Earnings Transcript for SOIL.V - Q4 Fiscal Year 2023

Kevin Smith: Hello and thank you for joining Saturn Oil's Fourth Quarter 2023 Financial Operations Investor Update. My name is Kevin Smith, Vice President, Corporate Development, and I'll be your moderator for this webcast. We'll start with a presentation from management. And following that, we'll be happy to address any of your questions and take your comments. You can submit your questions through the Q&A button at the bottom of your screen. Joining us today is John Jeffrey, our Chief Executive Officer; Scott Sanborn, Chief Financial Officer; Justin Kaufmann, our Chief Development Officer; and Grant MacKenzie, our Chief Legal Officer. I'll now hand the webcast over to our CEO, John Jeffrey.

John Jeffrey: Excellent. Thanks, Kevin. Good morning, everyone. Can you hear me all right?

Kevin Smith: Yes, John.

John Jeffrey: Perfect. Well, that's excellent. I know last time we had a couple of technical -- technical issues. Well, thanks, everyone, for joining today. Excited to go over a quarter and our full year last year. The fourth quarter of 2024 was a tremendous period for Saturn Oil, where in the first time in the company's history, we had three drill rigs active, developing light oil in each of the company's four core business units across Alberta and Saskatchewan. Oil and gas production averaged over 27,000 barrels a day in Q4, which was an increase of 115% year-over-year. This record level of production contributed to our second consecutive quarter of posting over $100 million of adjusted EBITDA. This is above our forward guidance for 2024, where our targeting EBITDA is between $350 million and $370 million. And we expect Saturn to generate a return on invested capital of over 55%, which when compared to our peer group averages closer to 30. Driving Saturn's outstanding return on continued excellent results from the drill bit is Justin and he is driving our excellent return is a continued success of the drill bit which Justin will detail a little more in a moment. I will highlight Saturn drilled its first two open-hole multilateral Bakken wells through November and December last year, which came online with initial IP30 numbers, 14% above our type curve expectations. These multilateral wells were some of the most economic wells drilled last year. This exciting new drilling technique is opening up additional drilling inventory on lands previously thought economic. So this is a big win for Saturn. We remain committed to rapid debt repayment and allocated $50 million of cash flow from operations in Q4 to principal repayments for total loan repayment of $164 million in 2023. Subsequent to year-end, Saturn has made an additional $50 million of principal repayments already in 2024 for a total of $215 million of debt repayment since the start of last year. And this all aligns with our strategy of rapid debt repayment, while maintaining corporate production levels, and this should continue to result in value creation for our shareholders throughout 2024. In January of this year, Saturn released its year-end reserves, highlighted by more than doubling of its total proof plus probable reserves to 145 million BOE, comprised of 82% oil and liquids. The net present value discounted at 10% of Saturn's PDP or proved developed producing reserves amounted to a value of $1.4 billion, which incorporates year-end net debt Saturn's PDP net asset value is approximately $6.10 per basic share. This strong net asset value gives us comfort that there is considerable value backing every Saturn share, and we look forward to enhancing that value going forward with Saturn's industry-leading return on invested capital. And finally, Saturn continued its commitment to the environmental stewardship with investments in reducing CO2 emissions and decommissioning older wells that have come to the end of their economic life. In 2023, Saturn invested $11 million in reclamation expenditures, funding the abandonment of 114 wells. That amounts to the cleanup of two wells for every one new well that Saturn drilled or participated in last year. Safety and protecting the environment are an important part of our daily operations. And for now, I'll turn it over to Justin Kaufmann, our Chief Development Officer, for more detail on how our capital expenditure program went last year. Justin?

