MEG Energy (OTC:MEGEF) reported positive Q3 2023 operating and financial results, largely fueled by robust oil prices. The company's financial performance was enhanced by WTI prices averaging $82 per barrel and a WCS discount to WTI averaging $13 per barrel during the quarter. MEG's market access and optimization activities garnered a weighted average premium of C$0.69 per barrel on its realized AWB price. The company used its free cash flow for debt reduction and share buybacks, aiming to reach a net debt target of US$600 million by mid next year.
Key takeaways from the earnings call include:
- MEG Energy plans to continue repurchasing its 2027 notes while retaining the outstanding 2029 notes, which offer liquidity without immediate maturities.
- The company anticipates holding approximately 160,000 barrels of line fill for TMX, classifying it as long-term assets.
- MEG Energy aims to expand into Asian markets like India and China, reducing reliance on the U.S. Gulf Coast market.
- The company is considering investing in a carbon capture facility between 2026 and 2029, provided fiscal and regulatory certainty.
- MEG's Surmont asset, while valuable, is not a priority for development at this time.
- The company expects power prices to normalize in the future after a period of high power prices and low gas prices.
- The company plans to allocate a portion of next year's CapEx to growth projects, with a third potentially allocated in the first year.
- MEG Energy anticipates more cash for buybacks in Q4, depending on oil prices and working capital requirements.
In terms of debt and stock buybacks, MEG Energy may prioritize debt buybacks in the near term, but aims to maintain a 50/50 ratio over time. The company expects the WCS differential to be influenced by factors like line fill from TMX and storage capacity, with potential for less volatility and a flatter differential in the future.
The company also discussed the ongoing Pathways project, which involves a proposed carbon capture and storage project. The project currently involves indigenous consultation, engineering, and fiscal negotiations with the government, with an update expected in the coming months.
Lastly, the company predicts lower product movement in the future and expects Q2 and Q3 next year to be around C$15 and under C$13, respectively. A budget update is planned for release in November.
InvestingPro Insights
MEG Energy's financial performance has been underpinned by robust oil prices and a strategic focus on reducing net debt. These efforts are reflected in the company's high earnings quality, with free cash flow exceeding net income, a key InvestingPro Tip. The company's financial strength is further highlighted by the fact that its liquid assets exceed short-term obligations.
InvestingPro's real-time data supports MEG Energy's positive trajectory. The company's market cap stands at 0.87M USD, indicating a solid market presence. The P/E ratio is 12.45, suggesting that investors are willing to pay a relatively high price for the company's earnings. Additionally, the revenue for the last twelve months as of Q2 2023 is a substantial 4368.44M USD.
It is worth noting, however, that the company's revenue growth has been slowing down recently, another InvestingPro Tip. Investors should keep a close eye on the company's future earnings calls and financial reports to gauge whether this trend continues.
For more insights, users can access a wealth of additional InvestingPro Tips and real-time data metrics on the InvestingPro platform.
Full transcript - MEGEF Q3 2023:
Operator: Good morning. My name is Ludy, and I'll be your conference operator today. At this time, I would like to welcome everyone to the MEG Energy's 2023 Q3 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. I would now like to turn the conference over to your speaker today, Mr. Derek Evans, President and CEO of MEG Energy. You may begin your conference.
