Kiwetinohk Energy Corp. (KEC) Earnings Call Transcript & Summary

Good morning. My name is Sophie, and I will I'd like to welcome everybody to Kiwetinohk 2024 Fourth Quarter and Year-End Results Conference Call. [Operator Instructions] Mr. Carlson, you may go ahead and begin the conference.

Thank you, Sylvia, and good morning, everyone. Welcome to the Kiwetinohk Energy Investor Call for the fourth quarter of 2024, and thank you for joining us for this update on our annual results. I'm Pat Carlson, Kiwetinohk's CEO. And to start, I'll ask Janet Annesley, our Chief Sustainability Officer to do an indigenous land recognition. Please go ahead, Janet.

Thanks, Pat. Kiwetinohk's conference call today is coming from Calgary, which is part of the traditional territories of the people of Treaty 7, which includes the Blackfoot Confederacy comprised of the Siksika, the Piikani and the Kainai First Nations, the Tsuut’ina Nish First Nation and the Stoney-Nakoda, which includes the Chiniki, Bearspaw and Goodstoney First Nations. Calgary is also home to the Métis Nation or Otipemisiwak, Districts 5 and 6. Kiwetinohk has operations in Alberta across, Treaty 6, 7 and 8, and we recognize the diversity of First Nations and Métis people in all these places that we call home. Back to you, Pat.

Thank you, Janet. I woke up with a horse throat this morning. And so I'll ask Kevin Nielsen to read my script and to conduct a meeting. Kevin?

Thank you, Pat. Joining us today, in addition to Janet are Jakub Brogowski, Chief Financial Officer; Mike Backus, Chief Operating Officer, Upstream; Fareen Sunderji, President, Power Division; Mike Hantzsch, Senior Vice President, Midstream and Market Development and Lisa Wong, Senior Vice President, Business Systems. We would like to use the first part of the call to provide you with a summation regarding our fourth quarter release from yesterday evening. The telephone line will then be opened up to allow participants to ask questions. Before going through the results, I'll remind everyone, the conference call includes forward-looking information and non-GAAP financial measures with the associated risks and disclaimers detailed in our news release and MD&A. The news release, annual information form, financial statements and management's discussion and analysis and all of the company's official disclosures are available on our website and SEDAR+. We are extremely pleased with the team's performance in 2024. In our Upstream division, we executed the largest capital program in our history, growing production by 19% year-over-year, an increase in our total 2P reserves by 10%. The results continue to highlight the quality of our asset, which has key differentiating factors that contribute to the superior performance. Among these differentiators are our Duvernay asset is high pressure, has a high liquid gas ratio and deliver some of the top-performing wells in the Duvernay. We also possess just under 25 years of unbooked drilling inventory on a proved and probable basis to continue our development and grow production in the future. Beyond our Duvernay position, we are continuing to delineate our Simonette Montney acreage, which sits directly above our Duvernay position and is able to take advantage of existing infrastructure. We brought onstream 3 wells in the past 6 months with the results that encourage our team to continue efforts to delineate and demonstrate the productivity of an underdeveloped Simonette Montney resource. We've been able to maintain strong netbacks, which Jakub will elaborate on for 2 main reasons. First, we own and operate our own facilities within our Simonette asset, which allows us to keep our operating costs low. And second, we hold 120 million cubic feet of pipeline capacity on the premium Alliance Pipeline, which recently facilitated the sale of approximately 95% of our natural gas production in Chicago at a premium to Alberta prices during 2024. We're now a couple of months into our 2025 program, and we are excited for the upcoming year. We have reached an exciting inflection point for Kiwetinohk, where we expect to generate free cash flows and repay our debt balances in 2025, while still growing production by 20% from 2024 levels. The company is well positioned to respond to an ever-changing operating environment, including most recently, the introduction of U.S. import tariffs. We continue to believe that the introduction of tariffs on Canadian oil and gas will result in negative impacts to both the Canadian and U.S. economies and increased overall energy costs. In addition, we have also begun to generate momentum in realizing value in our Power division closing the $21 million sale of our Opal Power project in the first quarter of 2025, and we are continuing to seek sale or financing opportunities for our remaining power portfolio in whole or in part. In our discussions with investors over the past year, we have most often been asked these 3 main questions. One, how are you addressing limited liquidity and the trading of your public shares. Two, what are your plans for your major shareholder, ARC Financial? And three, how are you going to handle your Power Division? These are all important questions, and we believe that looking forward with progress in answering these questions will help to unlock value demonstrated by comparable transactions, our reserve value and current cash flow generation. To ensure a thorough evaluation of all potential alternatives, which will support us in answering these questions, we are considering engaging advisers to support this process. Any alternatives pursued as a result of such process could take anywhere from a few quarters to a year or 2 to complete. In the meantime, we intend to continue to profitably grow our upstream business and opportunistically sell or otherwise monetize our power development projects. As we continue to move forward, I will look to provide you with further updates. I would like to thank our shareholders on behalf of the Board and our team for their continued support. I will now ask Jakub to provide some more information from the CFO's perspective.

