Peabody Energy Corp (BTU) 2005 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Peabody Energy quarterly earnings conference call. At this point, all the participant lines are in a listen-only mode. However, there will be an opportunity for questions and instructions will be given at that time. (OPERATOR INSTRUCTIONS). As a reminder, today's call is being recorded. I would now like to turn the conference over to the Vice President, Public and Investor Relations, Mr. Vic Zack (ph). Please go ahead, sir.

Thank you, John. Good morning and thanks for taking part in the conference call for BTU (ph). Our operations have been very strong out of the gate for 2005 and we are on pace for another great year. Today, Executive VP and CFO, Rick Navarre, will review our results and outlook. Chairman and CEO, Irl Englehardt will provide a brief economic overview and President and Chief Operating Officer, Greg Boyce will discuss the energy markets and our unique position to create value.

We will make some forward-looking statements today. You should consider these along with the risk factors that we note at the end of our release and the MDNA section of our Form 10-K. We also refer you to peabodyenergy.com for additional information. I'll now turn the call over to Rick.

Thanks, Vic and good morning to everyone. Welcome to Peabody's first-quarter earning review. Peabody is starting 2005 on the same trajectory as 2004 by setting record performance levels, delivering on our commitments and implementing plans to further improve our earnings in these very strong markets. Our post split (ph) earnings per share of $0.39 for the quarter is almost double last year. We set new quarterly records for revenue and EBITDA. Our sales volume, operating profit, and net income are much improved over last year's strong earnings. And we are raising our full year guidance. With that summary of our highlights, I'll discuss the financial results and outlook in more detail beginning with a brief review of the income statement on page 7.

First-quarter revenues were a record $1.1 billion due to higher volumes, pricing and the benefit of mines purchased last year, which fueled a doubling of our operating profit. Our EBITDA of $166 million for the quarter was 49% greater than last year and set a new quarterly record. Net income more than doubled to $52 million.

Turning to the supplemental data on page eight, you will note that revenues, average prices, and volumes grew in all regions. In the East, the combination of higher thermal and med coal (ph) pricing and increased Midwestern volumes more than offset geology issues at an Appalachian operation and higher contract mining costs in the East. Also extreme weather in the West Midwest caused heavy rainfalls that flooded our surface mines, disrupted barge and rail traffic for four to five weeks in the first half of the quarter. Our Western volumes were up almost 20% to nearly 39 million tons reflecting increased shipments from all three Wyoming operations.

Rail transportation in the West improved in the second half of the quarter allowing us to ship record volumes at both the North Antelope Rochelle and raw hide mine complexes in March.

Moreover, we realized a 12% improvement in our Powder River prices per ton. Looking ahead, published indices of forward prices are up as much as 35% since the beginning of the year. Furthermore, since SO2 allowance prices have tripled over the last year, the premium for ultra-low sulfur coals has also increased to more than $2 per ton. This suggests a very bright outlook for Peabody's North Antelope Rochelle product which totals 85 million tons per year.

These favorable conditions are also the reason we've announced the development of a new ultra-low sulfur mine on reserves we recently acquired. And Greg will talk more about those in his remarks.

Shifting to Australia, our volumes and revenues per ton reflect the benefit of the metallurgical mines acquired during the second quarter of last year. We expect revenues from Australia will increase greatly beginning in the middle of this quarter as new higher price med coal (ph) deliveries begin.

Moving now to the operating costs per ton, you will note that we have included the fourth quarter of 2004 information because of last April's acquisitions, first-quarter 2005 results are more comparable with the preceding quarter. You will see U.S. operating costs per ton are stable with last quarter. Our Western operations, when adjusted for revenue based taxes and royalties, reduced their per ton costs. Considering the ongoing external commodity and health-care cost pressures affecting our industry, this reflects the success of our process improvement initiatives and commodity consumption teams.

Turning to the resource management line, these activities contributed $28 million of EBITDA driven by a $31 million gain on the sale of our remaining equity interest in Penn Virginia resources. This area was offset by our sales and training business that had significant charges related primarily to legal issues on a brokerage contract. The majority of the overall $34 million in charges that we took this quarter reflect the value between the contract and estimated market prices of replacement coal to replace expected deliveries.

Our capital expenditures for the quarter were $110 million along with an additional $60 million in asset acquisitions. Greg will talk more about these investments in a moment. For the year, our CapEx targets remain 450 to $500 million. You'll note on page nine, that on our balance sheet that our cash balance remains very strong at $381 million and we continue to very favorable leverage with net debt to net capital ratio at about 36%.

Recognizing Peabody's continuous improvement in both our financial condition and our outlook, Fitch has raised the Company's credit rating for our senior secured facility to investment grade.

Let me now give you an update on our sales contracting position. First, we continue to execute our strategy of layering in profitable long-term contracts. As a result, we have contracted more than 50 million tons of higher average prices and we are essentially sold out of the remainder of this year. We continue to have excellent leverage for the markets with 50 to 60 million tons to be repriced in '06 and 115 to 125 million tons of 2007 production still available for pricing.

A large portion of these tons are located in the Powder River Basin, where we are the number one producer and have the greatest leverage to these improving markets. We also have 12 to 14 million tons of met coal (ph) available for repricing in both '06 and '07.

