Earnings Transcript for SOIL.V - Q3 Fiscal Year 2024

Operator: Thank you for standing by. This is the conference operator. Welcome to the Saturn Oil & Gas Q3 2024 Conference Call and Webcast. As a reminder, all participants are in the listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. [Operator Instructions] I would now like to turn the conference over to Cindy Gray, Vice President, Investor Relations with Saturn Oil & Gas. Please go ahead.

Cindy Gray: Thank you, Dorvin [ph]. Good morning, everyone. And thank you for joining us for Saturn's Q3 ‘24 Earnings Conference Call. Please note that the company's financial statements, MD&A, and press release are available on our website and have been filed on SEDAR+ Plus. Our corporate presentation will be updated shortly and will be available on our website as well. 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 the company's annual information form filed on SEDAR+ and available on our website. All amounts discussed today are in Canadian dollars, unless otherwise stated. Today's call features remarks from members of Saturn's executive team, including John Jeffery, Chief Executive Officer; Justin Kaufmann, Chief Development Officer; and Scott Sanborn, Chief Financial Officer. Following the team's prepared remarks, we'll be conducting a Q&A and we'll open the line to questions from participants. I'll now turn it over to John Jeffery.

John Jeffrey: Thank you, Cindy, and good morning everyone. I'm proud to share Saturn's Q3 results, which show how our strategic blueprint for value creation continues to drive successful execution. By effectively managing the factors within our control, the company is exceeding expectations and steadily growing adjusted funds flow. We are safely and responsibly delivering results that surpass market expectations. The third quarter was our first full period integrating the Saskatchewan acquisition of Battrum and Flat Lake assets, which were acquired in mid-June for less than two times cash flow. Although we've only managed the assets for a short time, we have already begun reducing operating costs and deploying capital. Early results are exciting, and we should be able to share those in the coming months with you. Not only do we achieve several corporate records for production, adjusted EBITDA, and AFF, we also exceed consensus estimates on a number of fronts. Saturn delivered our highest ever average production, surpassing 39,000 boe/d. During the quarter, Saturn was able to make the best out of a falling oil price by monetizing some older hedge positions required by our prior lender. We believe oil to be in a range about between USD $70 and USD $90, so we've purchased approximately $20 million of these hedges, which if we are correct, could have impacted future cash flows by close to $40 million. Our record adjusted EBITDA of $136 million also came in above consensus, while AFF was highest in our history at $94 million. When normalized for these one-off hedge costs, adjusted funds flow was over $114 million or $0.56 a share, ahead of consensus estimates. When oil price jumped back during the quarter, we acted quickly and layered in new oil callers that are in-line with our future oil outlook. As Scott will expand upon, we were also able to lock in favorable foreign exchange rates on principal and interest payments for our senior notes over the next three years. Our nimble capital allocation strategy and the nature of our asset base enable Saturn to target locations or production optimization that offer robust returns. We intend to continue growing per share value by pursuing strategic tuck-in acquisitions that bolster our footprint in high-performing areas, offer cost synergies, and expand our drilling inventory. For example, we've seen solid well outperformance in our development of the BrazeauCardium area of Central Alberta. Subsequent to quarter end, we closed a $20 million tuck-in acquisition in Brazeau that significantly increased our drilling inventory, production, and land base in that area, much of which is adjacent to Saturn's four best-performing wells. Such strategic and accretive acquisitions are an integral part of that blueprint for value creation. Concurrent with the South Saskatchewan acquisition, Saturn also reshaped the balance sheet with the issuance of 9.625% senior notes, which are free from punitive hedge requirements or limitations on capital, and have effectively reduced the company's interest rate by about 40%. While debt reduction continues to be a priority along with strategic tuck-in acquisitions, Saturn launched the first phase of our return of capital framework on August 27th with the implementation of a share buyback or an NCIB. Since inception of the NCIB, we have maxed out our daily purchase limits of approximately 46,000 shares, and to-date we have returned over 4.7 million to shareholders through the purchase and cancellation of 1.9 million shares in the open market. Longer term and in a more favorable commodity environment, our return of capital framework could evolve to include a dividend. However, until we see a tightening of Saturn's valuation gap relative to our peers, we believe buying back our shares lets us acquire the lowest cost barrels possible, while generating value for shareholders without driving up our acreage. It is a testament to the skill, experience, and entrepreneurial attitude of our teams that Saturn is able to see things differently, do things differently, and disrupt tradition. And often inefficient practices operationally and corporately. I am very proud of our team's commitment to innovation, safety, and responsible development, and for their unwavering support of the communities in which we live and work. Right at the end of the year, we expect to release Saturn's 2025 budget and guidance, building on our 2024 capital expenditure program and targeting continued AFF optimization. Given the steady growth and evolution we have achieved over the past few years, I believe now is an ideal time to take a first look or maybe even a closer look at the Saturn opportunity. With that, I'll turn it over to Justin Kaufman to speak to our operational performance. Justin?

