Good morning, ladies and gentlemen. Welcome to Saturn's third quarter 2025 results conference call. As a reminder, all participants are in listen-only mode, and the conference is being recorded. After management's remarks, there will be an opportunity to ask questions. To join the question queue, you may press star then one on your telephone keypad. Should you need assistance during the conference call, you may signal an operator by pressing star then zero. I will now turn the meeting over to Ms. Cindy Gray, Vice President of Investor Relations. Please go ahead, Cindy. Good morning, everyone, and thanks for attending Saturn's third quarter 2025 earnings conference call. Please note that our financial statements, MD&A, and press release have been filed on SEDAR+ and are available on Saturn's website. Some of the statements on today's call may contain forward-looking information, references to non-IFRS and other financial measures, and as such, listeners are encouraged to review the disclaimers outlined in our most recent MD&A. Listeners are also cautioned not to place undue reliance on these forward-looking statements since a number of factors could cause the actual future results to differ materially from the targets and expectations expressed. The company undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise, unless expressly required by applicable securities law. For further information on risk factors, please view the company's AIF filed on SEDAR+ and on our website. Also note, all amounts discussed today are CAD unless otherwise stated. Today's call will include comments from John Jeffrey, Saturn CEO, Justin Kaufman, our Chief Development Officer, and Scott Sanborn, our Chief Financial Officer. I'll now hand the call over to John. Thank you, Cindy. Good morning, everyone, and thank you for taking the time to join us today. I am pleased to share some additional context around our third quarter results, which reflects another consecutive quarter of outperformance as we continue to execute on our blueprint strategy. The Q3 production averaged over 41,100 barrels a day and exceeded our previous guidance, as well as analyst consensus, which had us just over 40,000 barrels a day. We also beat guidance on a BOE operating cost in Q3, which came in at CAD 19.24, below the CAD 20 per BOE annual target. This past quarter also showcased Saturn's ability to be nimble, our commitment to allocating capital to the highest potential return opportunities. Given the uncertainty and volatile commodity price environment that prevailed in the quarter, we elected to reduce our original CAD 300 million development capital budget by 18% to approximately CAD 255 million. We pivot our focus towards opportunistic tuck-in opportunities. These tuck-ins offered more attractive capital efficiencies than drilling, having a combined production addition cost of under CAD 16,000 per flowing barrel. Reallocating capital to M&A allowed us to increase production while preserving the value of our existing assets by not drilling them at a time when prices were weak. How we view this is when prices are stronger, we can always go back and drill those wells, but we will not be able to execute on these deals at this pricing level. Further, by coring up in areas where Saturn has strong development success, we can leverage our size, scale, and existing infrastructure, which allows us to optimize production, reduce costs, and enhance the performance of the assets. Our first tuck-in acquisition included an asset package in Southeast Saskatchewan that was approximately 4,100 BOE a day, comprising just under 70% liquids for a total consideration of CAD 63 million. These acquired assets have an estimated 255 gross company-identified locations, including open-hole multilateral development potential in the Midale and Torquay. The asset features high working interest, optimization, and cost reduction potential, along with extensive opportunities to consolidate facilities and batteries. As Justin will expand on, this package is strategic for Saturn. It expands our runway of open-hole multilateral drilling locations, which are among the highest rate of return wells in our development program today. With the second tuck-in, which closed in October, we acquired a private company operating in Central Alberta, located within Saturn's greater Pembina Cardium area, for a total consideration of CAD 22 million. In addition to its 1,300 barrels a day of low-decline current production, Saturn gained over 80 internally identified drilling locations in the Cardium, Glauconite, and Bluesky development, enhancing our operation in the area. Our operations team has already started digging into these assets to identify cost synergies, optimization opportunities, and streamlining potential. The nature of our conventional asset base had allowed us to be very opportunistic by being able to stay nimble and pivot quickly when market conditions require. We are unique from other peers who are developing resource plays where they can cost tens of millions of dollars with lead times that can take several quarters or even years to plan and execute. With our assets, we can respond and adapt quickly to dynamic market conditions. As a result of production adds from the acquisitions, along with our strong drilling results to date in 2025, Saturn remains on target to exit the year with a