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Petrohawk Energy Corporation (NYSE:HK)

Q4 2009 Operational Update Call

February 1, 2010 9:00 am ET

Executives

Floyd Wilson – Chairman & CEO

Dick Stoneburner – President & COO

Tina Obut – SVP, Corporate Reserves

Mark Mize – EVP, CFO & Treasurer

Steve Herod – EVP, Corporate Development

Analysts

David Heikkinen – Tudor, Pickering & Holt

Subash Chandra – Jefferies & Co.

Joe Allman – JP Morgan

Patrick Walsh [ph] – Stifel Nicolaus

Michael Hall – Wells Fargo

Ron Mills – Johnson Rice

Adrayll Askew – Hartford Investment Management

Nicholas Pope – Dahlman Rose

Chris Pikul – Morgan Keegan

TJ Schultz – RBC Capital Markets

Dan McSpirit – BMO Capital Markets

Operator

Good morning. My name is Cynthia, and I will be your conference operator today. At this time I would like to welcome everyone to the Petrohawk Energy Corporation’s fourth quarter 2009 operational update. 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)

I would now like to turn today’s call over to Floyd Wilson. Please go ahead, sir.

Floyd Wilson

Hello, everyone, and thanks for joining us this morning. 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 Web site as well as our other public filings.

Well, today, Petrohawk announced dramatic year-over-year production growth and year-end 2009 proved reserves that were double 2008 year-end proved reserves. These results were affected by new SEC reserve booking rules that added PUD locations in some cases, but also had the effect of reducing our curtailing proved reserves and values by using the average price for 2009 which was quite low, as we all understand, and only scheduling wells that could be developed in a five-year time frame.

We have included a significant amount of information in today’s press release that allows our reserve bookings to be viewed in a variety of scenarios. Anyway you look at it Petrohawk is a new company again. We are seeing the front end of significant conversion of upside potential to proved reserves in a fairly predictable manner based on drilling schedules, capital budgets and world-class results.

With today’s announcement Petrohawk also reported very attractive F&D results, these results are really positive whether viewed using today’s SEC reporting rules or those in effect last year. Our plan is simple and has not changed. We try to make good money with these awesome assets whose F&D profile indicate this will be possible for years to come.

Petrohawk and a handful of other independent producers are sitting on a lot of homegrown natural gas. Our plan and commitment to drill and hold these valuable leases and assets, particularly, in the Haynesville Shale has proven to be sound.

We hedge, we contract for certain materials and services, we make financing available and we drill to grow. Perhaps at a higher rate than some would choose in today’s natural gas price environment assuming that others would have hedged as much as we had, and of course, you have to own these types of assets to provide this kind of choice as the growth rate.

Our growth substantially hedged brings cash flow. We are quickly recycling until that day in the not too distant future when the Company turns cash flow positive. And our growth, by virtue of the hundreds of wells we are drilling, buys us experience and assures us a place at the table.

In the Haynesville Shale our oldest producing well as nearly two years of production history. We have identified many premier drilling areas within our acreage position defined by superior rock quality and well performance.

In our reserve report today the 1.5 Tcfe added in Haynesville Shale is in aggregate of EUR estimates for each individual well drilled with an average of three offset locations for each well.

The range of EURs for wells contributing to the report was between 4 Bcfe and 12 Bcfe with the highest EUR booked for a PUD was 9.7 Bcfe. Our 7.5 Bcfe type curve included in today’s presentation is holding.

Before I turn the call over to Dick I’d like to highlight that Petrohawk’s 2009 drilling budget set in early 2009 at $1.1 billion came in at $1.146 billion. If you lost a bet today, I’m sorry.

On the leasehold acquisition side we spent approximately $500 million, added much of what we own today in the Eagle Ford Shale and importantly, added about 60,000 acres in the heart of the Haynesville Shale play directly in the path of our drilling rigs.

Today, we stand with an excellent liquidity position sufficient to execute our 2010 program. And our 2010 asset divestiture plan which is targeting approximately $1 billion will provide capital and balance sheet strength for 2011 and beyond. Dick, all yours.

Dick Stoneburner

(inaudible) operations of Petrohawk. Although 159 wells were drilled during the quarter with 147 or 92% of those drilled in the three Shale plays that we operate in, the Haynesville, the Eagle Ford and the Fayetteville, 29 of those wells during the quarter were operated, all of which were in the three Shale Plays.

