Good morning. My name is Jodie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Petrohawk Energy Corporation First Quarter 2009 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Thank you. I would now like to turn the conference over to Mr. Floyd Wilson, President and Chief Executive Officer of Petrohawk Energy Corporation. Please go ahead, sir.

Good morning everyone, and thanks for joining. 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. I have a few comments and then I'll turn the call over to our CFO, Mark Mize. Petrohawk is well down the course to building and operating one of the lowest risk, highest margin portfolios in the natural gas phase. Operators including Petrohawk have reduced spending dramatically these past few quarters in response to weak commodity prices and unpredictable credit markets and a weak economy. At Petrohawk, we plan as well we came to this sort of volatility in our business and in the broad economy as most of you know, these defenses include a low operating cost structure, a well hedged production stream, ample liquidity and low risk drilling. And as John recently said, there is no dry hole here. Our capital structure is strong and supported by our hedge position in liquidity and we plan to continue to reinvest our cash flow into these world-class asset that for right great return. Our opportunity set is larger than ever. We think the time is right to pursue these awesome opportunities aggressively. Operator, somebody is not on mute. And we are increasing our capital budget today to 1.3 billion to accomplish that. We access the equity markets a few weeks back and this increase in our budget is a natural progression. We have sufficient liquidity and hedge production and sufficient savings to a lower cost and efficiencies that a few more rigs in the Haynesville later this year. We're getting close to NYMEX…

Okay, thank you Floyd. The first quarter has been somewhat busy but very positive for Petrohawk. We've been able to raise right out a billion dollars of capital combination of debt and equity issuance and as such our liquidity on our balance sheet remains strong. Before I address some of the specific quarterly financial information, I'm going to comment on a handful of matters. As discussed in the year-end earnings call, we went out to January with a 300 million high-yield offering and that was very well received by the market. It was the first E&P high-yield transaction in 2009, it was upsized from 300 million to 600 million. The notes were issued at a discount yield in probably three quarters but its set straight above par. In the first week of March we had an opportunity to place some equities so we took advantage of it. We sold an aggregate 22 million shares of common stock as transaction yield, the net proceeds to the company. And just over 375 million and as you can see on the page for balance sheet, we had just over 280 million at the end of the quarter. One final item before getting into our results of operations, in our year-end results in the fourth quarter we reported a full cost ceiling impairment charge of about $950 million. That charge was driven by declining natural gas prices for $55.71 at year-end. After recognizing this charge we had effectively marketable cost go down to 571 price environment. Unfortunately natural gas prices continue to decline in the first quarter and were $3.63 at the end of March. And that result in the recognition of pre-tax, non-cash impairment charge of $1.7 billion in the current quarter. Turning to the first quarter results from operations and financial position…

Thanks Mark. Well we had a great quarter to kick off 2009 and we feel incredibly fortunate to be where we are today. We're seeing incredible opportunities as a newly abundant homegrown commodity natural gas intersects with our need to move in new directions in terms of energy consumption, dependence on foreign energy sources and the importance of an healthier environment. While our production is certainly a drop in the bucket in our industry we built our company to be in the right place or places at the right time and we have an ability to even further accelerate our activities when appropriate. Operator we'll take questions, if there are any.

(Operator Instructions). Your first question comes from the line of Joe Allman with JPMorgan.

Thank you and good morning, everybody.

Hi, Joe.

Floyd, could you talk about the status of that well (ph) that you previously said you were extremely encouraged by and also just talk about what's your activity been so far in the East Texas. And what's your acreage position there? And I have a follow up too?

Well, we haven't disclosed our specific acreage position in East Texas. We are continuing to add acreage down there, Joe. We have disclosed our AMT down there with EOG, another great operator. And we're very encouraged by activities down there but we're not prepared to comment on that well at this time.

Okay. Could you talk just about other activity, you're active with more than just the one well or are you?

we are Joe, in fact we're adding rigs down in that southern area of the play in East Texas with EOG through the course of the year. We basically finished our drilling activities here in County area for now. And that's sort of our activity level a couple of one or two operated rigs due to the course of the year and three or four non-operated rigs to the course of the year.

Okay, it's helpful. And then, I think previously you talked about acquiring some more acreage in the Haynesville and you just said you're looking at acquire some more in East Texas. Are you presently acquiring acreage in Louisiana side as well?

