All righty. Good morning, everybody. Up next, we have Saturn Oil & Gas, traded on the TSX under symbol SOIL. On behalf of the company, we have Doug Deugo, Director of Exploitation Engineering, Cindy Gray, Vice President of Investor Relations, and they are one of our clients. If you are interested in having a conversation with them after, get in contact with myself, Cindy, or Jeff Elliot. Thanks, Errol, and thanks everyone for joining us this morning. I hope everyone is having a great conference so far, and thanks to Three Part for hosting it. Regardless of the political grandstanding that we are seeing today, I think Canadian energy is having one of the best backdrops that we have seen in decades. We are really excited to be here today and talk more about the Saturn story. All of the figures that we present today will be in Canadian dollars unless otherwise indicated. Saturn is a Canadian light oil company doing some very exciting things in some assets that might otherwise be considered boring. Our diversified asset base is spanned across 1.5 million net acres of land in Saskatchewan and Alberta, and we are weighted over 80% to high-value crude oil and liquids. Our assets are mid-life cycle, and that means that we have got the infrastructure already built out so that when we are developing the assets, the majority of our cash flow, almost all of it, can go into our development rather than having to build out infrastructure that does not add cash flow immediately. We have continued to outperform on our well results, which we are beating expectations, and our business offers downside protection. Not only do we have a very nimble and flexible capital program, the nature of our assets are lower risk, shallower conventional wells. We have limited concentration risk just by way of having a multitude of assets. Saturn has one of the highest free cash flow yields amongst our peers, and despite our share price having doubled year to date, or more than doubled year to date, our market value at CAD 6 a share is still disconnected from our total proved asset value of about CAD 11 per share. We hedge to protect our debt and the downside, and we can rapidly increase or decrease spending depending on commodity prices. All of this leads to a compelling upside. Saturn continues to meet or beat analyst expectations as well as our own internal guidance for performance, and we have done that for eight consecutive quarters in a row. Just a quick snapshot on the company. Our enterprise value is just over CAD 2 billion, and we are largely held by institutional investors. About three-quarters of our shares are in the hands of Canadian and U.S. funds. Atlanta-based GMT Capital and New York-based Libra Funds collectively hold over 40% of our stock. Since closing our first major acquisition in 2021 through to the end of June of this year, we have delivered a compound annual growth rate in production of over 86%, and we are targeting to exit this year at 48,000 BOE- 50,000 BOE per day. We have used a combination of debt and equity to fund this growth, and at Q2, our net debt was CAD 762 million, comprised primarily of an amortizing senior secured note with a mandatory 10% amort payment. However, in late July, we evolved our debt, and we issued senior unsecured notes denominated in both US and Canadian dollars, and we redeemed the previous notes. Doing so, we benefit now from a lower interest rate, extended maturity out to 2031, and relaxed covenants that I will speak to later. Saturn's strategy is relatively simple. We have a blueprint that is repeatable for value creation. First, we acquire assets, again, these mid-life cycle oil-weighted assets, at attractive valuations, typically 2x cash flow or less. We can integrate those assets seamlessly into our existing asset base in Saskatchewan and Alberta, thereby leveraging our size and scale in the areas. With that, we can then optimize the acquired assets, bring down costs, improve efficiencies, increase margins, which are called netbacks in the oil and gas industry, and increase our free cash flow. Making small, incremental improvements across the entire portfolio really adds up, as Doug will touch on later. From there, we develop. We look to enhance and expand our reserve base as well as our production, increase the runway of drilling locations, and further enhance our long-term sustainability. Lastly, we look to reduce net debt so we can repeat this process, targeting to achieve a 1x net debt- to- adjusted EBITDA ratio within 12 months- 18 months of any acquisition. This slide demonstrates this blueprint in action. Since 2021, we have done five major transactions totaling about CAD 1.6 billion, with the first four having nearly doubled the company's size at the time. These acquisitions were all done at those metrics I mentioned, under 2x cash flow. The first two of these, the Oxbow and the Viking, were asset acquisitions in Saskatchewan, while the third was CAD 500 million corporate acquisition of a company called Ridgeback Resources, which expanded our existing Saskatchewan footprint and also gave us our first entry into Alberta. The fourth was another CAD 500 million asset acquisition in Saskatchewan that closed in mid 2024. In concert with that acquisition, we reached