Thanks, Kevin, and good morning, everybody. We had a strong financial year, meeting or exceeding our guidance targets in all key areas within our control. I'd like to start by highlighting some key financial and operational results compared to our capital guidance. Production averaged 26,875 BOEs per day, coming in slightly above the midpoint of our latest guidance and just 0.5% below the high end of our original 2023 guidance. Strength in new well production supported by royalty incentive programs helped to drive our royalties towards lower end of our target range. Annual operating costs came in at $7.04 per BOE, improving 17% year-over-year and reaching the lowest level since Kiwetinohk acquired its assets. Since going public in 2022, we've reduced these costs by 27%. As Kevin noted, our ownership and operation of our Simonette infrastructure have been key contributors to these efficiencies. Annual transportation costs of $5.44 per BOE were ahead of plan during 2024, with 95% of our natural gas production delivered to the Chicago market through the Alliance Pipeline system. This provided access to premium pressing with the Chicago Citygate Daily Index averaging 2x the AECO 5A pricing seen in Alberta during 2024. Kiwetinohk has consistently been able to realize higher pricing than the Alberta AECO benchmark since we acquired our assets. Our combination of liquids-rich production, owned infrastructure and U.S. egress capacity continue to support a top-tier operating netback. In the fourth quarter, our netback was $31.38 per BOE or $32.18 per BOE with hedging. And with consistent operations and prudent risk management over the past 8 quarters, we've maintained an average adjusted netback of $32.52 per BOE despite commodity price volatility. We've updated our annual guidance sensitivities, factoring in year-to-date pricing, a stronger natural gas forward strip and the potential impact of a 10% U.S. import tariff on our Chicago natural gas sales. Even with our tariff assumption, our forecasted adjusted funds flow from operations have increased and our projected net debt to adjusted funds flow ratio has improved, demonstrating the strength in liquids-rich production, low operating costs and crucial market access for natural gas sales. Turning to capital investments. We executed the largest capital program in Kiwetinohk's history, investing $336.7 million in 2024. This was primarily directed towards high netback Duvernay and Montney production with spending landing within 1% of the midpoint of our annual guidance. As we pursued growth, we've reinvested cash flow and strategically used our credit capacity exiting the year with net debt at 1x trailing cash flow. Entering 2025, we're seeing the benefits of these investments with projected production growth of 21% and expected free cash flow inflection of $80 million at the midpoint of our updated guidance. This represents 12% of our current market capitalization. And when combined with production growth results in a projected total return of 33%. We maintain a solid liquidity position with over $200 million in available borrowing capacity and free cash flow generation expected to support debt reduction. Additionally, we closed the year with approximately $925 million in tax pools, which will help to defer tax payments as we continue to profitably grow. Finally, on valuations and reserves. Our 2P reserves net present value before tax of 10% grew 4% year-over-year to $2.9 billion, significantly exceeding our cumulative investment to date. On a per share basis, our reserve valuations remain compelling. PDP PV-10 before tax, $17.90 per share, on a total proved basis $38.09 per share and on a 2P NPV10 basis before tax, $65.34 per share. Compared to the December 31, 2024 share price of $16.35. To wrap up, we're excited about the quality of our asset base and the significant underlying value in our shares. Thank you for your time today. I'll now turn it over to Mike to discuss our upstream accomplishments.