We are very strategically oriented in terms of our current position and what we consider to be our focus area of the play, we are.

Okay. And then Floyd you said, I think you mentioned one well in particular in Bossier Parish 22 plus million a day and did I get that right?

Yes, you did.

Okay, All right, great. Very helpful. Thank you.

That was just the latest in the series of wells as you know we've got 10 rigs running there and the point of even bringing that well up is that our results are still consistent with our earlier results than we've reported.

Okay, that's helpful. Thank you.

Your next question comes from the line of Subash Chandra with Jefferies.

Yeah. Hi, good morning. Floyd, do you have the latest net or gross Haynesville production and the latest net or gross number of Haynesville wells producing?

Yeah, but in the new information I'll add on that beyond what we had in our operational press release a few weeks ago. Subash, we'll be updating that at some point is growing at the same rate that it was.

Okay, got you. And then secondly, is there another well count now for the Hayesville for 2009?

Yeah, we would intend to drill 80 to 85 wells now, few more wells in before.

Really?

What we find that in the first quarter, we reported 15 wells completed and 16 non-operated wells drilled. So, the non off component in the Hayesville is also a growing piece of our business.

Okay. And one final one in the legacy property side, your Terryville or Elm Grove. Any sense of you just break out specific production numbers, feel free to if you like. But if those volumes are holding flat, declining or growing.

Subash obviously that should be obvious because volumes are declining. We're not spending currently any drilling money there this year. We plan to resume drilling there in 2010 and get those things back on the increase if we can.

Okay. Thank you.

Your next question comes from the line of Ron Mills with Johnson Rice. Ron Mills - Johnson Rice & Company LLC: Good morning Floyd. Can you discuss a little bit about, hey I think you mentioned another well in the Eagle Ford, curious just in terms of relative to the other wells where it was located. It sounds like it was -- at one of the better rates and just any more details on that well?

Yeah, I'll let him talk to you a little bit about the location of the well. The point of bringing that well out was it is our best well to date. But the ideas of the programs going quite well, improving in terms of efficiencies in cost and the series (ph) behind is design a frac jobs and so on.

Yeah, that well is located in the Southwestern part of the field in the dry gas area. As Floyd mentioned we have two rigs running, its river kind of dissects the field. We got one rig running on the southwest side of that river, one rig on the northeast side. So we're going to have kind of a spread of results about the field as the year goes on. Ron Mills - Johnson Rice & Company LLC: Okay. And in terms of the, going from your 12 rig program to 16 rigs, I am assuming that you build that over the course of the next few months. So if we look at the remaining $900 million budget, should that $900 million be backend loading that a little bit just to account with the higher Haynesville activity later in the year?

Let me say, backend loading, Ron. But we will state the rigs later in the year. We intend to have them working, all of the extra rigs working by the fourth quarter. We don't like to bring in three, four, five rigs on the same day. We would like to state demand just keep operations moving logistics and planning. Ron Mills - Johnson Rice & Company LLC: Okay. And then Mark, just one last, just a clarification, 950 million available on your revolver, can you just remind me what the size of the facility on borrowing basis?

Ron, that's a good question. But the entire borrowing base is available at this time as rig market determine a month or two ago, $950 million borrowing base. And we think we have the potential to increase the size of borrowing base and naturally the termination data because of the add in reserves we made, first that will be dependant on what price the banks are using at that time. But we're considering that to be a little bit of reserved if we need it. Ron Mills - Johnson Rice & Company LLC: Okay, great. Thank you, guys.

Your next question comes from the line of David Shapiro with BB&T Asset Management. David Shapiro - BB&T Asset Management: Sorry, that was put in by mistake. Sorry about that.

Your next question comes from the line of Michael Hall with Stifel Nicolaus.

Thanks. Good morning. Just quickly in terms of the incremental spend on infrastructure, to an extent is any of that going to be used servicing any third parties or do you expect to service any third parties in term so you fill that up or that all going to be straight for Petrohawk?

Well, when we -- when our group design the gathering systems and trading to what not in particularly in the Haynesville, we thought we would have a lot of extra space. As it turns out, we're creating this space just in time. We do have space for third party gas and trading and we intend to make that a profitable piece of our business and we're actually have consummated a few transactions along those lines already.

Very good. And so the way you think about the increase in budget, is that fully shown that with the recent equity offering or do you think additional equity offerings might be in the future, coming in the future?

