Peabody Energy Corp (BTU) 2005 Q3 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 your 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 call over to the Vice President of Public and Investor Relations, Mr. Vic Svec. Please go ahead, sir.

Thank you, John. Good morning, everyone, and thanks for taking part in the conference call for BTU, amid very favorable fundamentals for the industry and the Company. Today, Executive VP and Chief Financial Officer, Rick Navarre, will review our results and our outlook, and President and CEO elect, Greg Boyce will discuss the markets, as well as our growth initiatives.

Forward-looking statements should be considered along with the risk factors that we note at the end of our release and the MD&A section of our 10-K. We also refer you to PeabodyEnergy.com for additional information. And with that, I'll now turn the call over to Rick.

Thanks, Vic, and good morning, everyone, and welcome to Peabody's earnings review. Our results continue to emphasize a record of performance and our position as the industry leader.

Year to date, sales, EBITDA, operating profit and net income all set new records. Our quarterly operating profit doubled and net income grew 161%, and our sales volume expanded as operating profit per ton nearly doubled. So results are at very high levels and Peabody's forward outlook is even brighter.

The most substantial change since our last call is the continued price increases for our largest markets, especially the Powder River Basin. Tight supply, low stockpiles, transportation issues and recent soaring of SO2 allowance prices have driven the OTC spot market prices to record levels. We add very good leverage to this market and expect to realize improved revenues as we sign new contracts.

With that as an overview, I will now review the financial results in more detail and then turn it over to Greg, who will discuss the industry outlook.

Starting with the income statement, you'll see that our quarterly revenues grew by one-third to $1.2 billion, reflecting increased pricing and volumes across the board. Operating profit grew 104% and EBITDA increased 53% over last year. Quarterly net income rose 161% to $113 million and our nine-month net income of $260 million set a new Peabody annual high in just the first three quarters of this year.

Moving now to the supplemental data, Peabody posted strong gains again this quarter. High customer demand led to growing sales volume in all of our regions and our 178 million tons sold year-to-date is our highest level ever. Eastern margins per ton improved 62%, reflecting higher realized prices for thermal and met coal.

Our Eastern margins improved, overcoming several challenges. First, an extended Longwall move at Harris, one of our high-quality met mines, led to higher costs as it finished its current panel. The mine will now move into a new reserve area in 2006. And we also continued to experience higher contract miner costs in Appalachia.

Western revenues per ton increased on pricing in all three western regions. Costs were impacted by higher revenue-driven taxes and royalties, as well as the impact of lower production due to a Longwall move this quarter at the 20-mile mine.

Also as many of you are aware, there was extensive maintenance work being performed on the Powder River Basin joint rail line this quarter. This resulted in 2 to 3 million tons of lost shipments adversely impacting our profits out of the Powder River Basin.

While higher commodity costs for fuel, explosives and steel continue to put pressure on the industry, our active management allows us to minimize this impact. Availability is also a critical issue that we are concerned about. For example, supplies of large tires for the mining industry are very tight. Our commodity management teams have implemented initiatives across our operations. At our largest mine, North Antelope Rochelle, this has led to nearly 20% longer tire lives so far this year. Ultimately strong productivity is the key to overcoming the cost pressures that we are experiencing. The latest data shows that Peabody operates the three most productive mines in America and we operate the world's best-in-class dragline in our North Antelope Rochelle property.

Shifting to the Australian results, you will see Australian margins per ton more than doubled, and would have increased even more absent geology issues at our North Goonyella underground mine. This led to lower production and impacted profit by 20 to $30 million, as we were down approximately 60 days during the quarter. The North Goonyella met mine has been challenging and offers one more example of the fragile nature of many of the world's high-quality met coal mines. As mentioned in our press release, we're taking steps to overcome the difficult geologic issues. The higher capacity Longwall that we ordered last year will be installed the first quarter of 2006. And as you will recall, we built the adjacent Eaglefield service operation last year and have begun increasing its production to supplement the underground mine.

Our other segments, trading and brokerage and resource management also posted solid quarterly increases. The results include the completion of several commercial transactions in the Midwest and the Appalachia regions.

Trading had a solid third quarter but it's full-year results are off prior year's pace. You will recall that we took charges of approximately $30 million in the first quarter related to contractual disputes. As part of a settlement with one of the suppliers, we both sold and acquired coal reserves, including receiving strategic met coal reserves for future mining. The combined transactions benefited resource management by more than $40 million and offset the first quarter charge to trading and brokerage. So really to better evaluate the results, you should look at the nine-month combined trading and brokerage and resource management areas.

You will recall that our resource management strategy is to aggressively manage our natural resource base so that we have a steady stream of commercial opportunities and can unlock the value of our 9.6 billion tons of coal reserves. Current market conditions will create numerous opportunities in this area for us.

With our robust results, Peabody's cash flow from operations nearly tripled for the first nine months to $422 million. Strong cash flow should continue to increase in line with the Company's earnings profile, offering multiple opportunities both to grow and create value.

These same results make our balance sheet even stronger. Our cash position stands at $479 million and our net debt to net capital ratio is at a very modest 31%. That's a brief look at our financials.

