Whitecap Resources Inc.

Good morning, my name is Sylvie and I will be your conference operator today. At this time, I would like to welcome everyone to Whitecap Resources 2023 Results and Reserves conference call. Note that all lines have been placed on mute to prevent background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star then number one on your telephone keypad. And if you would like to withdraw from your question queue, simply press star then number two. I would now like to turn over to Whitecaps President and CEO, Mr. Grant Fagerheim. Please go ahead, sir.

Thanks, Sylvie, and good morning, everyone, and thank you for joining us this morning. Here on the call with me are five members of our management team, our Senior Vice President and CFO, Tone Kang, our Senior Vice President of Production and Operations, Joel Armstrong, and our Senior Vice President, Business Development and Information Technology, Dave Morin-Bouquet. We also have Joy Wong, our Vice President of the West Division, and Chris Bolin, our Vice President of the East Division, joining us as well. Before we get started today, I would like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory that we set forth in our news release that was issued yesterday afternoon. We are very pleased to report strong operational and financial results for 2023. Our assets in each of our East and West divisions have performed exceptionally well with average production for the year at 156,501 BUE per day, comprised of 66% oil and liquids, 34% natural gas, which equates to 11% growth on a per share basis over 2022. Of the 215 wells drilled, 181 were in our 80% Northern Liquids East Division, and 34 wells in our West Division, which is 60% natural gas, 40% liquids highlighted by our Montney and DuVernay assets. From a financial perspective, we reduced debt by over $500 million since the end of 2022, and upon reaching our second internally set net debt milestone in the second

Please stand by, Mr. Fagerheim, as disconnected.

