Peabody Energy Corp (BTU) 2006 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Peabody Energy quarterly earnings conference call. For the conference, all the participant lines will be in a listen-only mode. However, there will be an opportunity for your questions, and instructions will be given at that time. [OPERATOR INSTRUCTIONS] And as a reminder, today's call is being recorded. I would now like to turn the conference over to Mr. Vic Svec. Please go ahead, sir.

Thank you, John, and good morning, everyone. Thanks for taking part in the conference call for BTU. Today our Chief Financial Officer and Executive Vice President of Corporate Development, Rick Navarre, will review our results and our outlook. President and CEO, Greg Boyce, will discuss the markets, as well as several prominent growth initiatives. Forward-looking statements should be considered along with the risk factors that we note at the end of our release, as well as the MD&A section of our 10-K. We also refer you to peabodyenergy.com for additional information. And I will now turn the call over to Rick.

Thanks, Vic, and good morning, everyone. And thank you for joining Peabody Energy's earnings review today. Peabody turned in record second quarter results, reflecting the strength of our diverse business portfolio. First let me cover some of the highlights. Net income increased more than 60% for the quarter, and more than 90% year-to-date. Our EBITDA grew 29%. We continue to sign business at prices well above last year's realized pricing. We completed major longwall installations, and progressed on several other capital projects to meet growing demand. And we announced the acquisition of Excel Coal, which Greg will talk more about in his remarks.

Moving to the income statement, you will see second quarter revenues were 19% higher than last year due to both increased pricing and volumes. Expanding operating margins and strong performance from our other business activities fueled a 29% increase in EBITDA for the quarter, and earnings per share grew 58% to $0.57. Before I drill down into the supplemental detail, I would like to point out that 2006 revenues per ton again grew in all operating regions, driven by higher across the board realized prices. While it was a challenging quarter for Peabody, the reasons I will discuss in a moment, we are still reconfirming the upper end of our full year targeted range, and raising the lower end of our targeted range.

So now looking at specifics, we're very pleased with our western cost per ton performance, which would have been essentially flat, absent the impact of new longwall installation at Twentymile. Elsewhere in the west, our Powder River operation set a production record for the quarter and for the full first half. While PRB transportation improved over the prior year, we are still experiencing rail delays. Our eastern costs per ton were affected by contract miner costs, fuel expenses and a production mix. The operations also had to absorb record oil prices, which we expect will impact full year earnings by $50 million. Oil prices also led to the idling of all the synfuel plants that we supply, reducing full year EBITDA $20 million from earlier targets.

Now, let me update you on our longwalls. As we mentioned in our first quarter call, we had planned 2 new systems this quarter to be installed. While we factored in some delays in the installation, the extent of the issues was much greater than we had expected. Specifically in Colorado, the new longwall start up has taken 54 days longer than planned. This was due to an extended install time and equipment failures. The North Goonyella longwall had similar challenges. It took 50 more days to complete because of extended set-up time, followed by equipment and software issues. All told, these events lowered second quarter EBITDA $52 million. Needless to say, we were very disappointed with the initial performance of both of these new systems. On the bright side, North Goonyella is now performing at or above our expectations, and we anticipate Twentymile will reach the same results after we work out the remaining issues with the vendor. What I can say is that as of this morning, of the last 7 days production at Twentymile have been running at targeted levels, which handily exceeds the production that we had under the old system. So we're very encouraged by that.

Turning to our other business activities, Peabody earned $21 million from trading and brokerage in the quarter, and resource management added $46 million. This quarter is another solid example of the power of Peabody's business model, with multiple regions and activities contributing to our performance.

Now I would like to update on you the organic growth projects that we have underway. We invested $200 million during the first half of the year, and continue to target full year CapEx spending of 450 to 525. Major products include the 2 new longwall systems, which will normalize at higher performance levels during the second half of this year, the new Black Stallion metallurgical mine in Appalachia, the Wildcat Hills thermal operation in the Midwest, upgrades at both Caballo and Rawhide in the Powder River Basin, our new ultra low sulfur School Creek Mine continues to progress. During the quarter we filed the permit for the first new mine to be opened in the Powder River Basin in 15 years. And development of the El Segundo Mine in New Mexico.

Turning to our sales contracting position, we continue to layer in profitable, long-term contracts at very attractive levels. During the quarter we priced 33 million tons of business, and our premium Powder River Basin products was committed at prices more than double last year's realized price per ton.

Which brings me to our outlook. After a record start, we are targeting third quarter results with EBITDA of $250 million to $300 million, and earnings per share of $0.35 to $0.55 per share. And as I mentioned earlier, we are raising the lower limit of our 2006 range to 1 billion and 50 million, reaffirming the high end at 1 billion 150 million, resulting in an earnings per share range of $2 to $2.43, which means we will have a higher fourth quarter, which is in line with past year's performance and in line with the guidance that we'd given you earlier in the year on how our quarters would work out. In summary, we've turned in another solid quarter in first half. We are completing important organic growth investments, and we are expanding our international opportunities into the fastest growth markets. And as a result, we are very well positioned for a strong second half. At this time I will now turn the call over to our President and CEO, Greg Boyce. Greg?

Thanks, Rick, and good morning, everyone. Rick has reviewed the strength of the Peabody model in driving record performance. I want to thank all of the Peabody team and operations for their very hard work. While we had some challenging equipment start-ups, these major investments greatly strengthened Peabody's operating base for years to come. I would like to focus my remarks on the very favorable long-term market conditions, as well as Peabody's progress on our growth initiatives. First to the markets. Recent industry data for 2005 confirmed that coal was once again the fastest growing energy source in the world, increasing at twice the rate of the rest of the energy sector. The strength of the global and longer term U.S. coal markets is notable, and this contrasts with the current noise that influenced much of the domestic markets during the second quarter. In the United States, we saw unusually mild weather for much of the first 6 months of the year, better than normal hydro conditions in the west, nuclear plants that are running well, and a temporary dip in natural gas prices. We should not let these near term issues mask some of the most bullish indicators of coal demand that I have seen.