Derek Evans: Thank you, Ludy. Good morning, everyone, and thank you for joining us to review MEG Energy's 2023 Q3 operating and financial results. With me on the call this morning are Ryan Kubik, our Chief Financial Officer; Darlene Gates, our Chief Operating Officer; and Lyle Yuzdepski, our General Counsel and Corporate Secretary. I'd like to remind our listeners that this call contains forward-looking information. Please refer to the advisories in our disclosure documents filed on SEDAR and on our website. I'll keep my remarks brief today and refer listeners to yesterday's press release for more detail. Our top priority at MEG is our focus on health, safety and the environment that ensures nobody gets hurt, eliminate serious incidents and delivers operational excellence. I'm extremely proud of the safety, operating and financial performance delivered by our team. Their focus on plant reliability, steam utilization, project execution and ongoing well optimization have all contributed to a strong operational quarter. Before I turn the call over to Darlene and Ryan to share details of our results, I would like to briefly touch on the business highlights. MEG's financial performance continues to benefit from strong oil prices, which reflects favorable supply and demand fundamentals for both WTI and WCS heavy oil differentials. WTI prices averaged US$82 a barrel in the third quarter, supported by increasing global oil demand and coordinated OPEC+ production cuts and supply management. The WCS discount to WTI in Edmonton averaged US$13 per barrel during the quarter, driven by effectively 0 apportionment on the Enbridge (NYSE:ENB) system, strong U.S. Gulf Coast exports as a result of rising heavy crude capacity in Asia and tight global heavy crude markets as a result of OPEC+ reducing supply. That WCS differential is a key indicator of pricing for our product in Edmonton, but it's important to remember that we sold 73% of our blend volumes in the third quarter into the U.S. Gulf Coast. Heavy oil in that market has been even stronger allowing us to receive a premium over what is achievable in Edmonton. Our market access and market optimization activities in the third quarter generated a weighted average premium of C$0.69 per barrel on our realized AWB price over the Edmonton AWB benchmark. After deducting diluent transportation cost to get our product to market, our bitumen realization was C$84.75 per barrel at our plant gate in Q3. WCS prices have more recently widened, reflecting refinery turnarounds, higher Western Canadian Sedimentary Basin production, seasonal heavy oil blending requirements as well as perceived concerns about Alberta storage capacity and TMX timing. TMX pipeline to Canada's West Coast is on track for start-up late in the first quarter. Line fill of 4.5 million barrels should positively impact the WCS differentials in Q1 2024. With 20,000 barrels per day of committed capacity on TMX, MEG will have over 80% of its production with access to tidewater. Near-term fundamentals remain strong as we head into 2024. The industry will also be positioned with excess takeaway capacity for the first time in many years, and that should narrow and reduce the volatility of WCS heavy oil differentials. We anticipate the current wide WCS differentials will narrow slightly as we head into the end of the year and will remain elevated until TMX moves into operation at the end of Q1. Q2 and Q3 or Q2 and Q3 2024 differentials should look similar to 2023 with Q4 2024 only marginally higher than Q2 and Q3. Our financial results reflect strong operating performance and enable our commitment to debt reduction and share buybacks. Since April 2022, we've repurchased US$853 million of senior notes and C$668 million or about 33 million shares at a weighted average price of C$20.16 per share. Those share buybacks represent approximately 10% of our 2021 outstanding share count. Free cash flow remains allocated at 50% to debt reduction and 50% to share buybacks, but that will ramp up to 100% shareholder returns next year when we reach our US$600 million net debt target. Corporation published its first – or excuse me its third ESG report in September 2023, which discusses its foundational commitments of business model resilience and governance and the corporation's priorities ESG topics: health and safety, climate change and greenhouse gas emissions, water management, energy security, energy affordability and indigenous relations. I will now ask Darlene Gates, our COO, to speak to our operating results and ask Ryan Kubik, our CFO, to talk to our financial results. Before I open the call to questions, I'll provide an update on the Pathways Alliance efforts this quarter. Darlene, over to you.
Darlene Gates: Thank you, Derek, and good morning, everyone. In the third quarter, as Derek mentioned, we delivered strong safety, health and environmental performance with no lost time injuries and no recordable spills. Production of about 104,000 barrels per day in the third quarter was delivered at a top-tier steam to oil ratio of 2.28, reflecting the successful completion of our short-cycle infill and redevelopment programs and a continued emphasis on steam allocation to the highest quality resource. When compared to the same quarter last year, this represents a 2% production increase and a 5% reduction in steam to oil ratio. These results were achieved while successfully completing our planned facility and field infrastructure projects, which will enable us to distribute a high-pressure steam to future well pads. Operating expenses net of power revenue averaged C$5.11 per barrel in the third quarter, primarily reflecting higher production rates, planned maintenance activities and inflationary pressures on services, chemicals and staff costs. Power revenue exceeded MEG operating costs in the quarter, generating a C$0.04 per barrel net recovery, which continues to demonstrate the value of our cogeneration facilities. As we head into the fourth quarter, lower facility and maintenance activity levels and increased production rates are projected to drive our non-energy operating expenses back within our full year guidance. Our outlook for second half production continues to be approximately 105,000 barrels per day and have us exiting the year near our 110,000 barrel per day facility capacity. In October, we also achieved first production from our newest well pad, which we will continue to ramp up throughout the fourth quarter. I'd like to take this opportunity to thank our teams for this quarter's operational performance and confident they have positioned MEG for a strong finish to the year. With that, I'll turn it over to Ryan to provide the Q3 financial update. Ryan?