For all of 2009 we drilled a total of 626 wells, all of which were successful. 564 of those wells or 90% were drilled in the three Shale Plays. 135 of those wells were operated with all but three being located in the three Shale Plays.

The main driver for the Company during 2009 once again was the Haynesville Shale. During 2009, total of 64 wells were placed on production. With the exception of those wells that were purposefully had produced at restricted rates the average initial production rate was 17.8 million a day.

These wells were able to increase production almost 450% for the year, growing gross production from approximately 110 million a day at the beginning of the year to approximately 480 million a day at the end of the year. This growth was accomplished with a relatively modest drilling program that average slightly less than 11 rigs on average during 2009. During 2010 the Company intends to operate 17 rigs and drill between 110 and 120 operated wells.

From a drilling perspective the number of days from spud to spud has consistently declined throughout the year. During the first quarter the average was 70 days and by the fourth quarter that number had dropped to 54 days.

We continue to see improvement in reducing the number of days and are forecasting 42 days on average for the wells drilled during 2010. This decline in the drilling days translates directly to a reduction in cost with the average cost per foot decreasing by almost 25% during 2009.

The completions in the Haynesville have seen a variety of changes throughout the year, with the most notable being the increased amount of sand being pumped. This increased volume of sand is being pumped in the form of considerably higher concentrations per barrel of fluid. While early in the play the typical sand concentration pump was 1.5 pound per gallon of fluid and the concentration now has increased to 3 pounds per gallon of fluid pumped.

Just as importantly, this change has been made without the need for significant volumes of gel. It is our opinion that the most effective frac fluid is slick water pumped at high rates and high concentrations and we have been able to accomplish that.

Potentially, one of the most important aspects of our Haynesville Shale operation has come from the production side. In mid-2009 we made the decision to test a concept that we felt might result in higher ultimate recovery per well and higher present work per well. We call it reservoir optimization and the concept is rooted on the premise that the reservoir produces optimally when the pressure is depleted at a more gradual rate.

We chose four wells to test the concept with each well having several older wells nearby with which to compare to. By the end of the year the data gathered from the wells was very compelling. It suggested that wells could and probably would provide higher EURs than the comparison wells. There is still considerable testing and analysis to be performed, which will take more time and more data points. But we do believe that the concept warrants further testing and we plan to do so during 2010.

Turning to the Bossier Shale, Petrohawk is very excited about the upcoming Bossier test that is scheduled for later this quarter on the Louisiana side of the play what we call our Whitney Prospect [ph]. We believe that this reservoir has the potential to add tremendous resource to the entire play and particularly in the extensive leasehold that we have under the prospective area of the Lower Bossier Shale.

Many of our peers have already tested the zone above Louisiana Texas with a notable test being a well that has been drilled by EOG in our AMI with them in Nacogdoches County. The well should be completed in the near future and will be a significant data point for this expanding play.

Switching to the Eagle Ford Play in general and Hawkville Field in specific, 2009 was a period during which approximately 225,000 net acres that we have under lease in the field was effectively de-risked. By mid-January 2010, we had 22 wells on production with gross production of approximately 61 million a day and 800 barrels of condensate per day.

One of the most impressive aspects of the results that were obtained during 2009 is the consistency of production across the entire trend. If you look at the field as being composed of three areas, dry gas, condensate yield less than 50 barrels per million and condensate yield greater than 50 barrels per million and one assumes that the gas to condensate on a revenue equivalent basis should be 12 to 1 instead of the conventional 6 to 1, then the average Btu adjusted IP for all three areas is 10.3 million, 10.5 million and 10.6 million respectively.

This comparison suggests that dry gas Eagle Ford Wells, because of their ability to produce so much more gas than a higher ratio of gas condensate well are very comparable to the high ratio wells.

Another interesting development for the Hawkville Field is the recent discovery of a high pressure and high rate dry gas well just to the northeast of our leasehold. This is a very significant well and provides evidence that a significant area of the Petrohawk’s acreage be in this area of high pressure dry gas production.

The most significant aspect of our drilling operations in the field was the initial testing of longer laterals. The first well to be drilled with an extended lateral was the Caroline Pielop #4H. It was drilled with a lateral length of approximately 5500 feet and was completed with 16 frac stages. The well had an initial production rate of 11.6 million cubic feet per day with 4800 pounds flowing casing pressure on a 2464 choke.