Mike, when we raised equity in February, the intentions of allocating portion of those proceeds to expanding the Haynesville infrastructure, a little extra drilling and liquidity. And so I think as I said in the earlier comment, this is a natural progression. We're pleased with our current liquidity at 1.2 billion and as I mentioned a minute ago, we have some potential for reserve capacity in our borrowing base. So the idea of resetting this budget is that we're just trying to get a little bit more specific based on events. The infrastructure allocation I think that we have on the website is about $300 million total for the year, about a $100 million total for non-off drilling is that right? 200 million for non-off drilling and then 800 million for operated drilling. We have no current plans to access to capital markets, but as you know we are -- we're always conscious of being out in front of need rather than behind need.

I appreciate that. Thanks for the forth right answer. I appreciate and understand my interest in the question. Thanks again. I appreciate it.

Your next question comes from the line of Leo Mariani with RBC Capital Markets.

Yeah good morning here. Just trying to get a little better update on what's going on in the Fayetteville. You guys still have two rigs running and you talked about a lot of non-operating activity just starting to increase out there. Can you give us a status of what the trajectory of Fayetteville production can look like for 2009?

Yeah, I'm going to get Dick to comment on that specifically. But just explosion in our activity, operated by some great companies in the Fayetteville Shale has come to just the right time because as you know, we've diverted almost all of our clients to the Haynesville play. And so this, I wouldn't call this an increase, I'd say an explosion. Dick, few specifics.

Yeah we drilled about 95 non-operated wells in the quarter. Pretty much spread between Chesapeake in Southwestern as you might expect. I think we had about 17 wells with Chesapeake and about 65 wells with Southwestern. So, we pretty forecast the balance of the year and plus or minus a hundred million dollars is what we think we'll spend there on non-operated basis. Production, about a third of our total net production is non-operative at this point and that percentage is growing. So like Floyd said, we're very pleased with performance of the wells that are being drilled by our partners.

Okay. And do you think that overall that non-op productions is going to be enough to offset a lot of the declines you're going to see on the operator side. Can you just give us a sense of what you think the overall trajectory of your favorable prices going to be?

Yeah, I think what you said is accurate. It's probably fairly difficult. You got since you don't have the level of working interest knowledge and certain things on a non-operative basis it's really hard to project as opposed to an operated program but I think we'll be able remain relatively flat if not grow a little bit in the Fayetteville.

It was amazing in the first quarter what went on these well are coming in consistently higher rates and the costs are coming down dramatically. I know you visited the management of other companies but it's a really good equation out there and as I said just in time.

Okay. And I guess I think you folks also mentioned some improving price realization out there I guess. Can you give us a little color on what you're seeing in the last couple of months since board walk become operational?

We're sitting here, but I don't believe board walk is fully operational quite yet. But it helps a lot.

Its helps a lot.

Our price realization is probably increased 4-5%.

Close to the 20%.

It increased 20% in our target is still about 95% of NYMEX is that right?

Yes.

We're not quite there but we're directionally heading there and we're projecting full completion of board walk.

Board walk should be fully operational, once ahead from a normally issues right now, the lower the NLPs (ph) so I do have some (Inaudible) but I expect to be at positive towards the end of the quarter.

So we still got another few months we get the system finalized and fully operational but the trend is definitely as Dick (ph) said by the third quarter, we should be at our target level.

Okay. And I guess jumping over the Haynesville. Can you give us a sense of what do you think well cost could be about last four, four or five months in the play?

I'd like Dick to comment if this is off based but we're targeting for Petrohawk about $9.5 million per well, we may be will need that because cost is still coming down. But keep in mind, this is with continued move towards the longer laterals and plenty of frac contact with the Iraq moving then.

No, that's accurate. In fact cost is a combination of drilling in I think some of the better parts to play. It goes hand-in-hand when you have higher pressure. I mean, you this typically have a little more time involved in getting wells drilled, but correspondingly you can make that well. So the longer laterals, the more stages and the complexity of the field all driven price is fairly high, but there we're also seeing a lot of downward pressure on service cost all basically except other are drilling contracts which are pretty much fixed because of the term involved. But we're seeing exceptional improvement on almost all of the other service cost, pick to the pumping services which is anywhere from 25 to 30% of your well cost.

Okay. Thanks a lot guys.

Your next question comes from the line of Jason Gammel with Macquarie.