Ryan Kubik: Thanks, Darlene. MEG generated adjusted funds flow of C$492 million in the third quarter of 2023, bringing our year-to-date total to just over C$1 billion. Q3 cash operating netback was C$58.64 per barrel, reflecting strong oil prices, lower diluent costs and the first full quarter of higher post-payout Crown royalties. After funding C$83 million of capital expenditures, we generated C$409 million of free cash flow in the quarter, which was used for US$68 million of debt reduction and to repurchase C$58 million or 2.3 million shares at an average price of C$25.40 per share. In the first nine months of the year, MEG generated C$699 million of free cash flow. That free cash flow allowed us to purchase C$227 million or 10.3 million MEG shares at an average price of C$22.07 per share. In addition, we reduced debt by a further US$194 million. At September 30, our net debt declined to US$885 million. And at current oil prices, we forecast reaching our US$600 million net debt target around mid next year. As we head into the last quarter of the year, we expect to achieve the low end of our 100,000 to 105,000 per barrel – 1,000 barrel per day production guidance. Under that production forecast, non-energy operating costs are trending to the top end of our C$4.75 to C$5.05 per barrel guidance range, and G&A will also trend to the top end of our C$1.70 to C$1.90 per barrel range. With continuing strong production in oil prices, MEG is well positioned to execute its strategy as we head into 2024. Guidance for 2024 is scheduled for release on November 27. Thanks. And with that, I'll hand it back to Derek.
Derek Evans: Thanks, Ryan. I'd now like to share a brief update on Pathways Alliance. MEG, along with its Pathways Alliance peers continue progressing pre-work on the proposed foundational carbon capture and storage project, which will transport CO2 via pipeline for multiple oil sands facilities to be stored safely and permanently in the Cold Lake region of Alberta. Significant engineering force-based evaluation and environmental field work is enabling more detailed discussions with indigenous groups, landowners and local communities about the proposed project. Following early engagement over the last two years, formal consultation with 25 indigenous groups along the proposed CO2 transportation and storage network corridor is underway. We remain encouraged by the work and collaboration with both the federal and Alberta governments to get the necessary agreements in place to advance this ambitious and important project. I'd be remiss if I did not remember and acknowledge with great sadness Ian Bruce, MEG's Chair, who passed away tragically at his cottage in Ontario in October. Ian was passionate about our industry and brought a wealth of experience and wisdom to MEG. He was a tremendous supporter of MEG and our management team and will be greatly missed by all of us at MEG and all who knew him. On behalf of our Board of Directors, management team and employees, I extend our deepest sympathies to Ian's wife, Darlene, his family and many friends. As I bring my remarks to a close, I once again want to extend my thanks to our team for their commitment and perseverance, proud of what we have been able to accomplish and confident in our future and our commitment to sustainable, innovative and responsible energy development. On behalf of MEG's Board of Directors and our management team, I want to thank you for your continued support. With that, I'll turn the call back over to Ludy, to begin the Q&A.
Operator: [Operator Instructions] Your first question comes from the line of Dennis Fong from CIBC World Markets. Your line is open.
Dennis Fong: Hi, good morning and thanks for taking my questions. The first one just around capital structure. You've obviously been very focused around repurchasing the 2027 notes. Just wondering and especially focusing also on the US$600 million net debt floor here. How are you thinking about your exposure to term notes and kind of longer-term debt? I know the next kind of tranche after the 2027 is quite far out.
Derek Evans: Yes, Dennis, thanks. I'm going to ask Ryan to talk to that.
Ryan Kubik: Hi, Dennis. You should think that we're just going to continue buying back those 2027 notes, take that to 0. At that point in time, we do have the 2029 outstanding US$600 million. That's our debt target. Those are at an attractive rate relative to where we could finance today so we're going to keep those outstanding. And that will provide us significant liquidity, obviously, going forward without any near-term maturities.
Dennis Fong: Great, thanks. And then my follow-up here is just around, I guess, inventory and sales levels. You guys built up inventory through the quarter. I surmise it's to some degree around or what's potentially in anticipation around line fill for TMX. Can you speak to that a little bit and just kind of some of your plans with the relatively elevated inventory levels that you currently have that may or may not be at Hardisty and maybe in other locations like most of the coast?