Well, thanks, Jakub, and good morning, everybody. I'm really pleased to provide you with an update on the Upstream business. So as mentioned previously, we safely executed the largest capital program in the company's history this past year. There's 2 key metrics. I'm very proud of. One is landing toward the upper end of our production guidance, which has also increased during the year and beating the bottom end of our operating cost guidance, which was actually lower twice during the year. Our production in Q4 averaged just over 27,600 BOEs per day, and we exited at over 30,000 BOEs per day, which led to the annual numbers in our release and previously highlighted by Jakub. We've continued to see production ramp up since the start of the fourth quarter. We've got 7 new Duvernay wells and 2 new Montney wells come on stream during that time. I'll highlight a few of the more recent well results. So at the 9-11 pad in Simonette, we have 3 new Duvernay wells that are now producing on average 7.5 million cubic feet a day of gas and associated liquids in addition to 1,600 barrels a day of condensate. We do have a range across these 3 wells as we're conducting some drawdown tests on the wells flowing them back at different choke levels, trying to collect data here, that we can use to continue to optimize and enhance ultimate recoveries. This was a good pad to conduct this test on as all 3 wells are drilled into a new part of the field. More recently at our 14-29 pad, which is also in Simonette, these wells have just recently come online and continue to clean up. I will say that the 2 Duvernay wells are actually averaging 7 million to 10 million cubic feet a day of gas and associated liquids as well as 1,000 barrels per day of condensate each on a per well basis. There's also a Montney on this pad. This is our third Simonette Montney development well, which is also showing promising early signs. Producing at 4 million to 5 million cubic feet a day of gas and associated liquids. In addition to 600 to 800 barrels a day of condensate. Now this is a well that is analogous to our very first Simonette Montney well that we drilled back in September. At 1-27 pad and both of these wells are drilled in the lower horizon. We also released our year-end reserves for 2024. I won't go into a lot of the details on this call, but I'd like to highlight a few of the key takeaways from the report. We grew all reserve categories in 2024, highlighting total 2P reserves growing by 10% even after deducting our annual production. We replaced 128% of our production in the proved developed producing category and over 300% on a 2P basis. We also added a 20-well development wedge into our 2P reserves in the Simonette Montney, which has historically been both underdeveloped and under booked. Now our recent drilling results and commitment to delineating this resource, gave us and our reserve evaluator confidence in starting to recognize this asset more. At our 2024 production levels, we continue to have a very strong 2P reserve life index of 24 years. Our current 2P reserves represent approximately 40% of our total inventory. As we continue to develop our asset, we see additional reserve growth potential here. In 2025 is shaping up to be another busy year for us. Here's a quick rundown of our activity -- current activity and into midyear. And we're currently in the latter stages of drilling operations with 2 rigs. We have a Duvernay and 1 Montney well pad at 1-27 pad, which is actually a reoccupation from mid-last year and is where our first Simonette Montney well was completed. This pad will be finished drilling this month with completion activities planned for midyear. We're also nearly finished in the Tony Creek area on our 9-33 pad, where we have 3 additional Duvernay wells. These wells will be completed in the second quarter and on stream before midyear. Next, we'll move one of our rigs to the Placid Montney area, which we haven't visited for the past while, where we have a 3-well Montney pad ready to go. This activity will take us through the second quarter. In the second half of the year activity, we previously outlined back in our December budget press release and still -- and remains unchanged. We're really excited about consistency and progress over the past couple of years in meeting our targets with this asset. We continue to expand and delineate our high-quality resources, and continue to move toward our goal of 40,000 BOEs per day. We're also looking past this near-term goal to further develop our asset beyond these levels. Thanks a lot for your time today, and have a great day. I'll now turn it back to Kevin.

Thank you, Mike. This concludes our first quarter conference call. I'll now pass it back to Sylvie for any questions. Thank you for joining us for this update.

Your first question will be from Michael Harvey at RBC.

