Century Aluminum Co (CENX) 2014 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Century Aluminum second- quarter 2014 earnings call. At this time, all lines are in a listen-only mode. Later, there'll be an opportunity for your questions, and instructions will be given at that time. (Operator Instructions) And as a reminder, this conference is being recorded.

I'll now turn the conference over to your host, Peter Trpkovski. Please go ahead, sir.

Thank you very much, Cathy. And good afternoon, everyone, and welcome to the conference call.

Today's presentation is available on our website, www.centuryaluminum.com. We use our website as a means of disclosing material information about the Company and for complying with Regulation FD. I would also 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 have 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 on our website.

With that, I'd now like to introduce Mike Bless, Century's President and Chief Executive Officer.

Thanks very much, Pete, and thanks to all of you for joining us this afternoon. If we could turn to slide 4 please; I'd like to give you a quick review of what we've been working on the last couple months before I turn it over to Shelly, who will take you through the -- some thoughts on the industry environment.

Before I get to that, just to tee that up a little bit, obviously we think we've seen sentiment turn in these markets over the last couple months. And we think sentiment may finally be catching up to some of the movement in the fundamentals about which we've been talking over the last year or so.

In our specific markets, in the trading markets and in the commercial markets, conditions remain quite favorable. We continue to see tight availability of physical metal and growing demand for value added products that are already in short supply in our markets, i.e., the US and in Europe. And I'll comment later in my remarks on what we're doing to address what we see as some pretty attractive opportunities for the Company.

Okay, let's get started over the last couple months. As you'll recall, the winter weather had a severe impact on power prices in the Eastern and Midwestern US. And as we expected, we saw significant improvement during the second quarter. And by the end of the quarter, we were seeing price levels back to what we would consider almost normal.

We saw some transmission congestion issues during the middle of the quarter that have largely dissipated. And I'll give you some more detail on that in just a couple minutes. Let me just use Hawesville as an example to give you a sense of the movement in power prices quarter to quarter. Hawesville's better to use here because, as you know, Sebree was only on market power for two of the three months during the quarter. As you remember, the old contract terminated on the 31st of January.

So for Hawesville, our total delivered price -- this is the price we pay for energy plus transmission plus all the other fees -- averaged $52 per megawatt hour as you'll recall in Q1. In Q2, that same number was $41 per megawatt hour fully delivered. And in July, we've had -- July to date, which includes (inaudible) as of yesterday, $37 per megawatt hour. And if you look at the last two and three weeks' averages, it's been even lower. Rick will give you some more detail on how this impacted our bottom-line financial results for the quarter in just a minute.

Just as important and maybe more so, the expectations for future prices has settled [down] quite a bit. So we don't think this is simply a reflection of the mild summer weather that we've had to date.

To give you a sense on the forwards, if you look at the 12- to 24-month forward strip, now trading in the range of $34 to $35 per megawatt hour. Now that, of course, is for energy only at the Indiana hub. In order to drive what the price would be at our plants, you'd need to add about $3 to $4 per megawatt hour. So $34 to $35 for energy today -- just at the end of May, those same strips were trading at $39 to $40 per megawatt hour.

As you know, these markets are also driven by the price of natural gas. The price of gas is trading right now just shy of $3.80 for -- per MMBtu. Just to give you a sense -- most of you follow these markets, obviously -- that same price was in the $6s and $7s at its peak during the winter and as recently as the end of June was still trading in the mid to high $4s.

So this is all, again, consistent with our expectations and we're now getting closer to the point at which fixing a portion of our power needs might make sense. Of course, the power markets are complemented by the increase that we've recently seen in [forward] metal prices. We're watching the situation very closely, and I'll give you some more comments about this in just a couple moments.

In the power area, again, I'll detail this a little bit later. We're also looking at a variety of alternatives, both to manage the market price risk and to mitigate any risks of future congestion pricing.

Moving on a little bit here, we've got a labor agreement at Sebree we're very happy to report. You saw us announce this a couple weeks ago. This is an early resolution. As you know, the existing contract isn't set to expire until the end of October. We've had a very good working relationship and good communications with the local steelworker leadership since we acquired the plant last year, and we mutually decided that our objectives were largely aligned and thus we decided to give it an early try. The yearly agreement allows us to enter the 2015 commercial season with good confidence.

The power curtailment at Grundartangi is now over. As a reminder, this winter the reservoirs in Iceland were at 40-year lows. And thus, the national power company curtailed the portion of our power that was obviously per their contractual right. They could curtail, pardon me, all the large users in the country. The reservoirs are now back to better levels and full power was restored to Grundartangi in May. And we had all our pots online as of the end of May.

We had very good communication and cooperation from Landsvirkjun, that's the national power company, during this difficult period, and we appreciated that. And Rick will give you some detail on the lost production and the financial impact of that lost production.