Justin Kaufmann: Thanks, John. As mentioned earlier on the call, Saturn achieved a new production record in the quarter, averaging over 39,000 boe/d, which exceeded expectations, comprised of 83% higher value oil and liquids. This aligns with our previous forecast following the Southeast Saskatchewan acquisition, as average volumes for the last half of 2024 are expected to range between 38,000 boe/d to 40,000 boe/d. Capital expenditures in the quarter totaled $84.4 million, including capitalized G&A. With that, Saturn drove 48 growth wells that contributed to volume increases, along with investments in capital-efficient production optimization initiatives that'll expand on shortly. Saturn's asset portfolio features diverse development potential that contributes to our long-term sustainability. Today, we are largely oil-weighted from a production reserves and revenue perspective, but we also have gas-rich assets in Alberta that offer longer-term development targets as natural gas prices rebound. Being able to quickly pivot depending on commodity prices, availability of services, or a shifting macro-landscape underscores the value of our strategy and diverse asset base. We can drill open-hole Mississippian wells, exploit the Balkans with a combination of frac and conventional open-hole approach, or focus on quick payback returns in West Saskatchewan Viking. Saturn's blueprint involves applying proven operating strategies from one asset or area within the portfolio to other areas in an effort to improve capital efficiencies, payouts and returns. In addition, it includes our core-up strategy of pursuing tuck-in acquisitions in areas where we are generating the highest rates of return. The $20.5 million BrazeauCardium tuck-in acquisition that John mentioned earlier demonstrates our strategy in action. The transaction closed October 1 and added 63 net locations and approximately 700 barrels a day of production, along with expanding land in an area where new Cardium development has shown material production outperformance relative to type curves. The acquisition also features land and locations adjacent to where our four best Cardium wells were drilled earlier in 2024. Recent Cardium wells have been drilled longer and used higher stage counts in the fracs, resulting in a significant uplift in oil production and increasing rate of return expectations. In the past couple of weeks, Saturn successfully drilled the longest Cardium well in Canada out of a sample set of over 6,000 wells, having a total length of 7,570 metres measured depth. The achievement demonstrates Saturn's technical ability to go outside the norm and create opportunities in areas overlooked by other peers. In our Kaybob Montney area, our team continued to unlock value through highly capital-efficient production optimization projects. Converting six wells from gas lit to conventional pump jacks at Kaybob, this low-cost, high-value exercise resulted in more than 500 barrels a day of new volumes coming on stream at a cost of just over $3,000 per barrel, representing some of the highest rate of return barrels in our portfolio. In Southeast Saskatchewan, incorporating an expanded use of seismic has increased confidence in well placement and resulted in improved production across several regions targeting Mississippian and the Bakken development. Our teams are currently processing and evaluating seismic use in rotary and success to map out drilling location targets for next year. Our Open Hole Multi-leg development deployed in the Bakken, where we have performed well above our peers on a length normalized basis, is now being tested in the Spearfish at Manor, demonstrating how bringing proven technologies to new areas can change the cost parameters and open up new inventory. Saturn is also continuing to invest in our pre-pressurized Bakken program with 10 Torquay conversions planned for Q4 of this year. Since this area was mostly booked from a reserve perspective, we expect being able to expand future reserves while also continuing to lower the plants. Each of these incremental improvements area-by-area and asset-by-asset contribute to Saturn's overall health performance. And now I'll turn it over to Scott to review the financial status.