Now turning to be committed to the committed sales position, Peabody retains excellent leverage to the improved markets, as we outlined in our release and as I mentioned at the beginning of my remarks. Three markets make up nearly 80% of our production -- the Powder River Basin, Colorado and the Illinois Basin. Peabody is a leader in each of those regions and these markets have also seen the largest price increases in the past year.

For example, the published price for premium Powder River Basin coal has increased more than 150% this year. We are now signing contracts in these regions and the duration of those contracts suggests that our results should continue to benefit for many years to come.

Turning to our near-term outlook, we are targeting full-year 2005 EBITDA of $825 million to $875 million; and earnings per share of $2.75 to $3.20. Results will continue to be sensitive to transportation issues and operational performance.

In summary, we remain on a record pace for 2005 and we are positioning the Company to continue its strong pace of growth and improving results for 2006 and beyond. I'll now turn the call over to our President and next CEO, Greg Boyce. Greg?

Good morning, everyone, and thank you for joining us. Rick has discussed Peabody's record results and excellent prospects and I'd like to provide you with our views on the traditional market fundamentals, an update on the emerging markets and our unique growth opportunities resulting from today's unprecedented interest in and demand for coal. As I review Peabody's assets, strategies and markets, it is clear that our premier status in the sector is well founded. Peabody has the industry's most diverse asset portfolio and customer base. Our reserve base provides us an unmatched number of organic growth opportunities, and we have the highest leverage to the Powder River Basin, which as Rick said, has seen the largest price increase this year. Our prospects for coal continue to be outstanding. Let's look at the key growth drivers.

Coal is fueling the world's largest and fastest-growing economies in the U.S., China and India. Access to large, secure energy sources is increasingly valuable. Around the globe, countries & companies are paying a premium to acquire what Peabody already has, vast energy reserves. Other fuels are straining to keep up with demand. In the U.S., natural gas faces enormous hurdles just to try to approach prior-year production. And globally, LNG is being diverted to the highest bidder, and projects are underway to turn natural gas into liquid fuels rather than LNG. So it is little surprise that coal has emerged as the preferred fuel to fill the void left by others.

Coal's traditional markets are seeing sustained strength. Global steel production continues to increase at 6% per year. The supply/demand balance for met coal remains very tight and we are obtaining premiums for the hard coking coals that several of our mines produce. Coal-fueled generating plants are working harder than ever. Last quarter, I indicated that Peabody believed that U.S. customer stockpiles would reach record low levels and that is exactly what has happened. Inventories are at an all-time low for this time of year, some 30 million tons below average. Today, we know of at least 15 to 20 major plants that are below 15 days of coal supply, several of these with less than five days. This suggests high coal demand for the foreseeable future, as the energy infrastructure in this country operates near maximum capacity. Our utility customers will try to meet immediate generation needs, grow to satisfy the expanding economy and someday replenish low stockpiles.

Longer term, 462 gigawatts of new coal-fueled capacity have been announced around the world. That represents nearly 2 billion tons of annual coal use. In the U.S. alone, plants representing 73 gigawatts have been announced.

Finally, coal and gas and coal-to-liquids technologies are being pursued in the United States, China and India. These technologies exist today and are, commercially, oil and gas prices well below current levels. Coal can be turned into natural gas at $5 to $6 per million Btu and coal can become diesel fuel between 35 and $40 per barrel. Simply put, the market for coal is quickly expanding to satisfy the energy needs of nations with abundant coal. The recently passed Energy and Transportation Bills further encourage these coal conversion technologies here in the U.S.

At Peabody, our entire team is implementing strategies to capture near, long-term value from these outstanding markets. Our opportunities to grow and create value are excellent. Our operations are running at high levels to satisfy record coal demand. The Peabody team is achieving impressive safety improvements, major productivity milestones and numerous environmental awards. Our marketing group is launching in long-term contracts at significantly higher prices and the resource manager group is capturing value by capitalizing on the improved prices for coal research.

In the Powder River Basin, Peabody has expanded its current operations through loading facility upgrades this year at the Caballo and North Antelope Rochelle mines and we are developing the largest new coal mine in the past decade, School Creek. This new PRB mine is going through environmental permitting and design engineering. We have combined 327 million tons of reserves that we acquired early this year with a large resource base that we already control. This results in 800 million tons of the best, undeveloped ultra-low sulfur coal in the U.S. We are in talks with customers to base load this mine, which will grow to 30 to 40 million tons of annual production over time. Simply put, Peabody is both expanding volumes and capturing improved pricing in what is the fastest-growing U.S. market. In fact, with School Creek, Peabody has identified more than 75 million tons of expansion and new mine opportunities on our reserves in the U.S. and Australia that could be developed over the next five years as market conditions warrant.

Now Peabody is also participating in the emerging market opportunities for Btu conversion. We reached agreement to purchase up to 30% in Econo-Power International. This company owns and markets a proprietary technology to convert coal into a synthetic natural gas. The same gas is primarily used to generate heat for industrial users, who need relief from high natural gas prices. And dozens of similar gasifiers are in use today in China. They are low in capital cost, easy to permit and can be up and running within two years.