Consider that imports to the U.S. are likely to be constrained due to strong European coal demand from an unusually warm summer. China's economy continues to grow at a double-digit pace. Japan is once again having safety issues with their nuclear plants. The Australians are committing to very strong pricing on their thermal contracts. In the U.S. we're seeing the largest buildout of coal-based generation in over 30 years. Natural gas forward year pricing is averaging more than $8.50 per thousand cubic feet. And coal-to-liquids activity continues to grow. All of these indicators are resulting in a sea change in the long-term projections for U.S. and global coal demand. In fact, the Energy Information Administration now forecasts global coal use to be 2 billion tons, or 26% higher than it did just 2 years ago. This global growth comes from increased utilization in existing coal plants, from a buildout of new coal fuel plants, from growth in world steel production and major new markets, such as coal-to-liquids.

Here in the U.S., 1 utility announced new plants that would increase the coal use in Texas alone by 32 million tons per year. Realize that this is the size of our planned School Creek Mine. Another utility announced 3800 megawatts of new coal-based plants in the South and Northeast, and we've started shipping coal to Springerville's new unit, as plants announced several years ago begin operation. Clearly, the western railroads also see this growing demand. They announced $200 million in investments by 2008 to upgrade the Powder River Basin infrastructure. This expansion will accommodate the major growth we all expect in Wyoming demand.

As we talk today, oil prices are at record levels due to geologic, economic and political challenges. This provides an outstanding back drop for coal-to-liquids projects, and activity is picking up sharply. In recent months, bipartisan bills on coal-to-liquids advanced in the Senate and the House. The Southern States Energy Board has called for a massive buildout of coal-to-liquid plants that would produce 5.6 million barrels per day. The U.S. Department of Defense has issued a bid for diesel and jet fuel from U.S. coal. And the FutureGen Industrial Alliance is narrowing its list of finalists. In short, we see accelerating growth in both U.S. and global coal demand, and it is creating significant opportunities for Peabody.

Now Rick reviewed several organic growth projects. I would like to discuss our key initiatives involving international expansion and Btu conversion. First, is our acquisition of Excel Coal, one of Australia's largest independent coal companies. Peabody has made a $1.3 billion all cash offer for Excel. We expect the deal to close in the fourth quarter of this year and be earnings and cash flow accretive in 2007. The benefits of this purchase are many. The new Peabody Australia will be a major presence in the world's largest coal exporting nation, as we triple our Australian position by 2008. A diverse product line will serve the world's fastest growing coal markets in Asia. Over 500 million tons of high quality met and thermal coal reserves will enable future organic growth in Australia, and we will extract a number of operational, marketing and transportation synergies.

Also during the quarter, Peabody signed an agreement with Shenhua Coal. This is the parent of the listed company to pursue coal related projects both in and outside of China, as logical to advance a strategic alliance between the world's largest coal company and the leading coal-based energy company in China. Now Peabody has been a strong supporter of Btu conversion technologies to expand coal markets and further equalize the value of Btu reserves. We have projects in advanced generation and gasification, and I am pleased to report on our agreement with Rentech to investigate coal-to-liquids projects. We will evaluate potential CTL sites in Montana and the Illinois basin to produce diesel and jet fuel using Peabody reserves and Rentech technologies. These and other coal-to-liquids refineries represent a significantly expanded market for coal, a unique Peabody strength given our multiple blocks of large reserves, and America's best opportunity to improve energy security. The Excel acquisition, Shenhua agreement, and coal-to-liquids development. These 3 diversified growth projects that build on Peabody strengths and create major opportunities to increase shareholder value.

In summary, the markets are showing widespread signs of increasing coal demand. The team continues to perform quite well and demonstrate the strength of the Peabody model. And we are developing a pipeline of projects that allow growth in our core business, in the high demand international arena, and in emerging markets for coal. Thank you for your attention, and we would be happy to take your questions at this time.

[OPERATOR INSTRUCTIONS] Michael Dudas, Bear, Stearns.

My first question would be for Greg or Rick to just detail a bit more the longwall issues from Twentymile and North Goonyella. Can you remind us what the contribution of these 2 pieces of equipment will be to Peabody going forward, and there has been issues with some of the equipment and installation. It seemed like a pretty large delay relative to what should have been, and how long is that going to bleed into the third quarter, do you think? And when will we see normalized output and production from these 2 operations?

I could talk a little about the equipment issues, and then I will let Rick finish up on some of the outcome. Talk about Twentymile first. I think we'll all recall that Twentymile has historically been the most productive longwall operation in the country. As we look to replace the old longwall system with a new system, we upgraded the longwall capacity. We had to go to larger shields, and we went to higher capacity longwall systems because of the favorable geology and reserves at Twentymile. Some of the issues that we had during start-up related to the newer and larger equipment. We've had some software problems. You have to remember that the longwall at Twentymile is probably the fastest advancing longwall in the world. So when you get all that equipment sequencing, the software had some issues that we now believe have been worked out. There was some equipment mechanical issues with some bearings and some of the drive shafts. Again, we believe all of that has been worked out. It did take longer than we would have anticipated because the equipment modifications after start up were much greater than anyone would have anticipated, including the vendor. As Rick indicated over the course of the last week, we're very encouraged with the volumes that we're seeing off of that longwall on a shift by shift basis, and are in fact confident that over the full normalized operations at Twentymile, we'll be exceeding even the forecast that we had established when we purchased that equipment.

On the case of North Goonyella, there were similar type issues, but a different longwall system. Again, because of the geologic issues at North Goonyella, which we had designed a new longwall system which had much stronger capacity, had a different configuration along the face. So with the installation of that new equipment we were delayed somewhat getting the old longwall system out, getting it on the surface and the components we were keeping rehabilitated. But once we started up, again we had some equipment issues on start up that you don't normally see. The vendors have been working 24 hours a day to get those fixed. Those are essentially all behind us. The longwall system at North Goonyella has been performing. And in fact, we've had some geologic issue that is in the past would have kept us shut down for multiple days trying to address the geology. As we've come across those issues, we've been able to just start back up with the new equipment as we had designed it, and advance through that geologic issue. So we're very encouraged how both of those longwalls will operate once we get them, and particularly Twentymile, fully to its normalized rate.

