Ladies and gentlemen, thanks for standing by. Welcome to the Fourth Quarter 2013 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given at that time (Operator Instructions) As a reminder, this conference is being recorded. I would like to now turn our conference over to our host, Mr. Peter Trpkovski. Please go ahead, sir.

Thanks, [Juana], and good afternoon, everyone, and welcome to today’s call. Before we begin, I’d like to remind you that today’s discussion will contain forward-looking statements related to future events and expectations, including our expected future financial performance, results of operations and financial conditions. These forward-looking statements involve important known and unknown risks and uncertainties, which could cause our actual results to differ materially from those expressed in our forward-looking statements. Please review the forward-looking statements disclosure in today’s slides and press release for a full discussion of these risks and uncertainties. In addition, we’ve included some non-GAAP financial measures in our discussion. Reconciliations to the most comparable GAAP financial measures can be found in the appendix to today’s presentation and our website at www.centuryaluminum.com. And with that, I’d now like to introduce Mike Bless, Century’s President and Chief Executive Officer.

Thanks so much, Pete, and thanks everybody for joining us again this afternoon. If we could turn to slide four please, I’d like to give you a quick review of the last couple months, which as I think you will agree has been a busy and productive period for the company. We generally really pleased with the progress that we have made. Okay, let’s started, at the end of January, as you have seen, the Kentucky Public Service Commission approved the new power contract to Sebree and it was approved exactly as filed by ourselves and by the power company. This development allowed us to move forward in long-term plans and investments for this excellent plant. I’d like to note how extraordinary it was that our employees were able to work safely and productively through these uncertain times. They should be commended for that. The plant is running extremely well. We have got great efficiencies in the potrooms and record production coming out of the casthouse and I will give some more detail on that in just a few moments. I should note, Hawesville is also firing on all cylinders now. We’ve got a record amount of high-purity production coming out of that plant. Again, I will make some more comments here in just a couple minutes. Let me talk about the power situation at Hawesville where we had some issues that impacted the full rates that we paid in the Q4, given some things that happened at the power company generation stages. As you might remember, we paid a net cost by contrast of maintaining that power station next to Hawesville, it’s obviously owned by the power company, until the power station can be closed and I’ll update you on the status of that process in just a moment.…

All right. Thanks, Mike. You can turn to Slide 9 please. I will take you through the company’s financial performance for the quarter. Our U.S. shipments were up 2.5% in Q1. This was largely due to higher production volumes at Sebree. In Iceland, we had direct shipments of approximately 3,400 tonnes in Q4 and total volumes for Grundartangi was at just about 1%, as a result of the additional volumes from the ongoing expansion projects. So, overall global shipments were up 2% quarter-over-quarter. On a one-month lag basis, the average cash LME price was down about 1% from Q3 to Q4. When you look at our realized unit prices, they were down 2% in the U.S. and essentially flat in Iceland, so both pretty much in line with the change in LME. Our net sales were essentially flat quarter-over-quarter with a slight increase in shipments, offsetting the decline in LME. Continuing down the operating loss lines, in addition to our normal adjustments for depreciation and amortization and lower cost of market inventory adjustments, this quarter we also had an $8 million charge related to the separation of our former CEO in 2011. After backing out these three items, we had an adjusted operating loss of $8 million in Q4, which compares to an adjusted operating loss of $4.5 million in Q3. Let me take you through with some of the changes quarter-over-quarter. Lower LME prices in Q4 reduced operating income by about $5 million. But raw material costs were favorable by $3.5 million, primarily due to lower carbon costs at our facilities. At Hawesville, power costs were up about $1 million in the fourth quarter. Given that Q4 was the first full quarter with Hawesville market based power, we expected power costs to go down by $6 million. The difference…

Thanks. If we could just turn to slide 15 please, we want to get to your questions. So I am going to quickly go through some of these items that we will be spending time working on certainly in early 2014. I have covered most of these already, so I think I can go through these reasonably quickly. As I said, we’ve got the meaningful issues still in Kentucky in the realm of power. First, as I briefed earlier, we need to complete the process of allowing the power company to close the generation station next to Hawesville if they choose to do so. We’ve installed the physical infrastructure that’s required to do this and the regulators have approved that, so that part of it is done behind us. What’s remaining now is the regulators need to sign off on the operating protocols that are required if we were ever forced to cut power during great emergency. After the regulators approved those protocols, as I said we will stop paying the monthly support cost of that generation station. And again, that’s the problem that hit us during the fourth quarter. Again, we believe this whole process will be wrapped up some time during the second quarter. The remaining issue in Kentucky to which I referred is the maintenance on the regional transmission system and the potential impact it could have on both Hawesville and Sebree. Thus far, the power company had maintained its insistence on de-energizing the transmission line when they perform maintenance even on a scheduled basis. If an unscheduled event were ever to occur during this period, we will be at risk to have to curtail load at one or both plants, potentially a significant amount of power. Working on energize lines is a proven and safe practice…

Thanks Mike. Juana, if you could please take the first question in queue. Juana, at this time, are there any questions? Juana, at this time, we would like to take questions please.