This is just one of a number of coal conversion technologies that are being developed around the world. In recent months, we have had talks with multiple companies regarding coal to synthetic natural gas and coal to diesel projects. We believe that coal reserves are valued at a significant discount to oil and natural gas reserves. Converting coal into these energy forms should narrow that gap. Convert a portion of our 9.6 billion tons of reserves into oil and gas and, thereby, add substantial value for our shareholders.

So to summarize, the Peabody team is positioned to deliver increasing earnings and operating cash flows in coming years. We are locking in value and greatly improving markets, we are expanding organically, using the industry's best reserve base and we are participating in projects to arbitrage the value of coal with that of natural gas and oil.

That's a brief review of the industry and Company. Thank you for your continued interest and support in Peabody. When we next report earnings, we look forward to posting another record year, discussing our pipeline of growth projects and long-term contracts and offering our targets for 2006. So at this time, we would be happy to take your questions.

(Operator Instructions). Ladies and gentlemen, we ask that you please limit yourselves to one question and a backup question.

Daniel Roling, Merrill Lynch.

Hi. It's Dave Lipschitz. UP and BN announced that they are cutting back on some of the maintenance in the Joyette (ph) line. Have you seen any of that yet? Do you expect transportation, the maintenance to go on longer but be better? Do you think you'll be able to get more tons out going over the next couple of months?

Yes, Dave. We have looked at that announcement and we've talked with obviously both the BN and the UP. I think they both recognize that the schedule that they had in place and with the maintenance work that was occurring, they were causing more delays in the system than they had anticipated. So they have revised that schedule to allow for more shipments during the remainder of the fourth quarter. Their plan currently will then to be to look at their total maintenance program for 2006 and integrate that work into 2006. So overall, it should be a better result than what we were seeing in August and September for the fourth quarter and next year.

And follow up, Rick, can you break down the costs or the lost income from the regions, like Australia East and the PRB, to all like either transportation or geological issues?

Sure. At the highest level, Dave, I think on the Australian side, with the combination of lost production and the merge charges that we incurred, it's about 20 to $30 million of lost profits. We hope to get that back as we move forward. In the Powder River Basin, 2 to 3 million tons, roughly 8 to $10 million of charges for that. In the East, it's a little bit tougher number to get your arms around, but I would say about $5 million. And then the one piece that I didn't really mention, and it's really more of a timing issue, Dave, than anything else, is that we missed by a day two significant vessels, both in the East and in Australia for a combined profit of about $10 million that will fall into the fourth quarter that we didn't get in the third quarter.

And finally, I guess if you were looking for one other item, that is kind of a big charge that occurred in the quarter because of our stock price appreciation during the third quarter of about 60% and the combined appreciation of about 180% in the last 12 months, we had a charge through A&D for equity-based compensation plans of about $19 million.

Now that won't be in the fourth quarter, obviously?

It depends on what happens with stock prices in the fourth quarter, Dave.

Okay.

It's going to double!

We don't treat these as nonrecurring items, hopefully.

We assume they are going to continue.

Michael Dudas, Bear Stearns.

First question, Greg, I guess Peabody started their initiatives regarding Thoroughbred and Prairie State, I'm guessing late '90s, 2000, and one, could we maybe get a little update on where those stand. By the time that gets onboard, it could be eight, nine years. Could you relate that to some of the initiatives you talked about in the press release and your prepared remarks regarding liquefaction and gasification technologies? And how, though it's early stage, how rapid, how much government incentive, are partners just feeling it out, or is there real initiative here to get something to work say over the next five years?

We will try and take those in order. Yes, we started in about 2001, both Thoroughbred and Prairie State. Take them one at a time. Thoroughbred, which had gone through the permitting process initially earlier, has been in a more extended appeal process and we are still in a stage of waiting for the final decisions out of Kentucky as to the status of those permits.

In the case of Prairie State, we received all of the permits for Prairie State. Again, that is in the appeal process. It has a more defined appeal process. It's in front of the Environmental Appeals Board as we speak. We hope to get a decision and to allow us to begin construction next year of Prairie State. So it's likely to move forward on a quicker schedule.

Now as you tied both of those into the liquefaction possibilities as well as the gasification possibilities, there's no question that the environmental requirements and the permitting requirements for these large electric generating stations are very complex with the air emissions and some of the opposition is extremely strong that causes these lengthy delays.

In the case of gasification liquefaction, basically these are chemical facilities. Their emissions profiles are significantly reduced. The view is that the permitting time for all of these plants would be substantially less although for the large-scale facilities, the capital costs would be in a similar range.

In both the current energy bill -- the energy bill that was passed this summer as well as the refinery bill that was recently passed in The House, there is language in there that allows for some incentives, both in terms of interest rates as well as in the transportation bills, credits for coal-derived transportation fuel that would, we believe, allow all of these plants to be expedited, such that you would expect to see liquefaction and gasification plants in that reasonably three to five-year time frame.