Yes, sure. Just a quick one, I guess, on some of your comments about the hiring of advisers. Just any additional comments you can provide just as it relates to which assets could be divested? I know everything is on the table at this point, but just any thoughts about how you might be thinking through that would be helpful. And then I guess just to add on to that, one of your past priorities was actually acquisitions. So in the past, that would have been gas for power, but obviously, priorities have changed a bit. Maybe just your updated views on acquisitions and if that's just been kind of put on hold for the time being?

Mike, it's Jakub here. Thanks for joining the call. Yes, look, I think there's a lot to unpack in that question, but I think just a few things. When we look at just the growth in the company's production, we've tripled the production since we've come public. Where we're seeing cash flow this year, we're seeing on the high end of our upside sensitivities you're seeing the potential for cash flow of over $400 million. So that's pretty significant. And then as we kind of watch just around our neighborhood and particularly in the transaction environment right beside our assets, we've seen some pretty compelling value paid for assets of similar quality. We think there's a lot of differentiators to our assets. We've talked about the owned infrastructure. We've talked about our Chicago access, our higher netbacks, some of our top-performing wells. We have assignment at Montney sitting on top of our Duvernay assets. So when we look at all those things, we see a great opportunity for upside in our value. And so we're just going to start discussing potentially with some advisers, what's the best way to address that and capture some of that value for our shareholders. So I think, definitely, that could include, as you said, a sale of the whole business, it could include acquisitions, as you said, I think we need to do a thorough review of all of that and see what we uncover through that process.

Next question will be from Josef Schachter at Schachter Energy Research.

Thank you very much. And, Pat I hope you feel better quickly. Congratulations on the good year and the fourth quarter. Couple of areas. You talk about op cost in your guidance, in your presentation of $7.25, $7.75. You were $7.04 last year. What are you thinking is going to put pressure on your op costs in 2025?

Yes. Thanks, Josef, it's Mike here. Yes, we had a great year in 2024. Obviously, we saw some very stable, strong production, which helps that metric, but the team did a great job in managing and in some areas, reducing some of our OpEx, and we continue to learn more and more about this asset. In 2025, we do have budgeted slightly higher OpEx, there's really a couple of structural drivers there. We have a plant expansion in our small Simonette plant, that's planned that's going to add a little bit of cost, but a little bit of downtime. And we also have a fairly major outage in our Placid area with one of our third-party downstream providers that's going to have about a 40-day outage so, and we've got some turnaround costs built into that. So there's a couple of structural differences there. Outside of that, fundamentally, we expect to continue to on an absolute cost basis, see the numbers trend in that kind of low $7 range.

Okay. Good. Second question, you're looking at the total CapEx of $290 million to $315 million in 2025. Have you -- it's still very early in the tariff game from Trump. Is there any 10% or something extra given in that taking into account any things that he does. And where do you see the worst or the most pressured in terms of cost changes, steel, where do you see the compression equipment? Where do you see the pressure to those -- to that CapEx budget?

Yes. Thanks, Joseph. Good question. Everyone's trying to answer that one. I think these days, but we took a really close look at our Upstream business. And I would say, it's probably 3 areas that you would say we have exposure to. We get some of our frac sand from -- well, most of our frac sand from the U.S. We get a lot of our casing out of the U.S. and some miscellaneous chemicals come out of there. I would say the chemical side is pretty immaterial. On the steel casing side of things, we're very well insulated in 2025. Most of our inventories on the ground, plus to be honest, we have options outside of the U.S. with our current suppliers to source from other international locations at the same pricing. So I'm not too worried about that side of it. And then on the sand side, there's a lot of the cost in sand is transportation when you get it kind of moving on trains and trucks. So if you break it down to the actual raw material cost, it's actually a fairly small percentage if we were to say even a 10% or 25% hit from that. So that is one area where we're working with our suppliers. But on a whole, Josef, in a $290 million to $300 million program, it's not really keeping me up at night right now in terms of major pressure.

Okay. Last one for me. You're growing your production and you've got the range of 31% to 34%. And again, commodity prices, other issues tell you which one. But I'm looking at the reserves, and of course, you have a great 2P, 24 years, 1P 12.9, PDP 4.3. What's the trade-off in terms of that PDP number versus growth? Do you want to see a 5 or 6-year or more PDP, which means you don't push down on the gas pedal as much for growth. How do you look at that trade-off? And where do you see the optimal PDP number?