So with that as a backdrop, we are raising our targets for 2005. We expect earnings per share to more than double those of last year, rising to range of $2.50 to $3.10 per share. And we're also targeting higher EBITDA of $775 million to $875 million.

In summary, we have had a great start to the year turning into solid results that our shareholders have become accustomed to. We expect the rest of the year will be even more rewarding for Peabody shareholders as we provide even stronger results. At this time, I’d like to turn the call over to our Chairman and CEO, Irl Engelhard. Irl.

Thanks, Rick and good morning everyone. My role in today's meeting is to provide a few comments of the status of the industry and to hand off to Greg Boyce who will succeed me as Peabody's Chief Executive Officer.

Turning to the industry, that both the near and long-term outlook for the coal industry remain very bright, the best that I have seen in my 14 plus years as Peabody's CEO. My enthusiastic view of the industry's future is a result of the strong economies in countries around the world, coupled with the obvious long-term pricing and reliability questions related to competing fuels. Those strong economies are consuming record amounts of coal for electricity production, steelmaking and industrial use and the shortages of the competing fuels ensure that coal will have a bright future for many decades to come.

Some analysts have raised the obvious question, has the cycle for coal run its course? My view is the coal cycle has just begun. Large investments are being made in the existing fleet of coal generating units. We see other large investments being made in new generating units around the world that will use coal. And we see sophisticated investors studying the production of alternate fuels from coal due to the shortages of those fuels for the long run. So we see coal demand growing more than 50% over the next 25 years as a result of those factors.

As you can glean from Rick's remarks, Peabody is performing very well. It's controlling its cost. It's capturing the markets -- it's presented by the market -- the opportunities presented by the marketplace. I believe that Peabody's future will be characterized by growth and very strong performance.

Early last month, we announced another phase of Peabody's CEO succession process. We began that process in 2003 with the selection of Greg Boyce as President and Chief Operating Officer and beginning next January, Greg will assume the role of President and Chief Executive Officer. We're working together during the remainder of 2005 in a very smooth transition. The Board of Directors has asked that I remain in my role as Chairman commencing in 2006 and Peabody will continue with excellent leadership posting improved results and continuing to set the standard for the industry.

At this time, I'll turn the call over to Peabody's next CEO, Greg Boyce.

Thank you, Irl and good morning. During our investor call last month, I said that I look forward to taking on the CEO responsibilities at a time when Peabody and the industry are stronger than ever. As I evaluate our operations, I see a company performing very well. We intend to create value from our portfolio of safe low-cost operations, capitalize on leverage to the buoyant market, and seize the large number of opportunities created by our unmatched resource base.

Looking at the broad markets, we are seeing continued healthy growth in the U.S. economy and 6 to 9% increases in India and China. These three nations are important to Peabody because they are forecast to account for 90% of the growth in coal demand over the next quarter-century.

Since our last call, the global metallurgical markets remain very tight. We expect sustained high demand particularly for the hard (indiscernible) coals that we produce in Australia and Appalachia. Thermal markets have strengthened in many regions, including our largest market, the Powder River Basin. In emissions (ph) allowed (ph), prices continue to reach new highs. And as Rick said, this greatly enhances the value of products from our 85 million ton per year North Antelope Rochelle mine whose sulfur value over standard PRB coal is now in excess of $2 per ton.

Transportation is improving in the Western United States as more PRB coal moves east. For instance, more than 10% of our first-quarter contracted PRB volumes were for Eastern plans using this coal for the first time. Courts (ph) continue to face long queues in Australia further tightening the global supply demand balance. Other fuels continue to face constraints. Global oil prices have also kept the U.S. natural gas prices high. This reminds us that LNG in the U.S. will ultimately be pegged to global oil pricing, as it is now for the major LNG consuming countries of Japan and China.

Much of the moisture in the Western U.S. has come too far south to aid U.S. hydropower and nuclear units ran below their limits in the first-quarter due to outages. This has all driven coal stockpiles at U.S. plants to near record low levels, despite a winter that was milder than normal. We are seeing continued growth in coal fuel generation driven by a sturdy U.S. economy and the industrial revolutions of many Asian countries through our billions of dollars earmarked for retro-fitting existing plants and developing new plants. This greatly increases the long-term growth potential of the global coal industry.

That's a brief look at the excellent market conditions. I'd like now to spend a moment on my expectations and yours. As investors, you and I each have the right to expect a track record of performance. The coal industry is attracted significant capital in recent years and I believe that resources should ultimately flow to those companies that have a superior business model and a team to create long-term value.

Peabody's leadership position as a premier energy and mining company gives us a unique ability to capture future value. They're four ways I see us seizing that opportunity. First, we are determined to execute the basics that make us so successful. We are intensely focused on increased safety and productivity. We had a record low U.S. accident rate in the first-quarter. Our U.S. tons per miner shift (ph) exceeded 100 for the first time ever.

I'm particularly encouraged because these productivity improvements result in lower costs and often capacity growth without the need for capital. I find that when the Peabody team is presented with a new challenge it quickly discovers innovative ways to meet it. We intend to continue these improvements.