Yes, and as Greg said, when you look at, Mike, when you look at the production that we expect out of these, you're taking Twentymile operation from an operation when we acquired it, it was running about 7.5 million tons a year. We're going to run it up to 12 million tons. So we're going to get significant capacity out of this particular change. So while we had a bit of bumps along the way to get there, and obviously given the choice, if it wasn't for the timing of the longwall panels and when they ran out, we wouldn't have obviously tried to do 2 longwall installations in the same quarter. But that's just the way things happen at times. So we're very encouraged that the equipment as long as we think we have the equipment issues behind us at Twentymile, and so 7 straight days is good news. And we'll see where we go from there. But that should get us on a 12 million ton a year pace, if not even higher than that from the way it is running now. And you go down to North Goonyella, a lof the issues we had in North Goonyella was because of geology. Part of the reason the longwall delay took so long was getting the shields out of the mine, because of that tough geology and the shields not having the right -- the capacity of the longwall that we had in existence down there.

So we have run into some tough conditions under this new longwall, and it has run right through those situations, some faults that it would normally would have got caught in those faults, and essentially we've have had to slow down. And so we're encouraged that the stronger horsepower and capacity of this particular set of equipment over the long run is going to improve North Goonyella's operations as well. That's a market where we're selling coal for $100 plus a ton, you want to mine those tons. So long and short of it is, big impact on the second quarter. I think it will have maybe a little bit of a lingering impact into the third quarter, because Twentymile is just now getting there, and we're kind of getting close to the end of July. So we still lost probably 25, 30 days of good strong production in the quarter. But going forward we feel very good about it.

I appreciate those answers. My follow-up is regarding, Rick, your early comments about synfuel and the $20 million EBITDA, or EBIT, impact to I believe you said the quarter of that's a yearly impact.

That's a yearly number, Mike.

That's a yearly number. Could you just elaborate a little more on the tonnage? Is this coal that you think you'll be shutting down? Do you see this impact replicating itself throughout the synfuel industry? And could that put pressure on certain some of the coal production that we've been seeing out of the Appalachian basin?

It is a good question. There's probably, as all reports go, there's probably 100 million tons of coal in the system that is being -- that's going through some type of synfuel facility, or being sold to a synfuel facility. And the credits essentially bleed out at oil prices above $60 plus. And there is a moving number because they kind of look at it on a backwards basis. But nevertheless, at this point in time -- and we don't own the plants. We're selling to a host site who is using the tax credits they receive under the section 29 exemptions that they are receiving from running these synfuel facilities. Then the coal is then run through the facility, they earn the tax credit, and the coal goes ultimately to one of Peabody's customers. As it is all said and done, there will not be any reduction in production because the customer still needs the fuel.

But the subsidization from the tax credits that was going to the host plant, as well as what Peabody received is maybe a couple of dollar a ton credit, and about 10 million tons that we were involved with will go away. And those credits were going to go away at the end of '07 anyway, without the higher oil prices. So we really had only 2 more years of the synfuel credits. And I think longer term, it is probably a good thing, because I think some of those synfuel credits we're probably subsidizing in some cases - not in ours - but some marginal mines that may not have been in production. It ought to get -- set the prices in the Midwest at a more reasonable level. It will impact others. I can't believe that there is many synfuel plants that are still open, unless that host site did a very good job of hedging in advance.

Appreciate the answer. Thank you, gentlemen.

Paul Forward, Stifel Nicolaus.

We've seen coal prices come down in the U.S. pretty much across the board east and west so far this year. Do you see any of your competitors with high cost operations actually idling production in response to these weakening markets? And maybe as a follow-up, do you yourselves have any higher costs, maybe less profitable operations that could be candidates for idling if the markets continue to soften?

Well, Paul, just to talk a bit for on coal pricing, certainly in terms of all of the major indices, the pricing has softened since the first quarter. All of the business that we have been booking, whether it was the first quarter or through the second quarter, are still at substantially higher levels than business that we would have booked or realized last year. So for all of our operations, we're still having margin expansion as you look at our operations. So in terms of any impact of what's happened over the second quarter, we're not feeling that impact at the operating level. I think what other people decide to do will be their call, relative to their operations.

But we're selling our coal based on the long-term fundamentals of this business, not based on what's happening within the day-to-day or the week-to-week over-the-counter market indices now. There is no question that when you look at the first quarter to the second quarter, there has been a difference in the price horizon. But we are so far above where we were last year, the year before, even at those ranges, that we're still booking business and our operation margins are still expanding.

And Paul, I would add, if you look at what I would consider the high-end of the cost curve, which is Appalachia, which should be setting the prices at the end of the day, and you're seeing market prices below $50 short-term, I would tell you that I don't think that's a sustainable number. Because over the long-term, you're right, there are marginal producers where that is going to be below their cost -- the marginal guys at the end of curve, that's going to be lower than their cost structure.

All right. Appreciate it. Thanks.

Mark Liinamaa, Morgan Stanley.

Last quarter you gave guidance of $0.40 to $0.58, which you cited at the time was going to include some rail disruptions and impact of longwall moves, which came to pass - evidently came in the middle of that. With your $0.35 to 5 $0.55 guidance, could you give any indication of what the factors that could lead to the high-end versus the low end?

Well, I mean we had some of the same issues, Mark. Obviously, once again we put the guidance out. We're just now every day getting a bit more confidence with the Twentymile longwall. So we still have to make sure that's still running. And we've got a few weeks under our belt at North Goonyella, so we still are obviously a bit hesitant to say that everything is fixed. But we're certainly feeling pretty good about it, but not good enough that we're going to bet the guidance on it. So that's how we get to the higher end of the range at the end of the day, if those things work out, that's high margin business, things run well. We have experienced rail delays, and frankly we are expanding our operations in the Powder River Basin. And the second half for us is a higher production level, and we haven't seen the number of trains that we're comfortable with into all of our operations. So we know the railroads have stopped the maintenance now until October, so hopefully that will help us, but we still have some concerns. They're still -- while they're setting records, they're setting records off of pretty low numbers from last year.

So it is pretty similar issues?

Yes. Exactly. Same issues.

Those issues would be similar in any quarter when you look at basically the underlying mining business that we're in, there is always going to be variability in transportation issues, variability in geology and production issues. We try and take those into account when we provide that range, and I think we've done a great job factoring those into the guidance that we provide.