into the U.S. credit markets, and that is when we issued those senior secured notes. It effectively enabled Saturn to lower our borrowing costs by issuing the US dollar-denominated notes. More recently, we acquired two private companies, those closed just at the end of July, in our core Southeast Saskatchewan operating area, picking up both entities for 1.8x cash flow, adding volumes, increasing our oil and liquids weighting, and enhancing our netbacks or margins. I will hand it over to Doug now. Yeah. As Cindy touched on, we are about 43,000 bpd- 44,000 barrels bpd, but we are pretty busy right now with the acquisitions and with our drilling activity. We are drilling in all of our core areas. We should be getting up near 50,000 bpd by the end of this year. We are a very oil-weighted producer. Oil and liquids weighting of 82%, but the majority of our assets are in Saskatchewan, so 70% of our production, with over 50% of our total corporate production coming from our crown jewel in Southeast Saskatchewan. This is a high working interest, high focus area for us and with an expansive infrastructure network that we have amassed over those deals that Cindy touched on. Saskatchewan is a great province to work in. They offer really low royalty rates, and the government is really collaborative with us. They also have a provincial goal to double their production. To that end, they are really willing to work with us. The balance of our production does come from Alberta, where we have our oil-driven Cardium and Montney assets. Across our acreage, we have identified 3,000 locations at this point, which is enough to keep us going for 20 years at this rate. The nature of our assets allows us to be very strategic and flexible. Our wells have very short cycle times, with many of them having less than a week of drilling time to be completed. We are very diversified, selling into a lot of different hubs, which minimizes the impact of local disruptions. We have never dealt with any apportionment issues in Southeast Saskatchewan. To touch on those acquisitions that Cindy brought up, at the end of July, we closed two deals of private equity companies, Burgess Creek and Triland Energy, both of which fit perfectly into Saturn's existing footprint. If you look at the map there, you can see green was Legacy Saturn, orange in Burgess, and Triland in blue there. They added 3,700 bpd to our company there of 97% light oil and liquids. Very consistent with that blueprint, we acquired these at 1.8x cash flow and 80% of their PDP reserve value, and only 25% of their 2P reserve value. So very good deals. Combining with these assets, adding 400 locations, including 40 open hole multilateral that we have initially identified with the room for our team to find more as we continue to work up these assets. The synergies that we have with our existing operations, we anticipate will be able to drive out about CAD 2.50 a BOE and see another CAD 7 million of enhanced value to those deals on those assets by having them in our hands. That is just what we can see today. At Saturn, we pride ourselves on being great operators. Applying that blueprint, we work really hard to find opportunities to improve our margins. We have seen a 25% reduction in our OpEx from 2021- Q2 2026. Keep in mind, Q2 is typically a higher OpEx quarter for us as we deal with spring breakup conditions in Canada. In aggregate, we expect 2026 as a whole to probably be CAD 0.50- CAD 1 better than what we saw in Q2. For royalties, similar story there. We have seen a 17% reduction since 2021 over that same time frame. Royalties, we view them as same as any other cost to our business, and we develop strategies to minimize those as well, like favoring drilling on lands with lower royalty rates. The OpEx and royalty effort, coupled with our high liquids weighting, shows in the strength of our operating netbacks or field margins. As you can see, Saturn has really high torque to oil prices, where we saw CAD 60 a BOE in Q2. I'm not going to spend a ton of time on this slide here, but it's in our deck. You can see how we derived some of that OpEx out of our business there, CAD 8.40 from 2021- 2025. The theme I'll leave you with is that we really leverage our size and scale and that infrastructure footprint we have to consolidate fields and reduce redundancies and do strategic procurement. The one thing I will say that is a bit, not unique, but interesting portion to this is we allow our teams time to focus on production optimization opportunities. By adding that production to our existing base wells, it comes at very marginal increases in OpEx but adds more barrels to divide over. For example, since the two years we've had Flat Lake, we've added over 400 bpd just by optimizing pumping conditions, which took OpEx from CAD 24 a BOE down to CAD 21 while adding nearly one million barrels in reserves. I mentioned the 3,000 locations that we have to sustain ourselves. There's quantity, yes, but also quality. We're quite proud of our execution success, having outperformed our internal budgeted expectations or type curves by 23% in 2025, 22% in 2024, and so far to date in 2026, I'm pretty happy with where we're sitting. The graph on the right shows an independent assessment of