Now the particular gasification technology that we have entered into the agreement with EPIC, is targeting industrial users. And these plants are very small and the capital numbers are on the order of less than 50 million per facility. It can be permitted very quickly because their emissions are extremely low. So we would expect to see those within the matter of a couple of years.

Terrific. My follow-up question surrounds your discussion in the release of 75 million tons of organic growth from your reserve base and if you've highlighted the 30 to 40 million tons out of the PRB. Could you touch on some of the other areas you're looking at? What are the return requirements that you're looking at to invest in these projects? And are you waiting or needing customer contracts to go ahead with some of these growth prospects, or are you billing them more to speculation that you will be able to sell the coal when you put it onboard?

Well, it's a combination of all of those, although it depends on the region. If we start saying the Illinois Basin, as you know, we had started up the Gateway Mine earlier this year. We will be looking to expand that over time. We've got a couple of other large projects that we have through the design phase and are out talking to customers about in the Western Kentucky and Southern Illinois region, and those particular projects, we would look for a couple of large, longer-term sales contracts to baseload those operations before we would build those. We've announced the expansions at Twentymile. We've got an expansion potential at our Lee Ranch operation, which we call El Segundo. We received that mine permit earlier in this last quarter. Again, would look to predicate that on a longer-term contract in the Southwest region.

We've got expansion potential in Australia, both at our Wilkie Creek operation, as well as a met coal deposit at what we call Curlong (ph) at our Burton operation. And again, both of those we would look to have contracts in place to help baseload the capital for those projects.

And then lastly, we've got School Creek as a new mine and expansion capability at both Caballo and North Antelope Rochelle and we are in discussions with customers about extended timeframe contracts for those.

So probably a long way to answer your question, we do look for longer-term contract to baseload the capital. We don't expect all of it to be sold under long-term contract. We like to have exposure to the increasing markets but would want to get our capital recovery under some long-term contracts.

As for returns, we clearly would expect those to be high-return projects before we would move forward.

Paul Forward, Legg Mason.

Looking at the two problematic met coal mines, Harris and North Goonyella, what would you say would be a combined fourth-quarter production figure for those two mines? And then given that you are planning to expand or recover some production in '06, what would be a comparable, let's say, quarterly run rate production figure in '06? It just seems like fourth quarter looks like it will be pretty weak there. Is that correct?

Fourth quarter was already expected to be a little bit light on the Harris mine. Part of what's happening with Harris is that we are on the last panel in finishing off that particular mine. And it's now moving into a new location, which will be called the James Creek mine going forward, and that doesn't get started up until the second quarter of next year to the third quarter of next year. So you'll probably see a light number coming out of Harris in the fourth quarter as well as in the first quarter of next year.

As it relates to North Goonyella, we are still working through the issues there. Production certainly will be down and that's embedded into our forecast. Normally, that mine will produce 2.5 million tons on an annual basis so that's kind of a normal run rate for the quarter. This next quarter, it's going to be probably we're guessing maybe 60% of that number.

One of the other aspects about the Australian situation is we've got a wash plant facility that sits there at North Goonyella. And when we bought North Goonyella, we recognized all of the mines in the Bowen Basin in Australia, the underground met coal mines all faced difficult geology and all have intermittent periods of issues.

When we bought North Goonyella, there was an adjacent surface operation in the Eaglefield that was identified. We immediately developed that because it feeds into the exact same prep plant at North Goonyella. So what we now have finally brought Eaglefield up to its full stride, our anticipation going forward is that the prep plant capacity will be fully utilized, either between the surface or the underground to balance that production flow going forward, Paul.

And that's my 50% number. I'm including the Eaglefield production as a supplement to the North Goonyella underground.

All right. And any recent data points you might be able to give us on met coal pricing and the outlook for 2006?

Well, other than the markets remain very tight and extremely strong, as you know in the Pacific Rim, we won't begin looking at renewing those contracts, which expire at the end of the first quarter of next year until right around year end. In the U.S. markets, we are in discussions now for next year's business. And just to reinforce that the market remains very, very tight for high quality met coal.

Dave Gagliano, CSFB.

Just turning to the contract commitments, it looks to me like you committed about 50 million tons of '06 and '07 volumes in the just-ended quarter, and I just have two questions. Number one, if you could just give us a quick breakdown of the mix of the volume that you committed in terms of regional breakdown; that's the first question.

The second question, we've been hearing contract prices for 8800 Btu PRB coal of north of $16 a ton, and I'm just wondering if you are seeing those types of pricing, if those numbers are reasonable. If you could just give us a quick comment there as well.

Let me talk about the PRB coal first, Dave, and what I'll do is just point you to the most recent. Today's edition of Coal Daily, which indicated the over-the-counter market transactions yesterday, there were two transactions that traded for two-year deals for '06 and '07 at 18.85 a ton. So coal is being secured at those prices and that's an OTC small tonnage, obviously, as we've said in the past, that's a standard 8800 Btu product, not a premium 8800 Btu product, which we're not going to -- where the value of that $900 sulfur credit will improve that price significantly. And in addition, typically, when you are contracting for large tons, not just a trainload, I mean 2, 3, 4 million tons a year commitments from a reliable supplier, you would expect that those numbers hopefully are better than what you see on the OTC. So hopefully that gives you a little confirmation of what's happening in the met market.