Scott Sanborn: Thanks Justin. Good morning, everybody. As John mentioned, we had another record quarter based on production, adjusted EBITDA, and strong adjusted funds flow and continue to execute on our NCIB, all of which demonstrate the strength of Saturn's strategy. We believe the normalized adjusted funds flow of $114 million, free funds flow of $29.7 million, excluding the one-time hedge monetization, offer a better indicator of Saturn's run rate capabilities for generating cash going forward. With our senior notes debt refinancing complete in the second quarter, we started Q3 in a strong financial position with cash on the balance sheet and a lower prospective interest rate. Further, we are no longer subject to restrictive hedge requirements that were part of our previous debt instruments, including an obligation to hedge total production three years out. As John spoke about earlier, this resulted in Saturn carrying some unfavorable price swaps in low-range callers, which we meaningfully addressed in the quarter, improving our hedge book going forward. We similarly took advantage of the upper price movement and layered in higher value callers, including contracts with ceiling that are north of $84 per barrel. The company also capitalized on the strong Canadian dollar relative to U.S. mid-September, locking in foreign exchange rate hedges for the next three years on both principal and interest payment portions of our senior notes. Since natural gas is generally immaterial to our overall financial picture, representing only 1% of revenue and approximately 17% of production volumes, we did layer in a small amount of natural gas hedges, approximately 10,000 GJ/d at$2.73per GJ through the end of 2026. This active hedge management provides another example of a factor within our control that allowed us to protect against the downside and mitigate risk. Identifying opportunities to reduce costs remains a priority for Saturn, and I'm proud to highlight that our OpEx of $19.86 boe/d in Q3 with again our $20 target, even though the new Battrum and Flat Lake assets had a higher operating cost than our corporate average. This exemplifies how our team improves efficiencies and can bring down per unit cost of OpEx post-acquisition. From a netback perspective, this focus on controlling costs coupled with our relatively low royalty rate positively contributes to our bottom line. Saturn's Q3 royalties averaged 13%, operating costs were under $20 per boe, and transportation was $1.70 per boe, driving average operating netbacks of $42. We'll continue to focus on cost reduction and netback enhancements to support adjusted fund flow and free fund flow going forward. Net debt at December 30th totaled $779 million, representing approximately 1.4x net debt to annualized quarterly adjusted EBITDA. We remain committed to continued debt reduction as part of the Saturn blueprint and anticipating achieving net debt to EBITDA approaching 1x by the end of 2025. The company had liquidity at September 30th of over $260 million, including $113 million of cash and $150 million of undrawn availability under our credit facility. This financial flexibility positions the company for continued advancing activities that improve per share metrics, including the NCIB and tuck-in strategic acquisitions. Since October 27th through the end of last week to-date, Saturn has returned $5.4 million to shareholders with repurchase cancellations of approximately 2.2 million shares. This aggregate dollar value represents approximately $0.03 per share based on the Q3 weighted average shares outstanding. We intend to continue this pace of buyback with WTI Holdings at or above $70 per barrel. We saw WTI in the range of $60 to $65 for an extended period through 2025, our capital allocation strategy would be assessed and potentially adjusted. However, at current WTI levels, we anticipate maintaining our practice of maximizing the daily NCIB purchase limits. Further, we are expanding our capital markets focus to reach new growth capital and introduce the Saturn story to be interested for potential investors. We believe there's opportunities for multiple expansion given our fundamentals compared to our current relative valuation. Our full 2025 budget and guidance are expected to be released before the end of the year, with our preliminary expectations being to maintain a stable budget to support continued robust free cash flow generations. With that, I'll turn it back to the operator to open up the line for any questions.

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Amir Arif with ATB Capital. Please go ahead.

Amir Arif : Good morning, guys. A couple of questions. One just around the hedging. The one-off hedges, just curious, was that limited based on the cash flow you had or are there any additional legacy hedges that you do plan on closing in future quarters, or have you closed everything you’d like to close. [Multiple Speakers]

John Jeffrey: Yeah, we're just trying to be as opportunistic as things come up. Again, liquidity at the end of the quarter has been well in excess of $100 million in cash, over $260 million of total liquidity. So cash flow and cash availability is definitely not the limiting factor. Just really trying to take advantage of volatility. When we see an oil spike up to $78 in the quarter, we layered on some additional hedges. When it fell back down, we bought up some legacy ones. So that was a one-off in the quarter. We’ll likely keep doing it. We're always watching that, if we can improve that hedge book again. Our thoughts here is that we believe oil is going to be in that $70 to $90 range. So, just trying to upgrade our hedge book to kind of reflect that range. So that's really been our strategy and I think you're going to continue to see us kind of roll that out. If we have an opportunity there to buy something up, that's underwater or layered on when it strengthens, I think we're likely to do that.

