Good afternoon. Thank you for attending today's Century Aluminum Company Q3 2022 earnings conference call. My name is Tamia, and I will be your moderator for today. All lines will be muted during the presentation portion of the call with an opportunity for questions and answers at the end. If you would like to ask a question, please press star one on your telephone keypad. It is now my pleasure to pass the conference over to your host, Peter Trpkovski. Please proceed.
Thank you, Tamia. Good afternoon, everyone, and welcome to the conference call. I'm joined here today by Jesse Gary, Century's President and Chief Executive Officer, Jerry Bialek, Executive Vice President and Chief Financial Officer, and Shelly Harrison, Senior Vice President of Finance and our Treasurer. After our prepared comments, we'll take your questions. As a reminder, today's presentation is available on our website at www.centuryaluminum.com. We use our website as a means of disclosing material information about the company and for complying with Regulation FD. Turning to slide one, please take a moment to review the cautionary statement shown here with respect to forward-looking statements and non-GAAP financial measures contained in today's discussion. With that, I'll hand the call to Jesse.
Thank you, Pete. Thanks to everyone for joining. I'll start off today by discussing the current macro environment and our operational performance, and then Jerry will take you through our Q3 results and Q4 outlook before I wrap up. Market conditions remained quite complex in Q3, with the war in Ukraine and Russia's curtailment of natural gas flows to Europe causing significant turmoil across commodity markets. The resulting high energy prices and lower aluminum prices significantly impacted our results in Q3, driving a Q3 adjusted EBITDA loss of $36 million. In this challenging environment, our team continues to take prudent measures to guide century through these short-term macro headwinds while remaining focused on the stability of our operations and our long-term strategies. We made substantial progress during the quarter to lower our cost structure, reduce our exposure to spot energy prices, and increase our sources of liquidity.
I'll provide additional details on each of these measures in a bit. Despite current headwinds, the long-term demand fundamentals for aluminum remain excellent, and we continue to execute on our existing projects to expand our value-added product lines with our Grundartangi cast house project and U.S. cast house debottlenecking programs all progressing on plan and on budget. As a reminder, we expect the first phase of our debottlenecking program to be completed by year-end, enabling an additional 10,000 metric tons of billet to be sold into the 2023 market. We will also enter the U.S. slab market for the first time next year and expect to sell around 10,000 metric tons of slab. This is an excellent area of long-term growth for century as U.S. rolling mill demand continues to expand. Our Grundartangi cast house project also remains on schedule to be completed by year-end 2023.
Turning to slide four, you can see that despite near-term turbulence, global aluminum supply and demand remains roughly balanced. While high energy costs have reduced European demand this winter, this has been offset by the significant contraction of Europe's aluminum supply base. High energy prices have now caused more than 50% of Europe's smelters to curtail, with additional closures expected at year-end. In fact, as you can see in the chart on the upper right-hand quarter of this slide, the loss of aluminum production caused by Russia's actions have created the largest deficit for aluminum in the history of the European market. Ironically, this European deficit is now being increasingly filled by Russian-produced aluminum, creating a situation where Russia is benefiting from the very problem that it's created. Increased Russian imports will make it difficult for the European smelter base to ever fully recover.
For this reason, we believe it's critical that Europe, the U.S., and their allies take urgent action, including sanctions, to address these unfair Russian actions and protect this critical industry. While LME pricing will likely remain volatile in the short term, longer-term macro trends towards electric vehicles, renewable energy, and sustainable packaging continue to support strong value-added premiums. While we have seen some softness in the building and construction markets, automotive demand has continued to improve, and we anticipate continued strong renewable energy demand, especially as the effects of the recent Inflation Reduction Act further incentivize renewable energy and electrical vehicle build-out in the U.S. All told, we expect to sell out our value-added product portfolio in 2023, including the increased volumes from our debottlenecking projects, with pricing levels roughly unchanged from 2022.
Turning to page five, you can see that Russian curtailments of natural gas flows to Europe have continued to drive record high energy prices in Germany, France, and other regions, with winter forwards over EUR 700 per MWh. High mainland European energy prices have in turn put upward pressure on pricing in Nord Pool. In Q3, Nord Pool energy prices averaged about EUR 175 per MWh, up about EUR 50 from Q2. Unfortunately, most market prognosticators now expect the European energy crisis to persist for several years. While Europe has successfully filled gas storage to near capacity this year, Russian energy flows to Europe have continued to decline, and the recent destruction of the Nord Stream natural gas pipeline has created a situation that means Europe will likely remain significantly short energy for at least the next couple of years.
