Good morning. My name is Tiffany and I will be your conference operator today. At this time, I would like to welcome everyone to the fourth 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 call over to Floyd Wilson, Chairman and CEO of Petrohawk Energy. Please go ahead, sir.

Thank you, operator. 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 yesterday and posted to our website as well as our other public filings. Since Petrohawk released a detailed operational update on February 2nd, we will spend most of today’s call covering our financial results on the fourth quarter and full-year 2009 and also give you our perspective on our major plays and where we are headed for this year. Last year Petrohawk bucked a trend and we grew. We grew a lot. 2009 was year one of our multi-year development strategy in two important US shale plays. We had a robust drilling budget, an increasing rig count, and double-digit production and reserve growth. We also hedged and locked in the pricing for a substantial amount of our production for the next couple of years and realized nearly $400 million during the year from hedges put on prior to last year. I hope this doesn’t turn boring, but our plan for 2010 looks very much the same. Our program is all about NAV and generating cash to self fund the development of these valuable assets over the coming years. Looking at our balance sheet, our position at the end of the quarter was exactly where we expected it would be. We had $1.2 billion in liquidity at the end of the quarter and only around $200 million drawn on our $1.3 billion credit facility. We are executing a precise plan in 2010, which includes a lease capture development drilling program in the Haynesville Shale, a ramping up and expansion in the Eagle Ford Shale,…

: The last time that Petrohawk reported on impairment was in the first quarter of ’09. And at that time the gas price required for the impairment test was $3.63. And at the end of the year, utilizing a 12-month average gas price drive by the SEC rules, we were required to use a price of $3.87. While we did experience dramatic increase on our proved reserve bookings, there wasn’t as much of an impactful result on the PD, and that resulted in the recognition of a pretax non-cash charge of $106 million in the current quarter. As part of our year-end press release, we have published full-year 2010 guidance, and consistent with historical periods, we’ve guided on a per-Mcfe basis on all significant operational cost metrics. LOE per Mcfe continues to show a steady downward trend attributable to continued cost reduction initiatives, increases in production rates, and the divestiture of the Permian properties. The only other guidance line I’ll comment on is gathering, transportation, and other. We are guiding for an increase in this line, with the most significant contribution being made by pipeline operating expenses. We continue to push forward and ramp up Hawk Field Services. Finally, two other points to touch on regarding 10-K disclosures, and then we’ll move on to the financial results. For the first time, we have broken out Hawk Field Services into a separately disclosed midstream segment in the Form 10-K. So if you do look through MD&A in the financial statement footnotes, you can see a distinction of revenue and expense between now our E&P and our midstream segments. And then secondly, we’ve had a couple of questions that have come up on a disclosure in the 10-K. During the third quarter of last year, there were three wells that were cited…

Thanks, Mark. We included in today’s release the information that our 307 Bs of PD adds in the Haynesville Shale for the year came to us for $621 million or about $2 per Mcfe, also that our developed Haynesville wells are estimated to cume [ph] 7.1 Bcfe, and that our operated Haynesville developed wells are estimated to cume 7.5 Bcfe each. This is all very exciting and gratifying to us. And isn’t it great when your focus is useful and timely in a larger context. Home-grown American natural gas is surely significant part of the solution to important problems like dependence on foreign sources for fuel and carbon emissions. We have time for questions now, operator.

(Operator instructions) Your first question is from the line of Joe Allman from J.P. Morgan. Joe Allman – J.P. Morgan: Thank you. Good morning, everybody.

Good morning, Joe. Joe Allman – J.P. Morgan: Hey, Floyd, could you talk about the asset sales process, in particular, when do you expect the data rooms to close? And could you just give any other comments on the sales process?

Well, as we’ve put it out in the press release, Joe, we’ve got bankers hired on the three main components of this. And everything is underway and well organized. And we expect to be able to report during the first half of the year. We hope to be able to report during the first half of the year what the outcome is on all three of them. Data rooms are not specifically set to close at any given day just yet. Joe Allman – J.P. Morgan: Okay, thanks for that. And then in terms of your pilot projects, choking back the wells, could you talk about -- you gave the estimate 7 million to 10 million a day restricting the initial production. Compare that to what it would be if you didn’t restrict it on a per-well basis. And then what does that mean for full year production?