Number two, we are expanding our global reach to serve growth markets. For example, you'll see us establish a marketing and business development team in China and possibly India during 2005.

Number three, Peabody is entering a period of organic growth using our unmatched reserve position. We have the number one positions in the Powder River Basin and Midwest, both of which we expect to grow significantly in coming years. We are already signing contracts in the PRB and Midwest for multiple years at levels above the average prices we now realize. We are combining new reserve purchases in both regions with our own assets to facilitate future mine development.

Look for the startup of the Gateway Mine in southern Illinois in the second half of 2005. It will serve a long-term contract with a plant that has scrubbing technology. We acquired 950 million tons of ultra-low sulfur Powder River Basin coal in the past year to continue our growth in that region.

Today, there are only two high BTU ultra-low sulfur mines in the Powder River Basin. Our reserve acquisition in the first-quarter combines with existing reserves that we owned to create an 800 million ton base for a third new mine. We are beginning the permitting process in talking with customers about long-term contracts. We hope to develop the operation within several years.

Fourth, also because of our unmatched natural resource base, we are uniquely positioned to participate in and benefit from the industry growth resulting from BTU conversion technologies. Traditionally, coal's major markets have been electricity generation and steelmaking. While these base markets will continue to grow, we are seeing the signs that two new markets are emerging. Technologies exist that allow coal to be turned into a pipeline quality synthetic natural gas or a transportation fuel through liquid faction. Companies like GE and Vector (ph) are investing heavily in coal gasification.

In China, it's like the U.S. in one major way. It is short on oil and natural gas and long on coal reserves. China alone has earmarked $15 billion for coal liquid faction. These plans could provide a template for commercial scale coal to liquids technology use in the U.S. and in other countries. The market demand growth from the use of these two technologies would be substantial.

Executing the basics, expanding the serve growth markets, growing organically, and participating in BTU conversion opportunities, Peabody's near-term prospects and our long-term growth potential are both extremely bright. We had a great first-quarter. We are raising our 2005 outlook and we look forward to even stronger results in the future. As the new CEO, I will look forward to meeting or exceeding your expectations. Again, at this time, we would be pleased to answer any of your questions.

(OPERATOR INSTRUCTIONS). Daniel Roling with Merrill Lynch.

Good morning, gentlemen. Interesting what you said about signing long-term contracts with utilities, almost implying the utilities are concerned about the long-term supply of coal. Do you think we are going to see a significant wave of announcements regarding new coal mine construction, greenfield type, not just expansion?

Dan, I think as -- I talk with a number of the CEOs of the major utilities, it is as much a concern about alternate fuel sources that's driving them to begin to look at signing long-term contracts for coal. And we have had a number of discussions with our customers about those types of contracts. In terms of capacity construction, as we've talked in the past, there is only a very limited number of opportunities to bring in greenfield operations. Clearly this opportunity in the Powder River Basin that we have is one of the premier chances to do that. In addition, in the Illinois Basin, again, our resource base, we believe we're uniquely qualified and capable of bringing on those new developments. But the view that there is a tremendous amount of new developments just waiting to come online, we don't see that on the supply side.

That's good to hear. And lastly, when we talk long-term, are we seeing five or ten years in that category or are we going back to what we used to see, 15 to 20?

We are having discussions on 5, 10, all the way up to 15 year type arrangements, Dan.

Paul Forward with Legg Mason.

Good morning. How much extra volume do you think the rail(ph) infrastructure and the PRB can handle in 2005 versus 2004? And I guess looking longer-term when you talk about a new mine, what sort of investments will the rails (ph) need to make in order to serve that new mine?

Paul, thanks for the question. In terms of 2005, it's our view that the railroads have in the West succeeded in building up their talent of people and equipment in order to move all of the supply that will be available out of 2005 from the Powder River Basin. Over the longer-term, as you look at the additions, the demand, going forward, the railroads assure us that through additional triple tracking and additional investments, they will be able to meet that demand going forward.

Quickly, on this trading and brokerage loss, just to get a sense of how that happened, was it due to a mine outage? Was it rail service in the East? Was it perhaps an opportunistic move into a market with better pricing by the producer? Can you give us any information on how that happened this quarter?

Yes Paul, this is Rick. I'll probably be a little bit limited in my remarks due to the legal nature of the claim. But what I will say is that it certainly, from the best of our knowledge; it was not anything due to their physical capability to produce the coal. So in our sense, it's more of a price majeure issue versus a force majeure issue. It's a long-term contract that has been in place, at least this particular leg of the contract, since 2003. And the producer has decided not to ship the contract for a variety of reasons that we think are not covered by the contract. So we're going to enforce our rights under contract to get the coal or get monetary damages.

Michael Duda with Bear Stearns.

Good morning, gentlemen. When you talk about -- a little more detail on sulfur credits, how you guys are looking at the market, how tight you think it will be going forward? Could you talk a little bit about the Delta and how much you get per ton of coal from your North Antelope Rochelle product? Does the utility pay that extra or do you get the credit? Do you trade it? Could you give a little more detail about that? And then just to follow-up. Is the new mine you're talking about, you're saying that production base will have very similar metrics as well?