Considering the expected continuation of this crisis, we decided to take action in Q3 to eliminate the remaining unhedged Nord Pool market exposure from our Icelandic energy contracts. If you turn to slide six, I'll walk you through the details. Prior to taking this action, about 30% of our Icelandic energy contracts were pegged to the Nord Pool price, with the remaining energy provided under long-term LME-linked power contracts. Due to the extreme volatility on the Nord Pool market, we worked with our energy supplier to convert the majority of our remaining unhedged Nord Pool exposure to a fixed price more in line with pre-COVID Nord Pool pricing levels.
Following this amendment to our power contract, we entered into additional financial hedging transactions to balance the remainder of our Nord Pool exposure, including unwinding excess 2023 financial Nord Pool hedges at a net gain of approximately EUR 16 million. The benefit from the unwound hedges will settle in cash evenly over 2023. Finally, as is our normal practice when we enter into fixed price energy contracts, we also sold forward a small amount of LME, creating an effective LME-linked price for the energy. You will see those hedges reflected on our hedging slide in the appendix. All told, we were pleased to be able to eliminate our remaining unhedged exposure to Nord Pool and remove this volatility from Grundartangi's bottom line results.
Turning to the U.S., domestic energy markets remained elevated over the summer, resulting in average Indiana Hub energy prices of around $90 per MWh in Q3. As we enter Q4, strong domestic renewable energy and natural gas production, paired with recovering coal production, led October Indiana Hub to fall and average about $60 per MWh for the month. We are cautiously hopeful that these trends will continue, with forward Indiana Hub prices now averaging around $65 for the remainder of Q4. As expected, tight energy markets also continued to impact the power provider to our Mount Holly facility, where a force majeure event from their largest coal supplier has left the utility to cover shortages in their coal generation with market power purchases. We have started to see Mount Holly energy prices decline in Q4 as U.S. energy market conditions have improved.
Moving to our other cost inputs, API alumina prices averaged $340 per ton in Q3 and have fallen to a spot price of $310 per ton today. On the other hand, carbon prices remain at historical highs as we enter Q4. While we did see the first signs of declining coke prices in Q3, the commodity remains stubbornly high, and pitch prices have yet to abate. Stepping back, when you combine the effects of the global energy crisis with historically high carbon prices and other inflationary pressures, we estimate that about half of global aluminum production is loss-making at current market pricing. Judging from past cycles, loss-making this deep into the cost curve has typically not been sustainable for an extended length of time.
Over the long run, LME prices have instead averaged around the 90th percentile of the global cost curve, which would require a significant improvement in current conditions, either on the cost side or price side, in order to reach a stable equilibrium. Turning to operations, all of our sites are operating well and at full production. I'd like to commend the teams at each site for achieving this result while also executing on the capital and cost reduction programs we discussed on our last call. As a reminder, in response to market conditions, our teams have implemented programs to reduce planned CapEx and OpEx in 2022 by over $40 million, including headcount reductions and other efficiencies. We remain on track to achieve these savings, which are reflected in our outlook on page 10 and the appendix.
Most importantly, we have remained focused on improving our health and safety and our ultimate goal to achieve an injury-free workplace. These efforts span a wide range of programs, from leadership to behaviors to technology, and I'm pleased to say that we are seeing the benefits from these efforts, with workplace injuries across the enterprise decreasing by nearly 15% year to date. We remain focused on consistent and cost-disciplined operations. We finished the quarter with liquidity of $215 million and remain well-situated to continue to operate our facilities at full production through this portion of the aluminum cycle. In order to further solidify our position, we have also added a new $90 million credit facility secured by our voestalpine assets. This new facility will be incremental to our existing U.S. and Icelandic credit facilities and additive to our quarter-end liquidity position.
Combined with our cost-cutting measures and already strong liquidity, this new facility should leave us well-placed to continue to execute on our long-term strategies. With that, I'll turn it over to Jerry to walk you through the financials.