I’m going to ask Dick to join in this. I believe in the press release we said that -- we had taken that into account in production guidance that we expected to be able to manage production in such a way that the group of wells would produce about the same amount as they would have under full production with a larger choke. Dick?

Yes, that’s exactly right. We’ve run some time versus cume, plots that suggest that plus or minus 300 days, they produced about the same volumes of gas regardless of whether they produced on a restricted rate or a normal production practice. And I would say to your first part of the question, it’s variable, but yes, I think 7 million to 10 million probably equates to 15 million to 20 million or maybe a little bit more than 20 million in certain areas. But most or all of our wells average about 18 million a day. So you can kind of use that as a baseline for what our unrestricted rate program is and compare that to the 7 million to 10 million that we mentioned in the press release. Joe Allman – J.P. Morgan: Okay, that’s helpful. And then lastly, in terms of the cost in the Haynesville, so your expected average cost to drill, complete and hook-up, is it $8 million to $9 million a day? That’s the number that’s in the press release.

Right, $8 million to $9 million.

We hope that the average of all of the wells for the year, the average can get down into that range, yes. Joe Allman – J.P. Morgan: Okay, all right, helpful. Thank you.

Your next question is from the line of David Heikkinen with Tudor Pickering Holt. David Heikkinen – Tudor Pickering Holt: Good morning, guys. As you think about the Hawk Field Services and the amount of capital, a couple hundred million dollars being put in that, what type of growth in EBITDA do you think you get for that capital spend?

Well, we don’t put out EBITDA estimates, David. However, you can imagine that the way that our production has been growing that the EBITDA growth is very dramatic in Hawk Field Services to the tune of tripling or thereabouts year-over-year. David Heikkinen – Tudor Pickering Holt: Okay. And as you look at the -- on the Eagle Ford side, just kind of getting into gathering, infrastructure and the bigger development, particularly as you go in onto the oilier side, can you just talk about infrastructure needs there and kind of the path forward for 2010 and ’11?

Well, we have a very -- I think a really well thought-out plan to provide for all of our needs. And just as we did in the Haynesville, we stand ahead of the drilling rigs with our pipeline and treating design and installation. So we don’t -- we anticipate a very smooth year in terms of deliverables -- deliverabilities. David Heikkinen – Tudor Pickering Holt: Maybe what’s the split of CapEx that goes into the Eagle Ford versus the Haynesville from a midstream standpoint?

Steve is here. I think it’s about $100 million or --

85% Haynesville.

85% Haynesville and 15% or so Eagle Ford. David Heikkinen – Tudor Pickering Holt: All right. Thank you.

Your next question is from the line of Leo Mariani from RBC. Leo Mariani – RBC: Hey, guys. Just kind of expanding a little bit on the Eagle Ford here, do you folks have any kind of estimate at this point based on your drilling Hawkville Field, sort of how much of your acreage do you think is in the dry gas window and how much of it is going to be in the condensate window, any kind of rough percentages on that?

It’s still early, Leo. Particularly on the Northeast end of the field, we are drilling our first well in the Swift joint venture area, which will provide a good data point for that answer. I would say that probably 65% is probably dry gas based on our current interpretation, something along those lines. Leo Mariani – RBC: Okay. Jumping over to your Red Hawk Field there in the Eagle Ford, I know you folks said that -- you seem excited about it at this point. You drilled the well, you’re still kind of waiting on fracking over there. Just curious as to what about the geology over there at Red Hawk that’s got you guys excited and whether or not there is any other well control in the area that you’re looking at?

Geologically, the rocks are very, very similar to what we see in Hawkville, but just a little bit thinner. So in terms of petrophysical properties and the things that you want to see in the rock, we are very encouraged. The biggest issue is the perm to oil. This is not condensate -- gas condensate. It’s most likely oil. So that’s what we need to learn as to what kind of rates we can get out of these rocks. But based upon the quality of the rock, I think we have a good chance of having commercial production. Leo Mariani – RBC: Okay. Jumping back over to your Hawk Field Services here, I’m just trying to kind of decipher some of the numbers you reported here with 4Q. Are all these numbers that you’ve kind of reported, you’ve got some revenues and you’ve got some expenses, is that third-party, is that including the inter-company, and kind of how some of the allocations work if it doesn’t include some the inter-company? Was that your effect on realized prices or LOE? Just trying to kind of work through those numbers.