Yeah, it looks like we're having a bit of technical difficulties here, so I'll just continue on on behalf of Grant. It's Ton Kang here. So from a financial perspective, we reduced debt by over $500 million since the end of 2022, and upon reaching our second internally set net debt milestone in the second half of 2023, we increased our dividend to 73 cents per share annually. We also returned $500 million to shareholders in 2023. Three quarters was returned through our base dividend, and the remainder, or $123 million, was returned through share repurchases. In addition to our focus on strong operational performance, our priorities include discipline debt management. Our net debt is currently just below $1.4 billion, and we have over 1.7 billion of undrawn capacity on our credit facilities. Our leverage is low at 0.7 times debt to EBITDA, and the available capacity of 1.7 billion provides us ample flexibility to manage through commodity price volatility and to capture strategic opportunities should they present themselves in the future. One of those strategic opportunities that we executed on in the fourth quarter was the acquisition of 4,000 barrel per day high net back, 100% light oil Viking production in the Elrose area. This acquisition made a lot of sense for us as it consolidated an active area of development and was completed at very attractive acquisition metrics of 1.7 times cash flow, resulting in strong accretion to both funds flow and free funds flow, as well as a healthy drilling inventory that we plan to capitalize in 2024 and beyond. 2023 was a very important year for operational execution and we're very proud of our results and the contributions made by our employees. We look forward to building off the success in 2024 as we continue to enhance our development strategy across our deep portfolio of opportunities. The continued refinement and optimization of our drilling and completion designs are expected to ultimately result in improving sustainability and profitability of the business. This includes well spacing and development design, increasing both lateral lengths and the number of horizontal legs, and secondary and tertiary recovery pilot projects. Both Joey and Chris will further elaborate on the specific initiatives that their teams are undertaking. We also had a very strong year from a reserves perspective, especially on organic basis, which reflects strong operational execution and a high-quality drilling inventory. Prior to the impact of net dispositions completed in 2023, we had greater than 100% production replacement as well as strong reserves per share growth. On a debt-adjusted basis, we grew PDP reserves by 6%, total proven reserves by 10%, and 2P reserves by 7% per share. Our inventory life ranges from six years on a PDP basis up to 19 years on a 2P basis, and coupled with long-term recycle ratios, averaging 2.6 to 3.3 times, demonstrates our commitment to long-term growth that is both profitable and sustainable into the future. Our 2023 funds flow was approximately $1.8 billion, or $2.94 per share, and after capital expenditures of $950 million, we generated $840 million of free funds flow. This, along with the net dispositions completed in the year, contributed to our ability to reduce debt by $500 million while also returning $500 million to shareholders over the course of 2023. For the fourth quarter, we achieved production just shy of 167,000 BOEs per day and funds flow of $462 million, or $0.76 per diluted share. After capital expenditures of $200 million, we generated $262 million of free funds flow returning 76% of this back to shareholders through our base dividends and buybacks during the quarter. We recorded current income tax expense of $65 million in 2023, and we had $3.6 billion of tax pools at the end of the year to shelter future income. With the closing of the Viking acquisition late in the fourth quarter, we are adjusting our guidance for 2024. Our production guidance has been increased to 165,000 to 170,000 BOEs per day, while we reduced our capital expenditures by approximately $100 million to $900 to $1.1 billion to partially offset the cost of the acquisition. The capital reductions will primarily come from our second half program, and we're now forecasting $600 million of capital in the first half of the year and approximately $400 million in the second half. The midpoint of our updated guidance represents production per share growth of 8%, year over year. However, capital program remains flexible to changing market conditions. Our fund flow forecast at a price deck of $75 USWTI and $2 ECO per GJ gas is $1.6 billion, resulting in $600 million of free fund flow after $1 billion of capital investments. With currently weak natural gas prices, we have been focused on drilling oil-weighted locations In our east division and in our west division, we're drilling liquids-rich portions of our acid base. So the liquids content is currently driving the economics of our 2024 program. For context, although natural gas represents 36% of our production, it only represents 9% of our revenues. For 2024, our price sensitivities are as follows. For every $5 increase in WTI, our funds flow increases by $130 million. For every $0.50 increase in ACO, our fund flow increases by $40 million, and for every penny decrease in the Canadian to U.S. dollar exchange rate, our fund flow increases by $25 billion. As we mentioned previously, our balance sheet is in excellent shape with significant liquidity on our credit facility. While our variable cost of debt has increased, commensurate with the broader interest rate environment, we have cushioned this impact through our private placement notes and interest rate swaps totaling $800 million with a weighted average interest rate of only 3.25%. I'll now pass it off to Joey for remarks on our West Division results.