production range of 43,000-44,000 BOE a day, which would represent a new production record for the company. We are committed to value creation and continue to use share buybacks as an effective way to return capital to shareholders and drive equity value over time. Our team believes a combination of ongoing share buybacks coupled with tuck-in acquisitions contributes to growing production per share, adjusted funds flow per share, and free funds flow per share. For example, August 2024 to today, we have bought back nearly 16 million shares in the open market through the NCIB and SIB, returning approximately CAD 36 million to shareholders. Over a similar timeframe, we have also increased our production per share by 22%. I'm extremely proud of the team who continue to give 110%, putting in the hard work needed to advance Saturn's goals and deliver compelling value for our shareholders while prioritizing safety to ensure that every one of our employees makes it home safe at the end of every night. I'll now pass it over to Justin to expand on our capital program and development highlights in the quarter. JK, over to you. Thanks, John. Good morning, everyone. As John mentioned, Saturn made the decision to shift a portion of our 2025 drilling capital to M&A during Q3, as we identified two tuck-in opportunities that would compete for capital in the prevailing commodity price environment and which we could acquire for attractive metrics. Our Q3 production does include new volumes from the Southeast Saskatchewan tuck-in acquisition, but it also showcases our ongoing type curve outperformance, plus the start of our drilling program after spring breakup, which supported the guidance beat. Our Bakken open-hole multilateral program and conventional Spearfish development wells coming online in Q3 contributed to another quarter of strong results. Saturn invested CAD 87 million of capital in Q3, with CAD 58 million of that directed to drilling and completion activities, including 29 gross wells, 23 of which were in Southeast Saskatchewan and 6 in Central Alberta. We also directed CAD 17 million to purchase two strategic parcels of undeveloped land, which we believe will unlock 60 new open-hole multilateral locations, representing five years of drilling inventory to an additional rig in Southeast Saskatchewan. Our open-hole multilateral locations in Southeast Saskatchewan offer some of the shortest payouts and highest potential returns among our undeveloped locations, even in a softening oil price environment. Several of our open-hole Bakken wells ranked as Saskatchewan's top 10 best-performing wells over the last year. Most recently, our 1621 well was ranked as a top 10 well in the province in September for monthly oil volume and daily oil rate. This is a testament to how prolific these wells continue to be. We are excited about the potential we see with this program, and our open-hole inventory currently represents about 15% of the 2,500 total identified locations in our portfolio. The open-hole multilateral portion of this portfolio has essentially doubled every year for the last three years as we continue to progress this exploitation technique to other plays. Most recently, we continued this expansion into the Spearfish play, where we became the first and only operator in Canada to have drilled an open-hole multilateral Spearfish well. Now we have drilled three of them. Our third Spearfish well at 1605 came online during the quarter with an IP30 rate of 330 barrels a day. This is about three times our internal estimate type curve of 110 barrels a day. These initial strong results support our plans to drill four additional Spearfish open-hole multilateral wells next year. Building on this success, we are planning two open-hole multilateral reentries into the Midale in Q4 with up to six legs each. This would represent the first-ever Midale open-hole multilateral reentry wells ever drilled. These wells are expected to be drilled on land acquired through the Southeast Saskatchewan tuck-in we completed in Q3. More broadly, we expect to allocate up to 35% of our 2026 development capital to our open-hole multilateral program, including plans to drill our first of two Torquay open-hole multilateral wells. With this, we expect to be the most active open-hole multilateral driller in Saskatchewan next year. If oil prices further weaken, we can shift more capital to this program, positioning us to generate compelling returns and robust economics even in very weak price environments. In addition to our open-hole multilateral development, we continue to advance the Creelman waterflood in Saskatchewan, where we currently have five active injectors. In late October, we received regulatory approval to convert another two producers into injectors, which not only support base production but also fuels future repressurized development locations. Investing in waterflood is a part of Saturn's ongoing strategy to mitigate declines and enhance our long-term sustainability. In Alberta, we finalized the drilling and completion of our three-well Montney pad, featuring three-mile extended reach laterals. These wells are the longest laterals on record to ever be drilled in the Kaybob area. The north well on this pad has the most productive days and is already exceeding type curve expectations. The south two are still cleaning up, but based on reservoir