Moving along at Mt. Holly -- as you saw us announce a couple weeks back at the end of June, we were forced to give a notice of termination for post-2015 power. Let's take a step back. As a reminder, in 2012, we entered into a 3 1/2 year agreement, and that agreement allowed us to go off system and purchase power from a dedicated resource. This agreement expires at the end of 2015 but the master agreement with the power company, with our supplier, Santee Cooper, a public service company in South Carolina, goes on through the end of 2023.

Without that termination notice, we would've been liable for a significant demand charge for the period 2016 to 2023. And that, of course, is whether the plant is operating or not. We weren't able to agree to the last proposal that the power company made to us several months ago. The terms of that proposal would have rendered the plant not viable. It would have given Mt. Holly the highest power cost of any smelter in the US and by a pretty good margin.

We're now re-engaged with the power company. We absolutely wish to operate this plant over the long term. As you know, those of you who followed the Company for a long time, it's a terrific plant, got an excellent safety record, one of the most efficient smelters in the US. But, of course, the noncompetitive power price trumps all those favorable attributes. We believe the power company and the state political leadership are committed to help us find a solution that works for all sides. Again, I'll have some more comments in a few minutes.

Last, but definitely not least, after a six-month search, we have a new Chief Financial Officer, and we're absolutely delighted to have Rick Dillon on board. You'll hear from him in a couple minutes. He joined us in mid-June, has already dug in in numerous ways. Those of you who've had a chance take a look at his CV, he's got a terrific background. He was -- has been the chief accounting officer of three respected public companies. He's got a good knowledge of the mining industry through his last employer, Joy Global, obviously a major supplier for mining industries worldwide.

And most important, Rick's got a real passion for helping businesses improve and he's got the knowledge and experience to understand what it takes to make it happen. Again, we'll let you hear from him in a couple minutes but first I'll ask Shelly to detail our views of the market environment. Shell?

Thanks, Mike. If we could move along to slide 5 please, I'll provide some comments here on the industry environment. The average cash metal price during the quarter was $17.98 per tonne. That's up 5% from Q1 when the price averaged $17.09. Since quarter-end, LME prices have had a significant run-up and are currently sitting right around $2,000 a tonne and sentiment toward the aluminum space has become much more positive recently.

LME inventories remain high compared to historical levels but there has been a significant downward trend over the last several months and we've seen a decline of about 500,000 tonnes just since mid-March, although it is likely that some of these inventories have simply moved from registered to nonregistered warehouses.

As you can see on the chart, the combination of steady growth and demand and declining inventories has led to a meaningful reduction in days' inventories from almost 70 days at the peak of the financial crisis to less than 45 days currently.

On the back of these positive developments, regional premiums have continued to strengthen and are near their all-time highs set earlier this year. The US Midwest premium is currently $0.20 per pound, and the European duty paid premium is slightly higher at $455 per tonne.

Digging in to the industry fundamentals a bit, in the second quarter, global demand was up almost 7% versus the second quarter of 2013. If you pull out China, demand was still up 4.1%. In the US, we saw improved demand in Q2 as compared to the first quarter, which was impacted by severe winter weather. And in Europe, consumption was strong in the second quarter despite some recent signs of economic softness.

Both of these key regions that we sell into are showing good growth in aluminum requirements for the automotive and aerospace industries, and this is a trend which most industry experts expect to continue for some time.

On the supply side, global production was up 6.5% in Q2 versus the year-ago quarter driven by continued Chinese growth. Outside of China, production was essentially flat. We continued to see announcements and implementation of curtailments in the Western world during the second quarter, but these were mostly offset by the ramp up of facilities in the Persian Gulf.

Bottom line, most analysts expect to see a modest global deficit for aluminum in 2014 with the supply-demand gap growing over the next several years as a result of healthy demand growth and few smelter projects in the pipeline outside of China.

Okay, just a couple quick comments on alumina before we go onto the next slide. This market traded down over the quarter to about $310 per metric tonne or FOB Australia pricing, and Atlantic Basin is trading at about a $15 discount. This market looks to be reasonably in balance, but there does remain some uncertainty as to how the Indonesian ban on bauxite exports could impact the market in the future.

If we could move along to slide 6 -- so just to round out the industry discussion, we want to provide an update on the aluminum cost curve. This curve here shows global smelter cash costs net of premiums received above the LME price. So this will be comparable to the way we presented our expected 2014 net cash costs back in February. As you will recall, Grundartangi's costs are highly sensitive to the LME given that both its alumina and power costs are directly linked to the aluminum price.

So with the recent improvement in LME, we believe the Grundartangi plant now sits at the low end of the second quartile and our US plants are all right around the midpoint of the curve thus resulting in a Company-wide position of about the 45th percentile.

With that, I'll hand it back to Mike to talk about operations.