Thanks, Jesse. Let's turn to slide seven, and I'll walk you through the results for the quarter. On a consolidated basis, Q3 shipments were down about 19% sequentially, primarily driven by the curtailment of our Hawesville facility. Realized prices were down 14% compared to prior quarter as a result of lower lagged LME prices and lower regional premiums. The combination of lower shipments and lower realized selling prices drove a 26% decrease in sequential net sales. Looking at operating results, adjusted EBITDA was a $36 million loss for the quarter. Adjusting items include the removal of $5 million for Hawesville curtailment costs and the removal of $6 million for lower costs or NRV impact on inventory. Moving on to liquidity. As of September thirtieth, we had liquidity from available cash and credit facilities of just over $250 million.
We took actions to strengthen liquidity during the quarter, including initiating a new EUR 14 million term facility secured by the Nord Pool in-the-money hedge unwind. This facility remained undrawn as of quarter end and is included in our total liquidity of $250 million. Additionally, in November, we agreed to a new $90 million credit facility secured by our Vlissingen assets. This credit facility will be available beginning in December 2022 and will further increase liquidity by $90 million beyond the $250 million we had at end of quarter. Turning to slide eight to discuss adjusted EBITDA. Again, for the Q3, adjusted EBITDA was a $36 million loss, a decrease of $123 million from the prior quarter.
This change was driven by lower LME and regional premiums, as well as higher energy and other raw material costs, which were partially offset by the curtailment of our Hawesville facility. The quarter three realized LME of $2,636 per ton was down $425 versus the prior quarter, while realized Midwest premium of $643 per ton was down $201. Lagged European delivery premiums were up $117 at $578 per ton. Indiana Hub power prices in Q3 averaged $90 per MWh , which is up 15% versus Q2, while Nord Pool prices averaged $177 per MWh, up more than 37% versus prior quarter.
As Jesse noted, Indiana Hub energy prices have decreased significantly since the end of Q3, averaging around $55 per MWh Q4 to date. Excuse me. The realized price of alumina was up $57 per ton versus prior quarter. While we saw signs of spot prices softening, our realized coke and pitch prices increased about 10% and 19% respectively. Finally, as discussed during our last call, we realized a combined $20 million incremental benefit from curtailing our Hawesville facility and our global cost reduction initiatives, along with more normalized maintenance and pot relining spend levels. Okay, let's turn to slide nine and we'll take a quick look at cash flow.
Our cash position increased, going from $30 million at June 30 to $65 million at September 30 as we offset the negative impact from adjusted EBITDA and the use of cash for capital expenditures with borrowing on our revolving credit facilities, working capital improvements, and gains in hedge settlements. Total capital expenditures were $18 million in Q3 , with about $12 million related to the Grundartangi cast house and $6 million in other capital expenditures. Cash gains for hedge settlements were $5 million for the quarter, primarily due to our in the money Nord Pool hedges. Now let's turn to slide 10 for some insight into our expectations for the Q4. For Q4, the lagged LME is expected to be down to a realized price of $2,275 per ton.
The Q4 lagged Midwest premium is forecast to be $475 per ton, and the lagged European delivery premium is expected to be $485 per ton. Realized Alumina is expected to be $400 per ton, which, as discussed in the past, reflects a three to four month lag in aluminum prices running through our income statement. Taken together, the moves in LME, delivery premium, and Alumina pricing are expected to decrease Q4 EBITDA by about $60 million compared to Q3 levels. From a power perspective, we are assuming a base price of approximately $60 per MWh for Indiana Hub and approximately $105 per MWh for Nord Pool, which are in line with our current spot and market forward prices.
The net impact of energy costs would equate to an improvement of about $50 million in EBITDA, which reflects the changes to our power contracts that Jesse described earlier. As a reminder, hedges are recorded below EBITDA, so you will continue to see the market price impact running through EBITDA, but the net hedged impact reflected in the bottom line. Realized coke and pitch prices are expected to be down slightly in Q4, expected to yield a $5 million EBITDA improvement versus the Q3. Finally, we expect to see a net EBITDA benefit in the quarter of $5-$15 million related to volume and anticipated savings from our global cost reduction initiatives. In total, we expect these items taken together will equate to slightly improved EBITDA compared with Q3 levels for a Q4 result in the range of -$25 million to -$35 million.
From a hedge standpoint, using the assumptions on the slide, we expect a realized gain of approximately $5 million in the Q4, and we expect tax expense of approximately $5 million. Again, recall the impact of both of these will be below EBITDA geographically and will be reflected in adjusted net income. With that, I'll turn the call back over to Jesse.