Justin Kaufmann: Thank you, John. As John mentioned, Q4 was a busiest development period in Saturn's history. We drilled 19 wells across each of Saturn's four core areas for $57 million of capital expenditures. In total, for 2023, Saturn drilled 59 gross horizontal wells with 100% success ratio. The development of the Viking light oil resource in West Central Saskatchewan was a highlight of the 2023 program. Saturn contracted a third rig in Q4 to drill an additional four Viking wells, 100% working interest to Saturn, bringing the total 2023 drill count to 19 gross Viking wells. Saturn's 2023 new Viking wells had an average IP30 rate of 98 barrels per day of light oil and strongly outperformed our type curve expectations by over 40%. Saturn has improved its Viking new well productivity year-over-year as we have focused development on our two best-performing areas, Hershel and Plato. In these two key areas, Saturn has effectively expanded our understanding of the boundaries of the light oil resources, particularly in the Plato area where we shot new seismic in 2023 to better understand the structural features of the area. This helped us add dozens of new derisk development locations to our reserve bookings and inventory. Southeast Saskatchewan was a strong area for growth in 2023, where the company increased production by 67% compared to 2022. Saturn continued its successful conventional development in the area with 11 Mississippian and 6 Triassic aged reservoirs wells drilled. These were predominantly in the Frobisher and Spearfish formations, which outperformed our type curve expectations by 17%. Also, a fantastic addition to our Southeast Saskatchewan Capital Time 2023 was the Bakken program, which was Saturn's first development into this prolific light oil horizon. As John mentioned, the 2023 Bakken program yielded outstanding results, exceeding our expectations. In total, Saturn drilled seven stimulated Bakken wells last year and the greater Viewfield area with IP30 rates of 110 barrels per day of light oil. With over 400 wells in our deep inventory of development locations, we expect the Bakken to be a strong contributor to future development programs, including this year, where we expect to drill up to 10 Bakken wells, including two to three open-hole multilateral wells. For the open-hole multilateral wells currently underway, we are now drilling two-mile laterals compared to the one-mile laterals that were drilled last year. We believe the extended laterals will save on drilling costs and enhance the economics of this new drilling technique even further. Saturn's success last year in the Bakken, Spearfish and Frobisher is strong validation of the multi-zone potential in Saturn's core area in Southeast Saskatchewan, where we have a deep inventory of derisk locations. In North Alberta, Saturn drilled a four-well pad in the Kaybob area targeting Montney light oil with 100% working interest. This pad -- this first pad delivered an IP30 rate of just over 1,250 barrels per day in aggregate. The Kaybob wells met our expectation for Montney type curve for this area, and we will look to drill another four-well pad this year. In Central Alberta, Saturn rig released five operated Cardium wells in 2023 that have IP30 results. Again, these results met company expectations and will continue to be a big part of Saturn's development story, where we plan on drilling eight additional wells in 2024. In total, Saturn had a very successful 2023 drilling program, while scaling up development efforts across its four business units. The depth of our continual expanding drilling inventory with over 1,500 identified booked and unbooked locations speaks to the sustainability of our high cash flow and light oil production base. For more details on Saturn's 2024 development plans, please visit satternoil.com, where we have posted our 2024 guidance presentation. I will now pass the webcast over to Scott Sanborn, CFO, for a financial overview of the quarter.

Scott Sanborn: Thanks, Justin. It was a phenomenal year for all of us here at Saturn. As a brief recap, we closed the Ridgeback acquisition effective February 28th for total consideration of $525 million funded through $125 million bought deal equity financing and expansion to our senior term loan and $50 million in share consideration. We increased annual production by over 150% to average approximately 25,000 BOE per day in 2023, continue to deliver on our debt repayment strategy and successfully executed our annual capital plan. As we move into the quarterly and annual results, they continue to highlight the success of our 2023 drilling program with Q4 production volumes averaging approximately 27,000 BOE per day, up from just over 26,000 in Q3. Company realized total petroleum and natural gas sales of $185 million due to Q4 WTI prices averaging $79 per barrel, slightly down from $82 per barrel in the third quarter, offset in part by strengthening US dollar. Despite this, the company realized record quarterly adjusted funds flow due to lower cash costs in each operating expenses, royalties, G&A, interest and realized hedging. On a metric basis, the company achieved back-to-back period EBITDA over $100 million in each Q4 and Q3, contributing to annual EBITDA of over $363 million or 1.3 time and 1.1 times on an annualized basis pro forma Ridgeback acquisition. Record Q4 adjusted funds flow of $80 million or $0.58 per share, up from $76 million or $0.55 per share in Q3, contributing to a total of $278 million for the year or $2.20 per share. We executed on an annual capital program of $131 million to realize free cash flow of $148 million, of which $57 million in CapEx was invested in the fourth quarter to yield Q4 free cash flow of $23 million. On the debt side, we continued with our leverage reduction strategy, repaying a total of $164 million in the year with $51 million repaid in the fourth quarter, resulting in 2023 exit net debt of $460 million, representing 1.4 times total leverage on an annualized Q4 basis, down from 1.5 times in Q3. To end the year, the company had a working capital surplus of $8 million, with cash on hand of over $26 million. As Justin detailed, Q4 capital was $57 million, summarized as $54 million directed toward DSAT and facilities with $3 million direct towards corporate and administrative assets. Subsequent to year-end, the company completed a $50 million equity financing and entered into an agreement with a senior secured lender for up to $55 million in additional liquidity, strictly at the company's option. With that, I'll pass it on to Kevin, and you can relay any questions you may have.