Ryan Kubik: Yes. I mean we did – inventory will move around, Dennis, and we did have a couple of hundred million billed in working capital at the end of September, I guess, versus the end of June. That was due to a couple of things. We did see oil prices rally, so receivables rallied into the end of the quarter. On the inventory side, you can see movements around various factors, whether we're building a cargo, for example, that might ship off the coast, which was the case at the end of September, whether we're buying non-proprietary volumes to manage our pipeline space and add some optimization activities through our marketing activities, et cetera. So you will see movements up and down in that inventory level. With respect to TMX, we're expecting we'll be holding about 160,000 barrels a day – or 160,000 barrels of line fill. That will be long term. It will be classified as long-term assets, I guess, in our financial statements and won't be classified as inventory for working capital.
Dennis Fong: Great. Thanks. And then if you may permit me one last question here. I understand that you obviously have a lot of experience with respect to marketing, some of your production, not just within North America, but even potentially globally. How do you view that as being a potential advantage when TMX eventually comes online in terms of finding buyers for your crude and obviously, I guess, a different means of accessing that market. Thanks.
Derek Evans: Yes, Dennis, it's Derek. I'll take that one. A big part of our marketing strategy is to ensure that we don't move all of our crude into the U.S. Gulf Coast and overwhelm that market and create a bigger differential. Just instead of moving the – instead of having a differential egress related differential in Edmonton, we've now got an oversupply in the U.S. Gulf Coast. So we spent a fair amount of time working to develop Asian markets, both in India and in China. I think we have a very good idea of people that like the quality of crude that we have. And this was a big driver behind our tankage and dock space in the U.S. Gulf Coast. As we move to Burnaby, at this juncture, we think Burnaby has got basically two markets: the West Coast of the United States, that California market and fundamentally China. We don't think transportation rates are going to – our netbacks are going to be sufficient to access India. But our understanding of those markets, our understanding of buyers in those markets, our historic ability to have shipped them samples of our product, so that they can determine whether they would want to get in a queue to buy some of that is all very, very important not only to finding a market, but helping us be less reliant on U.S. Gulf Coast operators or refinery operators to give us a fair price for our product.
Dennis Fong: Great. I appreciate that color and context. I will turn it back. Thanks.
Derek Evans: Thanks, Dennis.
Operator: Your next question comes from the line of Greg Pardy from RBC Capital Markets. Please proceed with your question.
Greg Pardy: Yes. Hi. Thanks. Good morning. Thanks for the rundown guys. Derek, I wanted to come back to Pathways. So let's just say in a hypothetical world that the incentives are inclusive of operating costs like you've got. Pathways has got adequate incentives in place, let's just say, by the end of this year and the trunk lines in place for 2029. What's the plan then for MEG? I'm just trying to think in broad strokes, what are the series of steps that you're going to take in terms of decarbonization.
Derek Evans: Great question, Greg. And a little more forward-looking, I guess, I appreciate this because we're not going to talk about when the pipeline is going to be, and let's just assume that all of that has taken place. What that means for MEG is in 2026, 2027, 2028 and 2029, in those four years, we would probably spend somewhere in the neighborhood of a net a C$50 million to C$75 million of capital building our first carbon capture facility at site. So, that would be a facility that would capture a net capture of somewhere between 0.63 and 0.73 megatons a year of carbon. So, once we've got sort of the fiscal certainty and the regulatory certainty, which would be associated with having the pipe in place and up and running by 2029, we will then start to push forward past our feed type of work to an FID decision which have capital being spent in that time frame of 2026 to 2029.
Greg Pardy: Okay, [indiscernible] because I was going to ask you about the capital. So that's super helpful. And then maybe kind of related because it sounds like you'll be doing – probably going with post-combustion capture. Where does eMVAPEX fit into everything, or is that something that might be several years away?
Derek Evans: I think eMVAPEX, so just for other people on the call, eMVAPEX is a solvent process that was developed at MEG and helps us reduce our steam oil ratio significantly. It replaces steam with solvent effectively. So, very important if you are trying to reduce not only your steam oil ratio, but also to keep down the amount of carbon that you have to capture. We have spent an extensive amount of time working with eMVAPEX. We think it's a technology that in a new greenfield development is something that we would look at very seriously. Or if we decided to move significant ways away from our Central Processing Facility, and we were going to create a brownfield facility that was connected back to our Central Processing Facility, we would look at it there. But at this point in time, there is a number of commercial aspects that we don't have in place to conflate that, that biggest one, which would be really the solvent that we would need, and a long-term agreement and pipeline transportation agreement, both for the supply and the transportation of that product. And just to be very clear, we thought about those. We've costed those out at this point in time, the brownfield work that we continue to do inside of the facility is much more economic and significantly lower cost on a dollar per flown BOE than eMVAPEX would be at this point in time.