The answer to the second question, Michael is essentially yes. It will be the low 0.5 pound S02, so it will be that ultra-low sulfur coal that set that premium price. But typically, as you may know, PRB pricing is going to be based of the benchmark price which is the 0.8 pound coal, more like the Northern mines and the Black Thunder mine.

In our case, at current S02 allowance pricings, in excess of $800, the sulfur premium has been at 0.5 and a 0.8, in excess of $2 a ton. So how do we capture that? A variety of ways. Just baked into the essential flat pricing into the contract is the simplest manner. In some cases where we may have a different view with the customer as to what the allowance of -- the future value of allowances are. We may set it to an index and price that premium to an index, or we may just take the allowance back physically. And in our case, we can take it back and then it's our view to take our own view of the market and sell forward those allowances.

So there's a number of ways to do it for us, but in essence, we capture the value on those 85 million tons that we're selling out of the North Antelope Rochelle complex.

Would that show up in your brokerage side or the (indiscernible) percent you get out of your West operations as we look through the --?

Production side mostly and the Western side. I mean, the Western production would not be in the brokerage business.

My follow-up question speaking with PRB, as you guys look at the market and the excess added production you may bring on or others into the market, do you anticipate the majority will be going to customers West of the Mississippi River for new or expanded coal-fired capacity, or do you believe that the majority or delta will go East to penetrate on the price differential and possibly sulfur issues as well?

Well, it's our view when you look at the 8800 ultra-low sulfur coals that that will go predominantly East of the Mississippi into that utility base that needs the higher BTU content coal and needs the ultra-low sulfur. That's not to say for the rest of the Powder River Basin we don't see growth west of the Mississippi in the core part of that marketplace, but for the higher BTU where we would be bringing on additional production going forward, we see most of that going to the East and the Southeast.

While I know you don't negotiate the transportation issues, what have you seen or in your discussions with these utilities about how the railroads are pricing their service product?

Well, as you indicate, we are not in the negotiations for freight rates. What we do understand, that the railroads and utilities are in discussions about their long-term rates. Given that there will be additional capital required in the freight sector and the rail sector; obviously those discussions are looking at potentially higher pricing. But I would say that from our customer base, we are engaging in long-term discussions for coal supply agreements. The railroad issues have not come into play in those negotiations.

Thank you, Rick and Greg.

Dave Gagliano with Credit Suisse First Boston.

Good morning. Just a quick question with regards to the new mine in the Powder River Basin. Considering that you're in the permitting phase, I was wondering if you could just give us a bit more detail regarding the operating metrics for the third new line, i.e. things like annual production volume, expectations, any early indications, capital spending; more details perhaps regarding the timing or early indications around timing for startup?

Sure, we'd be glad to. If you look at just the timing factor, to go through the permitting process and then to construct and build the operation, you are looking at a three-year, a three-plus-year timeframe at the earliest. As we have looked at planning for that operation, we look at an operation that will be around a 30 million ton a year producer. Now I would remind you that the Powder River Basin and that product in the Powder River Basin has been growing at 20 million tons a year. So even this operation will not meet the full demand growth that we see in the Powder River Basin. But a 30 million ton a year production, large surface operation, likely dragline type equipment, capital estimates -- and this is early days; we obviously have engineering details to work through -- but you could use a number in the 175 to $200 million range for the capital investment for that operation.

And then is there any early indication on cash costs for the operation?

No, it would be a bit early to be making projections there.

Okay, fair enough.

It's similar, though, Dave, to the current operations that we have in the Powder River Basin. Ratio is very similar.

Wayne Atwell with Morgan Stanley.

Thank you. I had a follow-up question on the discussion of the new -- potential new mine. The capital spending seems a little bit low. I thought load-out would be about $120 million, just for the load-out. Then when you add in equipment, trucks and shovels and prestripping and all, I would have thought the capital cost would have been more than that.

Wayne, as we have looked at the type of operation that we would put in there, we are talking about a luke (ph) and a couple of silos, simple loading facility. We're not planning on building a major complex. And then the mining equipment to run the operation. So, as I say, in today's dollars, 175, 200 million, we believe is the number it would take to put that operation in.

Maybe you could share your thoughts on the initiative in China and India. China, if I'm not mistaken, is the largest producer of coal in the world. Now it's almost like two countries; they both export and import. And India, I guess, has poor-quality coal from my understanding. Maybe you could share your thoughts in terms of potential in both of those countries.

In the case of China, our interest there initially will be to open up a trading and marketing office and then a business development team. Really to build the relationships, understand the marketplace; understand where the government is going in terms of their natural resource ownership and development, and to begin the development of partnerships with the major players in the Chinese coal industry. Once we've been on the ground there for a while and established all of that database, we will have a better view in terms of where we might begin to enter that market on a business activity basis.

India, obviously, would be a bit slower track. We may or may not open up that office this year. And India is, we believe, a bit farther behind China in terms of the full development of its resource base and really determining the structure internal to India as to how they will make that happen. But they -- clearly both countries have significant reserve basins and will have mainstay of demand growth for the next 20, 25 years and longer for coal.

