Saturn Oil & Gas Inc.

Hello, and thank you for joining the investor webinar for Saturn Oil's Q1 2024 Financial and Operations Update. My name is Kevin Smith, Vice President of Corporate Development, and I'm your moderator. We'll start with a presentation from management, and following that, we'll address any of your questions or comments. Please feel free to submit your questions and comments through the Q&A button at the bottom of your screen. Joining us today is John Jeffery, Chief Executive Officer, Scott Sanborn, Chief Financial Officer, Justin Kaufman, Chief Development Officer, and Grant McKenzie, Chief Legal Officer. I'll now hand the conference call over to our CEO, John Jeffery.

Hello, and thank you for joining us today live or listening to the replay for our Q1 2024 investor update. We have a lot to cover today. In addition to details of our Q1 results, I expect many on the webcast will be interested in hearing about the highlights of the exciting acquisition we announced last week, and importantly, how we see it enhancing Saturn's capital structure and greatly improving our cost of capital moving forward. But for now, let's start with Q1 results announced yesterday. We began the year with excellent initial production rates from nine wells drilled in southeast Saskatchewan and central Alberta, I'll leave it for Justin to go over some highlights, but I will say these are the best wells Saturn has drilled to date. Q1 also came with some operational challenges, including a cold snap that delivered record-setting low temperatures across Alberta and Saskatchewan, which had temporary impact at some of our production facilities. At our Kindersley Field Office in West Central Saskatchewan, the temperature fell to an all-time record low of minus 44 degrees Celsius in early January, And for our investors south of the border, that was close to minus 50 Fahrenheit. We estimate we are down for about 2,000 barrels a day for approximately 10 days, impacting Saturn's quarterly average production by around 300 barrels a day. I'd like to thank Saturn's field staff who braved the cold to minimize the operational impact and downtime. It was a cold one and hopefully one for the ages. Another challenge to Western Canada oil producers in Q1 was the increased price differential between WTI and Western Canada's benchmark MSB, which averaged US about $8.50 a barrel for the quarter. This unusual price gap came as a result of refinery maintenance in the U.S. matched with some temporary export constraints to the U.S. during the quarter. Comparatively, last year Canada's MSB sold for approximately $3 U.S. less WTI, which is closer to its historical price range. The good news is the Trans Mountain pipeline has been recently expanded and was just filled with product in April, making an immediate impact to Canadian oil differentials. which are now back to normal levels around that $3 U.S. a barrel. The Trans Mountain expansion is shipping three times the previous volumes of oil from Alberta to the Pacific coast. This allows producers to receive Brent oil pricing, which typically sells to a premium to U.S.-based WTI. This new export expansion is a major win for all Western Canadian oil producers, and we expect the positive impacts to be realized in Saturn's Q2 financials and moving forward. But for now, let's turn our attention over to the highlights of the Saskatchewan asset acquisition we announced on May 6, which we expect to close in about a month from now on June 14. It is an absolutely terrific acquisition on many aspects, and one that will have a lasting positive impact for Saturn shareholders for years to come. The essence are made up of about 13,000 barrels a day, 96% liquids, with high net back of over $50 per barrel last year, with low declines of approximately 16%. This production is set to increase Saturn Oil's overall crude oil production by about 60%, and Saturn's overall liquids weighting from about 81% to 86%, further solidifying Saturn as one of the most light oil-weighted producers of its size. The new oil production we are adding is currently unhedged, which will have a very positive impact to Saturn's average sale price and expand our net back per BOE going forward. The new production is an incredible fit with our existing operations in southern Saskatchewan. As you've seen in previous acquisitions, there will be many opportunities to drive material development and operational synergies. The deal is very accretive on a per share basis, over 10% accretive on a net asset value for both PDP and 2P. For the next 12 months after close, we see the deal over 20% accretive on adjusted funds flow per share and 30% accretive on a free funds flow per share. The acquisition has also offered the opportunity for a major recapitalization of our debt structure. This will lead to a significant reduction in overall interest paid, enhanced capital allocation flexibility, and no development capital spending restrictions. And of course, since we were able to acquire these amazing assets at a low valuation, it just makes the whole transaction an incredible step forward for Saturn and its shareholders. But for now, I'm going to hand the webcast over to Justin Kaufman for an operational update. Justin?

