Saturn Oil & Gas Inc. (SOIL) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen, and welcome to Saturn's Fourth Quarter and Full Year 2024 Results Conference Call. [Operator Instructions] And the conference is being recorded. [Operator Instructions] I will now turn the meeting over to Ms. Cindy Gray, Vice President, Investor Relations. Please go ahead, Cindy.

Thank you, Aishia. Good morning, everyone, and thanks for joining us for Saturn's Q4 and Year-end 2024 Earnings Call. Please note that the company's financial statements, MD&A, AIF and press release are available on our website and have been filed on SEDAR. 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 associated risks outlined in our most recent MD&A. Listeners are 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 statement, 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 our AIF filed on SEDAR and available on our website. All amounts discussed today are in Canadian dollars unless otherwise stated. Today's call will include comments from various members of Saturn's executive team, including John Jeffrey, our CEO; Justin Kaufmann, CDO; and Scott Sanborn, our CFO. Following our prepared remarks, we're going to open the lines up to participants on the conference call for a question-and-answer session. If we are [ not ] able to address your questions today, we'd encourage you to reach out to Saturn directly through our website. I'll now turn it over to John.

Thanks, Cindy. Good morning, everyone, and thank you for joining us. As demonstrated in our results, Saturn has continued to evolve and 2024 was a year of notable progress on many fronts. We enhanced the quality and sustainability of the asset portfolio through 2 core-up acquisitions and closed a significant South Saskatchewan acquisition of Battrum and Flat Lake assets in June. These transactions drove further growth and high grading of our drilling inventory while expanding our future development potential. The South Saskatchewan acquisition also provided waterflood development that can help further reduce Saturn's already low declines, while improving our long-term sustainability, and we booked our first waterflood reserves this year at Viewfield. Concurrent with the South Saskatchewan acquisition, we took the opportunity to refinance our legacy debt with a USD 650 million of senior notes, featuring lower interest rates, more favorable terms and an amortization feature that provides for systematic principal repayments of 10% per year. Recognizing U.S. denomination debt means we are exposed to currency fluctuation, we also layered on a foreign exchange hedge at approximately 1.34 Canadian to U.S., which served to fix the interest rate and principal payments on the debt for the next 3 years. Given the recent erosion in the Canadian dollar over the past few months, the impact of foreign exchange has significantly affected the Canadian dollar value of our U.S. debt. And some investors and market participants may not recognize the degree of that impact. For example, last half of the year of 2024, we made 2 debt prepayments totaling USD 32.5 million, resulting in a year-end balance of the senior notes of USD 618 million. Although when expressed in Canadian dollars, these payments don't seem obvious. Thanks to our foreign exchange hedges, Saturn has notionally offset a portion of the increase in net debt caused by the currency fluctuation, which at year-end represented an offsetting value of $20 million and would have reduced our net debt to $840 million if this could have been included in our net debt calculation. However, when the impact of the exchange rate is applied and converted to CAD, it almost completely offset the impact of our prepayment. That, in addition to our scheduled capital program, makes the net debt appear even larger in Canadian dollars. In reality, should the foreign exchange return to prior levels, we are exactly on track to meet our debt obligations as I'll illustrate. If we look ahead to Q2 of this year, the situation could be vastly different depending on the outcome of the trade wars and the Canadian election. Since our planned capital spending is so much lower in that period, it contributes to a working capital surplus, which improves net debt. For example, using our guidance assumptions for capital and production, which I will say we are well ahead of and using a $0.74, our net -- our ending debt for the quarter will be CAD 700 million or approximately $160 million reduction in Q4 levels. And again, this is exactly on track to our guidance, whereas applying the current effects of $0.69 result in net debt for the quarter of $750 million. Again, this just demonstrates the sensitivity of foreign exchange on our net debt and supports Saturn's decision to layer on that foreign exchange hedge to protect interest and principal. Again, adjusting for currency, our gross and net debts are exactly on track to achieve our guidance set out earlier in the year. Now what I don't want to overlook here is that a lower Canadian dollar helps the oil industry as effectively, we are paid in U.S. dollars. The lower the loonie, the higher the revenues. And at today's WTI levels, thanks to a depressed dollar, we are still enjoying prices in the 90s. Notwithstanding the foreign exchange impact on our net debt, our Q4 results reflect the consistent execution of our value proposition, coupled with strong operational performance. Production averaged just over 41,000 barrels a day in Q4, exceeding the high end of our guidance range and beating analyst expectations by 4% on a capital program of just over $105 million. We exited the year even higher with December volumes averaging approximately 42,000 BOE a day. We had a record Q4 adjusted funds flow totaling $124 million or $0.64 a share, beating the Street consensus estimates by 12%. For the full year 2024, our AFF was $2.10 or $380 million, reflecting on our team's ability to control costs, identify operational synergies and enhance margins. We reduced net operating expense for $19 for the year and just over $18 in the quarter, well under the $20 target we had set. We have also realized lower royalties and transportation expenses in both quarters and the year, which contributed to an operating netback of just over $43 a BOE in both periods. With approximately $134 million of free funds flow in 2024 or $0.74 a share, Saturn continued to deliver on our return-focused value proposition. Since the launch of our share buyback in August, we have repurchased about 6.7 million shares in the open market or about 3% of our outstanding balance. Our robust hedge book positions Saturn well to withstand market turbulence. Again, this backdrop and the impact of the commodity pricing and the weakening dollar, we have insulated the company from extreme volatility by hedging commodity prices, differentials and FX. So putting all that together, Saturn is resilient. We have a flexible asset base, and we can rapidly pivot our capital program and the pace of our development in response to the broader market. We believe we have added tremendous value to our shares in the period by returning approximately $15 million to shareholders through buybacks, repaying $45 million of debt, undertaking accretive acquisitions, exceeding our type curve on our CapEx while meaningfully reducing our operational costs below our stated goal. We firmly believe our shares offer an extremely compelling value at current prices and represent the deepest value on the market today. Once again, I am proud of Saturn's accomplishments, which showcases our team's exceptional performance and innovative approach. Our ability to challenge conventional practices, both operationally and corporately has been a key driver to our success. In addition, our team's ability to see and do things differently have allowed us to disrupt traditional often inefficient practices in our industry and things keep getting better. We look forward to continuing to consistently deliver results, walk the talk and keep all of our stakeholders updated a long way. With that, I'll turn it over to Justin to talk to our operational performance and reserves.