So your participation could be as an owner of capacity or as a joint venture partner in developing assets in these countries?

It could be any of those; most likely the joint venture type arrangements initially. We'd have to see a different set or more clarity in terms of asset ownership. So our initial focus would be on the joint venture type arrangements, building those arrangements for the long-term.

Well, presumably, you'd build capacity and sell it internally.

It could be either model at this point in time. But China, we believe, is moving towards being a heavier importer of coals. So it would likely be for internal type consumption.

John Wilkes (ph) with Wachovia.

Good morning. I was just wondering, first of all, how you are incorporating -- how you build up sulfur credits for the rest of year into your guidance; question number one?

John, a lot of the contracts that we've placed in '05, if they were on fixed prices they would have been based upon the sulfur value at the time we locked those in. The ones that are floating and are indexed, we are still looking up sulfur credits. Probably a conservative estimate would be in the 700 to 750 range in our view for the rest of the year. We don't see the sulfur prices weakening.

What's the mix of ones that float versus fixed-price?

I don't have an exact number but I'd say it's probably 50% fixed and 25% floating, 25% if you take back credits. That's just a ballpark number but it just gives you an idea of how to look at that.

When you look at the market today, if you typically got into a negotiation, are you looking to secure the option for the sulfur or do a fixed-price deal where you get credit for the curve or it doesn't matter?

It doesn't really matter to us with our trading shop and the sophistication that we have. We can either take it in the price and or take it in sulfur credits down the road. If we like the price today we can always sell forward those credits and lock in a $850 price if we think that's where the top end of the number is for credits.

On the other side of the world, when you look at Northern Appalachia pricing and negotiation, can you give us a little color on customer negotiations and just some other things to think about there that relates to the higher sulfur?

Can you repeat the question, John?

I'm just asking related to Northern Appalachia negotiations, in terms of having coal that is not compliant with the sulfur curve having surged, how is that affecting negotiations? Is there any (multiple speakers)?

It hasn't made much of impact, John, because most of those coals go into to scrub power plants, for the most part, because those are going to be a little bit higher in sulfur. It probably has more of an impact on your Central Appalachian product that the pricing in Central Appalachian remains extremely strong.

And then the non-Northern -- North Antelope Rochelle coal, is that pretty much 0.8? Is that what you are saying?

Yes, for the most part. The Northern coals are going to be 0.8, 0.9, some 0.7, but in that medium-range there.

John Bridges with J.P. Morgan.

Good morning, Greg and Rick. Just following on on that North Antelope thing. You are currently blending some of that stuff. So you are blending some of that up to contract levels, are you?

I guess I'm not sure exactly what you mean by the question, John. We have a number of contracts obviously out of North Antelope Rochelle that have a varying sulfur specifications as well as BTU. So we do a limited amount of blending. On average, the 85 million tons that we produce out of North Antelope Rochelle would be at that ultra-low sulfur compliant coal basis.

Yes, I'm like everybody else. I'm just trying to get to the bottom of how quickly these sulfur premium get into your sales prices. So --

John, I would say that we've been getting sulfur premiums for years on this product based upon the cost of allowances, even when they were $110 in allowance, $250 in allowance; we received a premium of $0.25 to $0.50 a time, always in the market. And today, that premier just become much higher because of the one-up in the prices that look to be fairly stable.

So 50% of it is -- you're going to get the premier coming in on the schedule of roughly three-year rollover in your contracts?

The higher value? Yes, as contracts continue to rollover we will continue to negotiate those contracts in order to capture the higher price of SO2 allowances within the market today.

John, let me make sure, we anticipate we're getting 50% of that value now and the remaining 50% we would get as the contracts rollover and the volumes get repriced going forward.

Absolutely. I'm with you now. With respect to these longer-term contracts, are these volume contracts which protect the utilities of (indiscernible) or are they talking yet about prices which would protect your ability to build new mines?

It would be the latter. We would be looking at long-term contracts with pricing mechanisms in them over the long-term. That would allow us to baseload new operations.

How far along are you? The utilities, so far as I understand it, have been unwilling to sign anything further than a three-year contract.

As I indicated earlier, we'll be starting up the Gateway Mine in southern Illinois in the second half of this year and that's a ten-year contract with the pricing mechanisms in place that have allowed us to invest in that operation and start it. We have done some other recent long-term contracts in the West to do the same thing for incremental production.

That's a mine math project, incremental mine math project. Thank you.

Jay Turner with BMO Nesbitt Burns.

Thank you. Good morning, gentlemen. A couple of quick questions. On Australia, I think you mentioned that the merge costs were high. I was wondering if you could just revisit that but then at the same time whether you have been involved in any of the discussions with the other Australian producers for strategy to remove some of the bottlenecks that are creating the demurrage.

Yes, let's talk for minute about the demurrage issues. They continued through the first quarter of this year. Probably about $10 million worth of our cost structure for the first quarter of light (ph) up Australia was demurrage charges. Which is -- we had about 3 million in our original budget so it was higher than we had anticipated. The good part is that's related to the demand being very very strong. And the port, while it has continued to improve its capabilities, as you recall, had damage to one of its loading shoots last year, which they are still going through the process of bringing back up to full production.