Greg Pardy: Okay, terrific, thanks very much.
Derek Evans: Thanks, Greg.
Operator: Your next question comes from the line of Menno Hulshof from TD Securities. Your line is open.
Menno Hulshof: Thanks. And good morning everyone. I'll start with a question on Surmont. Given Conoco's relatively recent decision to exercise its ROFR on Total's working interest on its Surmont project right next door, can you just give us a refresh on the status of your Surmont asset and the various options or scenarios longer term?
Derek Evans: Yes good morning, Menno. And thanks for the question. Surmont, it is a fabulous asset. I would say it's as good, if not better, than what we are currently developing at Christina Lake. The reason it hasn't been developed is because it's substantially further away. At one point in time a number of years ago, we had a – we had worked a license for the facility through the Alberta Energy Regulator. We no longer – we let that license go because as we thought about it, it's going to be at least ten years before we get there with the low-hanging fruit that we have at Christina Lake. And really, I think, the challenge for us is not to go out there and build another once-through steam generator type of facility. The challenge will be is this an opportunity for us to put solvents to work, warm solvents to work and to bring a different exploitation strategy to this reservoir. So, nothing in the medium term is going to be developed, and that's primarily because we still have a massive amount of running room going from, I would say, 110,000 all the way up to 210,000. There's 100,000 barrels of incremental capacity that we can develop at Christina Lake, which has got our full and undivided attention at the current time.
Menno Hulshof: Thanks for that Derek. And then moving on to buybacks, it looks like activity in the quarter was a bit light at $58 million, roughly 14% of Q3 free cash flow. Why was that? And does it imply an uptick in buyback activity in Q4 to get you closer to your 50% annual target?
Ryan Kubik: Hi, Menno. I guess, a couple of reasons for that. We already talked about working capital, we did see a build in working capital requirements in the quarter and so that meant we didn't have the cash available to actually buy back the stock. When we look at stock versus the debt buybacks, the stock market is actually more liquid, I guess, than the debt buyback market. So, we're a little bit more opportunistic on the debt side. If we see opportunities to buy different pieces, those may be chunkier. So we may buy back a little bit more debt than we actually buy back stock in the period. But over time, we do expect that we're going to do exactly what we said we would do fifty-fifty debt shares as we kind of move toward our net debt target. And you can – depending on where oil prices go, et cetera, you will see those working capital requirements potentially reduce and the cash available for both share and debt buybacks in the fourth quarter.
Menno Hulshof: Perfect, thanks Ryan. I will turn it back.
Ryan Kubik: Thanks, Menno.
Operator: Your next question comes from the line of John Royall from JPMorgan. Your line is open.
John Royall: Hi, good morning. Thanks for taking my question. So, you mentioned energy OpEx net of power revenue was actually negative this quarter. And I have noticed that net number has trended down a bit this year from an average of maybe C$2 to C$3 per barrel over the few years before that. Is there anything structural there with the relationship between energy OpEx and power revenue, or is it maybe just kind of a Goldilocks scenario of the relationship between gas price and power price, and do you expect it to normalize?
Derek Evans: John, it's Derek. I am not sure which one of the Goldilocks scenarios we should be going is too hot, just right or too cold. We do have a unique situation on the go. I think we've got very high power prices in the province and very low gas prices which has driven that. As we look forward into next year, we see those power prices or we're forecasting that they're going to normalize down into that C$90 a megawatt. So I think you shouldn't believe that this is a trend that is going to continue. We're very pleased with what we've been able to achieve or receive, I guess, in terms of that combination over the last couple of quarters. But it will, I think, revert to historic norms as we drive forward here.
John Royall: Got it, makes sense. And then I know you will come out with the formal budget later this month, but just thinking about next year's CapEx and am I thinking about it correctly, at least directionally, if I think about higher than 2023 levels of the ramp in the second half after you achieve your net debt floor and start to invest in the next phase of growth. Is that kind of directionally the right way to be thinking about it?
Derek Evans: I think directionally, I would tweak it a little bit and say you should be thinking about it as this year was sustaining capital. And as we've talked to you and others about what our sort of our growth project would be taking it from 110,000 to 125,000, we think that's somewhere in the neighborhood of C$300 million, and you should expect that a third of that notionally would get allocated in the first year.