Okay. Great. And as far as the PRB contracts go, you indicated you're seeing price on new contracts twice what was rolling off. Can you give any indication on the tonnage that was signed at that levels, when that was in the quarter, and how confident you are? I think it is a very strong case, if indeed we see the cost in central App set the price for PRB stuff, that would be a fantastic outcome. How confident are you that is going to be the case over the remaining contracts that you have left to place over the '07/'08 time frame?

I think we said we price 30 plus million tons this quarter, and most of that -- essentially is about 30 million -- 30 to 33 million tons were priced in the second quarter. Some of that was rollover business with re-openers obviously, and then some of it was just open tonnage that was uncommitted. It was all in the quarter.

And is that -- is the market still consistent with that kind of pricing power, do you think? For future contracts?

When we did it various times throughout the entire quarter, Mark, it hasn't really seen -- we haven't seen much change. But we've seen, as we said, there is some softness in the spot market that for the end of '06 and such because of the weather, but that spot market is not really driving the contract market.

That's what I am getting at. I think that is an encouraging number.

The markets have softened a bit from earlier in the year when you had $1600 allowances, and there is no doubt about that. But at the end of day, we're not in a position where we're going out and seeking long-term contracts at spot prices.

Good. Thank you.

David Gagliano, CSFB.

Just following-up on that last question. You -- looks like you priced some of the '07 volumes in the quarter. You still have 60 to 70 million unpriced. I am just curious in terms of the timing. First the timing. When do you think you will really get aggressive on pricing the remaining volumes? And then, too, what's your comfort level in terms of carrying unpriced volumes into 2007? That's my first 2-part question?

Well, I guess we probably have too many customers on the call to really tell you when we're going to get aggressive to place all of the volumes for '07. Suffice it to say, Dave, I think we're right where our normal historical profile would be at this point in time for booking business for next year. We will continue to layer in business through the second half of the year to get to a point by the end of the year where we're comfortable to be able to meet our production predictions and forecast for next year. So beyond that I wouldn't want to go into any more specifics, other than to say we are comfortable with where we're at now, and we will be continuing to layer in business through the back half of the year.

Okay. Just given the current environment, are you more or less apt to try and tie up the remaining volumes in the third quarter for example? Or are you willing to wait until the fourth quarter?

Again, Dave, we'll just continue to book business as we see fit, normally would during the course of the year. And I really am not in a position to tell you whether it would be more in the third or more in the fourth quarter.

Okay. Fair enough. Just -- just changing gears for a second. The -- quick question, the gain on the disposal exchange of assets, was 39 million. I see in the other sort of the gain line on the income statement, there is a total of 50 million. What was the other 11 million of the -- what's the delta there?

Just ongoing property sales we have. As you know, and you've followed us, Dave, for a number of years, that it is a line of business that we have is our resource management line of business. And there is nonstrategic assets that we -- out of our 9.8 billion-ton portfolio that we will sell from time to time. Typically you will see us make about $40 million a year on asset sales. We consider it a line of business. And this year, with reserve prices being higher, I would expect us probably to exceed that number and get closer -- to be up in the 60 plus range.

Okay. Thanks.

David Lipschitz, Merrill Lynch.

I was just wondering, are you having any issues finding labor for the new type of mines that you're bringing on, or even in the future for something like School Creek?

Well, as you know, we've talked in the past. We've been very, very aggressive in terms of developing and training new labor recruits for our operations. We opened up a very large training facility in Appalachia and West Virginia. We've recently during the quarter opened up a second one in the Midwest for training employees there, and we've got one under construction in the Powder River Basin. At this point in time, no question labor is tight. But we've been able to recruit and retain labor. I would point out that 100% of the graduates that have come through our training facility in West Virginia are still employed with us. So we're not seeing them go through our training programs and disappear, which is a credit to not only the training that we're giving, but obviously the quality of the recruiting that we're doing. So at this point, it is a challenge we all face. We got out early, knew it was going to be there, put it -- took it into our own hands to really address the issue. And at this point we're able to grow the business and attract the employees that we need.

Have you seen -- my follow-up is, have you seen more cost inflation on the labor front over the last year versus let's say over the last 5 years. Has most of it come over the last year or 2, or has it been spread out pretty evenly year-over-year in terms of labor cost inflation?

I think there is no question that the labor pressures and labor cost pressures have been greater over the last year to 18 months than they would have been 3 and 4 and 5 years ago. But again, we have continued to factor that in as part of the cost structure that we have to manage.

How much do you think up, percentage-wise do you think it has been up over the last 18 months? In terms of wage and things like that?

Oh, it's probably 5%, Dave.

Okay. Thank you.

Scott Hanold, RBC Capital Markets.

Could you guys sort of talk about production regarding the second half of the year, how much of the higher end of the production is predicated on the 2 longwalls versus sort of growth in the Powder River area?

I think we're looking at probably trying to -- we'll have about 3 plus million tons has to be produced in the second half out of Twentymile per quarter. So that gives us about 6 million tons for the first -- to go out there, and then roughly another 2 million tons at North Goonyella, a million tons. I am sorry. A million tons in total at North Goonyella. So about 7 million tons in total is tied to this longwalls with the high margin businesses, but out the total for the second half.

Okay. And so -- ?

So Powder River Basin obviously is still going to continue to be a significant portion of our production in the second half and expanding to get to the total that we expect to get out of there this year. We're still looking at 230 to -- 230 million tons production for the total year.

Suffice it to say we are still looking for a strong second half of the year on a production basis from both of those longwalls as well as the Powder River Basin. Particularly as you look at where we're at year-to-date with our volumes, compared to we're still holding our forecast of the 230 to 240 for the year.

For production, not sales. Sales is still 250 to 260.

Good. My second question is on cost and Rick, you went into a little bit of detail on costs in the eastern region, they did ramp up a little bit there in the quarter, and I guess have so in the last couple quarters. And fuel costs and it sounds like contract mining was sort of the reason for that. Could you sort of give a little bit more color on where we could see costs in the eastern region go over the next couple quarters?