Thank you, John. And as John commented, in Q1, 2024, we had one of the best development programs ever, exceeded production expectations in Southeast Saskatchewan and Central Alberta, which included record-setting Cardium wells for the company. These were our first Cardium wells in the Brazil area, which all four of them being completed and brought on to production in late Q1. These wells were all 100% working interest and delivered a total of 2,800 barrels per day, IP 30 between the four of them. To state how impressive this production number is, of the hundreds of wells Saturn has drilled since inception, these wells rank 1, 2, 3, and 4 on an IP30 basis. In doing that, they deliver production numbers that were 30% above forecasted expectations. These wells also came in 8% under budget, which set up a capital efficiency of about $6,000 per barrel. Saturn has over 120 booked and unbooked locations in the region, and we expect to be back drilling in the area within the next 12 months. Now turning to southeast Saskatchewan, Saturn drilled five conventional horizontal wells with 100% working interest in Q1, three Mississippian-age Frobisher and Tilston targets, and two Spearfish targets. As a group, these five wells exceed our expected IP30 type curve by 33%. Our Southeast Saskatchewan conventional well production results continue to get better year over year thanks to the strength of our technical team. Obviously, these results are important as the company has over 400 of these locations identified and they are currently our highest rate of return assets. Saturn also started drilling an open-hole multilateral well in the Bewfield area of Southeast Saskatchewan following our success with two open-hole multi-legs wells in Q4 last year. The new open-hole multi-leg well was drilled with eight horizontal legs up to two miles each. The well was just put onto production over the weekend, and we should have IP30 results in the next month. Q1 certainly produced some very excellent results with the drill bit, and after break, the team is excited to be drilling on the recently announced acquisition assets John described earlier. Given the close proximity of the assets to Saturn's existing operations, Saturn expects to seamlessly and efficiently expand the future capital program to include the Batram and Flatlake assets into the expanded capital development program. Our drilling and completions offsetting these two packages are direct analogs of how we are going to attack the exploitation of these plays. Also, the acquisition production has a very low decline rate of approximately 16%, which will reduce Saturn's corporate decline. and the acquisition comes with an extensive portfolio of high-quality oil-focused development opportunities that include approximately 950 locations. Between the decline rate and identified locations, we believe production levels can be maintained for over 20 years at a drilling pace of only about 20 to 30 wells per year. These are areas our technical teams know very well, and we are excited to get going in developing these new opportunities for years to come. I will now hand it over to Scott for a financial overview of Q1 and of the announced acquisition.

Thanks, Justin. It was an excellent period for Saturn as we progressed through the first quarter despite market challenges. Production held flat from Q4, averaging 26,000 BOE per day, resulting in an NOI of 96 million. The company realized an operating net back of $40 per VOE compared to $47 per VOE in Q4, driven primarily by the winding WTI-MSW differential and cold weather conditions in the first half of the quarter. The company keeping total cash costs flat. Saturn cash flowed $68 million, or 46 cents per share, and invested $40 million in capital expenditures, resulting in free cash flow of $34 million, which was directed towards debt repayments. In total, Saturn repaid $76 million in debt, resulting in net debt quarter end of $386 million, or 1.4 times on an annualized basis. Moving on to M&A, which concluded post-quarter end, we signed an agreement to sell our Swan Hills package in northern Alberta for gross purchase price of $27 million, expected to close by the end of the month, and continue to expand our footprint in Saskatchewan, acquiring 13,000 BW per day, 96% light oil for an anticipated net purchase price of $525 million, approximately 2.1 times NOA transaction metric. Proforma, the company will be approaching 40,000 BOE per day, and on a next 12-month basis, have over 1 billion run rate revenue, approximately 1.2 billion, to yield 650 million of EBITDA net derivatives. Net debt is expected to be 792 million, or 1.2 times next 12 months EBITDA, decreasing substantially over the next 12 months, targeting approximately $600 million, resulting in 0.9 to 1.0 debt EBITDA on a trailing 12-month basis. As John mentioned, the transaction is very accretive across most metrics. The transaction is expected to close on June 14th with an effective date of January 1st, 2024. With that, I'll hand it over to Kevin for any questions.