The well has several nearby wells by which to compare to and the data is conclusive that the longer lateral length has resulted in a well with a higher EUR. We intend to drill a majority of our wells with extended laterals of 6,000 feet or greater to further evaluate the performance of these longer laterals.

Regarding our Red Hawk prospect in Zavala County, initial test well in the Mustang Ranch No. 1H was drilled with an approximate 5,000 foot lateral length and is waiting on frac. We expect to have the well completed and evaluated by the end of the first quarter.

In the Fayetteville Shale we have only been operating one rig during the last half of 2009 and intend to maintain that level of operation during 2010. However, that does not suggest that it is a depleting asset that has limited potential.

As the Company moves toward having its leasehold held by production in the Haynesville and the Eagle Ford by mid-2011 the Fayetteville will once again be an area where we focus our operations.

In the meantime, we have been the beneficiary of very active and very successful partners that are drilling hundreds of wells for us. During 2009, we participated in 330 non-operated wells, while drilling just 35 operated wells. As a result of this activity we saw our net Fayetteville production grow 15% during the year 2009 from 75 million a day to 86 million a day.

With that I’ll turn the call back over to Floyd.

Floyd Wilson

Thanks, Dick, and thanks for making your way through that with your cold. An incredible year, Dick, and thanks to you and our fine staff. I believe these results speak for themselves and we have some time for questions out there are any.

Question-and-Answer Session

Operator

(Operator instructions) Your first question comes from the line of David Heikkinen with Tudor Pickering and Holt.

David Heikkinen – Tudor, Pickering & Holt

Good morning, guys. A quick question, first, Dick, on the testing of wells in the Haynesville with lower choke sizes. Can you talk at all about the shape of the curve and what you’re seeing and then the number of wells you’ll pilot in 2010?

Dick Stoneburner

Sure. The best way to describe that is if you can envision a rate versus cum [ph] curve, and this may be a little too technical, but I’ll try and make it evident. The wells that we put on a restricted choke have very little decline and actually some wells have no decline, during the period at which it takes to achieve the same cum that a high decline well would produce.

So in other words, around 1 Bcf to 1.5 Bcf, restricted weight rate well has made the same cumulative production as the high decline rate well, but it already has a higher rate as it passes that point of comparable cumes. That probably didn’t go over very well, but it basically tells you that the wells are clearly going to make a higher EUR, we just don’t exactly know how much more.

In terms of the number of wells, it will be selective. We are trying to test each area with the number of wells that have comparative wells nearby. So we’ll look at it on a case-by-case basis. Floyd, do you have anything to add?

Floyd Wilson

No. I think there are a few of the wells that have been on production this way for a while. I’ll get Joan to put a couple of those on the Web site so people can see the actual curve shape, it’s no problem.

David Heikkinen – Tudor, Pickering & Holt

And then you guys gave the number of PUD locations booked in the Haynesville. Can you talk about the Eagle Ford and Fayetteville as far as the number of offsets that you booked?

Floyd Wilson

Are you available for that one? I think it’s kind of similar, but what would you say to that?

Tina Obut

Yes, in the Eagle Ford we had booked 136 PUD locations for a ratio of about 5 to 1. And in the Fayetteville we have 394 PUD locations versus 863 producing wells for a ratio of about 0.5. Does that answer the question?

David Heikkinen – Tudor, Pickering & Holt

Yes. (inaudible) do you have the average book per location? I guess I can get to that.

Tina Obut

The average EUR in the Eagle Ford is about 3.2 Bcf equivalents and in the Fayetteville its 2.7 Bcf equivalent.

David Heikkinen – Tudor, Pickering & Holt

Thank you.

Operator

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

Subash Chandra – Jefferies & Co.

Hi, good morning. First, I guess a number of questions. Do you have the future cash flows, net cash flows for 2009 that relates to the PV10 number?

Floyd Wilson

Let’s see. I don’t think that number is published.

Subash Chandra – Jefferies & Co.

So just wait for the K I guess for that one?

Floyd Wilson

Yes.

Subash Chandra – Jefferies & Co.