Thanks, Don. On an asset level, our performance in the West Division in 2023 was very strong, with initial well results above our expectations across multiple areas of unconventional Montney and Duvernay development. Our most recent results at CAQA are so far validating our updated development strategy for the area. The 2-26B three-well pad has achieved IP120 rates that were 26% above our expectations, while test results for our most recent 3-21B three-well pad were also quite encouraging. That pad was tied into permanent facilities earlier this month. These two pads, we have adjusted our inter-well spacing to 250 meters from 200 meters following a detailed review of these lands. from a reservoir, geological, operational, and economic perspective. Our asset base will continue to undergo continuous review with the goal of maximizing economic return characteristics of this extensive inventory set. A significant amount of technical work has also gone into the development of our Muzro asset to the north of CAQA. Design factors such as well spacing, benching, and completion design have all been informed by a similar rigorous technical process that incorporates these localized characteristics on a pad-by-pad basis. Given its higher liquid content, we expect Musro to generate strong economics in the current environment. We spud our first two four-well pads for eight net wells at Musro in the fourth quarter, while a third pad was spud in January of this year. We plan to complete a total of four four-well pads for a total of 16 net wells in Musro in 2024. These pads will flow through our 20,000 BUE a day battery, which is expected to come online in the second quarter. Moving down to the northwest portion of our Resthaven land block, we are seeing strong initial results at Latour, which is encouraging for future Monty development in the latter half of this decade. The initial production results of our two-well pad is approximately 15% above our expectations after 60 days on production, and these results, along with offset results, are giving us more confidence in the liquids profile and the potential deliverability of this asset. We plan to drill an additional two wells at Latour in 2024. These initial well results, along with the success that we've been seeing throughout the refinement of our development strategy, is key to ensuring efficiency and the maximization of profitability across the full field development on this asset. Initial engineering and commercial work for an infrastructure solution at Latour has commenced, and we're looking forward to the completion of the design work on this next stage of development. We plan to grow this asset to approximately 30,000 VUEs a day by the end of 2028, drilling an initial 50 to 60 high-quality Montney wells with a huge land base to grow further and or faster as warranted. Moving on to the Duvernay at K-Bob, our first seven wells that we drilled into the Duvernay are continuing to outperform expectations. The seven wells now all have IP90 rates, with results coming in 24% above our expectations at 1,600 BOEs per day per well, of which 36% is liquids. We plan to drill a three-well pad and a five-well pad in the Duvernay in the first half of 2024. The first three wells will be drilled to a 4,200-meter lateral length, which is over 20% longer than our first seven Duvernay wells. Optimization of our development plan in the Duvernay is ongoing, and increasing lateral length is expected to improve capital efficiency while not sacrificing the total resource recovered over the life of the well. We currently have approximately 200 locations in inventory and plan to spud 13 Duvernay wells in 2024. Lastly, I did want to touch on our water management strategy for 2024 and beyond, given the recent headlines from the Alberta government on the topic. We have been developing a water management strategy as an ongoing initiative in preparation for this year's activity for some time, which included engagement with both industry and regulatory stakeholders. At this time, we feel comfortable, given our existing licenses and established water infrastructure in the area, both owned and third party, that we can effectively mitigate the impact of marginal limitations not only for this year, but by having a long-term strategy in place we will be able to minimize disruptions to our operations on a go-forward basis. We'll now pass it on to Chris for his comments on the East Division.

Thanks, Joey. The East Division had a very successful 2023, and we are looking to follow that up with a strong 2024. Our division is comprised of assets that produce over 80% crude oil and NGLs, and combined with a low decline rate of less than 20%, this division drives a significant portion of free funds flow for the company. Our technical teams have done a fantastic job in 2023, not only from a well results perspective, but also by continuing to push our ceiling higher through extensive work on technical initiatives and deepening our understanding of our assets. We highlighted in yesterday's release a significant portion of East Division well results that exceeded our expectations, with over 80% of well results in 2023 being focused on high net back, short cycle, and quick payout light oil assets, and with oil at approximately $100 per barrel on a Canadian dollar basis means that the profitability of our East Division drilling program is extremely robust. Allocating capital to decline mitigation and inventory enhancement initiatives will continue in 2024, with several recent initiatives being implemented upon success. Increasing reservoir contact through longer laterals, as well as increasing the number of horizontal lakes, has been ongoing for the last few years. Synergistic asset consolidations across our land base over the last few years has also provided the opportunity to drill longer laterals and multiple horizons across a greater portion of our assets, leading to improved capital efficiencies. As an example of strategic capital to enhance our load decline profile, we are very encouraged by the initial response of our CO2 pilot project targeting the Frobisher Formation, which lies beneath the existing Wavern CO2 project targeting the Midale Formation. We drilled two producer wells early in 2023. After drilling three injection wells, we initiated CO2 injection in late 2023. Production response was exceptional with an uplift of over four times the initial oil production rate, peaking at 500 barrels per day between the two producers before being facility restricted. Although in its infancy, this resource has the potential to be meaningful with 20 to 40 million barrels of incremental volumes based on our preliminary internal success case assessments. This is a good example of allocating strategic capital to further enhance low decline initiatives that will likely lead to broader implementation in the future upon success. Out of the $110 million of investments in secondary and tertiary recovery initiatives in 2023, it's worth noting that nearly 60% of this is for drilling producers in water flood areas, such as West Pamlico Cardium or Corrobart and Dodge Land biking, along with producer optimizations. These projects are highly competitive and would be top quartile from a pale perspective while also having the added advantage of reduced declines and enhanced recoveries when compared to our primary drills due to historical and or ongoing pressure support. The remaining 40% involves spending on injector drills and conversions, base maintenance, facilities, as well as CO2 and polymer procurement for tertiary assets such as Weyburn and Southwest Saskatchewan. Our 2024 East Division Drilling Program is well underway And we are currently running 11 rigs to drill 95 gross, 87 net wells in the first quarter. With that, I'll turn it back over to Grant for his closing remarks.