Thanks, Scott. A number of questions coming in. We'll start off with what is the interest savings from the Goldman Sachs debt and what details can you share?

Yeah, thanks, Kevin. This is Grant McKenzie, Chief Legal Officer speaking. We're really excited about the new debt commitments. We received an offer of commitments from both National Bank and Goldman Sachs to substantially recapitalize our debt structure. Both facilities will significantly reduce our interest costs and offer much greater flexibility. We are going to be able to provide much more wholesome details once final documentation has been entered into on closing, but we expect the new debt facilities will streamline our balance sheet and line up with much more traditional capital stack.

Okay. Question here, the vendor reported a sale of $600 million assets and Saturn reported an acquisition of $525 million acquisition. What is the difference?

Yeah, so John here. So the real difference is, is what is the cash at close? So lots of times you see with these deals that, you know, people have an effective date. In this case, the effective date goes back to January 1, which in that the cash flow from the effective date to closing date are those adjustments. But really the question is, you know, you could look at playing games with the effective date and setting it wherever you like. At the end of the day, it's what are you getting and what are you paying at the day of close. At the day of close, we estimate we'll be paying about $525 million for the 13,000 barrels a day. Alternatively, you know, how they're viewing it on the effective date, Gen 1, you know, we're paying $600 for closer to 14,000 barrels a day. So we just like to look at, you know, a closing date, what does Saturn shareholders receive and what are we paying, and that's $525 for about 13,000. Okay.

During the cold period in January, Saturn reported there was a reduction of 350 BOE a day. Was any of this damage permanent?

I'll pass that over to Justin to answer.

Definitely no permanent damage. We do see a little bit of downtime every year, but no permanent damage. And actually, usually we do see some flush production on the tail end of that. So we will lose zero barrels with that cold weather snow.

Question here regarding CapEx. Previous guidance was 145 million increasing to 200 million annually for the existing assets. What is the explanation in this delta?

Two major reasons for that delta. Once we did announce that Swan Hills divestiture, so we are replacing that 6 to 700 barrels lost in this development case. Also, our Q1 2025, we are going to be spending more than we did in 2024. 2024, there was some restraints on that. 2025, we are going to see some increased biking development activity to help maintain that safe production profile. So those would be the two main reasons.

How much more flexibility does the new debt structure provide for capital spending and overall operations?

Yeah, I think the big one there is it really just removes all limitations. So, effectively, in the past, you know, we've had to seek approval for capital and for other opportunities like that. We don't have any such restrictions with this debt. So it's really good. of market conditions a little quicker. But if we see a rally in oil, then we can react sooner and bring more production online. Yeah, it really just puts the power back into the company's hands.

Yeah, and I'll just add on top of that, John, the window for drilling in the wintertime is obviously pretty short in Canada. It's generally January, February, and then halfway through March. We have seen delays to our Q1 program in the last two years with our previous vendor. So this will give us added stability in knowing what our production profile will be coming out of our Q1 year moving forward.

Another question on operations. How will capital be allocated between the new and old assets going forward? What is the priority drilling targets of the new assets?

The production or the capital profile in the next year ahead will be close to about a 75%, 25% split. In the Flat Lake area we're going to be looking at some very exciting pre-pressurized Balkans. They are probably the most exciting development well in southeast Saskatchewan right now with having some of the highest or the most capital efficient wells we can drill. So we'll be drilling those and along with some Torquay wells. So those will be the majority of development in the Flat Lake area. And then moving into the Batram acquisition, we'll be drilling multiple Shondon wells this year, up to upwards of four. And then next year, some Success and Roseway wells on top of that.