Okay. Our first question, sir, sorry about that. (Operator Instructions) And our first question comes from the line of Mr. David Olkovetsky. Please go ahead sir.

Hey guys, how is everybody doing?

Sorry, David, we missed that one.

I was just -- yeah (inaudible). My first question is around the revolving credit facility. Shelly, you mentioned that the U.S. facility was increased to 150, I think you said?

Yeah. That’s right.

I didn't catch the number for the [Icelandic one], how big was that?

Five zero. 50.

50, okay, got it. Can you give us some metrics around those facilities, are they both asset based, what are the interest rate, what are the advanced rates, are they 85 AR, some of the inventory?

Right, so they are both backed by receivables inventory. They are both variable rates over LIBOR, U.S. is 125 to 175 depending upon availability, where Iceland is 375 over. Typical advanced rate 85% on receivables in U.S., I believe its 70% on inventory. Iceland is a little lower, 65% on both, but no ineligibles.

And are they both fully available with the exception of the 50 million or so that's drawn in Iceland and the LCs in the U.S.?

Yeah, I mean, there are things that we have to look at like different reporting requirements at different levels and dominions and things like that, that you get into but otherwise fully available.

Okay. Are there any financial covenants like a minimum liquidity requirements or a fixed charge coverage ratio or something like that?

No fixed charge coverage ratio. There is a minimum liquidity requirement but again that’s when you get into the dominion issues that I mentioned before. And that just on the U.S. side. On the Iceland side nothing like that. Sorry?

The dominion issues, what is that? What do you mean?

Basically if you get down to a certain level, the bank will come in and take dominion over your cash accounts as well as your receivables and inventory.

Okay. And what’s that level?

I believe its [0.5].

So in other words, you need to maintain at least 35 million of cash or revolver availability before the banks come in and say we’re pulling your line?

Yeah, and David, all the stuff is on line that you can get all the details that are filed.

Okay, perfect. And then with respect to, maybe just talk a little bit about Helguvik. When I first started looking at Century, now it was supposed to be the huge growth project and I guess I just want to get a little bit of update on where the conversations are with the Iceland government, what sort of sawing that and are there any potential breakthrough in horizon with respect to we’re starting it.

Sure. David, its Mike, there is two separate buckets of issues as it relates to power, and really three, but they compartmentalize it. The first bucket is the discussions as I said with the existing power providers. As you know, the national power company owned by the state is not a current supplier to help where the two contracts were signed. I’m sure you know that in 2007, we had two geothermal companies and we continued to talk with them. The biggest issue with those guys as we’ve said repeatedly has been they are weak in financial state after the financial crash. They’ve gotten a little bit better but not materially so and that’s impacted greatly. They are financing with their own power projects and that’s all been able to reach the final agreement and more on modest side agreement. As it relates to the national power company, I mean, the issue there is how that company wishes to allocate the power both that it has available to sale today on the one hand and that it can and wishes to develop in the future. And there -- the issues are complex but they know if there is no difference in anywhere in the world that I have seen, it’s simply how a company and in this, you can say, state, wishes to use its power resources. So there as political debate going on and we have to be mindful of that and respectful of that. And so that simply -- it sounds simple. There are zillion complex issues that are embedded in this but you see this kind of public discussions and debate going on all over the world, appropriately so.

And if I may just one more, I want to just make sure I’m understanding correctly Mike. Earlier you were saying that there was $3 million and the $4 million associated with the power contract. Is that or you guys adjusting for that?

No, that’s -- thanks David. So we haven’t adjusted for that because we felt like even though it was an unusual circumstance, and I’ll repeat again what it was. It wasn’t just the contract so much as that it drove up. Actually that’s not true. It drove up our price, part of it was the contractual obligations to the power company on that Power Station and part of it was just an increase in general prices in the region. As a result of that, unanticipated series of event but we haven’t adjusted for it because its power costs and it hit us and we just doesn’t feel like it was appropriate to adjust for it. But if you believe it’s a one-time event, you might adjust for it. It was $0.07 or $7 million of EBITDA. Again just to break it out $3 million of it was the incremental cost that the power company board to replace that power to their other customers. Again we're on the hook for that until we believe in the second quarter when we finished the process of getting another regulatory approvals and $4 million was simply market power price is being driven up by that unanticipated event.