Thanks very much, Chris. And I am back. And I apologize. Hopefully, I don't drop off again. But anyway, thanks very much, Chris. As discussed, our recent well results are performing better than expectations, while technical initiatives undertaken within our respective divisions are exploring ways to further improve sustainability and profitability going forward. As we look out over the next five years, we are targeting organic growth to in excess of 210,000 BW per day by the end of 2028. Growth in our west division, primarily from our unconventional mountain development, will be at an annual rate of 12 to 15%, increasing production from approximately 70,000 BW per day currently to over 110,000 BW per day. In our east division, which is light oil focused and generates significant free cash flow. We plan to increase production organically from 95,000 BW per day currently to approximately 100,000 BW per day over the next five years. We operate our business in a proactive way to effectively develop our assets for increasing profitability and believe that at a measured pace of growth is sustainable and appropriately manages risk over the longer term. At the same time, we also maintain the flexibility and to be reactive to unexpected market events, and will continue to allocate capital to the assets and projects that provide the highest returns. Our current corporate production split of 64% oil and liquids and 36% natural gas will increase towards 40% natural gas weighting at the end of the five years. At that time, we forecast to be producing approximately 500 million cubic feet a day of natural gas. With joining the Rockies LNG Partners Group, We aim to have approximately 20% of our natural gas production exposed to non-North American natural gas prices once the Salismas LNG project off the west coast of British Columbia is operational near the turn of the decade. Our inventory set is very robust with over 6,400 locations in inventory at year-end 2023. This inventory has been modified for some of our updated spacing assumptions, along with further technical analysis across our asset base. While we expect our full location count to always be evolving, we do believe that the recoverable resource at our asset base can support 5% annualized organic growth for each of the next 25-year period of time. As a Canadian energy producer, we are nearing an inflection point with the Trans Mountain Expansion Pipeline nearing completion and reports that the LNG Canada facility will begin commissioning prior to the end of 2024. Both export facilities off Canada's west coast will open new markets for responsibly produced Canadian oil and natural gas, and we are excited to see these projects come to fruition. With that, I will now turn the call over to our operator, Sylvie, for any questions.

Thank you, sir. Ladies and gentlemen, if you would like to ask a question, please press star followed by one on your touch-tone phone. You will then hear a three-tone prompt acknowledging your request. And if you would like to withdraw from the question queue, please press star followed by two. And if you're using a speakerphone, we ask that you please lift the handset before pressing any keys. Please go ahead and press star now if you do have any questions. And your first question will be from Dennis Fung at CIBC World Markets. Please go ahead.

Hi, good morning, and thanks for taking my questions. The first one is just in the press release, and I appreciate the commentary that you've highlighted through the conference call. there's been a lot of focus on applying new technologies and techniques to improve operations, costs, and even well productivity. Can you discuss a little bit more about what we'll call the stage of deployment across your entire asset base, as well as how quickly you think some of the kind of latest developments can be applied, whether it be the longer horizontals, more use of multilateral legs, and even kind of changing up or tweaking the completion design can drive improvements in capital efficiency and maybe the upper bound of five-year tagger growth.