Sure. If I look at it right now, what happens in the second quarter, and when you look at that cost increase, $0.54 was tied directly just to fuel costs. And then what happens, you have got additional taxes and royalties because you saw prices going up $3 plus, so that's another $0.65. Contract miners were almost $1. And frankly, that's passing on the same cost increases that we're experiencing. So at the end of the day, two-thirds of that cost was related to fuel, higher taxes and royalties related to higher revenues, and the contract miner issues, and a bit of longwall timing in movements. As I look forward to the next couple quarters, frankly, I don't see the pricing coming down. So we're still going to have the higher add-on taxes. I don't see fuel coming down, so we are going to have to assume that, and the contract miners are going to pass it on. So at a minimum, two-thirds of that increase I think I still see, and we'll try to knock out the other third as much as we can.

But we're still going to be talking about a $28 number plus to finish out the quarter in the east. And some of that is mix as well, because we're producing more coal out of Appalachia than we did last year. So that when I talk about mix, part of that includes our Midwestern operations which include surface mines that have cost structures that are high teens to low 20's, compared to cost structures obviously in Appalachia that are higher. And in part, that's by design. That's why our prices are higher, because we've moved into thinner seam mines intentionally to mine metallurgical coal. And Harris to James Creek is a perfect example. We moved our longwall into a thinner seam operation. We knew it was going to cost us more per ton, but at the $85 to $90 a ton sales prices, it is a good deal for us.

Okay. And actually, 1 real quick question on the synfuel, the $20 million impact to EBITDA you indicated, where did that -- would that be a revenue item, or would that flow through the expense line? Where would that run?

It is a revenue item.

Okay. So, it is a reduction revenue.

Reduction in revenues. And that's just for the really 3 quarters to an extent. Because we did most of synfuel plants still ran in the first quarter, while the oil prices were under $70. And then most of them began to shut down in this quarter. It is just a revenue item.

Thank you.

Perad Sengani, Raymond James.

Just a quick question on realized pricing for the quarter. We saw pricing actually come down on the east and the west. Was that mainly due in the west due to Colorado? Or was that something else? And then on the east, was that really due to the synfuel or was there something else going on?

Realized pricing is up in the east well over $3, if you look at revenues per ton on the supplemental schedule. Our last quarter was 33, and now we're at 36.70. So pricing increased in the east. But as it relates to the west, we're up marginally. But there is really 2 reasons why, when you look at the west, what's happening with the west. It is a mix issue -- first and foremost, it is a mix issue, because you have western tons that are coming from the southwest operations, the Colorado operations, and mixed in with the Powder River Basin operation. So what happened is first, you're correct, by not having the higher priced tons for Colorado, which a market that's now spot pricing well over $30, losing those sales obviously hurts. We also shut down the Black Mesa mine and closed the Seneca operation, both of those with revenues per ton in the $20 plus range. Obviously, on total and on balance, that's going to bring down the average, en masse the fact that the PRB pricing improved. So that's really what happened at the end of the day.

Justine Fisher, Goldman Sachs.

The first question that I have is just with respect to costs in Australia. Those costs looked to be up pretty significantly quarter-over-quarter, and I was wondering whether they were related to Goonyella. And then if they -- to the longwall issues at Goonyella. And if they were, how come we didn't see the same type of cost increase related to longwalls in the west because of Twentymile?

The answer is absolutely. It was clearly North Goonyella in Australia. What you're talking -- the issue difference, the real difference is volume. In Australia, you don't have near as much volume, so that impact gets spread over -- our total volume in Australia was only 2.4 million tons for the quarter. Our total volume in the west was 38.8 million tons. So you're spreading the volume impact of what's going on in Colorado across all the PRB tons as well, when you blend them altogether. So it is really just a volume issue. The impacts were both frankly, per mine, both in the $20 million plus range.

And so I guess I just didn't have time to do the math in my head. So going forward, if once the Goonyella longwall issues are resolved, can we expect the run rate cost to be sort of in the low to mid-50s in Australia? Not taking into account Excel, but just Peabody operations in Australia?

Sure. I don't have that in front of me, but I would say that that's a fair number. That's a fair number because the other operations in Australia are running very well, surface operations, and they're doing -- their costs are in control. So they're doing well.

Okay. And then I just wanted to follow-up on the question with respect to eastern revenues, because I was looking at the revenues per ton reported for the March quarter, and it was about 37.50 in the east. So it looked to be down this quarter. But you did say that you were looking to mine some of the more expensive, but some of the higher priced coal as well. So was it the synfuel that accounted for that decline? Or what else would account for the revenue per ton decline first quarter -- ?

Sequential quarters, it was a minor decline, but it's really just 2 issues. [inaudible] pricing declined which took off some of the premium that we would be earning on our very low sulfur coal out of the east. And second, as I said, and we didn't put as much emphasis on the fact that we were doing a longwall move from the Harris Mine to that thinner seam James Creek. So during that same time frame we weren't selling some of that $85 coal during that quarter while we were making that move.

Okay. Great.

So some of that higher priced coal got shifted, and we'll make it up in the third and fourth quarter.

Super. Thanks a lot.

Pearce Hammond, Simmons & Company.

The one thing, I know you don't break out your PRB volumes, but one thing it's not pencilling for me, is if you look at the volumes out of the west, the tons sold for this quarter, lower than first quarter and lower than third and fourth quarter of last year, yet rail has shown very, very strong numbers. So were you actually having some problems at the mine?

No. Actually, we're higher -- we're higher. We set records at PRB, Pearce, first quarter and first half. We shut down the Black Mesa operation in the west, which is a 4.5 to 4.8 million ton a year operation. We shut down the Seneca operation in the west also. So you've got 2 big operations that we shut down. And then we missed 1 million plus, to almost 2 million tons of production out of Twentymile. So when you put all of those together, that's what's driving the decline sequentially.

Right. And as far as -- but it was a record quarter for you, as far as volumes in the PRB.

Absolutely. Absolutely, we set records.

A quarter and a half.

A quarter and a half. But I will still say that we could have shipped another 3 million tons out of the PRB, had the train showed up.

And then my follow-on question is, as it relates to customer stock piles at utilities. If you were to segment it, and look at east and west, and then bituminous and sub-bituminous, I mean would describe that we're kind of close to normal stockpiles, and normal being defined as the '01 through '05 average for maybe eastern stock piles? Is that what you're seeing in the marketplace?