It definitely gives some confirmation. All right. And in terms of the mines that you committed just regionally in the quarter, can you give us a bit of a sense on how much you committed in each region into this strong market?

I'm trying to look at the numbers real quickly, Dave, that was committed during the quarter. All right. It was pretty well evenly split really for the most part amongst, on a proportionate basis to where we have uncommitted sales. And as you know, we are going to have more uncommitted sales in the Powder River Basin than we will in most of our other regions, but we also have a good amount of uncommitted sales in the Midwest, which we are happy about because they are rolling off of some pretty depressed pricing from the late '90s, early 2000's, and now we're starting to turn that business over and repricing that business. So we are seeing a fair amount of that moving forward as well. So probably saw about 50% of it happening in the Midwest, 50% happening in the Powder River Basin, and then a little bit in Southern -- in Northern Appalachia.

Perfect. Thanks.

Jim Rollyson, Raymond James.

Just going back to the PRB pricing that has obviously moved a lot, are you starting to see people trying to sign up any reasonable amount of tonnage at kind of recent prices? Or is it still pretty preliminary at this point?

We certainly think that the customers we are talking to are interested in security of supply. As Greg mentioned in his remarks, we've got customers that have -- a number of customers with less than 15 days of coal in the ground, many of them with less than five days of coal in the ground. They need reliable suppliers that have a good transportation network, good infrastructure at the mines to move the coal. Folks are interested in locking this up, particularly when you're looking at the alternative is burning gas.

Right, right. So there's obviously, relative costs are kind of irrelevant?

So we are looking at their gas forward curves and comparing that to a coal forward curve and they are interested in signing contracts.

Suffice it to say it's been a very active period for us and we don't see anybody sitting on the sidelines.

When you look forward to expanding your PRB production through things like School Creek, what do you think the expansion does ultimately, barring what royalties do with pricing moving up. What do you think expansion projects like that do to your ultimate unit cost in the PRB? Does it help them or hurt them or neutral?

Well, this particular operation should help our unit costs because we would design it and build it to be one of the more productive PRB mines. As you might recall, this reserve base that I talked about sits on what's called the crop line. It's the last new mine to be developed, and what that means is the starting/stripping ratios are extremely low relative to the basin average. So that gives it a cost advantage just by lowering the stripping ratio. In addition, we would plan to put in a new large-scale dragline operation, which again, the cost of operating draglines in the Powder River Basin reduce your overburden costs by half relative to running a truck shovel fleet. So ultimately, it should improve our cost position in the West.

Great. Thank you.

Pearce Hammond, Simmons & Co.

Just two quick questions on labor. Any progress as we head into 2006 on the labor agreement in the U.S.? And then secondly as it relates to labor and specifically legacy liabilities, Arch Coal, through their Magnum Coal transaction will more than likely be able to significantly reduce legacy liabilities. Would you consider a similar transaction or do you see similar transactions taking place? Thank you.

Well, two parts. First part, on the labor in '06, you know, the contracts that exist predominantly for us in the East expire at the end of '06. When the time is right, those discussions for the renewal of that contract will begin. There have been no discussions to date. And the concept of the Arch transaction, all I can say is if that fits their interest and model, I hope it succeeds. We have, over the last 15 years, moved the vast majority of our production and developed our operations to where we have reduced the intensity of our unionization and we would continue on that path.

John Bridges, JP Morgan.

I wonder if you could give us a bit of color on the disposal of assets. That's quite a big number in there.

Sure. I'll give you as much as I can, John. Part of it is under a confidentiality agreement on a comprehensive settlement that we had because of a lawsuit that we were entered into. So what I can say is that we were very pleased, obviously, with the outcome of the transactions. What we were able to do was to exchange some reserves at terms and conditions that were favorable to us and then hopefully were favorable to the other party as well, that allowed us to record a gain on some of the reserves that we already had on our books, basically. I mean there's not a lot of color I can give you. You can see the numbers -- it's $45 million, roughly. Part of that goes to one customer dispute among other items that we had in the settlement over the last two quarters. Pretty reluctant to get into too much more detail, John, because of confidentiality issues.

Okay. On met coal, you have delays with Goonyella and Harris. Has that delayed when you were picking up the new met coal prices or are you fully into the new prices by now?

It didn't have an impact at Harris, so as we were fully into the met coal prices and we didn't really have any carryover business. But as you recall at North Goonyella, we had carryover business from the previous owners that we needed to honor. And we thought we would work most of that off in the second quarter of this year once we began the new contracts. But because of some of the delays and we were still working off some of that business even into this third quarter at some of the 45 to $50 price range. So that's why you might see the price being a little bit lower than you might have thought it would have been in Australia. I think we've -- we should have worked most of the business from the previous year off now and everything else should be at the higher prices.

Okay. Thanks.