Kevin Smith: Thanks, Scott. All right. We have some questions coming in. The first question is, can you expand on how the two-mile lateral wells in the Bakken will enhance the economics?

Justin Kaufmann: Yes, I can grab that one. Essentially, when you're drilling these multilaterals, you need to sync casing to your intermediate casing point. So there is a lot of steel costs associated with that. But if you can extend the length of these laterals one, two miles as opposed to two, one mile, you're going to save on those steel cost, plus you also save on the fixed cost at surface that have to be paid in perpetuity with production of that well. And you reduce the upfront drilling costs, of course, the one well versus two wells. So all that equates to higher capital efficiency with that two mile over that one mile.

Kevin Smith: Great. Another question. Can you comment on the upcoming debt schedule for 2022 -- 2024, sorry, for repayment? And where is there a step down in principal payments.

John Jeffrey: Yes. I don't know, Scott, if you want to jump in on this?

Scott Sanborn: Yeah, sorry about that, I was just on mute there. Yes. So for 2024, we plan $180 million in debt repayment schedule. The step down changes from April to May, and it changes from $25.3 million down to $15.2 million per month.

Kevin Smith: Great. Question here. Operating costs were down on both the per BOE basis and overall on a gross basis. What's driven this reduction in operating costs? And is it sustainable for 2024?

John Jeffrey: Yes. We have been targeting a reduction in operating costs. What we're starting to see now is the synergies of combining legacy Saturn with legacy Ridgeback. So we're just starting to see more of that come into play. It does help that we're seeing power costs come down across Alberta as well. So there's a mix of kind of internal controls that we have rolling out with synergies between merging these two entities and some macroeconomic things outside of our control such as power costs going down. So I think we're forecasting about $20 per BOE rolling through 2024. We believe that's a goal we can achieve.

Kevin Smith: Next question. How active will you be on OHML Bakken wells in 2024? And when should we expect to see the next set of results?

John Jeffrey: I'll pass it over to you, Justin.

Justin Kaufmann: Yes. We're going to be drilling two or three open hole multilegs this year. We are on -- drilling rig is on one right now, that's that 8-legged 2-miler. And then it's going to be moving over to an 8-legged 1.5-mile well. That will most likely be it. There might be an additional one this year. But you should see -- you should start seeing IP30 rates for those probably around in that May, June sort of time line. Barring the success of those, we do see scaling up of that program potentially as high as 8 to 10 wells in 2025.

Kevin Smith: Okay. A question here from someone that was looking at our guidance presentation online from our website. I see from your guidance presentation, you added options lands in Alberta Montney. Are there any more opportunities to do something similar in the Bakken for Frobisher, where the wells would have lower declines|?

Justin Kaufmann: Yes. There is areas where there is freehold land available. I would say we do have quite a bit of fee land in the Balkan area right now. We are active in Crown land sales, too. If you'll see by public data, we won a 3.5 section block of Crown land that is going to support our open hole multi-legs. So we are continuing to prove up some of the stratigraphy edges of our places in Southeast Saskatchewan and we continue to pick up freehold land. We do have a land budget about $3 million or $4 million this year to help continue to grab land around our core areas.

Kevin Smith: Next question. How many wells do you plan before spring break-up? And where will you be -- where is the focus?

Justin Kaufmann: Yes. So before break-up here, we drilled five conventional wells in Southeast Saskatchewan, three of them being Frobishers, two of them being Spearfish wells. Those wells are complete. They are on production right now. The very first three of one well in Southeast, we do have IP30 rates for it and it far exceeded our expectations. The rig is on that multi-leg that I said that it will be done drilling that around mid-April. Barring weather conditions, we're hoping that we can move it on to that next eight-well pad and continue drilling through break-up. In Alberta, we drilled three additional Cardium gross wells in Q1. They were just completed as of last week. They're being tied in right now, and we're expecting initial production results for those at the end of this month.

Kevin Smith: Next question. Saturn OHML wells are some of the company's most economic wells. How do the decline rates on the OHML wells look compared to other wells? And what is the oil to gas ratio?