I think they're still a little bit below normal on both sides. I think the eastern stockpiles are in better shape than the western stockpiles, based upon the information we have been able to gather. That the western stockpiles even -- are still have some room to go to get back to normal. But certainly they're in better shape than they were a quarter ago, obviously, because of the weather and the rail performance being what it is compared to last year. So they have improved. So it will take them until next year to catch up.

We can certainly assume that the last week's burn rates are taking a dip out of those stockpiles as well.

And so when you define -- if you had to quantify this, would you say probably prior to this heating event, we may be say 5% below normal or -- ?

That's a good number.

And then the last question, you're probably not going to give me an answer on this, but as you look at School Creek and you look for sort of anchor tenants on that particular mine, be it a TXU, NRG or whoever, what is a range, as far as a threshold price dollar per ton, that you want to sell the super premium coal out of there for it to make sense for you to bring that mine on?

Well maybe we'd go back all the way to almost a year ago or longer, when we bought those reserves and we talked about bringing School Creek online, and my recollection, we'll just talk about the OTC pricing at the time. It was half of where it is today, and we, at that point in time, believed that we had a healthy margin to pay for the reserves, capitalize the mine, and bring it into production. So we are well into territories where that mine is going to be a very, very successful operation for us.

Thank you very much.

Sam Martini, Cobalt Capital.

Just a couple housekeeping points. You usually give a level of SO2 allowances that are you assumed in your guidance. Are you assuming just a status quo in the low 600s today for the guidance that you gave?

I would use that as a rough estimate, Sam. We may estimate they come up $100 maybe, $150 towards the back half of the year. But whether we're right on or wrong on that doesn't materially change the numbers.

Okay. Then just secondly, just any update on what you're seeing on scrubbing as a result of SO2 allowances? I think people are surprised they came down so quickly, and have sort of stayed low. Any change on what you're seeing or hearing on the scrubbing front? And then 1 last quick question after that.

We're not seeing any changes at all in terms of the schedule or the intensity of the scrubbing decisions that have taken place. People see variability in the credits, but nobody is planning on those for the long-term.

Okay. And then finally, I hate to come back to this, but just -- I think what someone was trying to ask earlier was, sort of beginning of the quarter to end of the quarter we saw a 20% drop in the PRB pricing that we all get from trade rags. And was just curious on any further color, or just clarity that you would believe that the 100% up from '05 realized prices, that would be a reasonable estimate of where you would sign long-term contracts today, just to take any timing risk out of the quarter. Meaning no different than what it would have been April 1st, you would still see that today, July 20th?

Well, that number represents our average for the quarter. Suffice it to say, I really can't tell you where I would be signing contracts today going forward, but that number that we talked about was our average for the second quarter. We will sell coal during the back half of the year as we see prudent to do so based on our views as to where the longer term pricing ought to be.

Great. Thank you, guys, very much.

Jeremy Sussman, Natexis Bleichroeder.

Actually it is Ian Synnott on the line. As a follow-up to the last question there, talking about scrubbers and what you're seeing there, are you still seeing decent interest in Illinois basin product when you get out a couple of years? I guess a lot of the interest in that would be once scrubbers are in place. But are you still seeing that, kind of consistent with what you guys were talking about last quarter?

Absolutely. We're seeing very strong interest in the Illinois basin coals from a very diverse group of utility sectors as they look at sourcing coal, post their implementation of scrubbers.

Great. Excellent. That's very helpful. And then 1 last just update in terms of Prairie State and progress there. I don't know if you had mentioned anything. I might have missed it before. But if you could just give us an update otherwise.

Well we continue to advance Prairie State. We have achieved all of our permits required for Prairie State. The air permit is still under appeal. The Environmental Appeals Board has all of the information under advisement. We had anticipated we might have had a response by now, but we have not had a decision yet. That's really the last major hurdle to begin to move forward at Prairie State.

Great. Thanks. And I guess it is impossible to really handicap one that could come in, right?

I'm beyond my handicapping range at this point.

Got you. Fair. Thanks very much.

David Conney, FBR.

2 questions. First, Rick, maybe could you give me a sense of what are the positive offsets to some of the problems that you had in the second quarter to enable to you keep your guidance, both production and earnings, unchanged essentially?

I think we think these properties are going to run pretty good. We're confident that we can make some of it up, of course, with Twentymile running better than we thought it would run in these 7 days. It has been hitting some pretty good targets. So that's allowed us to put some pretty bullish forecasts in the second half with respect to Twentymile's performance. And obviously, that's subject to rail movements among other things. The PRB, we're hopeful that we'll continue to perform strong in the second half, and our production is going along well there. Those are the issues I think primarily that we think are going to help us in the second half. And we had already projected the second half was going to be stronger than the first half, because it typically is.

Usually the second and third quarters are the softer quarters because you're straddling a vacation shutdown period, and things of that nature. So those are some of the positive issues that we have, and things are going well in the Midwest for us, running nicely. So we're hoping we can squeeze a few more dollars out of those operations. You followed us a number of years, Dave. You know that at the end of the day we make a commitment to the Street that we're going to hit a number for the quarter, for the year, and with our diverse portfolio we have to run the other sites harder to make it happen, we're going to do that.

I agree, but just need to figure out how to model it. And the second question is -- .

Just put the last number in, and you will be fine.

If you can give us some sense of how much spot would you have left to sell this year? And then also in the second quarter did you have any roll over tons impacting your pricing?

Probably no real roll over tons I think to any great degree impacting prices in the second quarter. I guess on a spot basis at the end of the year, how much we had left to sell, once again, that's a question as to how the markets perform and where we think -- how much we consider safe to hold going into 2007. But traditionally it has been less than 5% of our production.

Is it safe to say maybe your contracted out maybe at the lower end of the range, and the upper end of the range is -- or some good piece of that is for the spot market, is that a fair assumption?

I am not sure I am following that question.

The 230 to 240 million tons that you have for guidance for production this year, are you basically contracted out at 230? And I know you have a higher sales number, but more importantly -- ?

Oh, for '06. I am sorry. I thought you were talking about what I was going to have left to sell for '07.

No, no, for '06. I'm sorry.