Okay. Probably the best thing for you to do is, if you will direct your attention at I believe it’s right around Page 100 where we have our segment disclosure, we broke out the midstream operations, and you can see the breakout of revenues between inter-company revenues and third-party revenues, and then you can also see gathering, DD&A, G&A, interest, et cetera, all detailed out. And there is notes to accompany the disclosure. Leo Mariani – RBC: Okay. Thanks again.

Your next question is from the line of Jason Gammel with Macquarie. Jason Gammel – Macquarie: Thank you. A couple of Haynesville questions if I could. One of your competitors mentioned that they were seeing pressure pumping cost in the Haynesville up by about 50%. And I guess locking in 75% of your pressure pumping cost would be consistent with the inflation. Can you confirm that you’re seeing that type of inflation?

I don’t think it’s quite that high, Jason. It’s clearly creeping up, and creep might be an underestimate. But I don’t think 50% is an accurate number.

It’s certainly for Petrohawk. Jason Gammel – Macquarie: Okay, thanks. Obviously, the drilling time has come down pretty significantly over the course of the last year. Can you talk about what the average spud to sales time is for your wells in the Haynesville at this point?

Well, from rig release to sales is typically averaging about three weeks in maybe some of the more challenging areas with pipeline construction. It might be a hair more, but I’d say we are in that 40 to 45 days spud to spud and add another three, maybe four weeks on top of that on the outside for sales. Jason Gammel – Macquarie: Okay, thanks. Very helpful. And then maybe just one more, if I could, on the Eagle Ford, you were talking about the factor [ph] being 1.5 or maybe even a little bit higher than that. Would that be fairly consistent with the first year decline of 61%, 62%?

Tina, little higher than that?

Little higher than that, about 75 to --

Yes. We’re just seeing -- once we do see that curve break over, it’s really flattening out. And I think that’s the real driver to that what we think is a potential bump in the reserves. I think it’s one of the most positive things we’ve seen out this year. Like everything about it, but the fact that the reserve estimates continue to seem to creep up is very, very positive. Jason Gammel – Macquarie: Absolutely. Okay, thanks a lot, guys.

Your next question is from the line of Brian Corales with Howard Weil. Brian Corales – Howard Weil: Good morning, guys. Just a quick question on the restricted flow rate wells in the Haynesville, you did mention there were similar EURs, first year EURs as a normal flow rate well. Would that imply almost a pretty flat decline curve or really not much decline in the first year?

Yes, there is a decline rate. It’s not flat. I think we’ve had maybe one of those test wells that Floyd referenced that I would say that’s darn near flat through the four, five months that we’ve seen it. But certainly over the period of a year we see a decline rate, but considerably less than obviously the normal production practices. So it really catches up to that either rate versus cume or cume versus time slot. So that’s the most encouraging thing that in a fairly short period of time we are seeing kind of a neutral production effect. Brian Corales – Howard Weil: And ultimately, you can you all maybe estimate in terms of what that potentially could add in EURs?

I think it’s too early. We’ve got some estimates, but I don’t think they are something we need to talk about. But it’s just intuitively -- I won’t say obvious, but it certainly appears though when these wells cross over and are producing at a higher rate at the same cume that you should expect a higher ultimate recovery but how much is yet to be determined. Brian Corales – Howard Weil: And just one final just on the same topic, what is the longest most production history we have with the restricted rate wells?

One, I think, was the first well that we did. So what’s that -- seven, almost eight months? Brian Corales – Howard Weil: Okay. All right, thanks, guys.

Your next question is from the line of Ron Mills with Johnson Rice. Ron Mills – Johnson Rice: Just to follow up on the restricted rate wells. In -- you talked about testing in certain areas, how much of you all’s acreage do you think you will apply the restricted rate wells or are there particular areas where you’re not going to test it or just what’s some of the thought process going forward?