Yeah, Dennis, it's Joey Wong here. I can take that one. So, I mean, our approach to these assets, going back to the acquisition, has been to ensure we're maximizing overall economic returns. So we do that, as we kind of discussed, using a case-by-case design that includes all of the models that we had kind of talked about, whether we're talking geological models, reservoir models, observation of offset results, and, of course, economic considerations. And, of course, the one example is the one that we highlighted in the call, where the two recent three-well paths in Kakwa, those six wells previously would have had eight wells assigned. and it's our belief that through those six wells we'll recover the same overall resource that we would have with the initial eight wells. So that's an example of what we're looking to do with respect to opportunities where we think we can influence that fracked geometry to kind of work with the rock, work with the fluids to the point where we're not unduly giving up any overall reserves and pushing that overall economic return profile upwards. So to go a little bit further in saying that you know, where it has worked in one place, we'll look to see where similar things can work in other places. But again, we have to recognize that with such a wide asset base, it's going to be something that we're going to have to consider in each area as the rock and the fluids interact.

And from a CAGR perspective, over the next five-year period of time here, we're targeting 3% to 8% production per share growth. Using the mid-case right now, 5% growth to get us to that 210,000 VOEs per day, and that's premised on a $75 WTI environment there. So we certainly have the ability to flex our growth rate depending on what the economic returns look like on the capital that we're deploying. In a low commodity and price environment, $50 WTI, we wouldn't be growing at all. We would just be maintaining our production, and if oil is in excess of $75, then we could potentially be growing at the higher end of that 3% to 8% per share growth that we're targeting.

Great. I appreciate that color. My second question here is just on net debt. You continue to make progress on lowering outstanding leverage, as you highlight on the call, achieving $1.3 billion kind of partway through the year. understandably your net debt increased modestly on the back of the Viking acquisition. My question relates towards at Q3, you highlighted the potential to reduce outstanding leverage towards a billion dollars in 2024. Obviously there's a few moving parts here. Was just curious as to how you fundamentally think about aggregate leverage for the company where it's kind of a good level or is lower just always better? And how does that potentially change how you envision returning free cash to shareholders? Thanks.

Yeah, thanks for that, Dennis. I think our balance sheet, as I mentioned, is in excellent shape right now with 0.7 times debt to EBITDA, 1.7 billion of liquidity that's available to us. I think as we think about the business going forward here, you know, commodity prices remain volatile. there's going to be opportunities for us to be able to use our balance sheet to create value on behalf of our shareholders over the next three to five year period of time. And so I think as we continue to allocate 75% back to shareholders, 25% on the balance sheet, we'll continue to build that dry powder. And if there's no opportunities that present themselves, then ultimately we'll have a better balance sheet to be able to run our business here. As we think about 2024, our leverage will be below $1.3 billion. As you mentioned, we took that up a little bit with the acquisition, with the Elrose Viking acquisition. They're consolidating a core area for us. But those are the type of opportunities with a very strong balance sheet that we can capitalize on very quickly, where we're buying assets at 1.7 times cash flow right within our core areas, whether it's synergistic with our lands, and we're the operator. So that's what we're focused on from a balance sheet perspective.

Great. Thank you. I'll turn it back. Appreciate the call. Thank you.

Next question will be from Patrick O'Rourke at ATB Capital Markets. Please go ahead.

Hey guys, good morning and thank you for taking my question here.

Just with respect to the ability to flex capital here, I'm just wondering if you can walk us through some of the levers. I think in the past maybe there's been a bit of shift between east and west and with the east being oily, is there any ability still within the 2024 framework or calendar year to shift some capital between those two units or even if there would be desire to do that? And I just wonder because you did make a comment earlier with respect to sort of 60% of the capital budget being in the first half of the year. And I would assume given breakup type conditions and planning that that's predominantly in the first quarter here.