Thanks, Shelly. If we could turn to slide 7, please. As Shelly said, I'd like to give you just a quick update on how the operations did during the quarter and then I'll turn you over to Rick for the financials.

First and foremost, as you see here, we didn't make the progress that we would've liked to make in safety this quarter. This is an area, those of you who follow it so you know, in which sitting still will definitely cause you to go backwards. Thus, continuous improvement is absolutely necessary. And looking through, there's no specific area that gives us pause. Our assessment is simply that perhaps we've had some complacency seep into our system given the very good performance that the teams have notched over the last couple years.

This is an area that our Board and our management team will only accept excellence in. And simply being better than the industry averages, which is squarely where we sit today, is not nearly good enough. Thus, as you would suspect, I and my senior team are spending a lot of time and effort appropriately in this area and will continue to do so.

Production, as you can see moving down the page here, was down a little bit at Hawesville this quarter versus Q1. Remember, this is all -- all these data are a comparison of Q2 to Q1. This production decrease at Hawesville was the result of some conscious decisions that we made in May -- I referred to these earlier -- in which we scaled back productions on days when power prices were higher than they otherwise should have been due to some congestion in the local transmission system. This condition is now gone and the average energy price that we are paying at our nodes or our plants is essentially equal on a weighted average basis to the Indiana hub to the liquid node.

This is also the result of some other power modulations that we saw during the quarter, most specifically a lightning strike which we took at Hawesville in late June. We're still feeling the impacts of these power modulations with more pots out of service than we would normally have at Hawesville, and our assessment is this condition will go on for the next month, month and a half or so. So that could cost us in Q3 anywhere based on our current estimates from 1,000 tons to 2,000 tonnes of production.

Moving to the right at Grundartangi, the decrease that you see in Q1 was solely as a result of the power curtailments that we saw due to the weather.

Moving down the page, production metrics and efficiencies -- as you can see, KPIs were stable across the plants. We've got nothing unusual to report there.

Before talking at the bottom of the page about the conversion costs of performance at each of the plants, I'd like to note again Shelly's point about Century's position on the global cost curve. Those of you, again, who've been following the Company for some time have seen the significant improvement here. Go back a couple years where our weighted average position on that cost curve was somewhere toward the middle of or even the back end of the third quartile. And as Shelly said, we believe we now sit at about the 45th percentile.

Obviously, a lot of that improvement is coming from the Kentucky power restructuring that, as you know, we've also made very good progress in all the plants and all the other cost areas and this is a process that'll continue.

To go through the plants one by one quickly -- at Hawesville, that significant improvement that you see there is largely driven by the decrease in the delivered power price about which I spoke. We also saw a nice improvement during the quarter in maintenance and supply spending specifically.

At Sebree, most of that decrease you're seeing is coming from the power cost. Mt. Holly, power costs were down about 4% quarter to quarter. We gave some of that back with supplies and maintenance spending at Mt. Holly, up about 2 percentage points quarter to quarter.

And at Grundartangi, that increase is solely due to the production decrease due to the weather as obviously we had to spread the fixed costs of the plants across a lower tonnage of production.

And with that, I'd like to hand it over to Rick.

Thanks, Mike. Let's turn to slide 8 of the presentation. I'll provide some additional details on the second quarter financial performance.

Our net sales were up 9% from the first quarter reflecting the combined impact of favorable market conditions as well as increased volumes quarter over quarter.

Looking at the market impact, on a one-month lag basis, the average cash LME price was up approximately 2%, and Midwest premium transaction price was up approximately 4%. Realized prices in the US and Iceland were also up 4% sequentially in line with the Midwest transaction price increase and a European duty paid price increase.

On a consolidated basis, global shipments were up 4% in the second quarter versus the first quarter of 2014. Our US shipments were up 5% with the Mt. Holly operations driving this increase.

As we discussed last quarter, we ended the first quarter with elevated inventory levels at Mt. Holly due to timing of production with shipments coming through in the second quarter. Our Kentucky operation's shipments were essentially flat quarter over quarter. In Iceland, we had direct shipments of almost 40,000 tonnes in the second quarter. Total volume for Iceland was up 3% sequentially. As a reminder, the nature of our business in Iceland is transitioning from tolling to direct sales and this is expected to continue through 2016.

The first quarter was an unusually low quarter for shipments as we made a working capital investment in finished goods needed to support a growing direct sales business. In addition, as discussed last quarter, the impact of weather patterns on power availability also resulted in lower shipments in the first quarter due to production curtailments.

As expected, the power shortages continued through the second quarter, and the impact was in line with our estimates of approximately 3,000 lost tonnes. As Mike noted, power availability in Iceland is now stabilized and despite these headwinds, total shipment levels for Iceland were back to pre-curtailment levels by the end of the quarter.

Turning our attention to operating profit, we are reporting an adjusted operating profit this quarter of $44 million, an increase in its entirety when compared to the zero reported adjusted operating profit in the first quarter of 2014. The two drivers of the improvement are market pricing and power costs.

