, is our highest free cash flow generating period because it's our lowest capital spending period. That's just because spring breakup, which is when the snow melts and the ground softens in Western Canada, you can't get heavy equipment in to drill. That means our spending drops.
This year, what we found is weather conditions have been favorable and oil prices are high. We've elected to accelerate CAD 20 million of capital from the latter half of the year into the second quarter, allowing us to bring new volumes on sooner and capitalize on those high prices. That's a reflection of our nimble and versatile flexible capital program.
We could get rigs back in the field a month earlier than we originally anticipated. That just allows us to generate the cash flow from those even sooner. Our high torque to oil prices does have a meaningful impact on both our cash flow and our net debt.
If we were to run this same scenario at today's, say, $90 WTI, we'd generate an incremental CAD 150 million of cash flow, and we'd see our net debt to adjusted EBITDA ratio come down to 1x or below by the end of the year. Saturn's covered today by seven firms, and the average target price amongst those firms is CAD 8.15. Even with our market cap having gone from about CAD 450 million to CAD 1.3 billion today, just since the beginning of the year, we continue to trade at a discount evaluation relative to the peer group.
The graph on the left demonstrates our high free cash flow yield according to Roth Capital, while the chart on the right shows our enterprise value to debt adjusted cash flow. If Saturn traded at just the average of our peers, that 5x versus our 3.4 x, our stock would be CAD 12, showing the upside that we believe Saturn represents. Thanks so much for everyone coming to listen to the presentation today, and hopefully you take away three key points.
Again, Saturn has a diversified oil-weighted asset base that continues to outperform. We've got downside protection due to our conventional development, high free cash flow, and the hedge position. Our compelling upside continues to be an opportunity for investors as we are buying back shares, we're reducing debt, and we are outperforming. Thank you, and we can open it up if there's any questions. Yes, sir.
A couple of questions. If you go back to your slide 11 on the open-hole completions. If I understand that right, from the time of the kickout, those are all uncased. Is that right?
Yeah.
It's only at the terminal end of the lateral that you're open. What I'm getting at is, what prevents the wellbore from collapsing on itself?
Yeah. I guess the question being.
How far out? Yeah.
What keeps the lateral open in an open-hole multilateral? Yeah. Basically, the process we're using there, we'll drill intermediate down till we get into the zone and then set casing point there. From there, we'll drill our boss leg and all of our subsequent legs off that initial boss leg. Now, the zones that we're dealing with, there's nothing inside there.
There's no fracs, no perfs, no casing, nothing. It's just that full lateral open to flow oil. The beauty of the rock that we're drilling this in is it's very competent. While there being nothing to keep that lateral open, a hole collapse, with the type of rock we're dealing with, it's very competent. It's not really a risk to us.
What diameter hole?
Generally, I think the laterals are four and a half. We'll drill seven-inch intermediate, then four and a half for each of those legs.
Do you have any history? It sounds like it's a relatively new-ish completion technique, and obviously, it has to be applicable to particular type of lithology where that works. Is that a fair way to look at it? Is there any history as to how long those wellbores would stay open before natural pressures and so forth would cause them to potentially collapse?
The initial ones in the Bakken in particular, the first ones were drilled in 2023. We don't have a super long life. But again- Yeah. We do have wells that have been producing well and are staying on that type curve. This technology was originally employed in much, much more porous rock in the Clearwater. It's heavier oil. I believe it's about 20 API type oil.
What we keyed off in deciding to try this down here was that ratio of that oil viscosity to the permeability of that rock. Right? There's a bit of a sweet spot with where this works, where you can get enough out of it. They're dealing with much more porous, much more permeable, I think it's still fairly consolidated, but less consolidated rock, and they have a longer history up there.
Where we're using this in our Bakken and Midale wells. We're deeper. It's same perm to viscosity ratio, and that's what we're really keying off is to where these plays exist. We're looking at that viscosity and perm ratio. The rock that we're dealing with is much lower porosity and much lower permeability, but with a much higher quality of oil, like we're 40 API gravity oil here. It's not like it's pushing all that stuff through.