I'd like to reemphasize to everyone that the situation at Harris is a planned situation. If you go back to the end of last year, we thought that Harris would be shutting down middle of 2005. We identified a new reserve area called James Creek. We approved the capital and did the development work and we knew that the Longwall would finish up in Harris in the beginning of the third quarter, which it did, and the new mine at James Creek would not be open and ready for the Longwall to move into until the latter part of the first quarter or in the first quarter of next year.

So this gap had been planned all along for both this year and for these quarters. So that's one of the reasons why in terms of any carryover or any issues with our customers, this has all been part off the production schedule all along.

David Thickens, Deephaven Capital.

Most of my questions have been answered, but can you talk a little bit about if you are seeing any change in order trends from customers? We're hearing that because of the railroad problems, utilities have been getting 85 or 90% ballpark of their normal volumes. Are customers at all talking about contracting for higher volumes anticipating problems from the railroads that never go away, just thinking that you contract for a little more than you want, you get cut backs lately, you end up getting what you want. That would impact pricing if that was going on.

Yes, I mean I guess I can't speak specifically that we are aware of any customers that are over contracting. I will say that we hear more customers talk about -- they went through a number of years where they had made determinations that they were going to reduce their inventories and carry less inventory on an ongoing basis. We are now hearing more customers talk about the fact that they think that they probably drove those inventories to low. And given the increase in demand, the rail issues and their dependence on coal, that they will probably long-term raise those inventory levels over the course of the next couple of years to get back up to a higher steady-state level.

We are hearing though that utilities that were kind of conservative with their inventories that kept a lot of coal on the ground are seeing their trains or their rail cars sit idle while the railroads are giving priority to customers that let their inventories get into problem spots, problem areas. Are you seeing anything or can you back that up at all?

All I can tell you is when you've got utilities and there's a number of them, our power plants that have five days of coal supply, the last thing that anybody in the coal, the rail or the utilities sector wants is for those plants to run out of coal. How the railroad is managing their system I think is a better question for the railroads specifically to ask.

But what we are seeing is there are a couple of critical stockpile situations out there that are trying to be addressed to ensure that there are no outages.

Okay. The other kind of general question I've had is that we know it's a geology question that -- mines in the Powder River Basin generally run on a north-south line where the coal seems to outcrop. We know the coal extends quite a bit to the West but gets increasingly deeper. How much more coal becomes economically viable, given what we are seeing in terms of pricing if this pricing proves to be sustainable? How much more do we kind of open up in terms of broad reserves, just we can afford to strip more overburden at higher prices?

Well I think that's the exact answer. I mean the Powder River Basin contains millions of tons of reserves as that whole coal sector moves out to the West. Prices three years ago would have put a limit on the strip ratio, the overburden that you could have moved economically to produce a ton of coal. Today's prices have increased that overburden ratio. I don't have that number off the top of my head, but certainly when you -- it's going to have significantly increased that stripping ratio that can be sustained at the kind of prices that we are seeing today.

Senil Deptharter (ph), Bramwell Capital.

You mentioned in your presentation about cost increases in 2006 basically for the Central Appalachia and some new reserve mining probably in Longwall mine. Could you talk about that and give some color on this?

The question was related to the cost increases in Appalachia?

Yes.

What were talking -- and just really a follow-on to the discussion Greg just had, in Appalachia, we had really two issues that increased the costs. One was the Longwall move at the Harris operation, which drove up the cost per ton because, obviously, less tons were produced. So a smaller devisor drove the cost per ton up at Harris because essentially on a planned move the Longwall.

The other costs that we are experiencing that are a bit higher than they have been in the past are the contract miner costs, which are the third-party contractors that are mining coal that are running it through our preparation plants; they are likewise having production difficulties and the impact of higher costs inputs, such as steel and roof bolts and things of that nature. So those are driving up our costs as well.

That would continue to affect the mining costs overall in 2006 also?

Well we haven't given specific guidance on 2006 but obviously, the commodity cost pressures that we are experiencing for higher fuel costs, steel costs, as we look at it, that's going to impact '6. And from our standpoint, it will have maybe a bit larger impact than it had in '05 because we were fairly well hedged as it related to fuel in '05 at about $35 a barrel. So as we look forward to '06, while we are still hedged -- we are not hedged at quite as low a number, so we'll have a bit higher fuel cost on average, assuming the current price per barrel stays constant.

One follow-up question on the tax front. When do you think you would be going to a normalized tax rate or a full tax rate? Currently, your tax rate is around 11.5%. You do have a lot of deferred tax assets. What is a likely timeframe that you might give us an idea of?

Yes. We would expect that it would be '07, '08 timeframe before we get into what we would call a normalized tax rate, and that would be at an AMT tax rate of 20%, as opposed to a regular taxpayer because we still have substantial NOL carryforwards to utilize. And because of our preference depletion, we will continue to be an AMT taxpayer at that point in time. But we still have about 800 million plus of deferred tax assets that we expect to utilize in the next couple of years to reduce our cash taxes as well as our tax rate.

Mark Liinamaa, Morgan Stanley.

I'd be interested in your thoughts about recent developments in the import market and how you see that unfolding and possibly changing the competitive balance in your future markets in the East. And also, an update on the Black Mesa situation if you could provide one.