In terms of what happens going forward with the port, we are part of a group and we have contractual arrangements with the port. As the Australian government, the port operator, which is now a private company, having Queensland government gone through privatization last year and the users are all in negotiations and discussions about port fees; as well as the timing of capital expansions for that port facility.

I mean, I think it's prime investments or something?

Prime infrastructure.

And they just lost out on a bid to have the loading rate raised from a $1.30 Australian up to $2.50 or something?

Well, there's a process that they have to go through through the Queensland Port Commission to justify their rate structure and their initial rate proposal for ongoing operations. The Commission did cutback to what the Commission thought, and all of the users thought, was a more reasonable level. That separate and apart from discussions about the capital required to go forward in the future for any expansions.

They appear to be linking the two. Is there any opportunity, assuming that you want lower rates, you want lower coal loading rates, how would you go about addressing the capital issue?

Obviously, it's in the long-term interest to have logical expansions at that port to meet the demand going forward. All I can say is we're in negotiations with Queensland government, prime and the other users and I'm confident, given a reasonable set of assumptions, that they will come to agreement and we will ultimately see that investment in the port in Australia.

Then I guess to switch gears a bit here. I know that in the past, and I have heard Rick say this, that your Illinois-Basin strategy is because you believe that's where the market is going to be in three to four years. Assuming that you are expanding -- you're going to go through with this expansion and add 30 million tons of incremental ultra-low sulfur coal, how do you see your production base in the Illinois Basin evolving given that this ultra-low sulfur coal can be blended with some of the Illinois, the higher sulfur Illinois coals? And have you seen any utilities that have come to you with that strategy of blending the two coals as a means of getting a substitutable product that they can stick in their boilers?

As we look at the Illinois Basin going forward, and you step back and you look at the significant capital investments that are ongoing as we speak. In terms of adding additional scrubbers in the Midwest, we really look at that as baseloading the growth rates for the Illinois Basin.

Now, going forward, there will be some blending of coals out of the Powder River Basin but ultimately when we get to the next stages of the clean air requirements, the scrubbing technology needs -- has to be installed, is going in, and at that point in time, then you have the closer in, lower transportation freight costs of an Basin versus a Powder River Basin.

I guess I was also thinking in terms of BTUs. Mixing an 8800, 8400 BTU coal with a higher sulfur, you know sort of 12,000 BTU, would get you a product that might burn more effectively in an existing powerplant.

And we would agree with that and there are clearly powerplants that are using that strategy today.

Any chance of quantifying what you think was the volumes of coal that might be going into that type of market?

Just to quantify with blending, when we look at the PRB market and, Jay, we think it's going to grow 20 to 25 (indiscernible) in the next twenty years by 200 million tons. In similar projections, they are building the infrastructure to meet that capacity. There are going to be different types of scrubbers installed at different types of plants. Some plants will put the heavier scrubbing equipment in and they will burn the higher sulfur coal. It won't make as much sense to burn the lower sulfur coals. The eastern producer mixed the lower noncompliant, but lower sulfur coals, from the East and higher BTU with the PRB and (indiscernible) very successful and they have been doing that very successfully.

David Khani with Friedman, Billings, Ramsey.

Hi, guys. I know everybody's been harping on these long-term contracts but I want to ask another question. Price reopeners, directionally, are they going longer into the contract or shorter? Are you putting collars around them like you did prior?

Well, clearly we don't want to get into any kinds of details around our commercial negotiations. Suffice it to say that every market has some unique characteristics to it; but we are very comfortable that we're capturing the full growth potential of the markets going forward and protecting our ability to capture the increase in premiums and pricing going forward.

And moving over to sulfur, are you finding, looking forward now, that prices are higher, that utilities are looking for more floating and less fixed so that they are not locking in this high price even though maybe it goes higher, maybe it doesn't. What's the feel of the utility customer today?

Dave, I think it's a mixed bag. Some are willing to lock in the pricing. They are comfortable with that and that's something they can put in their rate base and move forward, not having an uncertainty with a floating price. But in other cases, they like the floating price concept because they may have a different view of where sulfur allowances are headed. In our case, an area we look at that says sulfur allowances, at least for the next five to six, seven years, are going to remain above 650. So we're very comfortable with that.

You don't see meaningful shift from that 50 floating and other stuff?

Not today, but things can change. Right now, we haven't seen that.

Last question, I don't think anybody's harped on yet is UMWA, there was a little shot across the bow up in Canada that -- potential mind strike and the end of this year the contract comes due. Do you have any insight into what is going on right now and give us sort of a timeline of what you think is going to happen in their negotiations?

It's actually the end of next year, the end of '06 when those contract negotiations come up. So, probably a bit early to making any speculation there. I might point out though that we just went through contract negotiations in Australia and successfully concluded those labor negotiations. That became effective at the end of February.

But if I remember correctly, the contract was coming due last time on the UMWA was negotiated early and surprised us how fast it got done. Is there any movement going on right now?

There's no movement today, no discussions about bringing those contract negotiations forward at all. And just as a reminder, essentially 80 plus percent of our production now is being produced from non-union operations. So while it's certainly something that is on our radar screen and we pay a great deal of attention to, there's no need for us to get into a hurry on the negotiations.