Thanks, Jerry. In closing, while the market environment has become more challenging in the short term, we continue to make progress on both our short and long-term initiatives. During the quarter, Century lowered our cost structure through our OpEx and CapEx reduction programs, and de-risked our energy supply by converting our remaining Nord Pool exposure to a fixed price. These actions helped us finish the quarter with strong liquidity, which we have further enhanced through our new $90 million revolving credit facility. Our operations remain at full production, and our longer term projects to expand our value-added product lines remain on budget and on schedule. Ultimately, we remain confident that Century is well-positioned to benefit from the long-term macro trends that make aluminum vital to the world's future. We look forward to taking your questions.
We will now begin the question and answer session. If you would like to ask a question, please press star followed by one on your telephone keypad. If for any reason at all you would like to remove that question, please press star followed by two. Again, to ask a question, press star one. As a reminder, if you're using a speakerphone, please remember to pick up your handset before asking your question. The first question comes from David Gagliano with BMO Capital Markets. You may proceed.
Hi. Thanks for taking my questions. I'm just trying to make sure I have the changes in the hedges, you know, straight. I'm looking at the last quarter slide deck versus this quarter slide deck, just doing a little side by side. You flagged one on the revenue side, you hedged an incremental, like, 20,000 tons at an average price of, like, $0.96 a pound in terms of revenue. I just want to confirm that that's correct. That's my first question. Related to that is, on a go-forward basis, are you gonna continue to hedge LME prices or LME volumes, I should say?
Hey, David. Thanks. If you look at slide 17, you can see the totality of our fiscal 2023 and fiscal 2024 hedge books. So you're right on the incremental volume. I don't have the calculator in front of me to do the cents per pound, but you should be able to back into what you're looking for there. Going forward, as we've said, we intend to remain and offer our shareholders exposure to the aluminum price. The one exception for that is when we are entering into large fixed price commodity contracts, cost inputs. Here talking about the change from the Nord Pool energy price to a fixed price.
The LME that we sold forward was just to match that energy fixed energy price, and to convert that to the familiar sort of LME-linked power price that you're used to seeing from us on Iceland.
Okay, thanks for clarifying that. That's my other, you know, part of the question. You know, on the hedges for the Nord Pool piece, you know, last quarter for 2023, there was, you know, roughly 1.1 million MWh that were hedged at EUR 30 on average, and now it's 990,000 hedged at EUR 30. I'm assuming that decline went into locking in the fixed price component. My question there is, you know, first of all, can you confirm that that's correct? I'm assuming it is.
The second part of that, but you know, the, I think the more relevant question is, what did you lock in? What's the price, the average megawatt-hour price now that's locked in for Nord Pool?
Yeah. Thanks, David. Yeah, maybe if you just turn to slide six, that's a good slide for understanding exactly what we did on the Icelandic power contract. You're correct that. If you'd maybe toggle between six and slide 17, the amount of Nord Pool hedges that we unwound, and again, if you reference my comments, we've unwound those for a gain of about EUR 16 million, which will settle equally, spread over 2023. That matches about the volume that we fixed with our energy supplier. We converted contractually a portion of the Nord Pool exposure with our energy supplier to a fixed price, which put us in an overhedged position in fiscal year 2023, and so rather than sit overhedge, we unwound those hedges for a gain. Does that make sense?
Not really, I don't really profess to understand this hedge stuff anyway, so I'm just really trying to figure out the math for, you know, what's the average price that, you know, the cost per MWh locked in for the Nord Pool now for 2023. You had 1.1 million MWh locked in at, you know, EUR 30 per MWh . Now it's 990,000 locked in at 30. You know, I'm just trying to figure out what's the fixed price that you've locked in. What is that price in cost per MWh?
Let me try one more time on the volume, and then we'll get around to the price at the end if that works. If you go back to last quarter and you looked at our financial hedge book, the equivalent of the slide 17, you would have seen that we were about 80% hedged on our 2023 Nord Pool exposure. What we did this quarter was we worked with our energy supplier to convert a portion of the contract with them from a Nord Pool exposure to a fixed price.