Okay. Yes, in terms of the import markets, obviously, imports have been struggling a bit here recently because of the disruption with the port facilities along the Gulf Coast. Longer-term, we have always had the view that the imports would be increasing over time as the Central App production continued to decline. That's been in our forecasts. We don't see anything in the way of imports that are going to materially disrupt our sense of where the Powder River Basin and the Colorado or the Illinois Basin coals are going to grow over time. So I think that one, we are pretty comfortable with.

And Black Mesa?

In terms of Black Mesa, as we had said earlier, Black Mesa is right now scheduled to close at the end of the year and discussions continue among the parties. But we have been planning for a stoppage of production at Black Mesa for a period of time prior to the resumption of operations.

David Khani, FBR.

If you look on your latest presentation, it looks like there's about 25 million tons of production under construction. And I know people sort of asked around the edges, how much would you say that is? Is there a replacement tonnage and what would you say is sort of the net growth over the next several years?

Are you asking across the entire U.S. coal market or --?

No, no, no, your production. Because in your presentation, you show about 25 million tons of mine expansions, organic sort of mine expansions. And we know part of it is, like James Creek is a replacement for Harris and Twentymile is part replacement for Black Mesa. How much would you say of that 25 million of incremental growth that's under construction is actual net growth after replacement tonnage?

Oh, okay. About 10 to 15 million tons a year of that would be net growth to offset falloffs of other mine production.

Okay, great. And then I guess secondarily, with the PRB rail shipment issues and all the PRB producers not being able to ship all their coal, is it safe to say that 100% or maybe what percentage would you think is kind of going to be rollover tons into next year?

I think you know as far as -- that's going to be contract by contract, Dave. This is Rick. But I think with the estimate right now for missed shipments if you will for the PRB is somewhere between 20 to 25 million tons. It could be a bit higher than that, so in our case, there's a chance that we will probably miss 7 million tons for the year out of that 25 million tons would be our share of what doesn't get shipped. And then it depends on the contract whether it's actually rollover business, so those become negotiable.

It's (multiple speakers) negotiable, but I would say that it is a very minimal number in terms of our planning purposes.

I know. Well, we've got to try to model all this stuff, so I'm just trying to keep track of it.

And the last thing I guess is, we've been hearing some of the new contracts have raw material cost inflators. Is that what you are seeing for some of your new contracts as well?

Yes, it is. I mean we can scale back the clock for over a year and we had identified a period of time where fuel pricing, steel pricing, input commodities into the mining sector, were going to be increasing, and we built indexed inflation language into our contracts to provide protection against those hyperinflation areas in those input commodities. So we've had that in place for a period of time.

Yes. It would be a very rare contract that we would sign that wouldn't have that.

And how well does it track if you go back and look?

Well, we have certainly changed, and if you go back in history, some of the indices weren't as exact, and we've gone back and selected different indices that have stronger correlations to the fuel prices and to the steel costs. So the ones that we've looked -- the ones that we've selected for the new contracts that we've been entered into, we think are pretty accurate.

Justine Fisher, Goldman Sachs.

The first question I have is about SG&A expense. It looks to be much higher on a dollar basis and also on a per-ton basis. Could you dig a bit deeper as to why that line item was up so much?

Sure. There are a couple of reasons. Probably at the lower end is the higher costs for compliance with Sarbanes-Oxley and some legal issues related to those types of costs. We are raising overall A&G. The addition of a full year of the Twentymile acquisition with our Australian operations and some of the travel costs associated with going down and operating and running those properties added some additional dollars.

But the biggest driver in SG&A is the fact that for the quarter ended September 30th, we had a 62% increase in our share price; and for the twelve-month period ended September 30th, we had 184% increase in our share price.

And we have outstanding equity-based compensation plans. They are not mature plans, but we have to adjust the accrual, not the cash to catch up to where the share price is. And that was about $19 million. So that's really the biggest driver in the SG&A.

So unless we wanted to take a crack at forecasting the stock price, it's pretty hard to get an idea of where SG&A per ton would be, going forward?

Well we don't really look at it on a per-ton basis. I'd really look at it as a percentage of revenues for the most part. But SG&A has been fairly predictable with the exception of the equity-based compensation. When you have the kinds of returns that we have experienced, it's a positive thing and it's a high-class problem to deal with.

And not a bad one. The other question I have is related to the diesel costs as well. I know you were just talking about how there are some cost inflation aspects of the newer contracts that you're signing and you did mention that you were less hedged for ;06. Would you be able to tell us what your hedge position is for '06 or even go over other things that the Company is doing that you mentioned in the press release to get around these higher costs?

I'll give you a couple of examples, here. On the fuel hedge side -- and I'll give you '05 first -- is that we expect that year-over-year fuel costs will be roughly $50 million higher in calendar year '05 before the impact of the fuel hedge. The fuel hedge should result in about a $35 million positive benefit, so net-net, we're only going to be up $15 million. So if I didn't have a fuel hedge at all in '06, you could assume that I'd be $35 million worse on the same average fuel price.