Okay. Perfect. I'll turn it over. I don’t want to hog the queue. Thanks very much guys.

Thanks, David.

Your next question comes from the line of Timna Tanners with Bank of America Merrill Lynch. Please go ahead.

Hey. Good afternoon you all.

Hi Timna.

I have couple of questions, you told a lot about us and we are trying to get smarter about this power arrangement. So this are really basic questions I apologies.

No problem.

Lot of moving parts, so on page 13, I just want to make crystal clear here , when you talk about the footer here of fee and you're saying LME price of $1,700 and $1,900 per tonne, those are your cash costs that LME price also includes in that's net of Midwest premium, that's net of any premium. That's the total aluminum price?

$1,700 to $1,900 is the LME price. And then any Midwest premium or other premium that we receive about that LME is a reduction to the cash costs that are shown on the page.

This is consistent with the way we've shown at the last at least three or four year. So the way you've been building your models, if you have been using these data to build your model based won’t change this year. Again, Shelly said, it's just, we think it's the most helpful to those looking at the company modeling because as Shelly said it's directly LME comparable cost, you don’t have to -- for that costs you don't have make any adjustments, you can just assume whatever LME you can, you've got the sensitivity right on there and you an calculate what the cash costs would be at any LME.

I got it. Obviously with the volatility in the Midwest, I mean, I just want to make crystal clear what that was in…

Sure. You see the Midwest that assumed down, yeah, we've just use in that the use, we just used the CLU estimate. And so you can, you know with yourself, you can see the U.S. tons for example that we have, so if you want to sensitize that number by attending or $22 per metric tonne if you did multiply for every penny $22 times the number of U.S. tonnes for example.

Okay. That was helpful.

Good.

And then a couple of questions, one is, you had talked in the third quarter call about concerned of supplying sourcing alumina and there has been some bauxite pricing strength on what's happening is need, so just want an update on how that’s going there for you?

It's going very well, thanks. So I just get over quickly, part of that was embedded in my comment on Grundartangi which implicitly we replace the total, so we got alumina and metal there. But we've got alumina contracts now covering all of our activities back, all of our production in the U.S. and in Iceland. We replaced expiring contracts in the U.S. as well as expiring contracts in Nordural and Iceland, it's all embedded in the cost data that Shelly has given you there. So the market remains, although, it's traded up a little bit as you said, I didn't make any comments, the index price was up a little bit during the quarter but tax price is now about $335 now, it's up a little bit during the quarter. But it's usually procurable we've got importantly the right material for our plants, despite the fact that it's a commodity as you know each alumina performed a little bit differently at each plant. And so it's important that we get the right source and so net, net will cover 2017 now and we feel good about our alumina supply.

Okay. And then last and I am sorry if I missed it, this was on the SG&A guidance refers a lot lower, sorry, if I missed why that would be the case from 2013?

Yes. So in 2013 excluding any unusual items that we've called that specifically, the biggest difference is the SG&A related to listening in Netherland that there NO plant we were starting up last year, I think that was about $7 million to $8 million, so we had SG&A that will basically go away in 2014 now that's a plant up and running.

Okay. Thank you.

Thanks.

(Operator Instructions) Our next question comes from the line of David Gagliano with Barclays. Please go ahead, sir.

Same line of questioning as Timna made a minute ago on the 2014 target on the cash costs side, I just want to make sure I got it right too. So if I, if you back into the math and I'm doing in pennies per pennies pound, I apologize. I will give it to you dollar, whatever easier and it works out in weighted average cash costs target let call it $1,560 a tonne? And but what you're saying is that number already includes what's called $325 reduction associated with the premium, correct?

Correct. Just make it -- same presentation is always there, David, because you think the gross cash costs in order to get these data, you reduce it by all premium, not just -- as Shelly said, not just physical premium which you are referring but the product -- the value-added product premiums as well.

Okay. Okay. All right. And essentially what I'm getting at it is and I think what we're trying to figure out here relative to 2014, I mean, obviously, I'm guessing that the premium assumption you're making for '14 is actually meaningfully higher than the premium assumption made for '13?

It’s right there on the page, right there on the page.

For '13 -- for 2013 as a premium assumption?

What was embedded in '13 is…

Correct.

Yeah. The Midwest pricing around the time we put out our last numbers of around $0.11 per pound.

$0.11, okay, so now with ’15 so?

Yeah.