quality observed while drilling, we do expect similar results once they've reached peak production. Finally, I'm proud to share that Saturn drilled the fastest extended reach horizontal accordion well ever on record during the quarter, drilling to 5,090 meters measured depth on a single run, achieving well completion from surface casing to total depth in only 4.8 days. These best-in-class results are another example of Saturn's commitment to enhancing efficiencies while operating safely and responsibly. With that, I'll hand things over to Scott for an overview of our financial results. Thanks, Justin. Saturn demonstrated continued resilience this quarter despite a challenging price environment, with WTI prices falling 14% over the comparative 2024 period. Operationally, the company continued with its success, producing over 41,100 BOE per day to earn revenue over CAD 235 million, driving adjusted funds flow of CAD 103 million, or CAD 0.54 per share, compared to CAD 94 million, or CAD 0.46 per share in the third quarter of 2024, a 17% increase on a per-share basis. The integration of the company's most recent tuck-in in Southeast Saskatchewan, which closed on July 31st, has been seamless, with our production mix remaining consistent at 81% oil and liquids compared to 83% in previous quarters, reflecting the 67% oil and liquids weighting from the acquired asset. Our team continued to focus on operating cost reduction initiatives, realizing year-to-date net operating expense per BOE of CAD 19.04, down from CAD 19.30 on a year-to-date basis prior year. Our third quarter net operating expense per BOE of CAD 19.24 reflects the increased field activity following a seasonal low period due to spring breakup in prior quarters, consistent with increased capital expenditures and associated workover costs. Saturn maintained its annual net operating expense target between CAD 19.50 and CAD 20 per BOE. During the quarter, we returned CAD 12 million to shareholders through a normal course issuer bid and substantial issuer bid. Subsequent to Q3, we returned an additional CAD 4.6 million via the NCIB. As John mentioned earlier, we successfully bought back nearly 16 million shares, representing approximately 8% of the shares that were outstanding at the time we launched the first NCIB in August of 2024. With the combination of tuck-in acquisition activity in Q3, the restart of our drilling program in July after spring breakup, and movement in foreign exchange rates, net debt at September 30th was CAD 783 million. Over the past five quarters, Saturn has repaid just under CAD 135 million, or $95 million, on the principal outstanding balance of our notes by making regular 2.5% quarterly amortization payments, as well as the open market purchases we did at a discount earlier this year. To provide a more meaningful leverage ratio, we are presenting our net debt to adjusted funds flow on a pro forma figure that incorporates the impact from our Southeast Saskatchewan tuck-in assets, resulting in net debt to pro forma annualized cash flow to 1.6 or 1.4 net debt from an EBITDA in line with guidance. Saturn maintains strong liquidity and financial flexibility with CAD 34 million of cash on hand at quarter end, plus an undrawn CAD 150 million credit facility and an uncommitted accordion feature that allows for the expansion of additional CAD 100 million, giving us up to approximately CAD 250 million in total. Looking out to year-end, we are expecting Q4 capital expenditures to range between CAD 60 million and CAD 70 million, with average production between 42,000 and 43,000 BOE per day, while our December exit approaching 44,000 BOE per day. This reflects our fourth quarter drilling program and new production from the Central Alberta tuck-ins, which closed October 20 through the end of the year. Saturn anticipates releasing our full 2026 budget and guidance mid-December. That concludes our formal remarks. Thank everyone for joining us and hand the call back to the operator to begin Q&A. Thank you. We will now begin the question and answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. Our first question comes from Adam Gill at Ventum Financial. Please go ahead. Hey, good morning, guys. One question for me. As we go into 2026 in a bit of a softer oil price environment, how are you thinking about prioritizing? Production maintenance versus buybacks versus net debt reduction? Thank you. Yeah, thank you, Adam. It is a constant kind of battle. We are always looking to deploy our capital at whatever can get us the highest rate of return. We are going to go into the year, most likely when we do set guidance, most likely just to maintain flat production. Meanwhile, the NCIB is likely to continue. However, should we find M&A opportunities that pose a higher return than drilling our own land, as you have seen us do in Q3, I think what we will do is likely reduce our CapEx to fund those acquisitions. We really like that strategy in that not only does it leave our reserves in the ground, but if we are able to acquire some of these assets at a discounted price due to this commodity, that is something we really like. We get all those reserves. Generally, we get production online that's a lower decline at a better capital efficiency than drilling our lands. Again, we can save our locations for that for a higher oil price. That's just something that we're