Thank you. I just wanted to ask you a couple of questions about the Hayesville and your first quarter performance. You obviously had a very strong average IP rate out of your Hayesville wells, but there was the one well that came out just a little over 3 million a day. Could you just talk about the general geographic location and then what you're seeing there that led to the lower IP and then talk about the percentage of wells that were drilled during the quarter that were in and around the Elm Grove area?

I'll let Dick is checking his notes here. But the smaller well was drilled on what we precede to be the northernmost area of the economic portion of the field. We felt comfortable that would be a smaller than average well and it was. When you have such a large acreage position, you need to determine the limits of the field and we're doing that and consciously that is our smallest well and rest of our wells are all averaging as the limit before that we've reported at average. In fact, even if you can keep that well in the average, we're still averaging about 17, 18 million a day, even with that, the smaller well which I saved well in the mid.

Great and then also just coming back to your comment about note ways on getting gas in the sales. Can you remind us of the step up that you have in then takeaway capacity out of the Haynesville?

Well we're building to I think about 850 a day due to course of this year and we have another 400 a day committed on the regency project or next year and a few odds in the ends on other projects that will be coming in for us later than that. And back to the -- I'd like Dick to say something. We've been drilling quite a few wells around Elm Grove and Caspiana. A quite a few wells outside of the HPP position, I don't if it's half and half or what?

It's more than half outside of Elm Grove. It looks like around four wells in the Elm Grove area and I would acknowledge that's a very large area. We'd kind of break them out into project areas and Elm Grove is clearly the largest and it's not necessarily just within our HPP position, clearly it's not at this point. But we drilled a number of wells and what we call our plantation area which is just south of Elm Grove, our Cicada area which is just south of plantation. We're drilling over in the western side of the state, what we call Greenwood area, Holly area which is down to the southwest and we got about six or seven different project areas that we're expanding everyday.

No wells are outside of Elm Grove and inside for the year, certainly.

Certainly.

Right. And maybe just one more follow up if I could please. When you mentioned the definition of the northern extent, is what you're saying essentially breakdown on parishes (ph)? Is that kind of what's leading to the delineation of the northern area?

Well, let's make it clear. That's just the northern most well we've drilled and the margins of a large field like this won't be straight line, Dick.

Yeah, I think in terms of your question whether it's a breakdown of -- clearly is. The section's still there I think in the area that you referenced where we drilled the Fayetteville (ph) well. I think we got over 200 feet of growth section but the actually net section and everybody is going to measure a little bit differently. But it's considerably less than what we have, where we have high deliverability wells. So it's really degradation of the overall section that's causing it.

Great. Thanks for the clarity guys.

Jason, it is too early to draw conclusions about the margins of the field. We just as we do with all of these wells, we report whatever we find.

Sure, enough. I'll probably should phrase a little differently. I was just trying to figure out geologically what's going on as you're moving into areas that have lower initial productivity?

The great news on that is we moved in quite a few of those areas that were unknown. And we've been presently surprised in all the states.

Excellent. Thanks.

Your next question comes from the line of Brian Corales with SMH Capital.

Good morning. Just a couple of questions on the Hayesville, what are you all seeing now on drilling time and spot the sales on average, I know it may vary but if there is a rule of thumb to use?

It's coming down all the time, Brian. We're targeting really probably, spread the spot around 55 days. I know there are 15 to 20 days to actually get the sales. If frac jobs take about a week, usually it takes two or three days to get to sales after the frac jobs but our operational guys pretty much have this lined out. So by the time the rigs moved off, a lot of time for frac within four, five days. So we're looking at around 75 days target despite deferred sale.

We've had a few wells under 50 and we've had a few wells less than 15 days from CD to sales. But 70-75 days is currently in our sight.

Okay and in terms of -- I know a lot of people are announcing IP rates. I'm just trying to get a understanding of kind of how the IP rate correlate with and even say a 30 day average. I mean is there a number that you can say if it comes on a 22 million a day? Can we assume may be 15-17 million a day first month average?

We can't speak for other companies. We have a consistent method of placing these wells on production and declaring internally what the IP rate is. If you had a consistent approach to this across the whole field by all operators, you probably could make these correlations. Internally, we certainly understand that if we use our consistent methodology, if we have a well that comes into 20 million a day, it's going to be in the higher end of our reserve expectations. And a well that comes in at 10 million a day on an IP rate is going to be in the lower end or the middle of it. I don't know if that's responsive, but that is not quite as an orderly procedure in Louisiana in the early stage of closing these wells as it is in some other areas.