Okay. I got it. All right. So understood and then just on the pricing side, the other question I had. I appreciate the breaking out the shipments by higher quality shipments and also the value-added number, 250,000 tonne on all premium tonnes. What I'm trying to get figure out is, what was that value-added number in '13, is this all incremental? I’m assuming it’s not.

No, I can take it down so really quickly. So, let me just do it one-by-one. So at Hawesville, as you see we're predicting about a 120,000 tons of purity this year, that number was less than half of that last year, a little less than half of that. And so the plant as I said, I can't say it enough. I don't say it enough to them, it has made just extraordinary strives there. And at Sebree, it's all well, it is all since June, so I guess it’s seven months since we have three, four, probably it will be five months incremental. We had Sebree for seven months as deal closed on the first of June. So it's about the same, a little bit more than the plant produced last year. But it's just -- we owned the plant for about five months, five months more. At Mount Holly, that's pretty comfortable to what we didn't do it last year. And at Henderson County, as I said, it's essentially nothing this year. We are doing some small trials as I said but the big stuff, the big volume stuff if the trial is successful and won’t come until 2015.

Okay. And then, so when you do that math on the U.S. value-added line, at $250 per tonne on average of all premium tonnes, was that a $250 per ton number as well last year or it sounds like that's probably gone up as well, correct?

It's gone up as well. Maybe, I’m just trying to get, David, where you might be heading. Let me give you the right figures, at least it might be a helpful statistic. So the last time, we talked about our breakeven and this was a breakeven pro forma for market power, so it's comparable for the numbers that I just gave you a couple of minutes ago. It was $17.75 and it's a holdback number and the new number I just gave, again after we get to the cold weather in Q1 we believe and get back to power prices as Shelly said at $37 is 1,600, so a $175 difference. If you look at that and again that’s a comfortable power for power, so there is no difference in the power there that $17.75 was pro forma for market power at both plants in Kentucky. If you look at that $175 improvement, about half of it is from, as you correctly pointed out the better assumption in regional delivery premiums, it's up regional delivery premium and the assumptions are up about 90 bucks. And about the other half is due to a better richer product mix and better high purity to do it and -- better high purity and billet premiums.

That's exactly what I needed. Thank you very much.

Cool. You bet.

Our next question comes from the line of David Olkovetsky with Jeffries. Please go ahead, sir.

That's actually the exact line of question I was about to go down. Is the $175 you just went over so, and then I guess maybe I will just ask something else. Talking maybe a little bit about working capital, how do you guys understand working capital sort of playing out over the next quarter or so with all of the various moving parts?

Well, I mean, obviously working capital can swing significantly from quarter-to-quarter, anything that I can’t think. If anything, that you can figure, there is nothing dramatically that we know in Q1 that would be a daily swing. There is a little bit of that inventory build maybe but nothing huge.

No. And as Shelly said, you're going to get variations just because you’ll have disbursements that are scheduled on mean other last quarter or a customer payment or two will be lumpy. But if you have over the course for the next couple of quarters, there's nothing. As you know, you've loss the company I mean basically our working capital over the long-term meaning longer than a quarter to those up or down in sympathy with the LME price.

And then with respect to about 37 per megawatt hour that you guys have alluded to few times. What -- how confident are you about being able to get down to that, what are the sort of parameters under which it will stay high, obviously, whether that's a big impact. But how confident are you guys when you get down to that 37?

Sure, I mean, one level of confidence is based on the forward screen and our discussions with dealers. We could create that price right now, we could hedge. We could buy forward to that price right now. And so that 37 again is made up of -- it’s actually a little bit conservative. Prices are sort of 32, 33, 34, when you get to the forward screen outside April and then for the rest of the year. And then once that support cost for the generation station goes away, the remaining costs are just another couple of bucks, two bucks or so for transmission and then buck or so of ancillary costs. So, I mean, one level of confidence is if we so choose we go on and create that price today.

And have you guys just made that decision to do that with elite part of your requirement?

We haven't done any transactions yet. But I think it's safe to say, it's very safe to say we've done a lot of work on it. And as I said we'll be reporting to it. I wouldn't be surprise that the next we report to you we'll have put some of that in place.

And then with respect to the breakeven, what is the maintenance CapEx level you guys were assuming for that breakeven cash flow?

Yeah, we used $20 million of this breakeven.

Okay. Perfect. That's it. Thanks so much.

Thanks.

Thanks.

And there are no further questions in queue.

Very good. We appreciate everybody’s time and we look forward to talking with you in April if not before. Take care.

That does conclude our conference for today. Thank you for your participation and for using AT&T Executive Teleconference. You may now disconnect.