When you take those megawatts and you take the MWhs you're seeing on that hedge slide from last quarter, that would have been more megawatts than we'll actually consume. That put us in a bit of an over-hedged position. Rather than sit with an over-hedged position, we unwound a portion of those for that EUR 16 million gain. That's what happened on the volume side. Same amount of megawatts we're gonna consume, but because we fixed a portion of the megawatts contractually with our energy supplier, we needed less financial hedges, and so we unwound a portion of them. To your question on price. There will be two sort of portions of this you need to think about going forward.
There's one portion that will run through EBITDA, which is just the raw Nord Pool exposure that you see that will continue to fluctuate based on Nord Pool prices. Of that, part of that will be totally exposed to Nord Pool. If you look at slide six, that's about 20% of our energy that we'll consume at Grundartangi in fiscal year 2023, and about 10% will be fixed. Now, because of our confidentiality provisions in our energy contract, we can't disclose what that price is fixed at. If you go back and you look at my prepared remarks, I think a good way to think about where we may have been able to fix that is to go back and look at where Nord Pool prices were pre-COVID.
As we sought to eliminate the volatility that's been caused by COVID and the events subsequent to COVID in Nord Pool, you might use that as a good way to approximate where we would have been able to to reach agreement with our power supplier at. If you use that for the fixed portion, and then if you continue to use the fixed price of in the hedge book for the rest of the exposure, that'll give you a good sense of where you need to be on the energy side.
Okay. Thanks very much. I'll let somebody else ask the questions.
Okay.
Thank you. The next question comes from Timna Tanners with Wolfe Research. Your line is open.
Hey, good afternoon. Thanks for all the detail. I'm not gonna profess to have that all figured out either, so maybe offline we can drill down a little further. It's good to see the exposure, you know, off the books if I understand correctly. Just wanted to take a step back and ask a little bit more about what further levers you can pull. I certainly appreciate that this all seems quite unsustainable, but in your Q, you point out that you have cash and cash equivalents for the next 12 months if conditions continue. I'm just wondering, you know, if they do, if this terrible environment continues, what other levers can you pull? How are you thinking about managing the business?
Yeah, that's a great question, Timna. Yeah. As we sit here today, between the $215 million of liquidity you saw at quarter end, plus the new Vlissingen credit facility that we put in place, you know, we feel quite comfortable with our liquidity levels as we look forward at the current environment, even if that environment were to continue. That said, I think you've seen from century in the past and certainly, from this cycle, you know, there are a number of levers in a business of this size and capital intensive of this size that we can pull both to lower costs, whether that's on the CapEx side or the OpEx side, and/or generate cash.
We continue to have a number of those going forward, on both cost savings, but also cash generation opportunities that we can exercise. I'm not gonna go into those at this point. They're somewhat hypothetical. You know, we feel really good about the liquidity that we have today, being sufficient for as long as this cycle continues.
Okay. Fair. If I look at slide 10, you know, it's kind of trying to get a sense of if this is the bottom in terms of market conditions. We have yet to see the full flow through of lower regional premiums, it looks like, for the Q4 and, perhaps a little better, alumina outlook for your consumption of it. Anything you can share with us in terms of what you're seeing in coke and pitch? Those are a little more opaque for us. How to think about, you know, if this is the bottom, what the delta is going forward, given those lagging factors.
Sure. Yeah. I think on coke and pitch, you know, those are much smaller markets than we see generally. We have started to see what we believe to be the top in the coke cycle. We saw a little bit of a decrease over the past quarter. We expect that to continue. Pitch is a little bit, maybe a little bit more sticky. There's a number of drivers and reasons behind that. Probably less near term relief on that side. Again, but kinda going back to my comments, when you start to add it all up, you know, coke, pitch, alumina, and given the global nature of this energy crisis that we're seeing, one difference from this cycle versus previous cycles is the same cost drivers seem to be driving a lot of the world's supply.
When you take that back to the cost curve and you look at how deep into the cost curve, the loss-making is occurring. It gives you some sense of an equilibrium that's probably not gonna be stable for the long term. That change can come in one of two ways. It can come on the cost side, again, alumina, coke pitch, energy eventually. You know, we are seeing in the U.S. at least, energy prices come off quite a bit over the past few months. Or but it can also come on the price side, right? We know, we've seen the curtailments in Europe. We've started to see some curtailments in certain provinces in China, whether those are short, medium, or long term.
You're starting to see some reaction on the, excuse me, the supply side. One way or the other, the market will balance and, you know, we don't see this continuing for the long term, and feel pretty good about where we stand.