A follow-on question to that. How different is this acquired asset base to Saturn's existing operations in terms of development and drilling?

Those Balkan wells are essentially exactly the same as our view field Balkan wells. They do drill theirs a little bit different. We run a surface casing and then a production string. In the south, the previous owner was running an intermediate casing string in between. So we do think that there's some efficiencies how Saturn engineers and drills these wells we can bring to the development of these assets. But there is essentially nothing new here. And even looking at the shogun wells in the bathroom that we will be drilling, very similar to our biking as for the production string fracking, the types of sleeves they use, sleeves per mile. So very essentially analogs to how we've been developing the offsetting areas.

Post quarter, Saturn sold its Deer Mountain assets. Are there any other non-core assets in the portfolio?

Yeah. John, here you go. I don't think so. You know, I think we have our three, you know, larger, more core areas, which would be the Viking, Southeast Saskatchewan, and the Cardium. Fox Creek would be one of the smaller plays but we have great inventory there Justin and his team have been drilling phenomenal wells with some of the highest rates returning the company so although a lot of people can see that and think yeah it is one of the smaller packages we do have a lot of running left there and really great returns coming out of that field so for us I think we've kind of got to the size and the core areas that align with our technical team and our plans moving forward

Question, can you explain the fit of the new assets with existing assets, and are there any operational synergies and cost savings expected once the deal closes?

Yeah, so we're excited to update our presentation online. Once we're able to do that, you can see how well the assets fit together. Both of them are a contiguous two asset blocks we already have, one in the southeast and one in the Viking region. as you've seen us do with the expansion from Oxbow to Ridgeback in the southeast. We experienced many synergies there, both operationally and capital-wise. Same with the Viking. When we originally started in Kindersley, did that Viking deal there in 22, expanded into Herschel and Plato. We've seen a lot of synergies come with that deal. We expect that same relative performance when tacking these onto it.

It was mentioned that the new production comes on unhedged. What is the hedging expectations or strategy going forward post-close?

Yeah, I think what we're going to plan to do there is we're actually looking at a few different options. So this production will come on unhedged. Our plan is to run with a little lighter of a hedge book than we traditionally have. about an 18-month rolling hedge. 12 to 18 months really depends on what it looks like, rolling hedge profile. And really, that's given a lot of flexibility with the new debt that we have in place. So, we don't need to carry burdens on three, three and a half-year hedges with that backwardation. So, it's really going to take a lot of burden off cash flow and EBITDA once we can alleviate those longer-term hedges.

Pro forma closing, how much of go-forward oil production is hedged currently?

So what we'll have, we'll have about 75% in year one for the first 12 months following, 50% in year two, and 25% year three. And that's approximately what is going to be at close. But, again, I think what you're going to see moving forward, more of a hedging strategy that focuses on that 12 to 18 months time horizon.

For 2025 and beyond, what does management see maintenance capex being per annum?

Essentially on a state flat case, we're looking at close to $300 million.

Well, I think we've addressed all the questions here from the Q&A. So why not hand it back to John, and you can just give a wrap-up of our thoughts going forward. And thank you all for attending.

Yeah, thank you, everyone, very much. This is a very exciting point with us. We're very excited to get this deal closed and announced. A couple of things that we hope to address upon closing is to give the street a more fulsome breakdown of this fantastic debt deal that we have in place. There's a lot of questions around shareholder returns, dividends, buybacks. What is the time horizon for that? Hopefully, we'll be in a position to give a lot more clarity and guidance to that here on June 14th when we close that deal. You know, I will say that is something that we hear a lot from investors, and that's hopefully something that will get addressed here in the next month when we get this deal over the line. But for now, it was a great quarter. You know, Scott and his team definitely delivered. Justin and his team did an excellent job on beating tight curves again. And I think that Q2 of 24 is going to be even more exciting. Stand by for more information on that, and we're really excited for June 14th to get this closed and to get more information back to our stakeholders' hands. Either way, thank you, everyone, for joining. We appreciate your time today.