Thanks, John. 2024 was our year of solid execution in the field that set several new records for Saturn, including Q4 results that beat analyst expectations on several metrics, many of which are due to the overperformance of development wells, thanks to the innovation and expertise of the technical team and the high-quality acreage of the company. The integration of the acquisition assets in mid-2024 resulted in the formation of our 3 core areas and expanded our development inventory of high-return opportunities in Southeast Saskatchewan and West Saskatchewan. We executed a $105 million capital program in Q4 and $246 million over the full year, drilling 54 wells in Southeast Saskatchewan, 27 in West Saskatchewan and 16 in Alberta within the Cardium and Montney plays. Other notable projects and developments in 2024 include several first or new record achievements across our core areas, such as we drilled the first ever Torquay mono-bore horizontal well. This is on a sample set of 600 wells drilled in the Flat Lake area and will lead to future capital efficiencies. We drilled the first ever Flat Lake open hole Bakken well and the first open hole multi-lateral Spearfish well, applying learnings and expertise gains from our open hole multi-lateral Bakken development. This is an extremely exciting engineering technique that is unlocking barrels in areas that were previously uneconomic, and we will continue to expand on this development in 2025. We had one of our frac Bakken wells ranked as Saskatchewan's seventh best performing well in December 2024. This is a rare for a 1-mile frac Bakken well to make this list and hasn't happened in quite some time. Our well spacing and frac designs are why we are realizing these strong production results. We also adjusted the frac designs in Flat Lake and Cardium, which improved capital efficiencies, specifically in the Cardium. The combination of longer laterals and innovative hybrid completion technique helped expand the efficiency of the fracs to reach the tow to and enhance the economics. This frac design involved a ball drop system on the tow followed by a switch to coil almost halfway through. This strategy allowed us to increase frac pressure rates, generate significant cost reductions, improve well completion times and is expected to be applied to future extended reach Cardium wells. We also implemented new downhole drilling bottom hole assembly tools that helped us drill Canada's longest Cardium well at 7,570 meters measured depth. These innovations and technology have helped us transform what was historically a sleepy play in the Cardium into a higher impact reservoir with competitive economics. Saturn posted growth in all reserve categories over 2023 with 2P reserves of 200 million barrels, 1P of 133 million barrels and PDP of 87 million barrels. This year, we also further increased the liquids weighting of our reserves as we high-grade the inventory. From a value perspective, the net asset value per share comes in at over $5.50 on a PDP basis and approaches $14 per share on a 2P basis, which we believe represents a compelling opportunity given the steep disconnect between current market values and the net asset value of the company. As Scott will also speak to later, our capital program is heavily weighted to the second half of the year, which means the outcomes from the activity are often realized in the following year. This holds true for reserves and production as volumes on stream from activity in the fourth quarter may not appear until Q1 or Q2 of the next year. We saw this in our 2024 year-end reserves as we invested significant development capital in Q3 and Q4 and yet a material amount of development won't be reflective until we report our 2025 reserves. While the access in June provided additional new reserves and locations, it also pushed more capital in Q4 development, which again mostly won't get credited until year-end 2025 reserves. Following the acquisition, we also chose to upgrade the 5-year development plan as part of our year-end reserve evaluation process. While high grading locations and reserves, this led us to shift some probable locations in the proved underdeveloped category, which is great and removed a portion of our previously booked locations that no longer fit within our development plan. In addition, we expanded our location inventory in 2024 with over 1,100 booked locations in the reserve report, an increase of 27% over last year along with an incremental 1200 internal identified unbooked locations. We are also pleased to have booked our first ever waterflood reserves at Viewfield in 2024 recording approximately 600,000 barrels. This booking is adjacent to [ Barents ] waterflood operations within an existing unit that has a large original oil in place of over 70 million barrels, booked at 11% recovery factor. However, we see the potential of getting to a 20% recovery factor with waterflood. Currently, we have 8 wells booked on this one. But if waterflood is successful, there's potential to expand this on a meaningful scale with pre-pressurized waterflood locations. We see waterflood as a significant driver to mitigate decline. And as John mentioned, increase the sustainability of the company. I'm also very proud of our team's safety performance in the year with 0 lost time injuries and only 3 reportable injuries. Despite increasing our person-hours by 38% in the year to a total of over 1.4 million person-hours. We also increased our hazard identification by 60% in 2024, over 2023, a significant step forward in preventing future incidents. I'll now turn it over to Scott to review the financial highlights.