Yes. I think we've been trending pretty close on that kind of 5-year range on PDP. We've got -- we're only about 40% of our total inventory that's booked. And as you're probably well aware, every year. We're -- as we bring new wells into the mix, you're largely looking at conversions. We're quite comfortable with and 5, 15 and 25-year range where we're at right now. We're comfortable with the drilling cadence that we've been delivering that growth of call it, 15% to 20% is been very comfortable in terms of drilling cadence and adding reserves and production to our books. We do have a -- a bit of a -- I will say, a little bit of a limitation in that 40,000 range. We do start to bump up against some of our planned capacity. So once in the next, call it, 18 to 24 months, we hit that level of production, which will be with this year's program and probably one more similar program next year, we'll have some decisions to make on further expansion of the asset base from an infrastructure standpoint. So whether we stay that cadence or speed up a little bit or maybe even slow down is completely within our control. But right now, Josef, I think we're quite comfortable with that pace of activity. Hopefully, that gives you some context to your question.

Next question will be from Michael Spiker at HTM.

Phenomenal year. Congratulations. I just have some questions on the 1-27 well, the Duvernay well that's facing south. So a great comment on the drawdown. I'm curious as to how high you guys can move EURs over pass programs by keeping that condensate in the stream as long as possible. Obviously, there's that competitor pad to the north of 6-23 pad that they've managed pretty well, and those EURs are tracking 0.5 million barrels or more. So I just -- kind of how much upside you see from production management, especially in the rich gas window? And then -- on the new 9-11 pad, the spacing was a little bit tighter, but the results are obviously a lot better than some of the pads to the south. Is that a function of just a richer part of the area, better stimulation. And just kind of how tight do you guys think you can move spacing throughout the Simonette area? You said kind of 320 meters or or even tighter or wider?

Yes. Thanks, Michael. Good questions. Yes, on the drawdown side of question, the jury is always out as to how fast or slow do you draw wells down and does it leave condensate or liquid stock in the reservoir. And like this 9-11 pad was a perfect opportunity, like I mentioned in the call, it's -- it's in the Northeast quadrant -- or sorry, Northwest quadrant of our main Simonette field. So it's kind of accessing a little bit of virgin reservoir that isn't kind of developed. So it's a good chance for us to kind of test that. I can't answer your question as to how much upside there is. We think drawdown strategies play a role but how impactful that is is probably very asset dependent. And that's why we're just doing these -- we're constantly testing all these sorts of things on our wells. So we're hopeful that we can glean some information there's always a trade-off, though, in terms of do you draw down the wells, produce substantial amount of your reserves in the first, say, 3 years, which can have some real economic value or at risk of maybe leaving something back in the reservoir, that's the trade-off we're always trying to play with. So we'll get some information and maybe make some adjustments going forward. In terms of the spacing, our reserve book is kind of based on a roughly 400-meter spacing. We've got anywhere from Ovintiv trials down to under 200-meter spacing. We've got some wells that are over 500 meters. And it really depends on the area as well, like this 9-11 pad, as an example, again, it's back into some fairly fresh reservoir. So we were quite comfortable getting down to about 300-meter spacing in that. That's also going to give us another 3-well occupation before we hit our lease boundary. So sometimes you space wells just based on future development planning. But I would say the 400-meter spacing on average is still a really good number for us. We'll have pads that are slightly less, but we'll have pads that might be in slightly more. And that's one variable. Actually, we're continuing to really optimize. And then you have to factor in parent-child impacts and things like that. So it's a very dynamic design variable that we -- and the technical team are looking at every time we drill a new well or a new pad. So a little bit of variability there, but I think 400 is a good number to use down the middle.

Awesome. And then one follow-up question. Are you guys still thinking or discussing cyclic gas injection? Is that a thing all eyes in the basin, frankly, hear glued on Simonette waiting for that to start. Is that still a possibility?

We've in the past 6 or so months. We've been doing some kind of preliminary technical work trying to understand the opportunity, where best it might have some potential recovery enhancement, whether that's in the north part of our field or more in the core. So we're working with a few different organizations and doing some technical work internally to understand that. We don't have any firm capital or pilot plans in place right now, but we do have a small team that's investigating that.