Okay. If I could slip in one more. Just wondering, back to Hawesville. Given that power costs have been a little less bad than it appeared, at the time of the closure, any updated thinking on how long that could be out or how to think about that operation going forward?
No. The curtailment at Hawesville went very orderly, and the asset remains in good shape. From here on out, you know, we'll continue to look at it. I think given where we are in the cycle today, you know, I think you'll see us be quite disciplined and make sure that we have a good sense of where the market is going before we start to undertake the costs of restarting that facility. The asset is ready, the option is available for us, and it's just a matter of watching the overall commodity cycle and both on the price and cost side to figure out when it'll make sense to restart that facility.
Okay. Understood. Thanks very much.
Thanks.
Thank you. Our next question comes from John Tumazos with Very Independent Research. Please proceed.
Thank you. Congratulations on three straight quarters with a book profit.
Thank you, John.
I'm beginning to believe in miracles. Is it reasonable for your shareholders to assume that the policy of the company is to have long-term electricity supply contracts for its smelters, preferably renewable, if it's available, moving away from the past strategy of buying spot power, at least for Kentucky, because the energy markets have changed and are tighter, and it's harder to buy the spot power?
Yeah. I think there's a lot of things going on on the energy side. It maybe isn't harder to buy the spot power, but we certainly have seen increased volatility in the spot power over the past 18 months, really since COVID, both up and down. I think you hit on a couple of things that are for sure in our long-term plans, and one is to find a way to take some of that volatility out of our primary cost input, which of course is energy. You've seen us do a little bit of that this past quarter in Iceland. But also more broadly is to move to increasing renewable energy mix.
Again, you've seen us do that both in Iceland and in the US over the past couple of years. I would look for both those trends to continue over the short, medium, and certainly long term.
Jesse, if I could ask another question, and you might not be able to answer this, but I'd like to ask the question just so that the big shareholder at Glencore, maybe some other advisors or attorneys just could hear that the question was asked. Is it reasonable to assume that the 42.9% shareholder would lend its balance sheet to support or guarantee a 20+ year renewable power contract and a bridge power contract, you know, for the one or two or so years it takes to build wind farms or solar farms?
A fair consideration for such a financial guarantee on Glencore's behalf might be first preserving the value of their 42.9% equity stake, and then continuing their aluminum metal sales contracts for a fee, continuing the alumina purchase contracts they have for a fee, and continuing the hedge futures trading representations, which would cease if you had less aluminum output or if something happened to rip up contracts like a reorganization.
Yeah.
Might be able to help.
Well, of course, any contract with Glencore will continue to be done on market and arm's length terms. I can maybe just start there. More broadly to your point of getting done long-term renewable energy contracts, and to your point maybe about credit support for doing those, you know, there are a number of ways that, you know, we've identified to get those done.
I don't think those will be a limiting item to our ability to enter into long-term renewable energy contracts, whether in Europe or the United States. In fact, I think some of the recent legislation we've seen, out of on the U.S. side in the Inflation Reduction Act has a lot of really great provisions that will help, both build out more renewable energy in the United States for facilities like our smelters in Kentucky and South Carolina, but also help support other programs within those smelters, including, increasing energy efficiency, and other capital projects that will help the U.S. smelter base have a longer life.
I think there's a lot of really good opportunities there, both to green our energy supply, but also extend the term and reduce the volatility of our energy supply, as you're hinting at.
You're saying that the Inflation Reduction Act is so generous that you think you might be able to get long-term renewable power without a credit support from, the shareholder?
Well, I think there's just a number of ways to get the types of energy contracts done that you're talking about. It's certainly something that we're working on a lot of different pathways.
Thank you. Our next question comes from Lucas Pipes with B. Riley Securities. You may proceed.
Thank you very much, operator, and good afternoon, everyone. I wanna circle back on the Icelandic Power arrangement, and I'm curious, if we just look at the contract side, I know you can't tell us where you hedged or rather locked in the fixed price component. If we look at the formula LME-linked Nord Pool, and fixed, at today's LME prices, at today's Nord Pool prices, what would be roughly the weighted average cost of your power in Iceland? Thank you very much for your perspective.