All right. And a question on Red Hawk, how do you think you’ll complete this well compared to how you do the balance of the Eagle Ford for dry gas or condensate rich gas? And can you comment on the type of pressures you’re experiencing in Zavala County?

Floyd Wilson

Go ahead, Dick.

Dick Stoneburner

It’s a normally pressured area, probably 0.45 gradients. We’re going to try and create a bit more conductivity with our frac job. With a slick water frac you always like to have what you call a complex frac, which is just a lot of micro fractures and not necessarily a lot of wing length. We’re going to try and have what we might call a hybrid frac for the Eagle Ford in the oil window. Then we’ll have a fair amount of gel pumped in order to get the higher concentrations and have a fairly complex frac, but also try and make sure we get some extended wing length and conductivity.

Subash Chandra – Jefferies & Co.

So you think it might be just more constitution of gel and perhaps a lower pump rate versus what you do in the dry gas area?

Dick Stoneburner

It wouldn’t be a lower pump rate, it would effectively just we try and get even higher concentrations that we’re doing in the three pound per gallon. If we can get more than that then the better. And we think we can probably do that with gel. Because we’re getting 3 pounds per gallon with minimal if any gel in the dry gas.

Subash Chandra – Jefferies & Co.

Got you. And a number I missed, I apologize, what was the Haynesville number of PUD locations on average? I got the range but I’m not sure I got the average.

Floyd Wilson

That was 3 per PDP location.

Subash Chandra – Jefferies & Co.

And what was the actual number?

Tina Obut

The actual number is 419 PUD locations.

Subash Chandra – Jefferies & Co.

Okay, great. Thank you very much.

Operator

Your next question comes from the line of Joe Allman with JP Morgan.

Joe Allman – JP Morgan

Thank you. Good morning, everybody. In terms of your 2010 production guidance, does that assume the asset sales?

Floyd Wilson

No, Joe, we normally don’t plug those in until they happen. So that would be a separate matter for when they come about.

Joe Allman – JP Morgan

Okay. That’s helpful. And then in terms of the Eagle Ford Shale that 310,000 acres that you have, does that include the Red Hawk field?

Floyd Wilson

It does as well as some other miscellaneous tracks along the trend that are outside of Hawkville.

Joe Allman – JP Morgan

Okay. All right, helpful. And then in terms of the negative reserve revisions, where were they? Were they PUDs or were they mostly tails of proved developed and PUDs?

Tina Obut

Mostly related to pricing and it is really just a combination of both the PUDs and just tail end.

Joe Allman – JP Morgan

Okay. Was there any type of well in particular that had a heavier weighting than any other type?

Tina Obut

Mostly in the conventional Louisiana area is where we saw most of that and a little bit in Fayetteville.

Joe Allman – JP Morgan

Okay, all right, great. Thank you

Operator

Your next question comes from the line of Patrick Walsh [ph] with Stifel Nicolaus.

Patrick Walsh – Stifel Nicolaus

Hi, thanks for taking my call. Just had a couple of quick book-keeping questions. With regard to the negative revisions and I believe this was just asked, but I want to kind of confirm it. All those 277 Bcf was that price related or were there some technical related revisions in there as well?

Tina Obut

There was a small amount of technical revision in there.

Patrick Walsh – Stifel Nicolaus

Okay, but pretty immaterial relative to the total?

Tina Obut

Very immaterial.

Patrick Walsh – Stifel Nicolaus

Great. Thank you. And then with regard to the 2010 production guidance, and this is just kind of a discrepancy I’m coming across and I just kind of want to clarify it. On the third quarter call and also with the BMO Capital Markets presentation that’s up on your website, I’ve noticed that 2010 production guidance was 665 to 685 Mcf a day on average for the year. And with this release you’re saying its 670 Mcf a day to 680 Mcf a day. Can you kind of clarify that discrepancy?

Floyd Wilson

Well, we just narrowed the range a little bit. I think the midpoint of the range is the same, is it not?

Patrick Walsh – Stifel Nicolaus

No, it is. It looked like you had written it was unchanged and I was curious if I had missed something along the way or if this is actually a change to that original.

Floyd Wilson

I wouldn’t call it a change just that these results are getting, the drilling is a little more predictable and we just narrowed the range a bit.

Patrick Walsh – Stifel Nicolaus

Okay, great, that’s helpful. Thank you.