Right. And just one more follow-up on -- I know a lot of questions on the infrastructure side, where you stand today? Is there a time where it does get tight before regency (ph) does come in or is it first quarter 2010, mid 2010 where the pipelines need to be in place before you, it starts getting very tight?

We're comfortable with where we are. However our results are better than we had anticipated. We certainly hope and are anticipating there will be an operation during the first quarter of 2010. I think they're still projecting to be an operation by year-end. So we planned for this as best as we can. But there would be a time after the first quarter of 2010 that brings the increasing in production that we will be looking for other options and then first, we're looking for those today.

We'll move with all the parts in the field.

We always give the GAAP our points out. But about half of our job is to get the best price possible as supposed to just selling the gas for whatever. The regency completion is an important part of that equation for us.

Okay, guys. Thank you.

Your next question comes from the line of Rahan Rashid with FBR Capital Markets.

Good morning Floyd. Most of the questions have been answered but just again on the Haynesville. Looking forward you guys are always proud of continuing to optimize, anything particular that you're looking forward to experiment with the desired slide of drilling or completion methodology?

Yeah, let me get Dick to respond to that then it's really interesting and dynamic what's going on here as more and more wells are getting completed. We have interest in many of these and we are sharing data with many of these great operators. We are gathering more and more data and we're able to spend some time reflectively in a quiet atmosphere and take these things through. So yeah, we are constantly thinking of ways to tweak either better freight jobs or lower costs or a combination there. Dick?

That's exactly right. Trying to have a combination of a better job at a lower cost is I don't think our goal and if not a lower cost it's a better job at same cost. Some of the things we're doing and we actually implemented here recently and probably we'll do so over the course of the next three months. Longer stages more precautious in each stage which will obviously reduce the total numbers stages per job and therefore reduce the cost. We're popping some in conjunction with the resin indoor ceramic sand that we use our high strength profit. We think that's the way to save some money and not compromise the world, for getting our concentration up a little higher in some instances, trying to get up to maybe 3 pounds per gallon and see if that helps the kind of activity to raw increasing our injection rate up to 100 barrels a minute. In some cases, we're doing all these in a control fashion. I think that's the key. So we can understand how it changes affecting the productivity of the rock at least as best as possible and then comparing to some of the wells in the same area. So I think we are at the stage of the game right now where we can do that effectively compared to the wells we completed very consistently over the last six months and hopefully recent completions that will make wells even look better.

To keep it clear though we are not pumping less profits even if we have longer stages. We might be pumping in less water and the less flow and carry fluid but probably about the same about of profit will grow overall length of lateral. In fact its powers well, I think our first well we employed a slightly longer stage and I think it was about 400 foot per stage contrast with 325 and the job went great. So we constantly tweaking things that we can come up with.

Yes just to address Floyd's comment. I didn't mention that we are pumping upwards 400,000 pounds per stage instead of the 300 which again equates to about the same amount of sand (ph). So, that's a very good point to make and we're not decreasing the amount of sand going in there, we're just spreading it out a little differently.

And Dick, all these efforts, do you think we are improving EURs, are we more in the mode of made this juncture, improving kind of productivity?

Both.

Both.

And hopefully decreasing cost. Maybe we can...

Yeah, sure.

Find the rest of these and address all three of them in a positive fashion. I think there is a real chance we do that.

Got it. And as you observe and get more history in all these wells, any material changes in the decline curves at this juncture?

In fact, we just reviewed that yesterday in an internal meeting and it's amazing how all the additional production on the wells we reported before and all the new wells are still tracking at the same, they're all clustered in the same area and they're all clustered pretty evenly around the 7.5 Bcf ultimate outcome for an average well that we drilled so far.

Okay, good. Thank you.

Your next question comes from the line of Subash Chandra with Jefferies.

Just a clarification, the Eagle Ford, the last Eagle Ford well I thought I heard Henderson or something and I was just -- the names that I had down for wells that we're drilling that one didn't show up. Did I hear something wrong?

It was the -- I won't say the second half right. It's the Henderson (ph) well and it's in...

In LaSalle.

In LaSalle county, was placed on production about 3 weeks ago.

Two weeks.

Two weeks ago.