North American top oil plays, Saturn plays being in green. Our Frobisher, Mississippian, and Bakken open hole multilateral wells deliver some of the quickest payouts and best values in North America. If you look at the graph on the left, we realized very strong performance across our play types. From those top Frobisher, Mississippian, and open hole multilaterals, which are some of our highest return opportunities, we saw some of our best performances as well. These also account for over half of our future inventory. Our technical teams continue to grind away at the details while planning wells. We also have the advantage of over 1,000 sq mi of seismic to leverage. On that success, we've managed to beat production expectations from the analysts for eight quarters in a row now, and we're excited to see what we can continue to do going forward. Our open hole multilateral program is our largest organic success story to date. An open hole multilateral is a well with three or more legs targeting that same zone. Saturn routinely drills wells with eight legs to 10 legs, and it's called open hole because there's no perfs, casing, or fracs within those laterals. The entirety of that lateral is open and available to flow. This technology is really taking off right now. It was the catalyst for the growth of the Clearwater play in Northern Alberta, and we've brought that technology down here to Southeast Sask. We're the only company to date to have taken that technology and expanded to four targets in Saskatchewan. We have 450 locations of these type across our acreage. When we bought Ridgeback back in 2023, we had ascribed zero value to open hole multilaterals in that deal. Today, our Bakken open hole multilateral inventory alone is worth nearly CAD 450 million, and our total open hole multilateral inventory is worth CAD 1 billion, which is in line with our market cap. Continuing on that success, we are leaning into drilling more of these multilats. 20% of our 2026 capital is going towards these well types or 37 gross wells. Remarkable given we only started drilling these back in 2023, and today we produce over 3,000 bpd of our company out of these well types. We continue to enhance the value of that inventory through improved execution. We have seen a 20% increase in our Bakken drill meters per day, which equates to a 10% reduction in our cost per meter in our Bakken open hole multilaterals from 2025 till the first half of 2026. These efficiencies are really significant. These wells are a lot of the costs are tied to rig time, so any efficiencies we can get in doing better in execution really directs very strongly with reductions in cost. Our Southeast Saskatchewan conventional, which encompasses our Frobisher Mississippian and Spearfish plays. Remember, these were the number one and number three on the ranked North American play chart. Unsurprisingly, these are our highest return opportunity wells at type curve expectations, made that much better with the 50% outperformance we saw in 2025. We are drilling 36 of these this year. These are our lowest capital wells but have very high oil deliverability. They are also very quick to drill and get on production. These are very geology and geophysical-driven plays, and we have a variety of pools and zones to target in Southeast Saskatchewan. That seismic library I talked about gives us a strategic advantage in Southeast Saskatchewan, where we have all that seismic. To replicate that seismic library would likely cost somebody between CAD 500 million- CAD 1 billion to acquire that amount of seismic again. The other advantage we have is that expansive infrastructure which Cindy talked on. These wells generally produce a considerable amount of water along with that oil. So if you do not have the infrastructure to produce, dispose, and treat that, it can really cut into your returns. So we have a strategic advantage down there in being able to leverage that, and we can go after these targets which other people cannot make money at. Again, that infrastructure, that being there allows us to focus more of our capital and time towards drilling wells, rather than setting up pipe and infrastructure to be able to produce them. In addition to our drilling initiatives, we are also advancing the value of our assets through waterflooding. Waterflooding is a tried and true method where you re-inject water into a depleted oil reservoir. This increases the pressure and sweeps more of that remaining oil out. Waterflooding can double the recovery of a pool. These initiatives bolster Saturn's sustainability and expand the life of our assets. They reduce decline rates, maximize utilization, reduce liabilities, and in the case of Creelman here on the slide, increase the value of our infill drilling opportunities. We initiated a waterflood here in the Creelman area of Bakken last year. We have 18 sections in Creelman offsetting a long-standing third-party waterflooding, which you can see in those blue wells are all injectors there, which we have the advantage of learning from. By repressurizing the reservoir, we expect to dramatically increase the recovery of the wells that we have in this area. We will have 40 repressurized locations once this flood is completely rolled out in