Yeah, Patrick, thanks for your question on that. I mean, one of the areas one of the strengths of Whitecap, actually, is the ability to be able to swing capital between natural gas and oil. And because we're oil and liquids, we're, you know, 64% that we talk about, what we wanted to do, we positioned the company for the first half of the year, and we'll make the evaluations in the back half of the year if there's a need to shift any other capital in any way, shape, or form. I mean, we see that we've got depressed Natural gas prices here are trading about $1.65 or $1.60 at this particular time and could end up even lower than that through the summer. But the majority of our revenue, 91% to 92%, is still driven through oil and liquids. So it has a small impact on us. We talk about the sensitivities in our presentation. But the biggest areas that is going to drive revenue for our company going forward So we'll continue to monitor this as we move through the year. But we do think that there could be quite a significant delta change in natural gas prices as we move forward from this $1.60 level currently to potentially north of $3 in 2000, where it's trading at today in 2025. So you don't want to switch this really quickly. You want to monitor it and see what we're doing. But in the meantime, we're focused on our long-term assets in the mountain and duvernay that have a high component of liquids.

We'll continue on with those programs. Great. Thank you.

Maybe just to build on a good comment that you made there with respect to recovery and natural gas prices, there's pretty steep contango in the price curve here. From your risk management perspective, what is sort of appetite right now for hedging into that forward contango, or do you see further upside there?

Yeah, it's Ton here, Patrick. Thanks for that question. I think from a risk management perspective, what we're really looking to do is protect our shareholders from the downside perspective. So making sure that we have the cash flows both on the oil and the gas to be able to fund our maintenance capital as well as our dividend down to $50 WTIs. For 2024 here, we're fully funded at that level, even with 18% of our oil hedged and roughly 17% of our gas hedged there. We started to layer on incremental positions. As you've mentioned, it is contangled right now, especially on the gas side. Just recently entered into some positions. We're actually now about 14% in 2025 on the natural gas, and we're about 9% hedged on the crude oil there. Our objective is to edge about 20% of our production, again, to make sure that we can fully fund both our maintenance capital as well as our dividends there. So we're not really taking a speculative view on whether we think commodity prices are too high or too low. It's a very systematic program that allows us to protect our cash flows from an outside perspective.

Okay, thank you very much. Yeah, thanks, Patrick.

Next question will be from Cody Kwong at Stifel. Please go ahead.

Hi, guys. Thanks for taking my call here. I got a question for you on the five-year plan. I see that you've updated the production numbers. How did the capital numbers behind that look with this update here, kind of in terms of quantum and maybe shape of the capital investment profile over the five years?

Yeah, thanks for that question there, Cody. I think as we think about investments in the east and the west division there, as Grant had mentioned, you know, the growth area will certainly come from our west side, taking our production from 70,000 BOEs per day to in excess of 110,000 BOEs per day. And in order to do that, we're spending about 55% of our capital program over the next five-year period of time. When we look at the east division there, we'll be growing that from 95,000 BOEs per day to in excess of 100,000 BOEs per day, and we're spending about 45% of our capital over the next five-year period of time here. What's important to note as we continue to invest in our EOR projects, as Chris has mentioned there, our decline rate being currently in that 24% there, it really doesn't go higher than 24% to 26%. over the next five-year period of time, so the maintenance capital requirements is very low. Our capital efficiencies that we're running at are somewhere in that 21,000 to 22,000 BOEs per day over the next few years here. I think another important aspect of our five-year plan is infrastructure requirements, specifically in the west division there. We're looking at completing the Muswell Battery in the second quarter here, or late Q1. commensurate with the production coming online in Musroe here. So we're going to be focusing from a drilling perspective in the Montney there, in the Musroe and our Latour areas there. From an infrastructure, this year we're spending about $130 million. I would expect on an annual basis net to us from a white cap expenditure somewhere in that $100 to $150 million on an annual basis over the next five-year period of time.

Okay, so is it safe to assume here that the capital kind of ranges that we would expect over the next five years would still be kind of in that same $900 to $1.1 billion range for the next five years? There's no one year that's super lumpy with extra infrastructure or anything like that?

That's correct. Yeah, somewhere in that I would say $900 to $1.2 billion on an annual basis is what we're expecting CapEx to be.

Okay. Awesome. Thank you very much.