Ashwin Krishna (ph) with Morgan Stanley.

Hi, guys. Just a couple of quick questions. Any update on the Black Thunder financing plan?

Can you repeat the question?

Any update on the Black Thunder financing plan?

Are you referring to the Black Mesa?

Yes.

The Black Mesa plan. Well, there's no additional updates from the last conference call that we had, Ashwin. The parties continue in the mediation process. And there's a tremendous amount of time and energy being dedicated to that process. All designed and hopefully with a positive outcome for both the Navajo and the Hopi in terms of their abilities to maintain their revenues from those plants; as well as the continuity of the mining operations in the powerplant.

But there's no update that we can really say or give any guidance at this point in time.

My second question was on the receivable stability that you have, what was the amount drawn at quarter end?

From the overall receivables, it would be $225 million.

Scott Suprelli (ph) with (indiscernible) Arch Capital (ph).

Hi, thanks. Could you give us comparable numbers for the revenue per tons that you disclosed for each of your mining jurisdictions at today's market value as opposed to what you realized in the quarter? Thanks.

We probably can't do that necessarily with respect to the contract, but what I can tell you for the Powder River Basin pricing, as we said in our remarks, is that the pricing that we realized in '05 was up about 11 to 12% over '04 historical average realized prices. And we are seeing forward prices today up 35%, excluding the sulfur premium. When you add that number in you'll have a bit more of an increase in overall pricing. But it's difficult for us to put out a number per se. But most of that information is available publicly through the trading rags that you can look at, the trade publications. And it would usually list it for each product. And while that might not be so indicative of a contractual price, it's directionally a good place to look.

Thanks.

Andrew Shirley with Ivory Capital.

I was wondering if you could break down your capital budget into some smaller bucket?

Sure. If you look at the 400 to 450 for this year, approximately a quarter of that, $115 to $120 million of that will relate to the successful bids for PRB reserves that we had last year and this year. Then in addition to that, we will have the -- a couple of projects that we mentioned earlier in the year for new longwall in Colorado, roughly $40 million project; additional longwall equipment in Australia to improve the efficiency of that operation, about $25 million of CapEx in that regard; another $25 million in capital being spent to extend the life of a metallurgical coal mine, our largest metallurgical coal mine in Appalachia region; our Harris mine moving into a new reserve; hit some of the bigger items that are baked into the capital budget.

One other thing, how much was the actual charge in the sales and trading?

The total charges that we took during the quarter for what I'll call sales and legal issues was $34 million. The actual amount that went to the sales and brokerage segment of the business was $27 million.

David Pickens (ph) with (indiscernible) Haven.

My questions have been asked. Thanks.

Senaro (ph) (indiscernible) with Bramwell Capital Management.

Could you just give us an idea about what caused your trading and brokerage operations to go into red?

As mentioned in our press release and in our call, we had to take a large charge in this quarter for the failure of a producer to deliver on its contractual commitments to us for coal. So that's the estimate of the cost that it will cost us to replace that product in the marketplace. So it's an accrual for the future purchase of coal that we will need to cover that contract.

On the metallurgical side, 12 to 14 million which is available for reprocessing in '06 '07, what kind of pricing environment are you seeing currently?

We haven't seen any changes in the pricing environment since the settlement of the contracts in January for this Japanese fiscal year that were sold, the metallurgical coal out of Australia at $115 to $125 a metric ton. Those negotiations won't begin for '06 until late '05, beginning of '06. We can't give you a prediction on those numbers but right now we haven't seen any softening.

You mean to say it does not increase or it's only stable?

We suggest that it's stable at this point in time. There's really not much in the way of negotiations going on. Most of the business has been contracted and most of the producers have sold their production for the year. So you really don't have much movement in pricing after that.

One last question on the PRB coal, you said there is some PRB coal available for repricing. Could you use just give us (indiscernible) how many tons are available for repricing?

Roughly, it's going to be a combination of repricing on contract reopeners, as well as uncommitted production. The best estimate I can give you is that we do 130 million tons a year there. The average life of the contracts and the PRB is three to four years. So the best estimate I can give you going forward without giving you specifics would be that about one-third of that business rolls over for repricing each year.

Michael Lucas (ph) with Appaloosa (ph).

Michael Lucas your line is open, please go ahead. We will move onto Fritz von Carp with Sage Asset Management.

Good morning. Or good afternoon over there, whichever it is. Back on the met coal, there has been some outages in the U.S. of large met coal mines, not yours but your competitors and their absences has helped the market. Are those -- first, just to help bring up-to-date, are those mines still out to the best of your knowledge? And number two; what impact have they been having on the market? What impact might they have when they come back up and just your general thoughts on that situation as it affects the market?

Our understanding -- the mines are still not in production yet. I guess I would say in terms of the met coal market, with all of the producers being in a sold out position, there's just nothing transacting in the marketplace. If coal was available, the market demand would still be there and we believe would be every bit as strong as it was previously. There's no inventories that we are aware of at any of the -- either at the producers or at the plants. And as I said, if people had met coal I think they would be able to contract and commit to that coal going forward in a very strong demand market.