For '06, I'd say we're pretty well -- for the most part we have very little to sell for '06.

Okay. Great. Thank you.

John Bridges, JPMorgan.

Peabody has always been very good at a general view of the energy market, and people are telling me that there is a big natural gas inventories. And I just wonder how you think that might impact coal prices that you settle in the second half as you negotiate going forward?

I was just watching -- the gas data came out just before we started our call, and it was basically at expectations, and short-term gas prices were going back up as a result. But as you look at the longer-term strip for gas, and it is averaging [8.50] and above, it is having no impact on people's decisions relative to whether you build a coal plant or you build a gas plant. And I have not been apprised of any points where people are switching from coal to gas, in terms of any kind of base load existing generation at all. Coal on a delivered basis, even at these prices of coal and rail, is in the 2.50 to 2.80 per million Btu versus gas which is back up $6 for next month, but 8.50 for the next 3 years. So we're not anticipating, and do not see any impact at all.

Okay. Secondly, on the Excel assets that you acquired, I was reading in one of the rags that there is some longer term contracts that they've got in there. Can you comment on that?

Well they've got 1 mine, the Wilpinjong Mine that they're developing under long-term contracts to one of the local power utilities there, Macquarie Generation. That's a major baseload contract for that mine. Then in addition, that mine will produce a component of export tons that will be exported out of Newcastle into the Asian thermal export market. So that would really be their biggest long-term coal supply agreement. They've got some -- in the Pacific Rim, typical to put together some long-term frame contracts, which have volumes per year. But of course, prices are negotiated on an annual basis in those thermal coal markets. So it would be for the Wilpinjong, the Macquarie Gen contract, which is a long-term contract, with a price structure embedded in it. And then the export frame contracts that have annual openers.

And the good news, John, is that in the last couple of weeks, the export thermal contracts have been settling for next year's delivery at record prices. So the market is extremely strong down there for thermal coal right now.

And Wambo's contract -- does Wambo got any long-term contracts?

Wambo would have the frame contracts that would be priced -- they're essentially all export component shipping through Newcastle.

So [inaudible] is a bit of price change every year.

Yes.

Okay. Got it. Thank you.

Zack Schreiber, Duquesne Capital.

On the synfuel, just want to make sure I understand that the $20 million, that's a pre-tax EBIT number, or post tax on that income number?

It's a pre-tax EBITDA number.

And is that an annual, or is that just for the second half of '07?

That was for the 9months of '06 and an annual number would be closer to $25 million. It is about $5 million, about $6 million a quarter, roughly.

Got it. And basically what you're saying is you guys were getting it to the $2 per ton spread on that business incremental to what you would have gotten from just selling it straight out?

Yes. It is $2 to $3 depending on the contract, but, yes. It was about 10 million tons of business that we shipped and the customer for us, was the synfuel plant. And then it ultimately went to a customer of ours at one of their generating plants.

Got it. Thanks. And then the follow-up question is just -- or second question. You had mentioned that you're not willing to sign long-term contracts based off of the sort of short-term noise of the spot market with the near term gas overhang, that's not reflected I guess in the gas long-term structural gas strip, and so forth. But you also recognize that, I thought anyway, that the prices have been a little bit weaker, in part based on the railroad shipments, as well as the SO2 netbacks coming down. Just trying to understand, if we're not basing long-term contracts off of the spot market, what are people basing long-term contracts off of? What are the things that we ought to be looking at out there in the market to sort of know and use as proxies? And are you folks alone in not being willing to use the spot market as an indicator or a proxy for long-term contracts, and others are? Or given your presence in the market, the fact that you're not willing to use the spot market as a proxy for the long-term market, that in and of itself makes it self-fulfilling. Thank you.

I guess I would say that from the standpoint that when we look at the short-term market, it is going to be affected, and once again, it is not as liquid as some of the other energy markets. It is going to be affected by weather situations, and we've had mild weather this year. So that's an impact. But as we look out for the long-term we don't see the same weather patterns or can't predict those same weather patterns in long-term contracts for '07/'08-type timeframes. So we try to balance that and try to get the right long-term price that we can. We're selling large volumes of coal out of multiple loadouts, with -- and with reliability premiums, as well as quality premiums. Certainly on the quality premium side, as it relates to SO2, yes, we're not going to get SO2 premiums based upon $1,600 prices that are no longer there, unless we index them and the prices come back. Which they can, and we do index some contracts. But as of today, we'll get the premium -- if we were just selling it straight, we will get the premium based upon a $600 allowance. But we do have the lowest sulfur coal. So we are getting a premium to the spot market, because of that lower sulfur coal even at a $600 number, we're still getting a pretty significant premium. It may be confusing for you when we're saying that we're not willing to sell at the spot prices, but it is because we have a premium embedded in our product, and we're not selling a train load at a time.

But do you guys demand the major premium off of the spot market plus the SO2, i.e., or is it just the natural build up of the spot price plus the natural premium from the SO2 netback?

You're always going to get the natural premium from the SO2. So we're going to get that, and I think as the customers and as we look at the market, I think everybody realizes that having a warm quarter, while it can have temporary impacts on any kind of commodity or product, it doesn't -- just like gas. Gas is -- the spot price for gas is $5, the strips are 8.50, because people don't expect gas to be -- this mild weather to continue. The same thing is true in coal. You just don't have a long-term strip to look to, to see what the long-term strip is for coal. Do we get different pricing than what our competitors get, and do we have any different influence on the market? We don't have any different influence on the market. We're producing coal and selling to the same customer base, and trying to be a reliable producer. We don't -- .

I guess my question is, in your discussions with customers, do your customers share the view that the near term spot price is overly influenced by the temporary gas storage overhang and that the real proxy to be looking at for long-term contracts '07/'08 is a '07/'08/'09 gas strip that is 8.50 or 9?

The astute customers would be looking at that. And the ones that aren't as astute, we probably aren't selling to.

Sunil Jagwani, Citadel.

My question was about the announcement with Rentech. If you can give us some more color in terms of how the deal came about, and what are the next steps that we should be looking at to see what progress is being made on the CTL front, and just any major sign posts, et cetera,.