Thanks, Cody.

next question will be from jackson austin at jack a capital please go ahead hey guys the first question kind of answered my my question there but i was just a blast anyways so i can see that your assumptions at 75 you got 150 million to the balance sheet and only 50 million to share repurchases with the high case for 250 for the balance sheet and then 315 for sherry purchases And I feel it's really unlikely that we'll hit 90 or 100 unless we get some geopolitical event. And you did 123 million in buybacks in 2023. So I'm just curious, is there a possibility to do any accelerated buybacks at all? Like we're at even a $10 share price or about 7.2% dividend, right? So I was just curious if there was any, or you could even go to 100% ever, but you kind of said no already, given that you just wanted to build up some dry powder there. So thank you.

Yeah, share buybacks. I mean, you know, that is a way for us to add value as well. But, you know, what we want to make sure, as we've talked about here numerous times, is balance sheet is the priority one. So from our perspective, when we talk about returns, 75%, 20%, 25%, 25%, of our funds flow going back to our balance sheet on a continual basis. And we'll look to be opportunistic with our share buybacks as we advance forward. You know, if that is the best way to do it versus growing our business, if that's the best method that's available to us versus growing our business or paying down debt, we want to make sure in this order that leverage, first of all, consistent growing dividend as we grow our business going forward into the future, and then share buybacks. So we'll look at that. And you have to look at it relative to the value of our company on a full-tax basis, you know, where total pool value is approximately $12 a share, so on a full-tax basis. So we have room to buy back shares, but at this particular time, our focus is on continuing to reduce our leverage to prepare our balance sheet for other opportunities as we move forward.

Okay, awesome. Thank you. And you read even at, like, 0.7 times, that's pretty low. So I was wondering, like, and you mentioned that you were looking to keep some dry powder. So I was wondering, I know you can't say directly, but are you looking to do, like, a big M&A deal or just keep doing tuck-ins, like the version one and the last four together?

Yeah, we're not looking at big transactions. What we're doing is... You know, if there's working interest uptakes or consolidation opportunities in and around the assets that we currently have, like we did as we referenced at the Elro Saskatchewan acquisition we did and closed in December, those are the style of acquisitions that we would look at. Again, focused on longer-term sustainability and profitability of our asset base.

Okay, awesome. Thank you so much.

Once again, ladies and gentlemen, if you do have any questions at this time, please press star followed by 1 on your touch-tone phone. And your next question will be from Joseph Schachter at Schachter Energy Research.

Please go ahead. Thank you very much. Good morning, and thanks for taking my question. On the abundant and liability, just trying to get my head around, I'm comparing the 22 AIF and the 2022-2023 AIF. And it looks like you knocked off 417 gross oil wells and 142 gross natural gas wells, total of 559. Are you looking to do similar kinds of numbers each year and effectively have a 10-year game plan to knock that down? Or what is a reasonable assumption on how many wells will be reclaimed each year and how much capex would you consider spending in 20 or going forward? Thanks very much.

Hey Joseph, it's Joel Armstrong. Probably better to answer in terms of amount spent. We're looking at spending $40 million in a culmination of reclamation, facility decommissioning, and well abandonment. In terms of absolute well counts, it would be somewhere in the 200. A lot of the early government-funded programs, we look at our the low-hanging fruit, if you want to call it, and bang off as many wells as we possibly can. But as time goes on, we'll continue to deploy in and around $40 million to help retire those assets.

And is there any government requirements that have changed, requiring you to change in terms of where you abandon, how many wells you abandon, or is this all within your own control?

There are requirements, and we intend to meet all those requirements, correct?

That's it for me. Thank you very much.

Thank you. And at this time, Mr. Fagerheim, we have no further questions registered. Please proceed.

Okay. Thanks very much, Sylvia. And once again, I would like to thank everyone on the call for taking the time and interest to listen to this call today. 2024 is off to a great start, and we look forward to updating you on our progress with the first quarter results at the end of April and throughout the balance of 2024 year. All the best. Take good care. Bye for now.

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 do ask that you please disconnect your lines.