Okay, got you. I was just looking at the presentation with and I am not sure if I saw it on the list, anyway, okay. And the second question is, as for at least retention purposes is 16 sort of the optimal rig count?

We had a program and still performing into that program with 10 to 12 rigs. However, there are two things going on here. We'd like to take a little pressure off to 2011 like in the few more wells drilled before the end of 2010 since the increase to 16 rigs. And Subhash, we've also been adding a little bit of acreage here and there which adds our it's not pretty more pressure on our lease capture situation but it's certainly providing us with additional opportunities to secure additional HPP acreage with new wells to be drilled. So we're trying to serve several different objectives here. We have a good plan. There are 10 to 12 rigs going to hold all the acreage and it's just an easier plan if we have 16 rigs running that's all.

Okay, got it. Thank you.

Your next question comes from the line of Ron Mills with Johnson Rice. Ron Mills - Johnson Rice & Company LLC: Subash just asked one, the other question just in terms of Eagle Ford since you're still early in that play. Any tweak that you can discuss in terms of how you all are completing the wells out there to this point and is there a depreciable difference whether you're in the gas (ph) and versus the oil wind go into completions.

No Ron the huge tweak has been that the, I think the first well took us 75 days to drill or more and this last wells is 20 or 22 days or something. Cost have come down from 12 or 12 plus million down to I think the last AFE I have signed was under 5 million so, those are some significant tweaks. Its early days to say that much. We can't say that so far, wells are exhibiting the slightly more shallow decline, didn't say Haynesville. And far as the completion, it looks to me like that we completing about the same whether they are in the dry gas area or the high Btu or liquid, high liquid content areas. Their made to completions are identical.

They are probably the most significant change we've made through out the course of this short program with some implemented so far is that we're pumping about 75% out of we're seeing in about 25% resin. This pressure grading here is considerably less that it is in the Haynesville well and research and performance have suggested that we think that's a good mix to pump to ensure that we still have good content through the own brand. Ron Mills - Johnson Rice & Company LLC: All right. Thank you, guys.

And our last question will come from Andrew Coleman from UBS.

I had a couple of questions on have you see any changed on the operating market as far as I've been able to look at some of the assets maybe you talked about that but you said a couple of weeks ago you want to advance that all this year?

Steve's here, I like him to answer that but we certainly see an encouraging signs that interest in those sort of assets and there's some companies around that had where we thought to acquire them, what do you think Steve?

Thanks Floyd. Andrew, there been a couple of deals announced I guess form the last couple of weeks range in their firm with their deals and certainly it's falling out a bit, people are interested in markets coming back and we are still evaluating our situation, our permanent assets are great properties. We're under no pressure to divest those. They are doing just fine for us at some point down the road, it certainly being good, a good candidate about half well and there were quite a lot of capital to keep the rate pretty flat. So we are still monitoring the market and we are making appropriate call on those at some point.

We could, there is not, its see what where could try to sell them later this stage next year. This will link with the overall...

Okay. Can you say approximately what production rate those properties were at March 31?

About 35 million a day equivalents.

And you said that was about 50-50 oil and gas or that was the reserve mix, was that oil volume 50% oil?

That's about 50-50 oil gas on the production and reserve mix.

Okay. And then from a reserve booking standpoint for the first quarter it will take advantage of all the wells that you've booked in the -- or that you drilled in the Haynesville I think it was 15 of them?

We try to follow the same pattern as the SEC outlined at year end. We assigned reserves and BUD reserves to those wells that we got on production.

Okay. And then kind of stepping bit to the mechanical side of things. With the impairment, it looks like your DD&A scenario of $3 in Elm, do you -- is that going to stay pretty flat for the rest of the year? Do you - - or can you give any color on what DD&A should look like?

At year-end, our DD&A work rate was around 375 and as you just stated we're closer to 3 and that's that 75% drop was due to that 950 million charge at year end. So with 1.7 charge, you will certainly expect to see that go down starting in the second quarter.

Okay. And then for share count, I have a little high share count for the first quarter. I guess we will see effect of that -- 20 million share offering to fully impacted it for the second quarter?

Yes, that's correct.

Okay. Thank you.

Thanks every one for joining in. We are really happy with the quarter and call us if you come up with something we didn't address you. Thank you.

Thank you. That concludes today's Petrohawk Energy Corporation's first quarter 2009 earnings conference call. You may now disconnect.