John Royall: Got it. And just to be clear, that would be after you achieve the net debt for, so probably more second half loaded?
Derek Evans: No. I think – and this is all dependent upon where our Board lands on this, but – so it's subject to their approval. We haven't gotten this across the line with them yet. But I think we are comfortable enough that we are going to achieve that US$600 million debt target. So we would be planning on – this would be a full year capital budget, which would basically be starting the growth plans or making allowances for and doing the long lead time work on the growth program starting as soon as the budget's approved.
John Royall: Understood, thank you.
Derek Evans: Thank you.
Operator: [Operator Instructions] Your next question comes from the line of Neil Mehta from Goldman Sachs. Your line is open.
Nicolette Slusser: Hi, good morning. Thanks so much for taking the time. This is Nicolette Slusser on for Neil Mehta. So, just the first question here would be on pricing dynamics, curious, any thoughts in terms of what you're seeing in the Gulf Coast? And then also more broadly, as you think into 2024, any outlook that you can comment on for the WCS differential would be helpful.
Derek Evans: Yes, good morning. And I think that one thing that we would say about the WCS differential is, for some reason, people aren't factoring in the 4.5 million barrels a day of line fill that TMX is going to need. So if you think – if you go and you look at the differential today and you see part of the reason that the differential has expanded or blown out is because of increased production or increased diluent and you think that, that's somewhere in the neighborhood of 100,000 barrels a day of incremental capacity. What we're talking about in terms of line fill is taking half of that away. 4.5 million barrels over the first quarter is about 50,000 barrels a day. So, I think my own personal opinion is the Q1 2024 differential is too high. It's not factoring in that TMX line fill. And I think there is also some concerns about storage, which I don't understand either. I mean last week, storage in the Western Canadian sedimentary basin was about 26 million barrels or somewhere in the sort of the low to medium 30%. We've got lots of room for storage. So I don't think we are going to see a tight storage situation. I think there is going to be effectively less – or less product moving down the line. I said in my previous remarks, I provided my predictions as to where I think you're going to see Q2 and Q3 land. And Q3 was under C$13 this year and Q2 was in that C$15 range. I think that those are quite achievable again next year. I think they will actually be a little bit high. But if I were modeling, I'd be using those. Where I think it's going to get very interesting is, as you model Q4 of next year because, obviously, with incremental TMX volumes, I don't think you're going to see that historic run-up as you've moved into the fourth quarter of the differentials. I think it will stay quite flat through that period. So maybe C$1 or C$2 more, but I think we're out of – finally out of a period of egress driven – lack of egress driven WCS differentials. And I think we'll have a lot less volatility on that front going forward.
Nicolette Slusser: That context is incredibly helpful. Thank you so much. And then not to come back to this question again. I know some other analysts have asked. But just on Pathways, any key updates we should be looking out for towards the end of the year or anything maybe early next year, we should all be keeping an eye out for?
Derek Evans: Where to start on Pathways? I think fundamentally, as we drive forward, you are going to hopefully hear something at some point over the next couple of months about how the federal and the provincial government or pathways are continuing to work forward. I think we owe the market an update in that regard. And I think you'll – something will be coming in that regard, I hope, over the next month or two. I can tell you that we've got a few hundred people working on this project at the moment inside of the company is continuing to work on the pore space, continue to work on the feed engineering, continuing to try and get the pore space approval through. So I worry sometimes that because we haven't hit milestones or we are not moving as fast as people think we should be moving that they think there's nothing going on in this project. I can assure you there is a massive amount of work that is going on in terms of indigenous consultation, pipeline sizing, looking for appropriate mills that could roll this type. So lots and lots of work going on, as well as the important work with both the federal and the provincial government trying to arrive at the appropriate fiscal terms, that will make this project economic.
Nicolette Slusser: That’s great. We’ll definitely be on the lookout. Thank you so much for taking the time.
Derek Evans: Thank you.
Operator: And there are no further questions at this time. I would like to turn it back to Mr. Derek Evans for closing remarks.
Derek Evans: Thank you, Ludy. And thank you to everybody that joined us this morning for our Q3 results conference call. We are excited about what we have been able to achieve and look forward to updating you on our 2024 outlook when we release our budget at the end of November. Have a great day and thank you.
Operator: Thank you, presenters. And ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect. Have a good day.
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