Good day, and welcome to the Petrohawk Energy Corporation's Second 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 thanks for joining. We have a lot to discuss today. 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 yesterday and posted to our website, as well as in our other public filings. In addition to our second quarter earnings release, our company issued a press release today relating to a senior notes offering that we are currently conducting. Due to SEC rules and regulations, we are not at liberty to discuss this subject matter of that release on this call. Well, I'll start off here. In May, we presented a multiyear plan, which defined milestones and targets ahead of us at Petrohawk. Major milestone is reached in mid-2011, when the bulk of our leasehold in the Haynesville Shale becomes held via production. This is based on our current rig schedule. A second milestone is reached in 2012, when we estimate the company will become cash flow positive. Several companies in our industry have similar milestones ahead of them due to large new discoveries and leasehold capture requirements. Although there is currently a supply-demand imbalance in the natural gas markets, many good companies have chosen to remain on a path of aggressive spending to hold acreage and protect future reserves and potential. And significant growth is an output of these activities. Petrohawk's early days in the lease capture phase have been aggressive, and we have had to grow our capital budget beyond current cash flow. Petrohawk and its shareholders endured a period of equity raises in 2008 and early 2009 to capitalize the leasing and lease capture phase of the Haynesville Shale development. Those days are behind us.…

Okay. Thank you, Floyd. We reported adjusted earnings per share of $0.09 and cash flow per share of $0.54 for the quarter. These figures were primarily impacted by an advisory fee of $7.5 million related to the KinderHawk joint venture transaction, as well as certain expenditures associated with litigation. These fees with settlements constitute right at $0.02 per diluted earnings per share as well as cash flow per share, and these charges will, not excluded from the results of operations in the Selected Items table in the press release, do result in about a $0.02 earnings per share decrease. During the quarter, there was a softening in natural gas prices. Petrohawk's realized gas price before hedges was $3.97 per Mcf. However, inclusive of cash collected on our hedge portfolio, the realized price was $5.26. For the first time, we've now started reporting natural gas liquids separately in our SEC filings, and we've achieved a realized price per barrel on the current quarter of 47% of NYMEX. Oil and natural gas liquids are approximately 4% of our production this quarter. As Floyd had stated, we expect this percent to increase during the second half of the year, as we continue to drill on the Eagle Ford and as more processing of pipeline capacity becomes available. Production for the quarter was above the high end of our guidance range, coming in at 625 million a day. And during the second half of the year, while we expect to have a slightly reduced rig count from the first half of the year, we are also expecting to start to see a meaningful stabilizing in the PDP decline due to the restricted rate program in the Haynesville. We have included a guidance range for third quarter of between 650 million and 660 million a…

Thanks, Mark. Petrohawk continued to achieve outstanding results from its operations during the second quarter of 2010. The success in the two primary operational areas for the company, the Haynesville and the Eagle Ford, were driven primarily by Petrohawk's dominant operated position in both plays; while the Fayetteville achieved excellent production growth, primarily as a result of its significant nonoperated position. In the Haynesville, the company operated an average of approximately 16.5 rigs during the quarter and drilled 28 wells, which is the highest number of wells drilled in any quarter in the two years that we have been drilling in the play. In addition, there were a total of 66 nonoperated wells drilled, which is also the highest number of nonoperated wells during any quarter. In the Eagle Ford, the company operated an average of 7.5 rigs during the quarter and drilled 19 wells, 11 in Hawkville, seven in Black Hawk and one in Red Hawk. This again represents the highest level of operated activity that Petrohawk's experienced in the Eagle Ford. In the Fayetteville, the company saw an unprecedented level of nonoperated activity. While we averaged less than one operated rig during the quarter and drilled only two wells, there were 111 nonoperated wells drilled, which is the highest nonoperated well count for any quarter in the three years that we have been active in the play. Instead of spending time speaking to specific well results, which are well documented in our press release and very consistent with the results we've been enjoying for the last two years, I would like to spend the balance of the call addressing what Petrohawk has been doing to achieve these results; because I truly believe the public does not fully realize the extent of the operational research that we perform and…

Thanks, Dick. And right here, I need to point out that Dick's leadership as President, Chief Operating Officer and partner has allowed our technical team to really examine these new and important reserves; and our operating teams to put this knowledge into action, even while drilling and completing wells at a eddy pace. Having said too much today about Hawk Field Services, and Eagle Ford Hawk Field Services is doing a great job of keeping up with the rig and keeping up with all the new oil and gas that we're producing down in the South Texas area. And KinderHawk, our joint venture with Kinder Morgan, is doing a wonderful job of getting our gas to markets in the Haynesville Shale. Our assets provide our shareholders with decades of growth potentials. Our operating and technical advances ensure that our activities are durable. And our conservative financial management and outlook will keep us out of trouble. We are ready for questions at this time.

[Operator Instructions] And we will go first to Gil Yang with Bank of America Merrill Lynch.

You commented that you're differing completion of wells. I'm sorry, I missed -- did you say how many wells you'd be deferring?

We've got an estimate of around 20 wells in the Eagle Ford, unfrac-ed at year end, and around 15 unfrac-ed in the Haynesville at year end.

End of 2010, you mean?

Correct.

And how does that affect your held-by-production schedule?

It doesn't. The way leases are structured, much initiated and completed the drilling operations. You have 90 days of cessation of operations before you can start another operation. So the way completion is styled with the initial work is preparatory work and then the actual completion coming in behind it. You technically have up to about 180 days from rig release to actually implementing the final fracture stimulation.

So you still need to put it on production within somewhat more than 180 days. But you have a little bit more time, is that what you're saying?

Yes, plenty of time. More time than we would have probably accommodated.

That's 180 days after lease. And the main thing Dick put out is that we don't anticipate that it has any impact on our lease capture schedule. We've spent a lot of time figuring this out.

Can you give a little bit more color as to what the lease capture schedule means, in the sense that by mid-2011, most of your acreage will be held by production in the Haynesville. Does that mean you can actually start taking rigs out of the Haynesville if prices warrant?

Gil, the whole commentary around this is that we get into a period of largely increased optionality about mid next year. We can keep the rigs flat as our current anticipation is, or we could remove rigs. We can move them from one play to another, or we could cut the budgets. We'll just have to see how things transpire, since we have been able to successfully hedge 2011. I don't think we would anticipate too many changes coming through in 2011, but we'll have to wait and see what gas prices to do and what service costs do. The lease capture schedule, we gave a fairly detailed explanation of it at our Analyst Day, and I believe we're just right exactly on track with what we've put out on that day in May.

One last question on Red Hawk. Can you give us sort of your current expectations for what that play will look like following that second well test?

Gil, it's really too early to make any definitive statements about the play, other than we've seen tremendous increase from the first well and the second well. It's too early to really forecast an EUR for that well. I would add that the well has been free flowing for a little over a month now, pretty steady, 250 barrels a day. Still has some pretty decent surface floating [ph] (00:37:34) pressures. So until we get the well put on an artificial lift, which we later this month, it will be difficult to accurately forecast. But all that being said, we're going to drill our third well either late September, early October. And if we continue to see the improvement that we've seen for the first couple of wells, then I think we have a commercial discovery.

Once you put on artificial lifts, will the flow rates increase from where they are today? Or would you be happy to get them back to where they are today?

No, I think they should significantly increase. There's very little energy support. We're flowing, basically, call them a dead fluid with as little as 50 Mcf or less gas support. So once you have a little artificial lift, I think we should see a dramatic increase in total fluids.

We go next to Dick Kindig with Keeley Asset Management.

I thought you said earlier you had 17 wells in the Haynesville awaiting completion. And just recently, you added to that 20 wells in the Eagle Ford, is that right?

No, we've had forecast by year end approximately 15 wells unfrac-ed in the Haynesville, and approximately 20 wells unfrac-ed in the Eagle Ford. And the 17 number might have been related to early rig count in the Haynesville, but that was stated, but I don't know where else where the 17 number was mentioned.

This is by year end 2010?

That's correct.

15 in the Haynesville, awaiting completion, and 20 in the Eagle Ford, awaiting completion?

That's correct.

Could you assure us that you will have a dedicated frac crew?

Well, we have two dedicated frac crews currently in the Haynesville, and we have other service providers that are providing frac crews on top of those dedicated crews. And we're working towards four dedicated frac crews in the Eagle Ford by first of the year, 2011. So we have plenty of dedicated opportunity, we're just trying to shore that up.

Dick, we can assure you we get all of our wells frac-ed in the appropriate amount of time. Keep in mind that every year, there's a certain inventory of wells that have been drilled, but not yet completed at year end. This year, that inventory is a little larger because of the scarcity of these frac fleet, these frac crews.

We go next to Michael Hall with Wells Fargo.

I just wanted to think about, kind of, completion capacity in the Haynesville, kind of, before thinking about the changes in well design that could reduce per well completion costs. What sort of capacity do you see coming over the next, call it, nine to 12 months?

You mean capacity for Petrohawk, Mike?

I mean capacity for the industry, in terms of, to help, kind of, loosen up the completion tightness in the market currently?

It's a big guess, Michael. We have forecast that by midyear of next year, just based upon conversations with service providers, their desire and intent to add more horsepower to the field and also, in our estimation, the increased availability of fleets because of the decrease in surface pressure that our new wellbore design will allow. And we think by midyear of '11, the demand supply question for the service sector will be neutral, but that's a forecast that certainly are not based on a whole lot of facts. It's presumption on our part.

The other thing, Michael, that we noticed is that the overall rig count in the Haynesville decreased slightly for the first time the last week or two. I have no idea if that's the trend or at one point. But if it's a trend, that would help ease the situation a little bit, too.

And then speaking to the change flow design that could reduce cost, how much of the 2011 Haynesville plan could be impacted in theory by that?

All of it?

All of it.

We think that by the end of the year, we'll have somewhere between, 15 and 20 wells established as wells that have been completed and produced on a new wellbore design. It's not a radical change by any means, but any change in your engineering needs to be done methodically. And therefore, it will take a good six months to feel confident that we should move forward with this on a total inventory. But that's our desire in '10, is to have all of our 2011 wells affected by it.

Co: *** Optimize start And I guess, what will be the key variables that would tell you that, that's working for those 15 wells?

Michael, is a very common wellbore design. It just hasn't been employed that much in these deeper high-pressure shales. Deep wells all around the world employ a similar design, or a hybrid of this design, so this is not something brand new to variables. We just want to make sure that this is suitable for the heavy task of drilling these deep high-pressure directional wells, but that's all. It should work just fine.

Just on the favorable assets, and I'm sorry if this was mentioned at the very beginning, I was late in joining. But do you have any EBITDA or cash flow figures on the Fayetteville midstream currently?

Michael, we don't put those numbers out. It's a relatively small system compared to, say, the Haynesville or the Eagle Ford. But it was very important to us to build because the capacity for Petrohawk just wasn't there when we started drilling in that field.

And then how much CapEx, I mean, if you were to -- for the Fayetteville asset, how much CapEx comes out of the 2011 program as a result of that?

Well, our 2010 capital, I think, we're projecting about 100 in the Fayetteville, and then maybe a little less next year, so it would be somewhere in that realm.

Next is Leo Mariani with RBC Capital Markets.

With respect to your well cost right now, could you just, kind of, give us what your current AFPs are running in the Eagle Ford and the Haynesville?

Right now, it's between 9.5 and 10 in the Haynesville and again, that's not with some of the things that I've mentioned in the call being affected. We think we can drive them down to 9 million, 9.5 million by year end, so we think we have a significant savings ahead of us, potentially even more. Lateral length is the big difference between the Eagle Ford and the Haynesville. We're not constrained by the regulatory limits of about a 4600-foot lateral in the Haynesville. We're drilling 606,500-foot laterals in both Black Hawk and Hawkville. Those are running right at 6 million to 6.5 million.

And do you expect those to creep up towards the end of the year with frac costs here?

I don't think so. As I've mentioned, we're pretty well convinced ourselves that the hybrid frac design is a better frac design for the Hawkville field, based on the first three wells that we frac. That, in effect, will decrease our overall frac cost going forward. And the rest of the components of a well cost have not been terribly, adversely affected. So I think we can maintain those costs.

You guys talked about, kind of, sticking within your drilling completion CapEx budget deferring some completions, you dropped three rigs, you guys have estimates of what you think your CapEx is going to be in the drilling completion side in the third quarter and fourth quarter?

Well, we don't guide that by quarter. We just report our actual expenditures throughout the year. And as I've said, we don't see the need to raise our capital budget estimate at this time.

I guess looking at acreage purchases, it looks like you're Haynesville acreage number has held pretty steady. Are you still buying anything in the Haynesville or the Eagle Ford at this point in time? Or are you pretty content with your pretty massive positions and just working on development?

We're very content. We're generally -- Steve has got some people watching out for opportunities that are right in the path of the drilling rigs and things that would create another operated opportunity. But by and large, those opportunities are few and far between these days.

We go next to Thomas McNamara with Impala Asset Management.

This is for Dick. The reservoir optimization program, just can you talk about -- any thoughts on cume [ph] production and when you would catch up with what it would be normally, if you can, any color on that? And the press release specifically mentioned deferral of compression in the fields, can you just frame that up for us upon, if this continues to be successful?

Sure, I'll address what would be called the catch-up time on production and maybe, Floyd can address the compression side of it. It really varies by area. We've seen some areas, maybe in the 4 Bcf to 5 Bcf area of unrestricted production. We've seen our restricted wells catch up within three to six months, because the performance is so much better in those areas than the wells that were produced on a high rate. In some of the really high cume [ph] areas where the high rate wells are unrestricted wells, were already in the 8 Bcf to 10 Bcf range. It could take a year and a half to make up that production deficit. But I would also add that, kind of, within the whole framework of the reservoir optimization and effort of the operations guys are putting forth in Tulsa, we are not trying. We are in the process of specifically branding certain areas, for our choking, for our pressure and for our rate. So it's not going to be a one-size-fits-all approach across the field. And so the idea would be to, kind of, normalize that catch-up time based upon the given area. So we may be producing wells at 12 million to 15 million a day in these high rate areas on an 18 choke. In some of the 4 Bcf to 5 Bcf areas, we may be producing 6 million to 8 million a day on a tighter choke. It'll vary by area, but I think the answer to your question will be, probably, a year or a little bit less.

On the compression side, on a general sense, allies that would take our gas to our at around Virgin hundred pounds or so. So we're trying to maintain pressure within the gathering system that will overcome that line pressure. And it's quite easy to do when you have these wells to start out anywhere from 6,000 to 9,000 pounds of service pressure. So the longer that the flow grows on a wizardry, the longer that they maintain a higher pressure, and we've estimated it could postpone compression parts of the field by years. We haven't really put a fine pencil to that yet because it's early days, but it's clear that it's quite an advantage. And it will be years, with an s, to postpone the compression in general.

But therefore, is it bigger than a bread basket, so to speak, in terms of savings, potentially?

Your bread baskets might be quite large, but to us, it's huge. Compression can run, I think, $0.10 or $0.15 per MCF over the life of the field. And that becomes a huge number when you have these 5 Bcf and 10 Bcf and 20 Bcf wells. So if you postpone compression over 40% or 50%, or 60% of the reserve life of a well, you've really a created a lot of PV. It's way bigger than a bread basket.

And then just one quick clarification, is the potential well-designed savings cited in the release of $1 million, gross or net? Relative to...

To the AH [ph] growth.

Next is Brian Corales with Howard Weil. Brian Corales - Coker & Palmer: Have you all looked at, maybe, restricting wells in the Eagle Ford, or any other trends for technologies, from what you've learned from the Haynesville to the Eagle Ford?

Absolutely. We've done it from the very get-go in Black Hawk. All of our wells have been initially placed on a 12 and 64s choke. I think we bumped one of those wells up to 13 after several months, but they are still all producing anywhere on a 12 to 13 choke, showing very, very attractive decline parameters. In Hawkville, where we were kind of following the same methodology of producing those wells on a 24 for the first year of developing the field, we are now -- all the wells that we produced are completed within the last several months, have been placed anywhere from a 14 to an 18. We're kind of doing what I just described in the Haynesville, and that is what we're trying to get a plan to have a certain choke size for the higher yield areas and a certain choke size of the high dry gas areas. So that's still a work-in-progress, but I would tell you that we're very encouraged with the early results, certainly a flattening of the decline curve, both the pressure and the rate. So the answer is definitely yes, we're taking it across the board in the Eagle Ford.

Brian, Dick failed to mention one of his exciting initiatives here at the company have been to create a formal venue for technology transfer between the groups. And while we have separate operating teams, then he's on a regular basis to describe new findings and historical stuff and just, bat the ball around and see what the design engineers come up with. So I think Dick's group is going an awfully good job of making sure that those groups are up on the intricacies that each one may find out about. Brian Corales - Coker & Palmer: Could we assume, maybe that Black Hawk is going to see similar declines as Haynesville, with the restricted rate there? I mean, you're calling at 50ish percent, not the 70-plus?

I think it's too early to say that, Brian. We just now mentioned that today, the first time we really spoken to first-year declines, and there's a reason. We actually have a handful of wells that have been on for a year. So we don't want to outrun our coverage and make statements that aren't based on actual data. That's one of the reasons we've been hesitant to come out and, specifically, give any kind of range of increases in the EUR, but I do use the term significant anytime I can. And I think that conveys that it's not any significant. Anyway, we're going to wait until we make any comments about the declines, but we certainly see a diminishment in the decline with the tighter chokes and what we hope is going to be an increase from the EUR. Brian Corales - Coker & Palmer: One final one on the Eagle Ford, I mean you all done a good job staying in the infrastructure in front of drilling, and how does that stand specifically at Black Hawk and Hawkville? Are you all mostly there? I mean is infrastructure, at that stage, ahead of the drilling?

Brian, this is Steve. We're on track down there just like we were in the Haynesville. We'll have a 90-some miles of gas and condensate gathering the line in the ground in the Black Hawk area by year end. That's a large acreage position and it will spider web through the whole play, but it'll come at a centralized point. In Hawkesville, we've been putting pipes in the ground there for over a year now, and we're on track with the wells program.

Next is Ronny Eisemann with JPMorgan. Ronny Eisemann - JP Morgan Chase & Co: In the Haynesville Shale, do you still have about 2/3 of your frac jobs hedged?

No, the coverage ran out on that particular safety feature we had tried to built in. So right now, it's just -- we're getting these jobs priced as we go. Ronny Eisemann - JP Morgan Chase & Co: With maintaining the CapEx budget, how much -- is the new wellbore design factored in, in keeping the CapEx flat from previous guidance?

Well, we're anticipating some significant changes, both in the cost to complete the wells and just in running fewer rigs. That's why we have said we don't find the need to raise our capital budget at this time. The big changes would really, hopefully occur in 2011 if we can run that program all year long as opposed to partial 2010.

Next is Ron Mills with Johnson Rices. Ronald Mills - Johnson Rice & Company, L.L.C.: Just following on the slide on your Analyst Day presentation. If you've passed forward 12 months and you have your leased capture issues in the Haynesville pretty much behind you. What would you forecast in terms of above rig allocation between the Eagle Ford and Haynesville given the relative IRR curves that you provided at the Analyst Day?

Ron, it's really hard for us to predict a future in which we would just run rigs in the Black Hawk. I mean it's so good there but keep in mind, the Haynesville is a world-class play. So what we've done with that analyst day presentation, we took our capital and ran it basically roughly flat, or the rig count flat for those years, keeping mind that we have a tremendous amount of ability to change that in the Haynesville and in the Eagle Ford trend, as soon as the leased capture issues are all in hand. I think we have -- we just have to take into account our hedging, and how effective that is in protecting threshold prices, and kind of play it by year, year-by-year. We have got a lot of rigs if we chose to in the Haynesville. Right now, we don't see the need. We could drop quite a few rigs down in the Eagle Ford area if we chose to towards the end of next year. So again, there's a lot of optionality, but we're just thinking about prices at this time and the fact that these are bonafide world-class plays. They are all bigger than the breadbasket. Ronald Mills - Johnson Rice & Company, L.L.C.: I'm just curious, a little bit more activities all else being equal just at the relative prices.

I can't imagine is going away from the Haynesville. I can certainly imagine us bearing down on the Eagle Ford depending on prices. I've seen -- I can't remember, but prices a year ago were quite a bit lower for crude, I think. That have some volatility on its own. So we have to be prepared to react as things develop.

I would just add just one thing to that, or I would add one thing. we did have a decrease in Haynesville rig count by one go into 12, which is just like Floyd said, we don't really know what you're going to do and we did suppose if I decrease, but time will tell in terms of how much that actually becomes. Ronald Mills - Johnson Rice & Company, L.L.C.: Business for Mark, just in terms of clarification on your guidance, nothing's really changed, including your initial cut that is that 2010 that you provided in the analyst they.

We no reason to change any of that at this time.

We go next to Dan McSpirit with BMO Capital Markets.

Given the contemplated sale of your Fayetteville Shale properties, any thoughts on the value of trends, or Bcfe that you booked at year-end last year and 1.5 Tcfe of improved reserves that you estimate? I would give you a number except for the Steve Herod. continually outperform anything that we can dream of. You have as much knowledge of that as we do. It's vary the property basically, just have to tell you I'm a defense about it. It's not to us but it's they operated by our partner there is doing such a great job. It's growing development costs are well in line with our outlook for gas prices. So 300 of these, or 85 million a day are thereabouts should command a nice price if that's the direction we choose to go. And I think we have miles of pipe the ground there, or 110 miles of well located pipe in the ground that has some great value as well.

And then revisiting the restricted rate program in Gainesville, this ever makes sense to reverse that program? Should we ever see the day of higher commodity prices for natural gas? And what would that price be, or what price is necessary to maybe again, reverse that program? Well, we're running some sensitivities of that just here recently, and we're finding that you'll have to be faced with the real dilemma somewhere north of $6 an m if you're going to have to make a choice between PV and ultimate reserves, if you feel like you're actually impacting the ultimate reserves favorably with these back pressure on the reservoir, you might give up some of that favorable impact by going for PV. So there is a point in the price cycle when your PV is better at unrestricted rates, and that number is a little bit north of $6.

Maybe a little guidance, you spoke about 40% of NYMEX with respect to your NGL utilizations. Any guidance on NGL price utilizations here going forward?

46% to 47% in NYMEX oil for the basket of natural gas liquids that get processed down there. The capacity's there for us.

Our capacity is not a problem. We're covered well through 12 it. There's three major projects on the board. Cute running, static obviously, it's going to effect equation but by butane, as we did, natural gas liquids are staying right inline with oil, propane and methane have outside factors, seasonal factors that affect the overall pricing.

And we will take our last question from Nicholas Pope with Dahlman Rose.

The CapEx mentioned, the split for the quarter, what was the split between drilling completion and lease hold?

Leasehold in the current quarter was $100 million.

And just with the balance sheet, just looking at the current liabilities, in terms of the crude oil and natural gas capital cost, should we expect that accrual, of the capital cost to the flat point or what's driving the increase their like it used to be creeping up each quarter? When should we expect that to flatten out, or how should the model but going forward? That accrual, honestly really does get back to the timing and operations of the company, and it will be very difficult for me to kind of forecast that accrual account number. Anish Patel - Crédit Suisse AG: And then just with the acreage acquired, how much of the acreage you're acquiring is the newly sold versus I guess extension of current leases and kind of maintenance of the acreage position that you already have? You have that number?

He said very little so far on extensions or maintenance of current, or already leasehold generally speaking in the Haynesville, we been adding some number of acres that we'll are the own acres in and with a few exceptions where we are getting a whole new section. But generally speaking, we do have some optionality coming at us to make some extensions, if we choose to at a fairly reasonable price level. We just haven't programmed those in yet or we haven't seen the need to program those in.

And then just there's been a couple of questions about this already, but back to the CapEx forecast. I just want to make sure, the numbers that we're talking about, the guidance, the $1.35 billion for CapEx for the year, the $500 million for leasehold, the numbers were looking at, that's where you'll spend like at $1.2 billion at this point, is that MIDI sure out I'm looking at an apples to apples there, is that right?

If I look at that, I think that's not only right. But let me see. There was $854 million spent on drilling and completion year-to-date, and there was about $406 million that have been for the acquisitions year-to-date and then again, $100 million in the current quarter.

About $200 million and some, which are not going to required to the KinderHawk transaction. Listen, thanks, everyone for calling. If you think of something, Paul, Mark or Dick was Steve, or Joan or me and we'll try to answer, and we'll talk to you soon.

That concludes today's conference. Thank you for your participation.