Higher all-in pricing, including a rising LME, regional premiums, value-added product premiums, and the impact of the LME on our alumina and power costs, all combined to improve operating profit by $21 million.

Now let's take a look at slide 9. Lower power prices improved operating profit by $23 million quarter over quarter. Hawesville power costs were down $12 million and Sebree power costs were down $10 million from the extreme highs caused by weather conditions in the first quarter. These improvements are consistent with our discussions on last quarter's call with the difference being two things: average Indiana hub prices coming in a little higher than we had assumed and the congestion issues experienced in May as Mike discussed.

So our average delivered price to Kentucky in the second quarter was $41 per megawatt hour and that's higher than the $37 assumed in our analysis on the last call. We have included again on slide 9 the historical and forward pricing information for the Indiana hub, which is the closest liquid node to our Kentucky operations. So you need to add another $3 to $4 per megawatt hour to get to the delivered price to our Kentucky operations.

The graph shows average Indiana hub prices in the second quarter were approximately $37, down from an average of approximately $56 per megawatt hour in the first quarter. The forward view of our delivered prices for the Indiana hub would suggest back half of 2014 prices of approximately $33, and that is consistent with July average prices to date. As a reminder, every $1 per megawatt hour impacts EBITDA by approximately [$1 million] per year.

Mt. Holly power costs were also down by $1 million driven by the decline in natural gas prices from the first quarter. As Mike discussed, however, prices in the second quarter remained elevated in the mid 4s compared to pre-[winter] pricing in the mid to upper 3s. Since quarter end, natural gas prices have followed nicely and currently sit around 3.8 MMBtu. So the operating profit improvement resulted in adjusted earnings per share of $0.22 per quarter, an improvement of $0.46 from the first quarter of 2014.

Moving on to liquidity. Let's turn to slide 10. Cash increased during the quarter by $9 million with adjusted operating profit being the obvious driver of the increase. The offsets include capital spending, taxes, interest, and working capital. Capital spending was $9 million in the quarter, which is down $7 million from the first quarter. The decrease reflects delayed timing, planned spending on our anode facility in the Netherlands, and continued investment in our smelters including expansion at Grundartangi. As a result, we expect back-half capital spending to be higher than the front half, but we still see spending in the $50 million to $60 million range for the year.

Taxes primarily reflect temporary withholding taxes in Iceland and interest reflects our semiannual interest payment.

The working capital increase is driven by the timing of liability payments in the quarter. The impact of the rising LME in the quarter on accounts receivable and inventory was offset by the work-down of inventories previously discussed.

In the third quarter, we expect working capital to be unfavorably impacted as the extended terms we have had on our Mt. Holly power invoices expires and we move from 60- to 30-day payment terms. This will result in a one-time impact of approximately $8 million in the third quarter.

There are no outstanding borrowings under our revolver other than letters of credit and available liquidity increased by $9 million. No change in our debt this quarter. However, a quick note here that we will retire the remaining 2004 senior unsecured notes carried at $2.6 million upon maturity in the third quarter.

With that, I'll turn the call back over to Mike to discuss our third-quarter priorities.

Thanks, Rick. If we could just go to slide 11. As Rick said, I'll go through for you a quick summary of some of the things on which we'll be focusing over the next couple of months and what you should be expecting from us, and then we'll get right to your questions.

As we've discussed before, we think the current market power environment looks favorable. This is partly due, of course, to the unusually mild summer that we've had to date in the Midwest and Eastern part of this country, but we think it principally represents a return to the pre-winter [bump] in forward pricing. Thus, we're looking hard at fixing a portion of our power requirements. We're considering [tenors of up to 24 months at most. We don't think the risk/reward tradeoff after that kind of period is favorable.

We're also analyzing a spread between power and metal prices. Obviously, when you're going to look at fixing a portion of your largest cost, you need to look at whether it makes sense to also fix a portion of your output as well.

We've got the hedging facilities in place. They have attractive credit support and so we're ready to go when we deem conditions are ideal.

We're also discussing with several third parties a variety of bilateral power purchase agreements, and some of these would likely mitigate any future transmission congestion issues were they to occur in the region. In addition, we're looking at the rationale of actually acquiring generation assets of our own and/or entering into long-term leases of generation assets. So, again, you should expect more to come from us on this topic over the next couple of months.

Moving on, the initial value-added investment projects that we launched earlier this year are nearing completion. I'll just detail them quickly for you. At Sebree, the small form foundry line is on schedule to start producing trial quantities in August. Assuming the product is qualified, we would plan to sell up to 60,000 tonnes into these markets in 2015. These products attract a good premium above the incremental casting costs and in addition it will decrease the amount of metal that we need to sell at Sebree next year.