always watching. Again, if we can monitor that and get the highest price, the highest return on our capital, that's what we're going to see us continue to do. Sounds good. One quick follow-up, just on terms of declines. What do you think your decline would have been through a 100% organic drilling program coming into 2026 versus doing the tuck-in acquisitions that you disclosed in Q3? Yeah, that's a great point as well. Again, by acquiring mid-life cycle assets as is our blueprint, you're getting assets with a much lower decline. Obviously, a new well has a much higher decline. Should we have spent all that capital on CapEx instead of doing the M&A? I think we would have been around the 23%-24%. However, this would be closer to that 20%-21% now with these two acquisitions and the reduction in CapEx. Okay, great. Thank you. Thank you. Our next question today comes from Jamie Somerville at Roth Canada. Please go ahead. Excuse me. How does the 330 barrels a day from this Spearfish multilateral compare to the previous two wells that you drilled? Why was your type curve only 110 barrels a day? What I'm trying to get at is, what are the chances that this is just a fluke rather than a significant technological breakthrough? I will pass it over to Sylvester Zdonczyk to elaborate a little more on that. I will say, I think generally Sly will agree that that was more of a risk type curve. I will pass it over to Sly to comment. Yeah, thank you, John. Thank you for the question. Absolutely, for us, this is a new concept, a new play. Our type curve was risk. While we're pleasantly surprised with 330 barrels a day, the 110 barrel a day type curve was a risk number. We've done modeling. We've looked at analogs, but we do have limited data coming into the Spearfish in this specific zone for the first time. This is better than our two previous wells. The type curve would have been closer average to the two previous wells. While we can't expect 330 barrels a day every time for IP30, we do expect strong and consistent results. This result may result in us writing up that type curve, but we wouldn't consider it a fluke. We knew what we were going after. We saw good signs while we were drilling. We're expecting to see strong results go forward. Again, it might result in a slight write-up in our type curve. That type curve represents an average. As we learn more about this play, as we drill more wells, we'll refine that as we go. We're confident in our inventory for 2026 and beyond. That's helpful. Thank you. Can I follow up? As we think about potential reserve bookings, from everything you've been doing, both organically and acquisitions, but in particular with regards to multilaterals, can you maybe talk around reserve booking potential? I'm not clear as to the extent to which the locations, I think you're indicating like 375 multilateral locations currently, but I don't think all of those were booked at year-end 2024. And I don't know to what extent that estimate has increased since year-end 2024. Thanks. Yeah. Corporately, we try and be conservative in that we only book what we have strong confidence in. As we have expanded our overall multi-leg drilling, that will allow us to further increase our booking. We definitely did not have those booked, but we are lucky because Sylvester actually does our reserves as well. He can give a little color in what we had booked going into last year, going into this year, and what we could expect going into next year. Absolutely. It's a well-timed question as we're going through our 2025 year-end reserves process right now. As John said, we were a bit conservative, but also not knowing to the extent which we would be drilling in the next five years, which, remember, with reserves, you need to maintain that line of sight development and also balance the inventory that you can drill. We have close to 2,500 locations internally that are viable and that we like, but unfortunately, we just won't drill them in a five-year development plan. For reserves, we must honor that. That's why last year we only had 1,115 booked locations. Looking ahead to this year, we will see growth in that number, and we will see growth in our open-hole multilateral wells as we drill more and have lines of sight to drill in those in the coming year and within the next five years. I can't give you a number of what 2025 year-end will be. We were only in the 20s last year for open-hole multilateral wells, so quite conservative, but it did honor our paper development. Now, as we drill more and have multiple rigs drilling open-hole multilateral wells, we will see an increase in that number. As we go through this process, that will become apparent in the next couple of months. Thanks. Sorry, really quickly, I missed the number of multilaterals that you had booked last year. Did you say in the 20s? Yeah, last year we were in the 20s in the Bakken, and we only had three booked in the Spearfish. Again, we had only drilled at that time one last year. Us and the reserves auditors were not prepared to book tens or hundreds of those Spearfish. Now that we have drilled two more and have a line of sight to four this year and beyond, we will see that number grow. Very helpful. Thank you very much. You're welcome. Thank you. Our next question comes from Abhi Patwardhan with Sculptor Capital. Please go ahead. Hey, guys. Congratulations on