Thanks, Justin, and good morning, everybody. As John outlined earlier, financially Saturn had standout quarter, a very strong year in which we transformed our capital structure, greatly enhanced our asset base, high graded our hedge book and implemented a share return framework with the launch of our share buyback or NCIB. Saturn has continued to deliver improvements in our operating cost structure, which contributed to our netbacks of $43.05 per BOE in Q4 and an average of $43.07 per BOE for the year. With ongoing cost reduction initiatives, coupled with high volumes, our Q4 net OpEx came down to $18.35 per BOE, equivalent to $19.01 per BOE on the year, under our $20 per BOE target. Royalties also came in below Q3 and lower than our 2025 guidance at 12.2% in Q4 and 12.6% for the year. We are pleased with the results, and we'll continue to maintain our 2025 guidance at this time. I will touch briefly on marketing as we've had questions given the U.S. tariffs and their impact on Saturn. Like most producers in Western Canada, we primarily market our barrels at delivery points in Saskatchewan and Alberta, which for us, the majority of that volume is directed towards the U.S. on the Enbridge Mainline and Line 3. Since we are not transferring our barrels directly cross-border into the U.S., the tariff impact is hitting WTI price differentials, of which we maintain differential hedges that protect us from such fluctuations. However, ultimately, the weaker Canadian dollar has a positive financial impact on revenue as our barrels are priced in U.S. dollars, which helps mitigate the impact of the wider diffs. In addition, we maintain WTI hedges on a forward 12-month basis at 50% to 60% of our oil and liquids production net royalties and at about 30% to 40% out 18 months out. Our hedge book is an advantage in a cyclical industry and the breadth and depth of our hedge book protects Saturn volatility. This is particularly true of foreign exchange or FX hedges. Saturn's outstanding debt is comprised of U.S. dollar-denominated senior notes, which are reported in Canadian dollars or CAD. As CAD has weakened significantly relative to the U.S. dollar, we've seen a corresponding unrealized revaluation at the end of the year, causing an increase in overall debt. Notwithstanding the revaluation, which we expect to reverse, the increase is positive for Saturn's bottom line as previously discussed. Put differently, Saturn repaid approximately $33 million on our senior notes since refinancing in June with our U.S. denominated debt balance decreasing. However, the change in FX caused the CAD converted debt balance to increase. Our FX hedges lock in the first 3 years principal and interest and notionally offset CAD $20 million of the increase in year-end net debt to attributable to foreign exchange. Factoring in our FX hedge asset, our year-end net debt would be approximately $840 million, driving lower net debt to cash flow at about 1.6x and net debt to adjusted EBITDA of 1.4x. We maintained liquidity at year-end of approximately $200 million, comprised of approximately $50 million in cash and $150 million of undrawn availability on our credit facility. We believe having this financial flexibility underpins our strength and resilience through volatile markets. I also want to touch on the cadence of our capital expenditures and the relationship between CapEx, production and free cash flow through the year. The majority, about 70% of our 2025 capital is expected to be deployed in the second half of the year with 24% in Q1 and the balance in Q2, given the typical slowdown during spring breakup. Because of the spending profile, we expect production volumes to peak in Q1 and Q4, reflecting the impact of a more active drilling period. Conversely, free cash flow is forecast to crest in Q2 when capital spending is lower due to this breakup and taper off as we advance capital spending through Q3 and Q4. As Justin mentioned, we see this cadence each year and is a good reminder that our spending, production and free cash flow fluctuate quarter-over-quarter driven by activity. Thanks again for joining us today, and I'll now hand it over to the operator to commence with the questions.