Amir Arif : I appreciate that, John. And so generally speaking, the future hedges you are layering on, they are all generally going to be more callers?

John Jeffrey: Yeah, we do prefer the callers. I mean, obviously, with the FX that was a swap, but looking at WTI here, we're going to focus on callers that kind of sit within borrower outlook price of oil.

Amir Arif : Okay, that sounds good. And then just a second question. Just on the capital – the pace of capital spending, I mean in the first half of the year, the company was smaller. It was about $50 million spent. Second half, there's about $170 million spend coming. Just curious if you have the systems in place and the staff to efficiently be deploying this larger pace of capital that you are starting to run with now, given the size of the company?

John Jeffrey: Yeah, absolutely. You’re going to see – again, I kind of alluded to it there briefly, but really excited to get the results. The results in Q3 look fantastic. Early results in Q4 are the same, so I think we have the exact right size of staff in place to execute on the balance of 2024 and going into 2025. So hopefully, we can have that guidance out here in December, early year ’25, but right now staffing levels are great. The team that Justin and his guys have put together have just been doing a bang-on job, beating tight curves, beating expectations. So I think you can expect more of that coming through the balance of this year and hopefully in 2025 as well.

Amir Arif : Okay. Sounds good. Thanks.

Operator: Thank you. We have the next question from Adam Gill with Ventum Financial. Please go ahead.

Adam Gill : Hey, good morning, guys. So just on the tuck-in acquisition, how active do you expect it to be on the smaller acquisition front? Is there a limit in terms of how much you want to spend on that? And how full is the slate of opportunities for you to make these tuck-in deals?

John Jeffrey: We're always looking. So, what you've seen us do throughout the year so far, if you ignore the Battrum and Flat Lake, the larger acquisition, you've seen us sell Swan Hill and then pick up that Adonai Resources in southeast Saskatchewan, as well as that Brazeau there in Cardium one as well. So net-net, we netted a couple hundred barrels a day. Actually more importantly, we netted about 50 locations better. When you look at PDP, when you look at locations, we definitely came out ahead of that, when you kind of take those three into its aggregate. That being said, if we can do smaller tuck-in acquisitions that build on our core areas with the best results, and we can do so out of cash flow, I think you're going to see us continue to focus on that. As far as pipeline, I think we're seeing an ongoing consolidation. Again, some of our core areas, they are a limited, although a number of smaller players are available. If we can continue to pick up good assets with good lending room at 2x or sub-PDP, you are going to continue to see us focus on that if it fits with our long-term blueprint strategy.

Adam Gill : Great. Thanks John. Second question, on the Open Hole Multilateral drilling, you've obviously started to apply that outside of the Bakken play. So first off, do you see that mainly as a boost to economics or as expanding the location opportunities? And then secondly, how many employees have you identified as potential candidates for this development technique?

John Jeffrey: Yeah, I think that feels like more of a dev question, so I'll pass it over to Justin Kaufman to chime in.

Justin Kaufmann : Thanks John. Hey Adam. Yeah, we're looking at it through multiple different plays. Some companies have tested in the Viking. Some companies look at it farther south in Flat Lake and the Bakken. Right now in the Spearfish, that's kind of the first way outside of our North Viewfield package. We chose that specific area because of the relative thickness of the P1 standard, and that's similar to how we chose it in the Viewfield Bakken. So, reservoir parameters essentially dictate where and how you can use that. We'll push it to the Spearfish and we'll see how it goes from there. There is potential in the Flat Lake area, but a little bit more science has to be on up front. But we'll continue to potentially try it in new areas depending on the development success we see along the way.

Adam Gill : Just with that Spearfish location, would that have been slated for a regular single-lateral, view-lateral, horizontal well? But just given the incentives, now you're going to go with the six-leg?

Justin Kaufmann : Yeah, actually, like the original P1 sand was developed as a single-legged frac actually, Spearfish stand, and it had very limited success on the actual inflow, but they got it below. It didn't really meet the volumetrics to make that location FAPA positive. But with the increased number of legs, we're going to see an increased number of inflows. Based on the current building process we're seeing, we think that will have similar results that we saw to our Bakken and the Viewfield area. So the single leg, based on the relative thinness of the zone up there, kind of restricted volume inflow, and we think we can span on that with the additional legs.