At Grundartangi, the foundry alloy project is almost complete. As you'll recall, this was a reasonably modest investment, about $2 million. We've been producing trial quantities on a manual basis over the last couple months, and this has given us the ability to learn the production process and, importantly, to engage with customers [and qualified their metal]. Again, assuming success, we'll dedicate between 50,000 tons and 60,000 tonnes most likely to this premium product in 2015.

Shelly noted the favorable conditions of these markets, and these value-added markets do indeed remain underserved in the US and in Europe due to the expected growth in the automotive market and several other industries as well. Right now, a significant amount of these products must be imported. The product is principally coming from places like Russia and the Persian Gulf. And for a variety of reasons, we're hearing from customers that they want high quality local supply.

In that context, we're analyzing more significant investments that'll allow the Company to address these opportunities over the years to come. And again, we'll be providing you updates over the next couple quarters.

At Mt. Holly, as I said before, we've re-engaged with the power company. With them, we're going through a complex series of issues, looking at a variety of structures. And despite this fact that the current contract doesn't end until December 2015, we'll be pressing hard for a conclusion over the next couple months for a post-2015 arrangement.

At Ravenswood, we've made some reasonable progress during the last couple months. We're exploring various structures that would provide a long-term, competitive power [rate] at the plant, and of course, at the same time, also need to work for the power company and for the rate payers. As we said, the market environment is favorable. This metal is needed in the US. And we hope to have news to report in the reasonably near future, perhaps before the end of the year.

One more time, we want to make sure you understand that the restart of this plant is right at the top of our focus list. We're working hard on it.

And with that, Pete, I think we can move to questions.

Thanks, Mike. Cathy, if you could go ahead and kick off the Q&A session.

Certainly. (Operator Instructions) Sal Tharani, Goldman Sachs.

I just wanted to understand or reconcile the (inaudible) from first to second quarter. The other slide last quarter revealed that if you didn't have power issues or other obstacles you would made about $31 million of operating profit. And then I think this quarter you announced about (inaudible) or so, but [we are still] $23 million of power benefit and your conversion costs were lower on both (inaudible) plants. So I'm just wondering am I -- I mean, what could be -- what are we missing in these two -- [in these slides]?

Sal, with apology -- we're going to try to answer your question. We heard -- the connection is quite bad. It sounds like either you're on a mobile or -- I'm not sure what. So we kind of heard every other word. But we think what you asked is could you compare -- and please correct us -- Q1 to Q2 operating profits, look at Q1 pro forma for what you said the power would have been if the winter weather hadn't driven up power prices and kind of relate that I'll call it pro forma number to what we actually reported in Q2. Is that where you're heading?

Yes, exactly. So from ]31 to 42], you had a power benefit in second quarter. You have a higher aluminum price. I thought that the [annual] conversion cost was lower. So I thought that the -- if I look at the sensitivity to your aluminum price to your volume or to your total volume, that's going to be even higher than what [you have reported].

So from a power perspective, the 31 versus the 23, that is almost entirely driven by the $41 per megawatt hour that we saw in the quarter versus the $37 we talked about. Using our 2014 items that we provided, if you calculate that sensitivity, it's about an $8 million impact.

So it wasn't -- the point is, Sal, it wasn't quite as -- that pro forma was done at a lower price than it actually came in. It came in a couple bucks above. Just to give you -- I can give you further to -- just to come at it from another perspective, let me just give you some of the big movers of profitability quarter to quarter sequentially.

Again, as Rick said, we went from 0 to 44, so of that, 18 -- of that [delta] of 44, 18 was due to the net impact of the aluminum price. And when we say net, of course, you guys know how we talk about that. We mean the realized price net of the increased cost for alumina and power in Iceland which, of course, floats with the price. So that was $18 million. Kentucky power, as Rick told you, was $22 million and South Carolina was another $1 million, so $18 million plus $23 million, that gets you to a little bit over $40 million.

And then there was a bunch of [nits and lice] going up and down, but that's basically the road map, if that's what you're looking for, from Q1 to Q2.

Yes. Okay, good. Now I understand now. I appreciate that.

Great.

And then on Mt. Holly, did -- is there (inaudible) there that you can do similar power (inaudible) as you did at Kentucky or is it not allowed in that state to do -- and go buy power outside?

Yes, I mean, the answer, Sal, is yes. It would require some call it structural changes, but as you know, we've gone -- we're buying power from outside the Santee Cooper system today. We have been since mid-2012. They wheel it in to us because as you suggest, South Carolina's not a retail access state so you have to buy power from the -- I'll use the easy term, the monopoly utility power provider.

The other difference is -- it's important to understand -- is that there's not an organized market in South Carolina like there is in Kentucky, which is part of MISO, of course. You'll see reference to the VACAR market -- that means Virginia and Carolinas. But it's largely a bilateral market. There's nowhere where you can go to see a price and there's not the kind of organized market that there is in MISO. So that's a long-winded way of saying it can be done in South Carolina, Sal, but it's not as, I guess, easy as it -- it wouldn't be as easy to do as -- not that it was easy in Kentucky, but it would take some more doing. Let me leave it at that.