Creelman. To date, we have seven injectors on. We are doing another 11 this year, and that is just the beginning, though. We have another 300 possible injectors over 100 sections to progress this to in the future as we go. All that kind of green land around there compared to our focus area in Creelman. Applying that blueprint strategy, our Alberta asset team is breathing new life back into the Cardium. When we had acquired these assets, wells were typically planned as one-mile wells with returns that just weren't sexy and couldn't compete. We started pushing the boundaries to increase the value of this inventory. We had to get creative to overcome several design and execution challenges, but by pushing to extended reach horizontals coupled with pad development, we have been able to enhance the value of these assets and get them to compete for capital. While on this road, we have already set a couple of records. We have drilled the fastest extended reach Cardium well and the longest extended reach Cardium well ever, with over three miles of productive lateral. Extended reach wells really add value because the costs don't scale linearly with length. A two-mile well only costs us 30% more than a one-mile well. A three-mile well only costs us 60% more, and you are getting 3x the reservoir exposure. Cardium wells are our most productive, and right now we are drilling our sixth well of a seven-well pad with three three-mile wells and four two-mile wells, which is our biggest pad to date. While we are pretty bullish on oil, within our Alberta assets, we do have gas inventory which we can draw from if we start to see strength in gas markets. Give it back to Cindy. Thanks, Doug. We just wanted to provide you with a quick highlight and snapshot of our Q2 results. We saw production ahead of guidance as well as internal expectations, as Doug mentioned, for the eighth consecutive quarter, which is a pretty impressive feat and it really speaks to the outperformance of the wells that Doug spoke of. We posted record revenue of just under CAD 360 million, with cash flow of CAD 123 million and free cash flow of CAD 82.5 million. We exited the period at 1.3x net debt- to- adjusted EBITDA multiple, and that was prior to our bond refinancing. With cash flow totaling about CAD 455 million over the past four quarters alone, we generate very healthy free cash flow, and that gets allocated to opportunities we see to give the best returns back to shareholders. As demonstrated and as discussed with the Triland and Burgess acquisitions, we have continued to find tuck-in opportunities that are accretive and that we can do for attractive metrics. We have also maximized our share buybacks, and we completed our normal course issuer bid, or NCIB, before it expired, which was just in July, and we bought back bonds in the open market last year when they traded down to the mid-80s during Trump's first tariff trade talk. Since our share buyback commenced in August of 2024, we have returned CAD 66 million to Saturn shareholders and have successfully reduced our shares outstanding by 12% since that time. We still see Saturn shares as the best quality, lowest cost, most attractive opportunity on the market, so we intend to renew our share buyback, which you should see announced sometime next week. As mentioned, at the end of July, we refinanced those senior notes, and they were previously senior secured notes, and we were able to issue senior unsecured notes. Our original issue was $ 504 million outstanding at 9.625%, and it had that 10% mandatory amortization feature with the amort payments being at 104.8, so it was definitely a draw on the cash flow. Our new issue is a dual tranche, US 575 million at 8.5% and a CAD 185 million at 7.5%, which lowers our effective interest rate by about 200 basis points and extends our maturity out to 2031. In addition, we gain more control over our capital allocation because we have removed that 10% amortization feature and replaced it with a call feature at 101, and that is a semi-annual call at 101, and it is a relaxation of covenants. In concert, and to reflect the impact of the Burgess and Triland acquisitions, the much stronger oil price today versus the beginning of the year when we first issued guidance, along with the new bond issue, we have increased our guidance for the balance of 2026, which we announced in August. We are increasing our capital spending to CAD 365 million at midpoint, which is expected to drive more than 10% organic growth in production. We are targeting an average annual production of 43,000 BOE- 44,000 BOE per day, exiting the year of 48,000 BOE- 50,000 BOE per day. By doing so, we anticipate increasing our cash flow by 60% to CAD 550 million. Our free cash flow is expected to increase to about CAD 200 million, and that is a 20% increase, and we are targeting to exit 2026 with a net debt to adjusted EBITDA multiple of about 1.3x- 1.4x, which is better than our 1.5x- 1.6x previously. With this enhanced positioning, we have set the stage to hopefully close the gap between our discounted valuation and where we see the true underlying value. Saturn has research coverage from seven firms currently, and they have an average target price on the company of CAD 8.36. Again, we are