Sure. Well, we have been active in the conversion space for quite some time. And we've had ongoing discussions with all of the technology providers. And I would say we'll continue to have discussions with all of the technology providers. In our discussions with Rentech, Rentech had become active, and in fact has a facility in the Illinois basin, up in East Dubuque they have purchased and are converting into a smaller scale facility. We got to a point with Rentech where we wanted to explore a couple of sites in the Illinois basin, and the potential for a site out in Montana using our reserves and their technology. We do like the technology they have, as we've had a chance to evaluate it. So we formalized that into a joint development agreement. And the agreement essentially anticipates that we will look at several sites. We'll both provide some funding to do additional engineering work, going through some prefeasibility work to look at the viability of those sites.

Preliminary estimates on the capital costs, and the operating parameters of those sites. And then at some point in the future, we would make a decision as to whether we would then take those sites, put them into a formal joint venture, provide exclusivity between the party -- between ourselves and Rentech on that site, and then begin to look at how we might fund -- bring in additional equity partners for those facilities and move those to a completion stage. During this interim period, before we get to this exclusivity stage, we continue to have the opportunity to talk with all of the other providers on not only those sites, but other sites. So we're very happy with the outcome. It allows us to share detailed information, both on our reserve base, coal qualities, as well as their knowledge of their technology and how it applies to the cost structure and the operating parameters of a coal-to-liquids plant.

The timing we should expect on I guess the next step in the process?

Well reasonably to go through kind of the prefeasibility and then some of the preliminary engineering work, we're looking at a 12 month time horizon to get to that point to where we would make any further decisions going forward on either formalizing a site and/or a joint venture agreement.

How does this contract like this tie into whatever mandates might be out there available coming from the Department of Defense for CTL based fields?

Well, obviously what the Department of Defense has out there right now is a request for who can provide coal derived fuels in the near term. Clearly Rentech, with their East Dubuque facility, I believe would be looking at those opportunities. These are a bit in more of the midterm opportunity. We believe the Department of Defense will be looking at entering into, and some of the legislation that has been proposed will allow them to enter into long-term contracts, 10, 15, 20 year contracts for coal derived fuel. Those would be the types of contracts that we would be looking to supply coming out of a larger facility that we might build, either in the Illinois basin or out in the West.

I see. Thank you very much.

Gill Alexander, Darfield Associates.

When you look at the PRB industry sales, what volume percentage is generally sold under the spot price versus long-term contracts for the industry?

Probably very little, because I think most of the producers are producing large volumes of coal and selling in large quantities to the customers. I think there is very little sold on just a spot basis, if you will. I would say it had to be less than 5% of the total production out of the basin would be sold -- saved at the end of the year to be sold during months and quarters into the -- for prompt delivery.

Thank you very much. Good luck.

Justin Bergner, Gabelli & Company.

I had a quick question about the EBITDA that you're generating from your resource management activities. I was curious if you might be able to give us a rough breakout of what that's comprised of across the different buckets that you indicate, and which of those are more repeating and which of those are more 1-time benefits?

Well, as we look at the resource management business, we consider it all repeating business, because it is a line of business for us obviously with the resources that we own. As I said earlier, 9.8 billion tons of coal reserves, with values that are continuing to increase, as well as 400,000 surface acres that we own. So it is a business that we're always trying to utilize the skills that we have in the real estate area to get as much value out of that particular area, and there is also some other revenues that come from royalties that we have on those properties. It may be a bit lumpy at times because of the nature of closing transactions, but for the most part if you follow our numbers, we've had resource management revenues probably in the $40 million range on average for the last 5, 6, 7, 8 years as I can recall. I would say you will see numbers obviously 60 plus this year, because reserve values are higher, and I guess I am not stretching it too hard because we already have 59. So it won't be too tough to get to 60.

Would it be safe to say then that that would -- you expect that to be a smaller contributor in the second half of the year?

Not necessarily, but I dont' think it will have -- it won't be another -- we won't -- I don't expect to see another 60 out of it in the second half. I would say that in total, if I was picking a number today, and this gets to be a dangerous game because of the lumpiness of these numbers, I would say that we -- is at 70, 75, that's a pretty safe bet.

Okay.

For the whole year.

I have 1 other question which might have been answered earlier. With respect to the 33 million tons of coal that you contracted in the second quarter, how much of that is western versus eastern?

Most of it is western.

Okay. Thank you.

Fritz von Carp, Sage Asset Management. We will move on. Justine Fisher, Goldman Sachs.

Just a quick question. I know that you mentioned that rail delays took out about 10 to $15 million of EBITDA from the western segment. Do you know how many tons they prevented Peabody from shipping during the quarter?

Let me clarify, Justine. The 10 to 15 would have also included probably 4 to $5 million of demurrage charges out of Australia. That was our total rail and port constraint number. So the rest would be PRB. And it is about 3 million tons we probably could have shipped out of the PRB, had the -- without the congestion issues and the delays in the trains showing up. So while we had record quarter, they had a record quarter. We felt we could have done better.

John Bridges, JPMorgan.

Just on the Rentech deal, what sort of alternatives are there for dealing with carbon dioxide from those?

Well, for all of these coal-to-liquids facilities, at the front end of the plant is a gasification system that converts the coal into a syngas, then goes the the Fischer-Tropsch process , which is the technology that Rentech has expertise in. The off take from the gasification process provides a CO2 gas stream that is concentrated, and allows you to capture that CO2 and produce a saleable product, or to sequester that CO2. So from a long term carbon issue, all of these plants can and are adaptable to carbon capture in the future.

Have you looked at the alternatives for those particular sites?

That will be one of the factors that we will be evaluating during the next 12 months as we look at each of these sites. One of the things that you do look at in addition to the sizing and the quantity of the coal reserves, you look at your ability to get the products to market, so the infrastructure for the products, look at availability of water and labor. But also in the case with these plants, we'll be looking at what is the CO2 market in the area, and what is the ability to move that product to market and/or sequester.

With no further questions, I will turn it over to Mr. Greg Boyce for any final remarks.

I want to thank everyone for your interest in BTU, and your questions this morning. It was a strong quarter for us. We believe as we look at the back half of the year, the operations are poised to perform very well. And we look forward to reporting on our progress when we get together again at the end of the third quarter. Thank you.

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