So you and your partners are ready to shut down if power price come to your expectations?

Yes. We're absolutely aligned.

Okay. All right. Thank you.

Thanks, Sal.

Brett Levy, Jefferies.

First off, I am also calling on a cell phone. Does it also sound like I'm coming from a Kung Fu (inaudible)?

No. Your mobile gets a higher grade. You sound good.

Okay. Can you guys talk a little bit about Iceland, either the Helguvik situation, if there's any progress on the Grundartangi expansion?

Sure. Absolutely, Brett. I'll take the latter first because that's easy. So we're on -- I think Rick alluded to this -- we're absolutely on target there. We lost production due to the weather cutbacks, but the expansion continues apace. We're right on plan or a little bit ahead. And we'll be updating -- we'll be giving, as we usually do in the February call, we'll be giving you the tonnage for 2015, but we're right on pace there.

On Helguvik, really we didn't talk about -- we didn't put it in our [outbound], I suppose, comments this quarter because really there's been no change to the assessment that we've taken you through, which is that we really need the national power company, Landsvirkjun, to step up into a leadership role in this project if we're going to get this thing going in the -- any time near future. And discussions continue, but there's been no substantive change in the status as of 90 days ago.

All right. And I mean, is it really just like an availability issue? Because, I mean, even if they gave you power at sort of half the global cost, it would still be very lucrative to make more aluminum in Iceland. I guess the question is are they being ridiculously greedy, are you being ridiculously greedy, or is it just sort of -- it's something in the middle?

It hasn't even gotten to that. It's -- let me take a step back. Maybe I -- I probably talked about this last time, but it may have been in a conference or something like that. So, really, in Iceland the debate, which frankly, for what it's worth, is an appropriate one as far as we're concerned, is on two levels. The first is whether they're going to develop it or not. So, to your point, it's certainly there, there in abundance. But the question is from an environmental and otherwise standpoint, do we as a country, as a society -- we, Iceland -- wish to develop it or not. So that's, call it, an environmental question.

And the government has put certain projects into -- they call it the framework program, a -- basically green light, yellow light, and red light is the easiest way to think about it. So, the question is are more projects going to be taken from yellow and put in green and more projects going to be taken from red and eventually [find] their way to green and that's an open and very public debate in Icelandic society.

And then after you answer that one, it's kind of -- they're kind of serial questions, I suppose. You need to ask yourself -- again, this is the debate in Iceland -- if we're going to develop it, how do we wish to use it? And as you say, we would agree with your comment, we couldn't say it any better, but there are other opinions as well. You may have seen, it's been very public, in the Icelandic press anyway, that they're looking at potentially building a submarine cable, an underwater cable. Quite a long one; it would go, of course, all the way to the UK and would be [terminus] in some place like Scotland. And then all the predictable questions are asked about how we as a society wish to use our power and we wish to use it to encourage employment and economic development in the country or do we wish to try to sell it in Europe for a price that goes up and goes down. It might be higher, it might be lower.

So that's a very long-winded answer to your question that the price negotiations to which you allude haven't even taken place because they're pending those sort of contextual structural decisions.

Got it. Okay. And then also, I mean, obviously, with the Midwest [premium] where it is and aluminum where it is, I mean, is there a percentage that you are locked in at for a certain amount of your US production? It's the same question I ask almost every quarter. What percent of production in the US is price locked in and what are your plans for the back half of the year in terms of percentage of the production that you'd like price lock?

None of it's locked, Brett. So it's all sold, but it's sold at the market price. And generally on a one-month lag is the way our business usually flows, not just Century's but the industry convention. So in -- you asked it for the US, but in Iceland and in the US, it's all sold. It's all committed. But it doesn't price until a month ends and then you calculate what the one-month prior price was and the Midwest premium or the European EU duty-paid premium and that's what the customer owes you. And so none of it is priced.

And there are no LME hedges or anything else like that?

No. Nothing on the books --

What it tells me is you're very [bullish] right now.

You know, this is where we were also, Brett, 12 or 24 months ago, and this is the wonder of hedging. You have Monday morning quarterback discussions all the time. Had we hedged, of course, we'd be flogging ourselves now. But as I did say in my remarks, an interesting analysis to do, which as you would hope we do and update daily, is the spread between -- and I'm talking about the US only, which is perhaps to your question, if you [were going to] quote-unquote protect some of your production where you'd be doing it and the spread between metal and power prices because the rest of your costs you pretty much know. Your alumina is priced. All the rest of your plant costs are within de minimus variations as long as you're running your plants correctly. You already know what those are, and so you know that spread is getting to be one that we're looking at hard because you can in essence -- I don't like using this term, but I'll use it for brevity -- lock it in.