trading today around CAD 6. Even though our market cap has more than doubled since the beginning of the year, and it is about CAD 1.1 billion today, we offer a compelling investment opportunity. As you can see in the graph on the left, this is showcasing by Roth Canada, our high free cash flow yield relative to our peers. The chart on the right is showing our discounted valuation on an enterprise value to debt adjusted cash flow multiple. For context, if Saturn traded at the average of our peers on an EV to DACF multiple, which would be 4.6x versus our 2.8x, our stock would be trading at around CAD 13. That just demonstrates the sheer magnitude of opportunity that we see by continuing to execute, doing what we say we are going to do, and generating these solid returns for shareholders. In closing, I want to thank everyone for attending today, and hopefully we have prompted you to take a closer look at Saturn and how we are doing, again, some very exciting things in some assets that have been legacy, have been around for a while, and some other people may consider boring, but we are really ramping those up. We have got the diversified asset base, we use downside protection, and a really compelling upside. With that, we can take some questions. Yes. That's a great question. The question being how are we able to pick these assets up when others What are we seeing that they're not seeing? I'd say one of the answers to that is the fact that we have established this footprint in Southeast Saskatchewan with the infrastructure that Doug mentioned. The value of that makes it very difficult for a smaller player to come in and start to develop because they don't have the infrastructure to handle the water, produce the water, treat the water. That's one big component. They would need to likely go through our facilities, and the economics of that just don't make sense. Our size and scale infrastructure in the areas we operate is one big advantage. The other, I think, is that you've probably heard about the Duvernay play, Clearwater, the Montney in Alberta. These are kind of bigger, juicier plays that tend to. Yeah, exactly. They tend to produce, perhaps they come on stream at higher volumes, but they can cost CAD 10 million-CAD 20 million per pad or per well, and it is a multi-year. It is a very different type of play to develop. Saturn is we are kind of slow and steady wins the race, and the economics of our plays, as you saw, are just the best in North America. Doug, what would you add? Yeah, just a lot of these companies, for instance, Crescent Point, they were trying to become a Montney Duvernay player, and in doing some of those things, a couple of our deals were done with them. We were able to pick their pocket with that because they were looking for money to then go invest in some of those bigger, flashier plays. Like I said, there wasn't the same level of demand at the time for those assets, especially through the cycles that we were taking some of these on. Like that Oxbow deal was done when oil was pretty low price, and I bet you that deal has paid off 3x or 4x now. That was really the big infrastructure footprint that started us off in Southeast Saskatchewan, and since then, we have been really just continuing to pick pockets there. Ridgeback was another deal where they weren't getting enough attention to get big money for the types of plays that they had, and we looked at it and said, "We can make money doing this," and we are able to get those deals done. Like I said, they are just a little bit more out-of-vogue properties. But with that, it is not like we are going into the same areas that were being drilling. We are pushing edges and stuff like that where stuff wasn't necessarily economic before. Take the Bakken, for instance. It was tried north where we are doing those open hole multilaterals, but you just couldn't seem to get economic rates with fracked wells, and so they wrote it off. Where we came back in, started drilling these open hole multilaterals, accessing that reservoir without bringing in the risk of water, and lo and behold, now we have a play where they had written off townships of land that they had played with fracked wells, but we knew it was there, just couldn't get it out economically. Bring new technology, and that is where we are at today, where now we have this area that has blown up on us. In terms of environmental safety, your open-hole technology is safer, better than the fracked well? If anything, I'd say it's better. Our water use for those is they're not fracked. The big fracks in the Duvernay that are using water, we don't have that issue. No, it's all the same. I would say the safety aspect is, if anything, better because you got guys working on the same well for longer rather than bouncing around doing some of our other week-long drills. No, I would say that there's nothing at a higher risk of doing those open-hole multilaterals versus any other business or anything else in Alberta with other operators. Your whole capital plan to get that oil to market for every multilateraled well is- Yes. We in Canada have very stringent abandonment reclamation regulations that we have to adhere to, and we are well and above everything that we have to do in that regard. Definitely