Thanks, Lucas. It's a good question, and of course, we don't break down the individual cost structures of any of our assets. Just to give you a sense, maybe just makes good sense to start back on slide six, and let's just look at the breakdown of the energy pricing going forward. The LME linked portion has not changed. That's the same 70% that you've seen for Grundartangi over the past several years, and you should have a good sense of how that performs through various cycles. No changes there. On the Nord Pool side, of course, you can continue to model that. You can see the Nord Pool market prices run through. That will be 20% of our exposure.
Of that 20% of exposure, substantially all of that is hedged at EUR 30. So you'll see it continue to run through on the EBITDA side, but on the cash side, that's all hedged at about EUR 30. Then the remaining 10% is that 10% that we fix contractually with our energy supplier. That's obviously subject to confidentiality, but a small piece of the overall puzzle there. I think you guys will have a good sense of where that may be or be able to approximate that.
That's helpful. Thank you. As a follow-up question, the LME linked component intuitively makes sense. You pay more for power when LME prices go up. Now we've had an environment where LME has gone up and so have a number of your input factors, not just energy. Does it make sense to rethink that construct and link to LME pricing given what happened to the global cost curve? Thank you very much for your color on that.
Yeah. It's a good question, Lucas. It's a structure that has worked very well for us over long periods of time, through many different cycles. Obviously, you know, it creates a smelter like Grundartangi, which has made money through the depths of the financial crisis to the more recent higher LME prices and back down to where we are today. It's a nice way to minimize the impact of a cost that can vary quite significantly. I think from our perspective, of course, we'll always be looking at what makes the most sense long term on the energy side, given the large portion of our cost base energy will always be. It's not something that we're going to discard easily given how successfully it's been over decades now at Grundartangi.
Of course, for century as a whole, when you pair Grundartangi, which has that large LME linked price exposure with the US smelters, which have either market-based power prices and/or some fixed price power, for instance, at Mount Holly, you get a nice mix of all three different types of pricing mechanisms across century as a whole, which serves you well both in higher LME environments, but also lower LME environments and can serve to balance each other a little bit. Overall, we like that sort of mix of energy pricing and think we're well situated to sort of make it through various different pricing environments.
When would this be up for renegotiation? If you could remind me, I would appreciate that. Is it maybe possible to set the base higher, for example, on LME pricing? I know I said automatic.
There's the Grundartangi power contracts run through 2026 to 2036. There's a variety of contracts there that are spread over that time period and will come up for renewal during that period.
Thank you very much for the color. Then, switching topics to the Alumina side, could you remind us at what percent of LME the Alumina pricing is fixed here in the coming year? Would very much appreciate your color on that. Thank you.
Yeah. We have a mix of alumina pricing in 2023. The mix is a portion which is LME linked, and a portion which continues to link to API, and a portion that is fixed. We're about 60% LME linked for 2023, 25% API, and about 15% fixed.
Got it. The LME linked portion, at what % of LME would that be on average?
Yeah. We don't break that out specifically. As you might imagine, that's pretty commercially sensitive information. Just to clarify, that's our mix for 2022.
Sorry.
For 2023, probably see something approximating that, a similar mix to that, in 2023. We don't disclose the specific percentage, given its commercial nature.
All right. I appreciate it, and best of luck.
Yeah. Lucas, maybe just what we have said before is that percentage tends to be between 15%-17% of the aluminum price, with some periods outside of that range, depending on the general relationship between API and LME whenever those contracts were struck.
Thank you. It appears we have a follow-up from David Gagliano with BMO Capital Markets. Please proceed.
Hi. You've addressed a lot of the questions already. I just wanted to come back to try and ask the same question again in a different way. For example, if we look at slide 10, the Q4 outlook slide, you know, power prices, Nord Pool assumption is $105 per MWh, and the Indiana Hub power price, $60 per MWh, and that's a $50 million tailwind. When we go to Q1 2023, we see the same slide, and we assume those same prices, Nord Pool 105, Indiana Hub 60. What will be the change in the power quarter-over-quarter in that, you know, now that the hedges flow through and everything like that in Q1 2023?
The power pricing should be pretty much unchanged under that scenario, David. Other than obviously there's LME dependency for 70% of the Grundartangi power pricing.
Okay. All right. That's helpful. Thanks very much.
Thank you. There are no further questions at this time, so I will now pass it back to the management team for any closing remarks.
Thank you, everybody, for joining the call today. We look forward to speaking with you again, in the new year.