Right. And so what you're basically saying is you will consider locking in aluminum after you've got a little bit more certainty on some of the elements of your power costs?

I think that's a good -- that's a fair way of looking at it. And the way, Brett -- so yes, but the way you can get more confident or certain about your power costs is about just driving that confidence or by locking in that power cost through the markets or through a bilateral arrangement with a power generator or somebody else who's got power to sell.

All right. Thanks very much for the color. Take care.

Thanks.

John Tumazos, John Tumazos Very Independent Research.

With the floating power or market base power, do you operate something resembling a small in-house trading desk for power, metal, alumina? Or do you farm some of that out to a consulting or trading company like your shareholder Glencore and pay them a market-based reasonable fee for that? Or how do you manage all the moving parts that we're looking at? And we commend you for working so hard.

Thank you, John, and thanks for an insightful and excellent question. And so the answer is on the metal, alumina, no. Absolutely not. Right now, we're price taker on a daily basis; like I said, priced every month.

On power, you ask a great question. And when we in May saw some, for example, some of those transmission congestion issues, it was over a course of like two, maybe three weeks. We did look at, as I said, the tradeoff every hour, literally, because as you know, the MISO prices come out in hour increments, every hour of whether it made sense on behalf of the shareholders to make metal incrementally or made sense to dial back. [That's why there was] a couple more sales out at Hawesville right now because it kind of -- it doesn't do well with the [stability] of the plant and to sell the power back into the marketplace. And so that's what -- at the margin.

Now, you could only do that to a certain extent. You can't crank the plant way back. It's not -- there's only an extent to which you can do it. But there is an ability under our power contract. Obviously, it's all laid out in the contract what we can do and what we can't do because, as you know and as we said in an answer to a different question, retail [wheeling] isn't allowed in Kentucky. We're not a utility. But to a minor extent we can do it and we did do it in May to the extent that we were able.

Thank you.

Thanks.

Sal Tharani, Goldman Sachs.

Thank you. Mike, you mentioned an interesting point about owning a power asset or leasing long-term. I don't know what the relationship -- is there any strong correlation between gas and power price? And how about owning a gas asset rather than a power asset? [You know, it's] easier to own and more abundantly available. Have you thought about that?

Oh, absolutely. When I -- if I misspoke, Sal, so thanks for the follow-up -- when I said a generation or a power asset, we're willing to consider coal-fired, gas-fired, a combination of the two. As you say, there's a pretty easy -- if you're familiar with these markets, a general calculation that you can make between -- depending on the asset that you're talking about and its efficiency heat rate in the parlance of the industry between the price of the coal, delivered price of coal, on the one hand or natural gas on the other and the cost of the megawatts that are coming out of the generator. So, absolutely.

And Mt. Holly, as you know, a deal that we struck a couple years ago is indeed with a gas-fired system. That's a long-term lease and that's, in fact, exactly what it was. We leased that capacity for 3 1/2 years, and -- so absolutely. We think there's great opportunity in Kentucky on the coal-fired side, of course, Kentucky being a big coal supplier, and so we're spending a lot of time there. But we would -- we are looking at and we'd be happy were it to prove economic to act on either.

Well, what I meant, Mike -- I'm sorry -- is actually owning a gas exploration field --

Oh, I'm sorry, Sal. I apologize.

-- rather than a power asset because (inaudible) a very good correlation between the pricing of the two makes it easy to own [and find] gas exploration. I'm not sure. I just wondered -- was wondering if that makes sense.

I apologize. I didn't listen well to your question. That is, indeed, what you said. I guess the way I'd answer that is that -- you've kind of got to draw a bull's eye or the archery target, whatever it's called, and as you get sort of a standard deviation or two outside your core competency -- which leads me to what we're doing now. We are working with some folks who actually -- companies who own those kind of assets and develop them. That's what they do for a living -- as partners to see whether we could attack a situation together, whether it's a generator that could be for sale, a generator that's currently closed that could be reopened, something like that. I think for a company like ours, that's the best way to approach something like that. And that's what we are doing right now in a couple circumstances. We've got a bunch of oars in the water.

Okay. Can you remind us of the Grundartangi transition from the tolling to the direct? Is it going to be transitioning fully to direct by 2016? Is that the idea?

Yes. It's Shell. So, the expectation is as we move forward the tolling contract will transition to direct. We have about 40,000 tonnes that roll off at the end of this year and the final 90,000 tonnes rolls off in mid-2016.

Okay. Great, and the last question I have is on Ravenswood power contract, the power negotiation. Is it going to be -- are you only considering talking to the power companies or are you looking at the other options like Kentucky option also?

Both. Both. It would, again, all be done through the power company, Appalachian Power, and so they're a part of all these discussions. They're a good partner. They -- we're convinced they want this plan open, truly, the smelter open, as much as we do. The question is at the end of the day assuming success what the right formula is. I wouldn't want to predict at this point in time, but the answer to your question is both.