we set aside. I think we're going to spend about CAD 18 million this year on our reclamation and abandonment program, which is government mandated. They do a lot of things based on your ratio of assets to liabilities, and our ratio of assets to liabilities is well above the healthy or average for a lot of these areas. We're definitely above average in that regard. In terms of getting the oil to market, what happens with the oil when you guys get it out of the ground to where it is sold? We will bring it to our own facilities and treat it, clean it, make it saleable oil. From there, we have contracts with all the big guys like Enbridge and Yeah. Midstreamers. Midstreamers. Yeah. Macquarie, who take the oil out of Alberta. All that infrastructure is all there. We sell it. We have very little on trucks. It is all that sale infrastructure that ends up back down into the U.S. as well. With the whole tariff issue from [inaudible], do you guys see that impacting you at all? It is a really good question. It depends on the tariff trade, I guess. From our perspective and even politically in Canada, there is reluctance to use energy as a bargaining chip just because we are so integrated between Canada and the U.S. I think that it may be threatened, but we do not see that as a realistic possibility given the sheer magnitude of energy that we export to the U.S. and how much back and forth there is. You think about all of our oil would go down to the refiners in the U.S., or most of it, and then they ship it back up to Canada. So the system is so integrated, it is very difficult to anticipate that that is going to happen. But fingers crossed. Do you think you would trade publicly on any form other than the TSX? It's certainly a possibility. I think demand will drive it. Obviously, our price traded largely down here, so we will certainly consider that. It's really going to be demand driven, so we need you guys to just convince us, like, "We're going to buy more stock if you were traded in the U.S." Any other questions? I'm just curious on the open hole you have multilaterals. How do you determine if one of those laterals collapsed on itself? Do you have any history as to how long those uncased holes can hold up before mechanical structures and so forth might cause a collapse? There's a lot of places where these have been tested. When they were experimenting, especially in the Bakken, they were trying all different things over the course of the years. So we have places where they tried single laterals and left them open hole, and effectively what would we be looking for is a step change in the production rate that would indicate some sort of barrier down hole. To this point, we just haven't seen anything like that. I don't even think they're talking about that up in the Clearwater where it would be a way bigger problem for them because their rock is less consolidated, more porous than ours. In the plays that we're targeting, we're targeting 15% porosity. These are very, very competent rocks. There's, I would say, very, very little risk that that would become an issue for us in the plays that we're dabbling in. Let's say it did happen eventually, we could always go in and redrill those wells. There's no really limit to that. How would you determine which one, if you've got eight laterals side by side, how do you determine which one might, I don't know. I realize that maybe the Red River Formation have some consistency to that, but nonetheless, when you drill them. I'd say the only real risk we'd have is there are some shales around some of these wells. They tend to be the cap rocks in a lot of cases for these. Generally, we know when we get into those shales. You can see those in the gamma signatures and those kinds of things. That would be our biggest risk for those. But in a lot of cases, we're so adverse to that issue, more from getting stuck as you drill past it. That's a bigger risk for us than hole collapse down the road. In lots of cases, if we get into a shale that we're not happy with, we'll pull back and sidetrack the leg anyway. That's the whole nature of what we're doing down there. We're getting really good at it. Rather than deal with the risk of continuing on past where you've intersected that shale, we'll just pull back and start a new leg and continue on and drill that leg as it was supposed to be without that shale intersection piece. Realistically, it's not a risk for us. To determine which leg would, you would look at the well path that you were doing and say, "Oh, this area looked like it might have had a chance." Then you could go in and redrill one of those legs. But to this point, we have wells with quite a bit of production history. We don't consider it a risk at all. Where they're doing this in the Clearwater, they're dealing with 30%+ porosity and very viscous oil. I've seen them done now in Lloydminster and stuff like that where you have truly unconsolidated sands, and they're still leaving them open hole. I don't think if anyone's going to have risk, it's in those plays. Where we're drilling with half that porosity and very, very competent rock, we don't see that as a risk. If there's nothing else, thank you again. We appreciate your time, and please take a look at Saturn.