(indiscernible) with Zimmer Lucas Partners.

Could you refresh us on your '06 CapEx guidance and whether it includes the lease payments?

Let me -- on '06, we haven't really given much guidance on the '06 capital. What I will tell you, at the last conference call, we indicated that our CapEx number would be as high as $350 million for '06. That was our ballpark estimate at the time. Since that point in time, we have been, as you suggested, on the third PRB lease, which is about $63 million of capital per year, so going forward, we're going to have about $178 million of capital on an annual basis related to these leases for the next five years. So if I was going to give you just a rough direction, we will give specific guidance towards the end of the year after we finish our budget. I (indiscernible) the 350 number that I gave you did not include the additional $63 million related to the successful acquisition of the last PRB lease.

Does that include the previous 114 million?

Yes. Yes it did.

Mark Levine (ph) with Davenport (ph).

My questions have been asked and answered. Thank you.

Mike Clark with Satellite Asset Management.

It looks like you had a nice pick up in equity income. I'm assuming that's from the Venezuela operation. Could you comment on the performance there and what we might expect for the year?

You're exactly right. That's the reason that we had the increase in the equity income; it was related to the acquisition of the Venezuelan operations. We had $5 million in equity income this quarter. We are estimating, and the mines are performing very very well, and we are estimating that we'll get another 5 million every quarter and maybe a bit more as we get further into the year. So we are very pleased with that investment so far.

What's the average quality of that coal?

It's a high heat closer to a 12,900, 13,000 BTU, less than 1% sulfur, so it's very comparable to the best Appalachian coals. It's a coal that actually goes into the very high end of the thermal market and also is being sold as what's called a PCI coal, which is a coal that can be used for metallurgical steelmaking purposes.

Dan Roling. Please go ahead.

Thank you. Gentlemen, maybe I missed it. But could you give us some of the details on the Gateway Mine, like the quality of the coal, and the volume you're going to produce and the capital?

This is a standard Illinois-Basin product and Dan; it would be about 4 million tons per year. At full production, it's about 11,000 BTU, plus or minus around 5 pounds sulfur. I would also add that property came to us as part of our purchase of the Lexington Coal assets. What we really were buying with that purchase was infrastructure and some reserves that we could couple with our reserve base. We wound up actually buying three properties. The first one that we will develop will be this Gateway Mine and the development costs are extremely low because the prep (ph) plant, the rail infrastructure, the slope, the underground access, the ventilation was all in place. So really all we're doing is a bit of rehabilitation underground, some new mining equipment and low capital cost, $30 plus million dollar range to bring that into production later this year.

Had it been an operating mine before?

It had been an operating mine before. It was former mine 11.

And what did it run as before? If you remember?

(multiple speakers) It would have run three to three and a half million tons.

We have a follow up from John Bridges.

My question has been answered. Thank you.

And we have a follow-up from Andrew Shirley. Please go ahead.

Just quickly back on the CapEx, you expect to do a couple of items in the 2005 budget which totaled about 200 million and I was wondering if you could tell us exactly what the rest of the 250 to 300 million is spent on. Is that mine press, is it equipment, are there other things in there?

Well, there are a number of things I guess and I'll try to bounce through those items just one more time. If you look at, and I wasn't intending for the list to be exhaustive of course, but I was looking at the larger projects, $115 million of acquisition reserves this year, $40 million of capital related to a longwall system in Colorado, plus miscellaneous other capital. So assume Colorado is going to spend a bit more than $40 million. Longwall system in Australia, new components, another $25 million, but in addition in Australia, we had some reserve acquisitions for surface mineable coking coal fields that we can mine to supplement the current reserves that we already have. And that probably adds another 40 to $50 million of CapEx for us to be able to get that good coking coal out of Australia.

Miscellaneous capital in the Southwest were equipment replacement, among other things. If you think about the overall operations with 175 to $200 million of replacements, you probably can get the rest of the number because you just have ongoing equipment maintenance issues and as I said earlier, our Harris, our largest metallurgical mine in the East, in the Appalachian region, will be replacing that with a new operation and moving it into the James Creek area and that will cost us $25 million in our Appalachian operation. I think roughly that gets you close to the numbers.

It sounds like the remaining part is a split of dollars you actually spend just getting the mines ready versus equipment.

There's ongoing maintenance in all the properties and there's going to be equipment that needs to be replaced, continuous minors that need to be replaced, rolling stock equipment at the surface mines, trucks that would need to be replaced on an annual basis, and it varies by operation on a number of those areas. And there's also some small capital being spent on our generation development project. You can figure that number is about$15 million.

I want to say two things. First, thank the entire Peabody team for delivering the results that we were able to present to you this morning. And then also thank all of you for your interest in BTU and we look forward to providing you an update in the next quarter. Thank you.

Ladies and gentlemen, this conference is available for replay. It starts today at 1:30 pm and will last until May 19th at midnight. You can access the replay at anytime by dialing 1-800-475-6701. International parties please dial 320-365-38 (indiscernible). The access code is 778181. This information is available at the Company website, www.peabodyenergy.com. (OPERATOR INSTRUCTIONS).