Operator

Your next question comes from the line of Michael Hall with Wells Fargo.

Michael Hall – Wells Fargo

Hi, good morning. Congrats on a solid release. Trying to get my head around how many rigs are actually drilling on PUDs versus kind of unproved locations in your current call, five-year plan. How might I think about that in the respective areas of the Haynesville and the Eagle Ford?

Floyd Wilson

Dick could take a stab at this. But essentially we’re not drilling any PUDs to speak of right now. There’s a few that are coming along just because they were approximate to another section that we already have a well. We haven’t published a five-year plan. As you know, we’ve estimated that we will have held all of our Haynesville acreage by the third quarter or so of 2011. So I think after that you could assume that most of the drilling would become PUD drilling by that time. Dick, anything different than that?

Dick Stoneburner

No, Tina, why don’t you, you explain better than I.

Tina Obut

Yes, I guess I’ll just say that the PUD schedule adheres to our five-year plan and can be accomplished really within the rigs, the total number of rigs that we had planned. So for Hawkville it would be starting with about four rigs and then ramping up to about 11 at the end of the five-year period. With Haynesville it’s about 16 and with the other areas, Fayetteville would be four rigs, Elm Grove and Terryville would be four and three rigs for those. But the schedule also honors the lease obligation wells, so the PUDs really won’t start being drilled until the later part of that five-year period. Does that make sense?

Michael Hall – Wells Fargo

Yes, I think so. And so, if I think about it from now until about the end of 2011, you’ll largely be drilling on proved locations and by then it kind of switches such that you’re predominately drilling PUDs, is that –?

Dick Stoneburner

Correct.

Tina Obut

That’s correct.

Michael Hall – Wells Fargo

That’s fair. Okay. And then can I get a future development capital number that’s assumed in that PV10?

Floyd Wilson

He’s looking it up.

Michael Hall – Wells Fargo

Thanks.

Floyd Wilson

Keep in mind, Michael, that the Bossier, which in some areas looks just as attractive as the Haynesville would be a little bit of a wild card on the – once all the rights are held we may well shift to drilling non-proved Bossier locations for a while.

Michael Hall – Wells Fargo

Okay.

Tina Obut

Did you need the future development capital for the total company or –?

Michael Hall – Wells Fargo

Yes, total company is fine.

Tina Obut

Total company is $3.18 billion.

Michael Hall – Wells Fargo

Perhaps I guess this if you have the split that would be great too, in terms of –

Tina Obut

I guess the Haynesville is $1.9 billion of that.

Michael Hall – Wells Fargo

Okay. Great. Appreciate it. Congrats again.

Operator

Your next question comes from the line of Ron Mills with Johnson Rice.

Ron Mills – Johnson Rice

Good morning. I just saw in the release that you’re expanding your leasing towards the north east into Webster Parish. Has there been any activity up there or what’s the plan as you move towards the northeast as you sound like your ramping activity on your east Texas portion with EOG?

Floyd Wilson

Dick, we own some leasehold in Webster Parish already. Quite a lot there. I think we’re just planning to get that rigorously tested this year. Is that accurate?

Dick Stoneburner

Yes, there’s a township in the southeast corner of the Parish that’s perspective and is probably pretty good, it’s not the core of the core, but it’s pretty good. But we haven’t really considered that an active area beyond what we initially accumulated within the geologic confines of the play. Now you made another comment about the EOG area?

Ron Mills – Johnson Rice

Yes. Sounds like you drilled a Bossier well down there. What’s the drilling plan on that EOG acreage in terms of ramp on that southwest extension of the Haynesville play into Texas?

Dick Stoneburner

There’s a fairly active program for '10. I don’t think I will need to get into details of it considering that it’s kind of EOG’s call as operator, but it’s a moderately aggressive plan. We’re going to develop the new acreage we acquired recently with them down there. And again, we’re hopeful that the Bossier is another component of that play.

Floyd Wilson

Ron, we have some other areas of non-EOG related down there that we’re currently working in as well.

Ron Mills – Johnson Rice

Okay. All right, guys. Thank you.

Operator

Your next question comes from the line of Adrayll Askew with Hartford Investment Management.

Adrayll Askew – Hartford Investment Management

Yes, congratulations on a good operational year, guys. Can you talk about your spud-to-spud improvement in the Haynesville? You’re expecting another dramatic improvement in the metric in 2010. What changes are you expecting to execute in 2010 to get you down to 42 days?

Floyd Wilson

(inaudible) respond to this, but the trend is already in place to get ourselves and others in the region have been drilling some wells in less than 40 days. I think it’s just a continuation of the trend that is many fewer days to drill the laterals, the horizontal leg, and just an overall improvement based on experience. We had, had a nice jump with a bid that we developed here last year which was helpful as well. Anything to add, Dick?

Dick Stoneburner

Not really. It is just a continuation of what we’ve already accomplished. And I don’t think it’s what you consider a, I don’t know what the term that was used of significant shift from 54 days to 42 days. I think that’s very doable.

Adrayll Askew – Hartford Investment Management

Okay, that’s very helpful, guys. Thank you.

Operator

Your next question comes from the line of Nicholas Pope with Dahlman Rose.

Nicholas Pope – Dahlman Rose

Quick question on just the CapEx for 2009. Do you have the spending related to leasehold? I guess the $1.15 billion doesn’t include that I’m assuming. And so the leasehold and just infrastructure spend for 2009?

Floyd Wilson

Yes, Nicholas, we propose to spend $1.45 billion in drilling and completing wells in the three Shale plays with a small amount being relegated to other fields. We’ve speculated that we could spend between $100 million and $300 million during the year in leasehold; we have no idea if that will happen or not. There’s not a lot of lease hold available in the areas we’re truly interested in. So there’s a number in there, the midpoint of being $200 million. And I think we’ve estimated about $200 million for midstream during the year. Of course that number could change given our plans to divest a portion of our Haynesville midstream. But going in it’s about $200 million for that as well.

Nicholas Pope – Dahlman Rose

Great, that’s helpful. And then 2009, like the total spend for the year? I didn’t see that part of spending broken out.

Floyd Wilson

I think Mark has it here. Mark can give it to you.

Mark Mize

Leasehold in 2009 was around $450 million and we were somewhere right around $300 million for Hawkville services.

Nicholas Pope – Dahlman Rose

All right. That’s all I had. Thank you very much.

Operator

Your next question comes from the line of Chris Pikul with Morgan Keegan.

Chris Pikul – Morgan Keegan

Hey, thanks. Good morning, Floyd. As far as the asset divestiture planned capital rates is there, how do you see that in terms of your 2010 budget? Does that give you more flexibility to accelerate drilling or how do you view some of that potential assets?

Floyd Wilson

The asset sale is really designed to monetize some great properties that have a lower rate of return than what we’re getting in these shale plays. And frankly, the timing of it and the ambition of the amount is such it really provides us with more fuel for 2011 and after. So 2010 in the absence of a huge increase in commodity prices we believe our plan is fairly well set. And we wouldn’t intend to increase it at this time regardless of the outcome of the divestments.

Chris Pikul – Morgan Keegan

Okay, fair enough. And then based on some of your comments about PUD drilling, would it be reasonable then for us to assume that somewhere close to your RIS number of 15 Tcf in the Haynesville would largely find its way into proved after five years?

Floyd Wilson

Listen, we’ll be shocked if a number that’s very much like that doesn’t find its way into proved. I don’t know if we can quite get it done in five years. However, we’re going to keep it up. I don’t think five years would quite do it, but certainly in the mid-term we would hope to convert more and more of those reserves every year.

Chris Pikul – Morgan Keegan

Great. Well, the results are great. Thanks a lot, guys.

Operator

Your next question comes from the line of TJ Schultz with RBC Capital Markets.

TJ Schultz – RBC Capital Markets

Hey, guys. Just following up on the asset sales, do you have or can you give us year-end reserves at both properties and current production?

Floyd Wilson

Steve, do you have that information?

Steve Herod

The production in Terryville area is around 22 million equivalents a day plus or minus and (inaudible) up in Oklahoma is around 12 million a day plus or minus. We don’t have the breakdown on the reserves by property right now.

TJ Schultz – RBC Capital Markets

Okay. And then just general, do have a little bit more detail on where you stand on the asset sale process? I know you’ve hired advisors, but just kind of a little bit more color on timing and data rooms are going to be open in the near-term here?

Floyd Wilson

TJ, keep in mind that Steve and his staff are highly experienced at this and our approach is to do it right and to do it once. And so these things are all underway and data rooms are soon to open in a couple of the areas, in the other areas we’ll space out a little bit, so, I think our projection was that it’s a 2010 divestiture program and that we would expect to have some first half of the year things to talk about. But we don’t give specific timing on that sort of thing; we try to make sure we find the right home for these assets with somebody that can execute a trade.

TJ Schultz – RBC Capital Markets

Okay, great. Just real quick on the balance sheet. Do you have kind of year-end where things stood cash and if anything was drawn on the revolver?

Floyd Wilson

Mark, we haven’t released year-end financials yet. So I don’t think we have that, do we?

Mark Mize

We’re still working our way through the audit. But obviously all that information will be available when we do our financial release here in a few weeks.

TJ Schultz – RBC Capital Markets

Okay, thanks, guys.

Operator

Your next question comes from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit – BMO Capital Markets

Folks, good morning. Thanks for taking my question. Now that you have the first full-year of operations under your belt in the Haynesville, how might we think about de-risking of the acreage at year-end 2010? Also what percentage of your acreage will be held by production at the end of this year?

Floyd Wilson

Dan, I think you could answer your own question. We’ve drilled all around the sides and all through the middle of this. So in our view we’ve already done quite a job of de-risking the acreage. And the risking factor that we use internally I think is proving to be conservative at least. In terms of the percentage, I don’t think we have that number in hand. But as we said, at least by the third quarter of 2011 we intend to hold all of our significant acreage in the play and we’re right on track with that. I suppose we could take a look at and look at some percentage of it but I don’t know what in there, what good that is.

Dan McSpirit – BMO Capital Markets

Okay, thanks. And then maybe the same question with respect to the Eagle Ford Shale?

Floyd Wilson

The Eagle Ford is quite such a different. It’s an interesting comparison. Longer leases, most of the large leases and even some of the small have continuous development drilling clauses. We don’t really feel the strong need to ramp up in the Eagle Ford until about the time we have the option of slowing down in the Haynesville. So I think Dick’s got us set to get up to about six rigs by early '11 and then hold that steady for a year or so. Is that about right, Dick?

Dick Stoneburner

Yes, six rigs or seven rigs as we go out to the '11, '12, '13 range will satisfy all our continuous development obligations. And I would add, Dan, that in the Eagle Ford I think we kind of knew this going in, but the more we drill the more consistent we see our acreage position. So we bought that in the dark of night without competition and with a pretty good geologic model. And I would eventually say that we’ve already decreased the risking to 80% on that and I wouldn’t be surprised at some point in the future that would even go higher just because of the consistency we’ve seen and the quality of the acreage across the board.

Dan McSpirit – BMO Capital Markets

Very good. Thank you.

Floyd Wilson

I think evidence of that, Dick, is the view that Netherland, Sewell took to allow contribution of about five PUDs per location.

Dick Stoneburner

Absolutely.

Operator

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

Subash Chandra – Jefferies & Co.

A couple follow-ups. Do you have the net well count in '09 and what it might be in 2010, all inclusive?

Dick Stoneburner

Net wells that we drilled?

Subash Chandra – Jefferies & Co.

Yes.

Dick Stoneburner

No, I don’t. Do you have that, Tina?

Subash Chandra – Jefferies & Co.

Because I add up I think the gross well is something almost 600.

Dick Stoneburner

That’s 650 or something like that.

Floyd Wilson

That’s going to be in the K, which isn’t too far away. I don’t think we’ve actually calculated that just yet.

Subash Chandra – Jefferies & Co.

Okay. And then secondly, we got the future development cost. What was the future operating cost?

Floyd Wilson

Do you have that, Tina?

Tina Obut

Yes, we don’t really have that handy.

Dick Stoneburner

We don’t have that handy, Subash.

Subash Chandra – Jefferies & Co.

Okay. I’ll wait. Thank you.

Operator

At this time there are no further questions. I would like to turn the call back over to Mr. Wilson for closing remarks.

Floyd Wilson

Well, thanks for joining this morning and we’ll see some of you up in the mountains and others just if there is something we didn’t cover give us a call. Thank you.

Operator

Ladies and gentlemen, this concludes today’s conference call. Thank you for your participation. You may now disconnect.

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Source: Petrohawk Energy Corporation Q4 2009 Operational Update Call Transcript
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