another strong quarter. With regards to your reserve report, since we're already in November, have you been talking to your auditors around getting better credit for a slightly higher or above type curve performance? Yeah. Again, I'll hand it over to Sly here in a minute, but what we don't want to do and what we've been successful in doing thus far is we've never had to take a write-down on our reserves. Again, maybe we are a little conservative in our approach, but what we'd rather do is have them come in a little more on the conservative side, beat expectations, and grow our reserves instead of getting in a position where you're overbooking and then having to take write-downs. I will pass it over to Sylvester to comment further. Yeah. The other thing to add to that, John, is that the type curve represents a field-wide average. We are not just looking at a localized pool, especially in Southeast Saskatchewan. We are taking our results from the past year as well as recent years, as well as our peers and competitors in the area. Our outperformance speaks to our technical team's ability to deliver on those results, as well as the quality of our reservoir and inventory. While there is potential, and we do look at this year over year, I should not say that it does not happen because every year our type curves are reviewed. We look at the well results, we look at our remaining land base, and we do reflect our remaining inventory. The fact that we've outperformed speaks well to our technical team and to the quality of assets and reservoir that we do have, but we are honoring the field and pool averages. We will look at that. We do look at that every year. It's not stagnant. They get looked at year over year, and you might see some changes to reflect the most recent performance, but we also want to honor what our remaining inventory is, not just within the next year, but again, within that five-year book period on our approved reserves. I think the best example of that is one of the fields we've been in the longest, would be the Viking. The Viking, for almost five or six years in a row, I believe, that type curve has increased because we've had such great results in that field. Again, the more time we spend in this field, the more data points we have, the more confidence we get, and that allows us to take higher estimates on those wells. The Viking is the best case because we were beating type curves consistently for six years in a row, and in each one of those six years, you've seen that type curve come up. Hopefully we can continue these great results in our other fields, and you'll see that similar trend. John, remind me for Viking. How much above the type curve are you right now? I mean, when I say type curve, I mean the type curve that you got credit for in your reserve report last year. This year, we have actually deferred a Viking program. Again, in favor of with this commodity price and the relatively higher declines that you get in the Viking, we deferred that in favor of some of these tuck-in acquisitions. The last Viking program that we executed on was last year. I think we were 22% ahead of type curve there. Strong, consistent results, which is what we like. Again, as the type curve comes up, year over year, your beat on that will eventually decline until you are at type curve. That is the point. It is not just to beat the type curve, but eventually land on it. You are booking properly, you are executing accordingly. No Viking results so far this year, but in the past, we have managed to beat our expectations, even with those expectations rising year over year. Got it. Would you mind sharing some color on hedging? I'm curious how hedged you are right now and if there are any changes to the hedging philosophy internally. Yeah, absolutely. I'll pass that over to Scott to have a couple of comments. I will say I think this will make this part of our corporate presentation moving forward. We have been really lucky this year in that the three times we have added hedges were the three highest oil prices we've seen in the last 10 months. As far as the amount hedged and where we're at with that hedge book, I'll pass it over to Scott. Hey, Abhi, Scott here. Yeah. Currently, right now, we're 50% hedged on a 12-month basis on oil and liquid volumes. We've actually been pretty active on the gas front as well. We're seeing 50%-70% gas between $2.80 and $3.50, makes up a small proportion of our production, but still there nonetheless. Thereafter, we're about 20% for the following six months. We're pretty active in the market. As John mentioned, we did take the opportunity this year to hedge at the peaks of oil in early January and again in August. We layered on some subsequent hedges in our financial statements, as noted yesterday. Got it. And one last one for me. What's the base decline across all the assets, the entire portfolio right now? Yeah. I think going into 2026, what you should see, our decline right around, I would think that 21%-22% kind of depends on if it is an annual average or specific to, say, January 1. I think we are going to be somewhere in that low 20%s would be a great number to use. Understood. Thank you. Thank you. Thank you. That is all the time we have for questions today. This concludes today's conference call. You may now disconnect your lines. Thank you for participating and have a pleasant day.