Next question will be from Amir Arif at ATB.

Just a few quick questions. First, just with the oil prices having come down. I know you still -- you generated a lot of free cash, but just curious on what oil price level you would think about adjusting some of your capital program for '25?

Amir, it's Jakub here. I think that really depends on where gas levels are, right? So now we've seen the strip for gas go to $4.70. We've hedged a lot of our gas for the year. We're probably hedged about 65%, almost 70% on our gas levels at a floor of about USD 3.30 to USD 3.50. So I think from that perspective, we could probably go pretty low on oil if gas prices stick in. So it really depends where both those go. I think as you've seen in terms of the ranges we gave today, on the low side, we gave $60 and $3.50 with a $0.70 FX rate. And at that level, we're still going to be generating about $45 million of free cash flow, Amir. So I think we're pretty defensive probably down to 50% and even lower gas prices. If it went below there, then I think we'd have to have another look. But it looks like we got a bit of cushion here still.

Got it. And you've got good hedges on the oil side, too, I think.

Yes, we do.

And then just moving over to the NGLs. On the reserve side, there was some negative revisions just on the NGL. It's again, not a big part of the revenue, but just curious what -- if you can just share some color in terms of what's happening in terms of NGL yields. Is that drop off over time? Or is it just the initial yields are a little leaner?

Yes. There's a couple of things there, Amir. At the end of last year, we were kind of playing around with our plants a little bit to see if we could change the cuts of some of those yields and we made some assumptions. Some of that didn't materialize. So we weren't getting quite as good an NGL cut out of those plants. So that resulted in just a little bit of an adjustment there. And as we start to move a little bit into the southeast part of our field. We were probably a little bit leaner on a couple of wells than we expected. So again, pretty modest changes as you point out. So not a massive surprise. But yes, small negative on that side. So that -- hopefully, that gives you the context there.

Yes. And I appreciate that color. And then just finally, Jacob, just on that cash flow sensitivity that you updated, and there's no change in production guidance or your line items. You're using the same commodity prices. You've added in the tariff impact. So I was just curious what makes the cash flow sensitivity have higher lows and a little like a higher range?

Yes, it's a good question, Amir. So we did change the ranges a little bit. So what we -- the main purpose of our sensitivities is -- we want to provide you a little bit of guidance that's below and above where the strip is, and we want to make sure that it's meaningful to where we currently see prices. So I think if you look at the oil side, we had $60 to $70. So those stayed the same. But we moved our gas up to $3.50 and to $5. So you'll see a bit of uplift there. Amir for the remainder of the year. The other thing that's factored into that is every time we come out for a quarter, what we'll do is we'll look at our actual realizations to the date of the release. And so what we've actually seen in January and February were very strong months from a production basis from a gas pricing basis. And from an oil basis. And so our netbacks were quite strong. And so you probably would have seen about $25 million of bump up just from the fact that we got those first couple of months in at stronger prices than the sensitivities published at the end of the year. So it's a combination of all those things. It's actuals have been very strong. Production has been strong. We've upped the gas price sensitivity, and we tweaked the FX down by about $0.02 as well. So when we've seen the FX come down, that's a net benefit to us.

Okay. And just so I'm clear, but the FX and the gas price change, that's reflected in both your previous numbers and your current numbers, like you're using the same commodity assumptions and FX assumptions for the previous and the current -- is that right?

So for January and February, it's what we would have actually realized, so what we've got in the actual market. So if you run your -- if you run what actuals you would get for condensate and for gas pricing, we would take that for January. And then for the remainder of the year, we use the price sensitivities and then we add those 2 together. So to date, its historical realizations go forward, it's the sensitivities.

Thank you. And at this time, we have no other questions registered. Please proceed with additional remarks or closing comments.

Okay. Well, thank you, everyone, for joining our call. And if you have further questions, please don't hesitate to contact any of the senior executive or Investor Relations, Kevin Nielsen, who spoke to you earlier. Thank you. Have a good quarter.

Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we ask that you please disconnect your lines.