But I do have about 50% of my fuel hedged for '06 at prices in the low 40s. So do the math. It says I'm going to have -- still have some positive benefit. I'm not going to have quite $35 million of fuel hedged profits, of course, unless the price per barrel drives into the '70s, or something along those lines. So I don't know if that helps you, but that's essentially what we are experiencing.

Michael Lucas, Appaloosa Management. We will move on to Reza Hatefi, Zimmer Lucas Partners.

I had a question, sorry if you've answered this, but seeing current PRB 8800 prices in the $17 range and I was wondering if you could comment on that and the quality of your North Rochelle Antelope quality being in the 0.4, 0.5 sulfur range and you know by my calculations, comes out to like $3 or so of sulfur credits. So moving that $17 maybe to 20 bucks a ton. Any comment on that?

Well, I think as Rick indicated earlier, if you look at the Coal Daily from yesterday, it shows that there was an over-the-counter trades transacted for '06 and '07 delivery for the 8800 point-A (ph) at 1885 a ton. Your estimate of the sulfur premium on top of a -- to get down to the 0.4, 0.45, or 0.5, you know, is the right way to add on top of the OTC to come up with a "reference" over-the-counter price. In addition, as Rick indicated, these are pricing for single lot or small tonnages and so the sulfur at 9 something is in the 286 range, I guess. But those would be for small lots over the counter. Obviously, with our marketing and sales organization, we challenged them to make sure that we do much better than that, given that our volumes that we contract are for larger volumes over longer periods of time, and obviously, with a very reliable supplier.

And is it fair to assume that the sulfur mechanisms are built into all your new contracts?

It's fair to assume that we either get the sulfur value in the price upfront or we sell at a 0.8, take the sulfur back and then we have the ability in the secondary sulfur markets to monetize that value.

And what kind of discounts should we assume for term large contracts rather than some of these quotes that we see like you talked about earlier.

I think as I just walked through, it's just the reverse. When somebody buys large volumes of coal from a secure, stable supplier with multisourcing, they don't pay a discount.

Oh, I'm sorry. I misunderstood. Thank you very much.

A follow-up from Danny Roling.

Greg, when you made the comment earlier that you'd like to baseload to recover your capital on some of these new mines and your expansions, can you give us some guidance on if you're talking about baseloading that at 50% like the industry did in the '80s? Or are you looking at a higher number in this market to feel more comfortable?

Dan, as you know, it's going to be project-by-project specific. I think if you took an average across PRB, Illinois Basin, Colorado and the brownfield expansions versus a greenfield development, that 50% number is probably not a bad average, but there will be some in the Illinois Basin that are pure greenfields, we may look for a higher percentage than that 50%. You know, in the Powder River Basin or out in Colorado, we might look for a lower number. But I think that 50 is probably still a pretty good average.

And we have a follow-up from Dave Gagliano.

I just wanted to follow up on a question that Dave Khani had asked earlier in terms of the mix in sales volumes over the next couple of years. Considering all the moving parts between the operations coming on and some coming off, I was wondering if you could just give us a quick snapshot of what you expect your sales volumes to be regionally, PRB, or at least West, East and Australia between '06, '07, and '08.

I think we have to defer that question until we get our final budget out, but I think you -- we don't expect that mix to change dramatically, but we will give you that information in the first quarter of '06 when we put our budget out. But we don't expect it to change any.

Okay, I just thought I would give it a shot. Thanks.

A follow-up from Senil Deptharter.

Just on the 2030 tons which is unpriced for 2006, just can you give us a breakdown of what is met coal and steam coal out of it, and for 2007?

Well, roughly, to get the met to steam coal breakdown, we would have, in 2007, we would have about 12 to 14 million tons of metallurgical coal available for sale in 2007. In '06, we have already sold some of that through the first quarter and a bit of it into the next year. So the number is about -- 50% of that number is available in '06 will be met coal. So it's called 6 to 7 million tons of met coal still to sell in '06 and 12 to 14 in '07, and then the rest would be steam coal.

Michael Lucas, Appaloosa Management.

I'm just curious about your guys' thoughts about buying back stock or putting more leverage on at some point. If you kind of look at these markets, if what you're saying is look at these coal markets and believe them, at 18.85? I mean I'm going to get EBITDA is at $2.5 kind of billion (ph) range for you guys and higher. So have you guys thought about that, vis-a-vis the contractual nature of the PRB being longer term than any other area of the country?

Well, Michael, I would say, as you know, the board has approved a buyback program. But we look at the buybacks as we would any kind of an acquisition or business development type activity. You know, how we look at that, when we would do it, and our thought processes, we view as commercially sensitive. So we would not discuss that.

No, I mean, obviously, I kind of view it the same way, what's economically sound to do. It seems if you believe in these prices, if you guys are actually locking them up, the best economic thing to do is buy your own stock. But, okay. Thank you.

And there are no further questions. I'll turn it back to Mr. Boyce.

Well, thank you very much for your interest in BTU. I want to thank all of the Peabody employees for another record quarter, and we look forward to talking with you at the year-end results and providing guidance for 2006 at our next call. Thank you, very much.

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