[Operator Instructions] The first question comes from Amir Arif with ATB Capital.

Congrats on a great quarter. Just had a question for you on the durability of the better cost structure. Can you just walk us through just your sense in terms of the production and transport costs on a go-forward basis, given the improvements you've made in the second half since taking off the assets?

Yes. Thanks for the question. And yes, we're really excited about the quarter. We're going to hold our guidance at $20 a barrel there for operating costs throughout the year. Q1 is always going to be the highest operating cost per barrel. Obviously, you have higher operating costs with colder weather. You have a little bit more downtime when you get these sudden cold that come through. So I'm confident we'll be able to beat that. I don't know that it would be appropriate to model $18 a barrel moving forward. But I'm confident in our ability to continue to be sub-20. Again, Q1 is going to be higher than Q4 likely. But I think the average for the year will be well below $20, and we should see levels closer to 2024.

Okay. I appreciate the color there, John. And then just second question. On the technical revisions, it was minor, not a big percentage on a 2P basis. But curious, can you just give us a sense of how much of it was related to just taking locations out versus type curve updates?

Yes, material was the locations. Essentially, the book that McDaniel's had on the acquisition we had was close to 240 locations. We adopted 210 of those into our bulk at year-end. So that equated to about 30 location drop, which was a material part of it as we were high-grading their inventory with ours. So mostly with the acquisition -- or the location upgrade.

Got it. That's helpful. And then just on the hedging, I think you guys are closed, if not at your hedge targets for the year. So just curious, are you comfortable with where it is now? Or would you still like to increase it further?

Yes. Our target is to maintain somewhere around that 55% for the next 12 months range. We're obligated to maintain 50%. What we like about having a little extra buffer there is that we see oil spike, then we can layer on a bit more. We don't really want to exceed 60%, so if we see oil run, then we can add on some more. However, if we see oil collapse and we're able to retire some of our lower ones and again, still staying within that band. So targeting 55% is what you're going to see us kind of maintain on a 12-month basis. Again, gives us flexibility if oil goes up or down and still gives us kind of a comfortable buffer either way.