Justin Kaufmann: They're almost 100% light oil. So there isn't a lot of gas associated with oil production up there. As far as declines go, it is a very new area. There isn't two years of production on any open hole multileg well in the Bakken up there. Our guidance type curves are based on what we're seeing in the area so far on a 12-month production basis, but those are continually refined. And even as far as the 2-mile 8-legs go, there is less than eight months of data out there. So we are being fairly cautious on how we type for those to make sure we hit our capital efficiencies for those wells. But, yes, those all continue to be refined as we further develop in the area.

Kevin Smith: Thank you. Next question. Considering the repayment plan of the debt and does the company assume that the warrants will be exercised. I must be referring to our SOIL.WT.A exchange rate warrants. And so is that part of the budget to repay debt?

John Jeffrey: Yes, I can take this one. So we don't have those numbers factored in. We would love to see them exercise. I think as we continue to pay down debt, that will create more and more value for our shareholders. As we said since the beginning of last year, we've paid over $215 million of debt. We continue -- as we continue down this path to pay $185 million this year or $184 million, sorry, we are not incorporating the proceeds from those warrants. However, we are quite optimistic that given the results of our drilling program and ongoing continued results and operations that we will see the share appreciation, and we will look for those warrant proceeds. However, we are not budgeting them at this time.

Kevin Smith: A follow-on question. Do you have an estimated WTI price that the company will need to see in order to achieve this debt repayment schedule?

John Jeffrey: Yes. I believe we budgeted that $184 million down to $70 TI. I think right now, if we see sustained 75 to 80, we can actually increase that debt repayment schedule beyond that. But that's what we've kind of stressed as down to between 65% and 75% depends on what happens with FX and EGO.

Kevin Smith: Next question. How much did the cold weather set back January production?

John Jeffrey: Justin, do you have that number available?

Justin Kaufmann: Yes. On a week-to-week basis, if you average it throughout the year, it did reduce our yearly production by close to 50 barrels. It did affect most of our single-well batteries in the Viking, I guess, have the biggest production impact. So we did see a couple of thousand barrels a day drop offline for a very short amount of time, affecting our annual average by about 50 barrels.

Kevin Smith: There's a question here regarding decommissioning expenditures. In 2024, the budget is for $12 million as management expect that this figure will remain around this level in future years.

Justin Kaufmann: Yes. That number should remain fairly constant based on what the regulators require through the provinces of Saskatchewan, Alberta. So we don't see a lot of movement on that in the short-term. Moving forward past probably year four or five, you should see that number start to come down as we complete the decommissioning activities of our suspended wellbores.

Kevin Smith: All right. Thank you. Another question here. Have insiders been buying shares?

John Jeffrey: Yes. Actually, as it was released back in December, there's actually 900,000 block of shares that came available. And this was from -- when we did that of Ridgeback. transaction, they were issued $45 million of shares. And this was basically cleaning up one of the last big blocks there were of that group. So for one, management was excited to buy in and increase our exposure there, but also to take off any perceived overhang of those shares coming available. Now the first half of the remaining shares from the transaction did become free tradable on February 28th. But the bulk of those shares now have been picked up by our biggest shareholders as well as management. So there was about nine of us in total that picked up that block and happy to see management and senior management getting behind the company and increasing the exposure.

Kevin Smith: Great. One more question came in. Currently, the company is focusing on decreasing the debt. Once the debt is decreasing the balance sheet is strengthened by the end of this year, what will Saturn focus on with its excess cash flow, further debt repayment, more drilling or shareholder returns such as dividends and buyback.

John Jeffrey: Yes. We've kind of maintained a bit of a loose strategy that 50% of our cash flow goes towards debt repayment and 50% back towards the bid. And it's kind of our belief that $1 towards debt repayment is indirectly $1 towards the shareholder. So I think what we'd like to do is I'm not sure the split where we're at now. But I think we'd look to maintain some split of that still where we take a portion of those funds give it directly back to the shareholders once the debt is extinguished and give the rest to continue growing the company through the drill bit. So I think you'd see us start to grow a little more organically and give a portion of that cash flow directly back to the shareholders for their benefit.

Kevin Smith: Okay. Well, that's it for questions that have been posted here in this webinar. So I'd like to thank everybody for joining. Saturn Oil has launched a new website. And of course, our guidance presentation has now been posted on there as well as our updated corporate presentation will be updated here shortly as well. So I encourage you all to check that out on saturnoil.com. And again, thank you for joining us today.

John Jeffrey: Thank you, everyone.

End of Q&A: