Good day, and welcome to the Petrohawk Energy Corporation Fourth Quarter Earnings Call. [Operator Instructions] At this time, I would like to turn the conference over to Mr. Floyd Wilson. Please go ahead, sir.

Good morning, everyone, and welcome. This conference call may contain forward-looking statements intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a detailed description of our disclaimer, see our press release issued today and posted to our website, as well as our other public filings. On February 1, we published a detailed 2010 operational update, as well as our year-end reserves. Today, we'll discuss our fourth quarter and full year 2010 financial results and focus on the financial health of the company. And we'll mention briefly a new frac technology which we have employed in the Eagle Ford with spectacular early results. Last year, we added $1 billion of book value to our balance sheet by developing our core assets in the Haynesville and Eagle Ford and we added reserves. There was nothing virtual about what we did last year. We raised $2.1 billion through divestitures, issued no new equity, did no upstream joint ventures and refinanced a significant portion of our long-term debt at attractive rates. The end of our Haynesville and Bossier lease capture phase is at hand, and we will have discretion over our capital budget for the first time since 2008. This is a great feeling. The assets that we've captured are extremely valuable, long-lived and have exciting future growth potential. One component of that potential is our cost structure. It has improved dramatically in most categories during last year, as Mark will describe. Keep in mind that both the Haynesville and Eagle Ford are young. They are so young that we haven't yet embarked on the most promising operational efficiencies, full-scale development in pad drilling. Our cost structure is moving in the right direction, and we focused on cash cost. It is clear to me…

Thank you, Floyd. We'll just jump right into the financial results. Revenue for the fourth quarter were $402 million and approximately $1.6 billion for the full year of 2010. This does represent about a 50% increase over prior year. Cash flow from operations before changes in working capital were $0.70 per share for the quarter, which does beat consensus of $0.66, and Petrohawk delivered cash flow per share of $2.47 for 2010. Our continued strong operational results as reflected by the production rate, underpinned by the hedge program, were the primary factors contributing to the strong cash flow per share metrics despite the low natural gas environment. A few housekeeping items that contributed to our adjusted earnings for the quarter of $0.11 a share. One in the fourth quarter: There were two items reflected in the income statement, which were a direct result of the Fayetteville asset divestiture, both of which were non-cash charges in the current quarter. Our DD&A rate increased quarter-over-quarter primarily due to the full cost, full impact of the sell of the Fayetteville E&P properties; and second, we had a write-down on the midstream component of the Fayetteville sell, the midstream portion of the Fayetteville sell, which did sell for $75 million. The remaining three items to touch on: One is our marketing company did post a loss, which equated to about $0.03 a share. We are in the process internally of reviewing the marketing company and coming up with a process that should take effect in 2011 to minimize losses on a go-forward basis. We also had a legal settlement in the current quarter, which is reflected in G&A on the income statement. And we continue to recognize severance tax refunds, which are being collected in Louisiana and some in Texas as well. Apart from…

Thanks, Mark. As I mentioned earlier, both our current great plays are young. No better example of this exists than our mention today of the MP7 or HiWAY frac designed by Schlumberger and implemented by Petrohawk. This is a breakthrough development that should add tremendous value to what we do today and in the future. While we focus on the day-to-day basis of commodity prices and development costs and the current squeeze we're in with natural gas and service cost, we also focus on refinements and improvements in all of our practices. And we've engineered a significant shift towards liquids. These efforts will pay off for years to come. Operator, we're ready for questions if there are any.

[Operator Instructions] And we'll go first to Jason Wangler with SunTrust.

Just curious on the HiWAY. It looks like you're going to obviously move that way to the Eagle Ford. Is there any look at going toward the Haynesville with that as well? Or is that going to be something you could move to other plays? Or is that going to be specifically in the Eagle Ford?

It's not determined where it can go. There are limitations of where the current state of that Schlumberger material can be used. We're going to use it throughout the Eagle Ford, all areas of the Eagle Ford, including Black Hawk. And I think other plays are sort of TBD.

And then just in the first quarter with the weather we had kind of all over the country, did you see anything happen in South Texas or even North Louisiana that kind of delayed you at all?

We've had normal weather delays like any E&P company has, but nothing that caused us to revise guidance or anything like that. Of course, we've had a pretty strong winter in places and in North Louisiana as well. But nothing that was that unusual for a winter season.

And we will go next to David Heikkinen with Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Just wanted to think about regional economics a little bit given the new technology in the Eagle Ford. Can you talk about kind of well profiles and kind of costs and kind of the overall thoughts around what the HiWAY frac costs? And kind of what is the different -- what are parameters for the well profile now?

Dave, good luck for you Dick is here, and he's ready to answer that.

Well, another positive aspect of the HiWAY frac, it's a little bit cheaper than a conventional hybrid frac. We pumped a little bit less sand. And overall, it's a little bit cheaper per stage. In terms of how the overall profiles, I mean I don't know if you had a chance to look at the curves yet. But as a Floyd mentioned in the introduction, it is truly -- it seems to be a breakthrough to us. It makes a lot of sense in the technology and what's being done and trying to create better permeability, a better channel, flow pass for the fluid in the rock. And I think intuitively it makes sense that it works better in the dry gas areas. It works best in the dry gas areas, I should say. It works very, very well, as you can see on those curves, in the high condensate yield areas as well. So I think it does change the economics of the dry gas, but you can't ignore the $4 gas world we're in, or sub-$4 world we're in. We're still going to do our business. We'll still drill a number of dry gas wells. We'll still drill a number of rich gas moderate and high condensate yield wells in Hawkville. We have not done one yet in Black Hawk. It's imminent. We're anxious to see how it works. There's no reason to believe it won't be beneficial in Black Hawk as well. So we really just scratched the surface like all of these technologies we employ in these plays, but we're very, very encouraged. Hope that answer your question. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: So what are the costs per stage then?

I won't give a specific number but I'll just tell you, they're cheaper than a hybrid stage. And each company has a little different pricing schedule but they are cheaper than a hybrid stage. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then just thinking about how did you estimate the incremental EUR? I'm trying to get into the shape of the curve a little bit to understand the 25%-plus to 90% increase in EUR.

Just straight decline curve analysis. You can -- some of the -- those two dry gas wells we were bumping the choke back and forth. We pinched it back at one time on the Heim well, as you can see on the curve, then we opened it back up on about 24 [24/64" choke]. The reason we flow these on a 24 is we've had the best comparative data set on 24. The wells in the neighborhood had all been produced that way. So we would typically produce them a little bit tighter choke than that. But higher pressure, much higher pressure at similar cums, much higher rates at similar cums and just pure decline curve analysis at a waterhead [ph] price. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And can you talk about cost for transportation out of the Eagle Ford now for trucking oil? And kind of where does that break in to the guidance for overall transportation $0.68 to $0.78 per Mcf?

I believe in the guidance, there's a line that actually guides for price realizations for crude and condensate. And I believe it's 88% to 94%. Is that right, Mark?

Yes.

That encompasses transportation costs that we anticipate but have not experienced yet.

I'll also just very briefly add that the -- I had made comment around gathering of transportation and that guidance did include additional costs around the compression transportation. And if you rolled all that up and just looked at it at a companywide level, you're probably looking at I would say a nickel or less overall to the company.

And we'll go next to Brian Corales with Howard Weil.

Just a couple questions on this new frac technology. How many frac fleets are you all running using this?

Currently two. Schlumberger has committed all the material that they have at this point to Petrohawk and will continue to contribute all the material that they have until there's excess capacity at which time it will be marketed to our peers. But right now, we have two fleets that are pumping 100% HiWAY frac.

And can we assume that, that number is going to increase?

In terms of the number of fleets that will be pumping this?

Yes.

Not necessarily. We have other service companies providing some of that.

And Floyd, you mentioned on your opening comments about pad drilling. Are you all going to start pad drilling in the Haynesville kind of later this year? Or is that still a 2012, 2013 event?

We're planning all of our locations with pad drilling and full section development in mind. We're not doing that much of it yet because we're still drilling lease capture wells was for the most part in the first half of this year. We anticipate that the savings that could be quite dramatic that comes through that practice will start to take hold in 2012 and be a really strong factor in 2013.

And can you maybe try to quantify a little bit of that savings?

It's really hard to say, Brian, this early, but studies show it could be in the $1 million per well range, maybe more, maybe more than that. It's just one good thing that we and you have to go on is the experience that some others have had in other fields that have been under large-scale development where in some cases the well costs have gone down to nearly in half of what they used to be. Different environment for that, those measures, but it looks to be a very dramatic number. As soon as we're done with the lease capture phase, we'll do everything we can to get into full scale development in a full section development in a big hurry.

Did you all give DD&A guidance? Or is that something -- what should we assume there?

No. We have never given DD&A guidance; just the multitude of inputs that go into that calculation. As far as what to assume, I would say that kind of where we are today is probably as good of a rate as any that you could utilize going forward. If there's any significant event-driven transaction in the future that would cause that to change, it would certainly be discussed on the quarterly call.

And we will go next to Leo Mariani with RBC Capital Markets.

Can you just give us a sense of how many wells you guys have drilled in Eagle Ford at this point with the new HiWAY technology?

We probably completed on the order of 10 or 12. And you're seeing about four of those that have the most significant production history on the drafts that are published on our website today. So somewhere in that neighborhood.

And where are your overall well costs running right now using that technology in the Eagle Ford?

They're basically with the numbers that we've put forth. It doesn't change it dramatically, if you're referring to my comment about being a little bit cheaper. It is just a little bit cheaper. It's not a material change in the overall frac cost when you look at a program. So I think our program cost on a per well basis are still looking pretty consistent with what we've mentioned before.

Just refresh my memory on that. It's, what, roughly $7.5 million?

Yes, about $7.5 million in Hawkville and $8 million to $8.5 million range in Black Hawk.

And how about your well costs in the Haynesville? Any recent changes there? Are they still sort of in that $10.5 million range?

It's hard to say they've changed. We're working hard at bringing them down. I'm hopeful and I'm optimistic that we're bringing them down. And so at this early in the year with recent well cost guidance, I'd hesitate to lead anything to significant change, but I'm quite hopeful that we can drive them down.

Any new well results in the Red Hawk area that encourage you here at all? Want to share?

No, there's really nothing. We're flowing back the third well, Chaparrosa "D", too. It actually started cutting oil overnight, so it's on target. It's way too early to make any kind of comment about it in terms of how it compares to the other well, but I'd say so far so good at this point.

Just any update on your asset sale program?

Leo, we're evaluating what we choose to do for this year and there's no real update or anything on it. We've mentioned that we've got some midstream assets and some conventional oil and gas assets that are likely to be divestiture candidates at some point.

But it doesn't sound like there's any type of ongoing sale process. You guys are still in the evaluation mode.

Well, yes, we're in the evaluation mode. Just keep in mind that those things go at pretty fast pace for Petrohawk.

And we will go next to Gil Yang with Bank of America Merrill Lynch.

What's the limitation for the capacity for doing the HiWAY frac at the moment?

Limitation for the industry?

Right. What's the limiting -- what's the bottleneck? Is it supply of some chemical or is it pumping?

I think you'd probably need to ask Schlumberger that, but I think it's just the actual material that they need to manufacture and provide for. We tested it just over the last, what, six months. I think our first job was in October, not even six months. So like any new product, they, being Schlumberger, I suspect wanted to see the results before they went into a significant production mode. And I'm just guessing that, that's probably a limiting factor on it not being available to the general public at this point.

So it's the consumable is what you're talking about, right?

Yes.

Is there any change to the equipment that the hardware that needs to be made or not?

No.

And based on your results because you don't mention any Black Hawk, I don't think you've done any Black Hawk wells with the HiWAY frac. Is that right?

No, we have not. I think the first one's coming up early to mid-March if I'm not mistaken.

So your upward guidance on the Black Hawk results that you gave a few weeks ago is prior to any benefit from HiWAY frac-ing obviously then.

That's correct. That's all cross linked gel results that basically we're just modifying the parameters under which we complete. It's basically the fluid and sand properties have been the same from the beginning there.

Did you do micro-seismic in all the wells in Hawkville and Black Hawk?

No. We do a representative number of those across the field areas to make sure we're knowledgeable of stress orientation, frac height, growth, things like that. Once we get the answer, the answer is fairly repeatable, so we have not done a microseismic event in a while.

So you haven't done the microseismic on these HiWAY frac-ed wells.

No. And we wouldn't expect it to be dramatically different than any other cross linked gel. It's just the manner in which we pump it.

So you wouldn't expect any change to spacing or anything like that.

I wouldn't say that. I mean, it's just the frac height growth, the wing length shouldn't change a lot. Now if we more effectively drain the reservoir, that's possible. So that's way, way down the road. But from an overall frac height growth and wing length growth, I don't think, there's no reason to believe that would change.

So just better pulverization, if you will, of the rock that you are frac-ing into is what you think's going on.

Better permeability, better effective permeability contacting more of the rock.

Going to your pad drilling expectations of $1 million per well savings. Where would those savings be coming from? Where do you anticipate that coming from? Just that faster drilling time?

Well, first of all, Gil, I mentioned that number as a potential. We're not guiding to that by any means. And the savings come all the way up and down the line. You're moving less. You're moving equipment less. It's just the whole -- the locations cost less when you build a giant one for every five to eight wells or whatever. The savings come all the way up and down the line. If you take it to the logical step, things like frac jobs are beginning to cost less because you're mobilizing maybe one time per pad and accomplishing a whole bunch of frac jobs all at once. And perhaps we're going to be doing this in a time when the frac capacity is less strained than it is now, which should translate into significant savings there. Rig moves, I mean just about everything, but you're going to reuse some of your drilling materials or whatever. You don't have to drill new pits and you can just lay a little more pipe.

You and I talked about this maybe a month or two ago: Do you anticipate that, will you park a rig on a pad and drill all locations on a pad or you think you'll move on and off a couple times to drill all the locations off that pad?

The perfect answer would be you drill all of the locations that you can with one or two rigs on a pad. It may not always work that way, but that certainly would be probably steer you towards the most cost savings. You have to come to a conclusion of what the, when you're doing the fracs, you have to wait on the frac jobs. You just have to decide what your production profile or what's the best way to manage that and so on and so forth.

Gil, I'd just add that we do have a group in Tulsa that we call our strategic planning group that is just studying this. Not just this, but they are studying this in great detail. I'm not crazy about the term. We're kind of calling it well manufacturing. In a sense, that's what it is. So they're looking at every single component itemizing it and doing just what Floyd said in a very specific manner to try and really get a hard number on what those savings might be, so that when we get there, we have a goal, we have a target and we have a plan. So we are studying it very specifically as we speak.

We'll go next to Michael Hall with Wells Fargo.

Mark, you alluded to some maybe some reorg around the marketing company. Can you talk any additional detail or quantify kind of what your thoughts are on profitability there on that line item in 2011?

That's a process that we're just now undertaking, so it would probably be a little premature to make any definitive statements around it. We just wanted to point out on the conference call that it is something that is being looked at currently.

No maybe qualitative color around what you're looking at or any process that you're thinking about implementing? Anything along those lines?

Not at this time.

On LOE, is there a point at which kind of Eagle Ford volumes ramp more and more as a percent of total, that you start pushing on LOE higher relative to kind of first half, middle '11 figures, or does the low LOE Haynesville always overwhelm the Eagle Ford?

I wouldn't say it overwhelms, but we don't anticipate any upward pressure for some time. And keep in mind that on a revenue basis, no upward pressure whatsoever because of the disparity between the gas and the oil these days.

Really, any Eagle Ford well, at least the areas we're in, except for Red Hawk, they don't make much water. They're free-flowing wells. They act a lot like a gas well. There's not a whole lot additional operating expense associated with those that I think would put pressure on those costs.

On the oil differentials, you talked a little bit about it as it relates to maybe transportation. But, I mean, relatively wide range you gave. What kind of drives that variance? And what are the variables we ought to think about in terms of planning on one end or the other?

Michael, any of these new strong growth areas like the Eagle Ford and some others [ph], you're just going to have a shortage of certain things, whether it's frac crews or sometimes rigs or whatever, and there's a shortage of capacity to get the crude out of that area right now. Trucks are not the right answer. Pipeline solutions and rail solutions take a little bit longer. So we're anticipating that the upper end of that range or the most expensive part of that range is what we might see near-term, but that we would expect to see that moderate over time. And again, as I pointed out, we haven't experienced this yet, but we're certainly cognizant that, that's the direction that things are likely to go in. So we've guided for that in mind.

And we'll go next to John Nelson with Macquarie.

I'm just curious what the lateral length on those 10 to 12 HiWAY fracs were relative to the EURs you have comparing on the slides.

I would think they're consistent. We've been drilling plus or minus 5,000-foot laterals really probably for the last year. The comparative wells, I don't think that's a component of the variable.

I looked at that. They're all within 100 or 200-foot of each other.

Have you guys topped out your lateral lengths sort of testing? Do you guys now have an optimal estimate? Or you're still working on that?

Well, the longer you drill the lateral, the most expensive a frac job you've got to put on, so we're kind of wondering if this is the right time to think about 10,000-foot laterals. They might be something for a different time. These frac jobs are extremely expensive down in the, well, in all areas right now, but certainly in the Eagle Ford. It's no exception. So we're actually looking at ways to maximize the money we spend for today and we'll consider expansions of this at a later date when hopefully the frac cost will be a little bit less.

There's another component that is somewhat limiting on lateral lengths except in Red Hawk, and that would be the limitations of coiled tubing. It's plus or minus 20,000 feet. And once you get too much beyond that, you're going to have to pick up regular steel tubing with a workover rig. So there's another logistical component and a cost component about pushing those lateral lengths out as well, in addition to what Floyd said about frac costs.

Just glancing through your K, I was just wondering what counties in Oklahoma your undeveloped acreage is in and if you had any wells planned for there in 2011.

We don't discuss those other activities.

And we will go next to Ron Mills with Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: On Eagle Ford, the oil pricing. I'm assuming most of that is still priced off of WTI. Or do you have any access via trucking to some of the more Gulf Coast pricing?

We've got Art in the room. Let me let Art address that but, Ron, we're very aware of all the imbalances and delivery points and we're very conscious of not just piling on Cushing or whatever. So, Art, what are we...

Could you please just repeat your question, just so I'm very clear on what you're asking? Ronald Mills - Johnson Rice & Company, L.L.C.: The question is, of your Eagle Ford oil and because of your price differential guidance, where do you sell your oil? And do you have any access via trucking to the Gulf Coast? Or how much of your Eagle Ford oil are you able to get towards the Gulf Coast as opposed to some of the tighter areas?

Currently, all of our oil is going to primarily Corpus [Corpus Christi] and it is being burned in a refinery down there. Cushing is not even on the radar at this point in time. We see it moving further and further up the coast. We're looking at everything. We're looking at rail. We're looking at barging. We feel that every optionality we have is going to be used because this is so successful. Ronald Mills - Johnson Rice & Company, L.L.C.: Mark, on the DD&A, did the fourth quarter include any catch-up for stuff throughout the rest of the year? So on a go-forward standpoint, it would be somewhere between where DD&A had been running and the actual fourth quarter rate. I know that happens sometimes at year end in terms of truing up costs.

There's always going to be some kind of true up activity that affects a metric that goes into that calculation. And since year-end was when we did our final reserve work with NSA [Netherland, Sewell & Associates], there was some of that, although I would say nothing of great significance. What really kind of impacted DD&A that couldn't have been predicted was when you sold the Fayetteville, your full cost pool goes down by the amount you sell it for and then you have to the extent you have any value assigned to any other gas assets, whether it will be probable/possible reserves, et cetera. That also folds into your pool and offsets the proceeds. So it was really more of the impact of the Fayetteville that happened this quarter that impacted the depletion rate. Ronald Mills - Johnson Rice & Company, L.L.C.: Until you all do some sort of reorg on the marketing side, should we assume that the net marketing margin in the fourth quarter to be the go forward rate until some sort of reorg occurs?

Yes, I would say holding that number flat would a good number to utilize for the time being. Ronald Mills - Johnson Rice & Company, L.L.C.: Floyd, I know there've been multiple reports of this lower smack [ph] over in Northern Louisiana and given your position there via the Haynesville, is that something that you all have started to take a look at?

We'll certainly look at it, Ron.

And we will go next to Marshall Carver with Capital One Southcoast.

One, you talked about you have two frac crews doing the new HiWAY techniques in the Eagle Ford. How many total frac crews do you have in the Eagle Ford?

Currently, we have three and we have a fourth contacted to come about midyear.

So three currently and that includes the two with -- that are doing the HiWAY fracs.

That's correct.

For Mark Mize, in thinking about any potential monetizations this year, how do you think about that in terms -- is there a certain debt metric you're looking at? Or is it debt-to-cap? Is it debt-to-EBITDA or a certain amount of revolver available that you want to keep? Or what would make you all decide to monetize either midstream or any additional E&P assets?

Our decisions on monetization of assets, if you look back over the history of the company, I think are fairly clear. I mean, we do look to keep the company pretty focused on what we deem to be core properties sitting here today. So obviously the Haynesville and the Eagle Ford. The pipes were something we got into because we needed to. They proved to be very valuable to the company. When we initially divested up half of the Haynesville pipes, it was really kind of timing and when we had enough throughput to make it an attractive valuation. So as Floyd has already indicated, the other half of those pipes is something that we would certainly look to sell at some point. And then possibly the Eagle Ford could be next.

So it's more of a strategic issue than a balance sheet issue. Is that fair?

Marshall, it's both, of course, but it starts with a strategic thought in mind and then we take it from there financially.

On the guidance for 2011, does that have any of the new HiWAY techniques cooked into that? Or is that all based on the old techniques at Eagle Ford?

No improvements have been forecast yet.

And we will take our final question from Dan McSpirit with BMO Capital Markets.

For Dick, is the unique quality of the HiWAY technique more about the pumping process than it is about the proppant? That is, is it more about the application than about the ingredients here? I'm just trying to get a handle on truly what's different.

It's a little bit of both, Dan. It's the pulsing approach to pumping the fluid and the proppant. It's also the inclusion of a fiber, degradable fiber that degrades at temperature pressure in the reservoir. It's the combination of the fiber and the sand pumped in a pulsing sequence that, by theory and now by performance we think, is creating much higher conductivity in the reservoir.

And then can you at all relate the history that is your history with Schlumberger and how this originated? And how it is you came to partner with Schlumberger on this particular technique?

Dan, who wouldn't want to partner with Petrohawk on some new technology? I'll let Dick give you a good answer to that, but Schlumberger's having an analyst meeting today, I believe, and they put something on their website about this in some more detail. So I think you should travel to that and get some more direct data on that as well.

Dan, it's a good question because I got to give some of our guys in Corpus that kind of were working with Schlumberger, had knowledge of this overall concept of the whole HiWAY design. And we really didn't go into the genesis of it, but we pumped it on a number of jobs before we actually pumped our first job, just to make sure it wouldn't screen out, make sure we didn't have any problems with flow-back or whatnot. We've been partnered with Schlumberger in the Eagle Ford from day one. They pumped all of our jobs to begin with. I'll make a comment that I just got a note this morning that we pumped six stages of frac on a well in 24 hours just last night. So we really have created a partnership that's very efficient. It is technology-driven, very reasonable in the pricing components that we negotiate amongst ourselves. I'm not saying this in detriment to the other service companies, but I am saying that in the Eagle Ford, they've been a great partner and I think they would echo those comments.

So your partnership has been somewhat exclusive up to this point meaning that this technique has not been tested anywhere else or really by anyone else, correct?

Absolutely. It had never been pumped in a horizontal wellbore prior to us doing it. It had been tested in limited fashion around the world on vertical wells. But they were very mindful of our relationship down there, and they felt like it was a very good application and they were right.

Well thanks, everyone. And if you think of something we didn't answer today, just give us a ring. Bye.

This concludes today's conference call. We thank you for your participation.