Got it. I appreciate that color. And then just finally on Spearfish, I mean the great open well there, tremendous rate for 6-leg well. Just curious how much inventory do you think you have there in terms of open hole multiline opportunity?

We believe we have 30 wells. If we drill them all at 6 legs per well, we'll probably play with that moving ahead. We actually just finished drilling our second one earlier this week and we'll have our third one on production before the end of the year. So barring the results of those, you'll probably see more capital flow towards their development based on the great success we've had on the first one we drilled this year.

And what's our internal estimates on the NPV of those 30 locations we found?

So we're seeing the capital cost come in on those close to $2 million. And depending on the price deck you use at a $70 price deck on the one we drilled, you're seeing over 100% rate of return.

So that -- all 30 in the field would be?

Yes, we're seeing at a $70 price deck again, you'll see close to $100 million of NPV value based on the locations that we have right now.

And Justin, was the second leg drilled with 6 legs as well?

Correct.

Next question comes from Adam Gill with Ventum Financial.

Two questions for me. Just with the drop in oil prices, can you give us your current thoughts on tax outlook for 2025?

For tax outlook?

Yes.

Yes. So we're looking at -- we're forecasting tax payable in about the end of 2025, 2026. So no change significantly from our previous estimated guidance, which is a publication right now.

Okay. And then just how you feel positioned on debt repayments and remaining active on the NCIB?

So yes, we have maxed out our NCIB on practically every day since we have announced it. So very active on that front. We continue to lean into that. Again, as I'm sure you're aware, Saturn is always on the hunt for the cheapest barrels in Calgary. And right now, those are ours. So happy to buy those out of the market. Debt repayment, again, what I find funny about the FX is, although it notionally makes our Canadian dollar look -- Canadian dollar-denominated debt look higher. In reality, if you've seen the dollar fall to $0.50, which again, nobody here believes it will. But if you've seen the dollar drop to $0.50, again, notionally, what you're going to see is our debt spike. However, that also spikes our revenue. That would give us netbacks at the top line price of CAD 140 plus. So it does go hand in hand. Now the other piece of that is your debt repayments. Does -- do our debt repayments get more expensive as the Canadian dollar drops? In reality, it doesn't. And that is because Scott and his team were able to layer on such a strong FX position that covers off 100% of the next 3 years principal and interest. So that's fixed at an exchange rate. So as the Canadian dollar goes down, all you're going to see is our revenue go up, and that's going to be just a positive for not only Saturn for all the Calgary oil producers.

Okay. Great. I actually have one more here. You've had good success on the open-hole multilateral wells, is there room within the booked inventory to convert some of those locations into a more capital-efficient open-hole multilateral? Or are they booked essentially the way they need to be drilled today? The fracs ones will need to be fracked and the open holes that are booked?

Yes, you're probably more referring to our Bakken location specifically. Our one-mile fracked Bakken locations that are close to tie-in points, we'll keep those bookings as is. There will be some conversions on some actually locations we have on the west end of Viewfield where we're not close to tie-in locations, just those open hole multi-laterals produce a lot less water. So trucking becomes a viable transportation option over time. So a few locations on the West side of Viewfield, but for the most part, they'll stay within their booking categories.

Now I will say just with that, that again we are always looking to add reserves. So the exciting thing with the open hole Spearfish wells that Justin was just talking about is those weren't a conversion booking. That is 100% additions to what we already had. So again, as we see $100 million of value, that is incremental to anything else we had. So again, Justin and his team have done such a good job of identifying different techniques and where it works in different areas. So again, we are scouring our land base now to see what other pools we have like that, that could work. So whether it be conversions or straight -- or just straight adds that you've seen us do here at the Spearfish, that is something that Justin and his team, I just don't think get enough credit for adding the company.

Yes. We increased our overall multi-lateral bookings by over 50% this year-over-year. And with us dedicating our rig to drilling to open hole multi-lateral Bakken this year and those Spearfish wells I talked about, those bookings should go up for year-end '25 as well.

Great. And congrats on the good quarter, gentlemen. That's it for me.

Thank you.

Since there are no more questions, this concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.