No paraffin.
No
Phase II at all?
No. Hole stability isn't a big concern on our minds.
Can you re-complete and do you have any way of knowing if you do, what is it, six or eight laterals off that kick? Is there any way of doing a re-completion at one of them, or you just say eh at one of them?
You-
How do you monitor that, I guess is kind of what I'm asking. Do you know that all those laterals are actually working the way they're supposed to?
We've done a couple of tests where we'll place a chemical tracer in the toe of each of the legs and then see what we get back. Based on the data we've got out there, looks like we're getting contributions from each of the legs. Some more than others. Probably depends on pressures and permeabilities and whether or not there's some natural fractures or any of that kind of stuff in the reservoir as to which ones contribute in early time versus late time.
We do have some of that data that would suggest that we're seeing good contribution from all those. To your question about intervening in these wells, it's certainly possible. The issue becomes, is it a big enough problem to warrant having to go in and figure out which leg you're in? Right?
You have to do a bit, almost go in with a bent joint to figure out, then run to bottom to test which hole you're getting into. To this point, we haven't had a reason to go into any of these wells to suggest that we need to do some sort of intervening. The other option is it's open. We could go in. We know where we're getting, and we can start spinning off new legs if we really wanted to add to it. Right? That is something we're doing in other plays, not this particular play, but as re-entries. Right?
We have stacked play zones in a lot of that conventional Mississippian stuff. We're going in where it was originally a Frobisher Stoughton, and we're re-entering those and re-drilling to, say, a Frobisher Griffin zone inside of there, doing that technology. Re-entering these and re-drilling is certainly doable. We'd probably go that way, to be honest, if we were worried about hole collapse, is just adding new legs versus trying to figure out what leg you're in.
Another question. How many wells do you anticipate? What's your drilling CapEx for 2026 and 2027, or have you come up with 2027 yet? How dependent is it on current prices, basically they're at?
The beauty of our program is, like we said, we are flexible. Our original guidance came out at that CAD 185 million. We did accelerate capital into Q2, with that frees up space on our rigs on the back end of the year.
We're not committed to drilling those wells at this point, if prices are sustained and there is market sentiment that's willing to us to continue, we do have the open end of the back end of our program to add capital without a significant ramp-up in bringing a bunch of rigs in, that kind of thing. It's the same amount of a rig count that we were initially planning to do. We just started earlier, leaving some more time on the back end of the year if we did want to push more capital into this year.
Your projections, what do you think your 2026 production rates I'm sure it's in here. Sorry, I haven't looked at it.
40.
What would you shoot for 2027, just at this point?
Too far.
Our expectation is we'll average about 40,000 BOE per day in 2026. Again, that's on that CAD 185. If we increase the capital, I think you can expect to see a commensurate increase in our production expectations as well. The other piece I'd add is, I know we talked a lot about outperformance, it really has been a feature of Saturn and something that the analysts are always They're checking us out. Are you 40,000 or are you going to be 41,000? It's something that I think you want to watch for. We're conservative, and we believe 40,000 is achievable for sure.
I'm saying that, are you trying to get a 10% growth, go from 40,000 to 44,000, 45,000, or?
Yeah. Our growth strategy is.
I'm just wondering what your game plan is.
Yeah.
Realizing that there are things that would change that pricing and so forth.
For sure. One of our philosophies is that we don't want to come out and say we're going to be 100,000 bpd in five years because that might mean we have to do some poor deals or allocate capital poorly in an environment that it doesn't make sense. Our strategy is to maintain production relatively flat, maybe 2%-3% increase per year, but really be opportunistic with that capital, whether it's buying back shares, paying down debt, doing some smaller tuck-ins that may end up in inorganic growth from an acquisition perspective. Any other questions?
Yeah.
If not, we're here all week. Just kidding. Thank you very much.