You mentioned that is your highest priority so we could [see that as the next big investment or big (inaudible) [from you]?

Sal, that one I missed. We missed entirely. None of us caught that one. You said you mentioned that and then we --

Of your most important priority of the company you mentioned [potentially.].

Oh. Yes, I mean, this is something that, as you know, we've been working on for in earnest for four years that I can remember off the top of my head and you know even before that since the plant closed, but in earnest for the last three to four years. We think it's in the prospective market environment and assuming we can get to a power structure that offers upside but protects the shareholders on the downside, we think this would be a great investment for the shareholders. There's a restart cost, but it's reasonably modest in the grand scheme of things. And the plant, we think, could be producing quickly and producing a product that's needed in the marketplace with that customer right next door that we believe would like a good chunk of it in molten form. That's Constellium's plant, of course. So, it's got all the attributes of something that would be reasonably low risk, again, assuming power and could give some nice upside.

And (inaudible) cash cost of the Kentucky power -- Kentucky smelter?

I'm sorry?

What sort of the cash costs eventually that would be close to -- I mean, the electricity (inaudible) are the same. It's the (inaudible) cost is very similar to the Kentucky smelter's?

It would be worse, Sal, because of the inefficiencies due to the output. Just to remind you, Ravenswood is 170,000 tonnes of annual capacity. Its next closest one going up size is Sebree, which is just a hair over 200,000 tonnes, as you know. And more importantly, the Ravenswood pot is quite small, so there are more [sells] per tonne of output, which means you need more operators to tap the metals and set the carbon, etc., etc., etc., so it would be more -- it would not be as good as Kentucky.

Okay. Thank you very much.

Thank you, Sal.

Paretosh Misra.

Hi, Paretosh Misra from Morgan Stanley.

Hi, Paretosh.

Hi. So, if you have considered hedging both pricing and cost for at least two of your smelters in the US, I'm just curious have you also considered an MLP structure?

An MLP structure?

Yes.

That seems to be all the rage these days, telecoms and now aluminum companies. That's a great question. The answer is -- the factual answer is no. And I'm not even going to take a stab at that one, but I'm sure going to go research it now. I don't even know whether it would be applicable to our industry from a tax standpoint. I understand your point on -- I think, I should say; I shouldn't be presumptuous -- understand your concept that if you kind of fix out the cash flows that would make a nice, conceptually anyway, a nice candidate for a partner, for an MLP. But the answer is no, we haven't looked at it.

Okay. And just going back to the hedging part for the metal, are you talking about hedging both LME and premiums? Because I wasn't even sure if the market for the premiums is that liquid.

You're correct on the latter.

Yes, it's not that liquid, but there are transactions that can be done. As you can imagine, in this market, with strong premiums, buyers and sellers are generally quite far apart so that's really making liquidity quite difficult. But we would look at all three components. We would look at power, we would look at LME, and we would look at premiums.

Understood. And last question, just any commentary on the imports, especially given, I think you said, that US premiums are now below European premiums? So that should be -- that should reduce an incentive for imports, right?

All those being equal, you bet. But that -- as Shelly said, Shell, that run up in the EU duty paid premium has really come over the last 60 days?

Yes. Absolutely. And the Midwest is now starting to creep up again, so they're kind of neck and neck.

But you're right. That -- those two premiums, obviously, people [who are in] metal are doing that same math every day.

Great. Thanks, guys.

Thanks.

Paul Massoud, Stifel.

I apologize for my cell phone connection, as well, but first, if you could just give us a sense of what you think your tax rate might look like for the second half of the year. And then the second question would be all else being equal with all the moving parts, where do you think you'll end up on the cost curve by year end?

I'll touch on the tax [issue] briefly. I think the effective rate the second quarter was close to 8%. We aren't a taxpayer in the US right now because of our outstanding NOLs with the exception of a few state taxes, and we pay taxes on our Iceland operations at around 18%. So, as you work through your model, if you can kind of carve out the Iceland operations at 18%, wherever that lands you from an effective tax [perspective.]

From a cost curve standpoint, the numbers we put out there were based on the information that we gave you back in February for Q2 through Q4 of the year. At this point, we have not made any updates to those numbers. There've been a few things that have moved around. Power is just a little bit higher in Kentucky, but premiums are stronger, which offsets that impact. So, again, no real update to those numbers. We will come out in February of next year, as we do every year, with updated forecasts for cash costs. So at this point in time, we're not projecting any change from what you saw on the cost curve.

Thanks.

There are no further questions. Please continue.

We'd like to thank everybody again for joining us this afternoon, and we'll speak with you -- look forward to speaking with you in October.

That does conclude our conference for today. Thank you for your participation. You may now disconnect.