Adam Gill : Sounds good. That's it for me. Thank you.

Operator: Thank you. The next question is from Christopher True with Eight Capital. Please go ahead.

Christopher True : Good morning, and thanks for taking my question. So Saturn discussed about validating a stratigraphic trend between East Plato and Plato. Could you please discuss a little bit more on what you are seeing with this trend and what it could mean for Viking development if it's proved to be a successful trend? Thanks.

John Jeffrey: Yeah, down in the Plato area, it’s more – the Viking's are a little bit more stratigraphically trapped. With our development, we've been able to identify the thickness of the Viking there. We're seeing anywhere from three to six meters in general reservoir thickness, and our development has helped us identify that. We have now drilled, if not every second section, along that total trend, we do see complete infill development to our East Plato field, which would involve about eight one-mile Viking locations on a per-section basis, and that is where a lot of our future Viking development is going to be placed. So we definitely see that trend continuing and we've been able to prove out the economics of it. If you look 10 years ago, there was some other producers that tried half a mile shorter horizontal locations that weren't able to make it work as far as the economics go. But with the new type of completions and the longer lateral lengths, you are seeing that increased rate of return and turning that return positive has helped obviously give us confidence in developing that trend at the same time. So, a little bit new findings and then just using kind of newer completion techniques to help make those wells positive, I guess.

Operator: Christopher, does that answer your question?

Christopher True : Yes, thank you.

Operator: All right, thank you. The next question comes from Jose Sanchez with Kashner Investment [ph]. Please go ahead.

Unidentified Participant: Hi. How are you? I'm pretty glad to see that we are unwinding our hedge books, especially the swaps. Maybe you can provide more color on what are the free cash flow expected on the next 12 months? How much will be lost due to the new hedges? The figures that I can find online are not updated with the new hedge book?

John Jeffrey: Yes, absolutely. So, unfortunately, we haven't given full guidance yet. You should be able to expect that from us here hopefully in the next 45 days, I think it will be great. I was going to say, when we did close Battrum and Flat Lake there in July, we did guide for 12 months out and we did guide an $80 oil, and that you can see in there. We show net and gross of derivatives at the time. Now, that should improve by around $30 million, given the hedge book that we bought out and given that $80 mark. Yes, I think for the full 12 months, I think you are just going to have to wait for guidance, but that will include the full impact of our up-to-date hedge book at that time.

Unidentified Participant: And you are working with $80 WTI baseline?

John Jeffrey: Sorry, we were working for the July to July, from July ‘24 to July ‘25, that is what we used. But we're seeing some of our peers come out, some at $70, some at $75 for 2025. Some of our peers, I think we're probably prudent to do the same. We're waiting to see, obviously, how this election turned out, how oil responds, and then what the OPEC meeting does in December. I believe it is December 1. So, when we come out, hopefully second week of December, hopefully, I think earlier the numbers were looking to guide at around $75 oil for next year. Again, we're just going to respond to what we're seeing in the market if that's relevant. The big thing for us is, we want our guidance to be similar to our peers. So, if the majority of our peers are coming out at $75, I think we're likely to do the same, as long as the market kind of supports that thesis as well. So, I think we're probably going to be probably around that $75 mark, but again, a couple of big data points left to come out before we can say that for sure.

Unidentified Participant: Thank you. And my last question will be about water flooding. We are seeing water flooding in several of our fields, great results. Can you maybe give us more color about how much of our wells are actually using water flood, and how much could we expand that number to? How much can we maximize that?

John Jeffrey: Yeah, absolutely, and I think what I'll do is I'll pass that back to Justin Kaufman to get into the details for where and how we are water flooding. Justin?

Justin Kaufmann : Yeah, specifically with the acquisition we did in the springtime on the Flat Lake area, we acquired close to 9,000 barrels a day. About half of that is under current flood, and that specific area is where we're going to be turning about 10 producers.

Operator: Sir, you are not audible at this moment.

Unidentified Participant: Hello?

Operator: Mr. Justin Kaufman, you are not audible at this moment. Ladies and gentlemen, please stand by. Ladies and gentlemen, we apologize. We will need to end our question-and-answer session at this point. This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day!