I think the wide answer there is an area that I would say in the very best part of the field where we are seeing EURs that are approaching and sometimes in excess of 15 Bcf. They just don’t make sense. These wells don’t decline that hard. Precious stays quite high. So when those areas where I think we just have been inherently better porosity and permeability that it doesn’t make sense. But then maybe 80% of the balance of the field, just to throw a number out, might be a good practice. But again, keep in mind, it’s way, way early to do much projection on that. Ron Mills – Johnson Rice: Okay. And you all talked about that being included in your 2010 guidance to the extent you all start expanding the employment of other restricted rates. Then how does that impact your longer term growth goals?

Ron, I -- the really interesting thing about this program is we don’t think it impacts it in the least, will be watching it like hawks, if you will, but we don’t think it will have any impact in the long run and we’ll certainly be in a position to adjust things accordingly if that seems like it would. But right now it’s -- there are some other kind of intangible things going on here. Let’s say, it’s a whole different style of company-wide or Haynesville-wide for Petrohawk production decline. There is much more stable and projectable and if we achieve the same kind of PV in a timeframe it’s an awesome tool for production management and reservoir management and a good way to test all kinds of issues that could arise in a new place. So it’s really an interesting situation. Ron Mills – Johnson Rice: Agreed. And then finally, just could you all talk a little bit about San Augustine and Nacogdoches County, what’s your current activity level is there? I know you have 17 Haynesville rigs. How many are in that Southwest extension number play in where are you on your drilling there?

There are no operator rigs there now. Like Floyd mentioned in the prepared remarks, he was commenting on JV partnerships we have in that area. Noble, EOG, to name a few. So that’s where most of our activity level is. It’s not insignificant. We have fairly sizable interest in those JVs, but we are not operator. Ron Mills – Johnson Rice: And is that with your operations with those JV partners? Is that where you are going to likely see more of your early Bossier results versus Louisiana just due to the (inaudible) in Louisiana do you think?

Yes. I think more just -- that's really good rock in the Bossier down in that Shelby and Nacogdoches extension. Really the only reason we have in operating a well in a Bossier yet and complete a well Bossier yet is simply that Hawk Field Services is in the process of getting tied to that far this up, part of the field that we call the Whitney area, which we think is the optimum place to test the Bossier for our particular acreage block. So -- but you are right. We are going to get more exposure to the Bossier through our non-operated partners, large, small and in between. That whole area is getting a lot of activity. Ron Mills – Johnson Rice: All right, great. Thanks, guys.

Your next question is from the line of Dan McSpirit with BMO Capital Markets Dan McSpirit – BMO Capital Markets: Folks, good morning and thank you for taking my questions. After you go about the sale of a portion of your midstream business in the Haynesville, what should we be thinking about those assets going forward? Is there an MLP in the future at all? And would you use that as a vehicle to maybe drop down more, more assets?

Dan, it’s hard to say there is certainly one attractive alternative, given the way that the MLP businesses rebounded since the very bottom of the recession. I would say that our intention is to maintain the operational control of those assets until the bulk of the systems are built out. And then we will consider all the various alternatives at some point in the future, whether it’s an MLP or additional sale of those types of assets that’s really the business -- kind of business that we developed in a two-year timeframe, and it’s really interesting how valuable that’s become even though the ethnic [ph] profile of it is quite different from the Haynesville wells that we drill. So when you have a disparity investment profile like that, you tend to think of what’s the right kind of asset to own. And at this time, though, it’s all about getting the infrastructure built out within the field. Dan McSpirit – BMO Capital Markets: Got it, okay. And then sticking in the Haynesville -- or to the Haynesville, can you remind us again the development spacing assumption behind your reserve bookings in the Haynesville in 2009, and what you might test in terms of density in 2010, and whether or not any of these restricted rate areas will have an impact on spacing going forward?

On the bookings, we were given 160 acres per location. So we think that has a lot of conservatism built into it in terms of the actual reserves within a given area that we actually book. Our belief hasn’t changed. It’s still we think about 80 acres, but I’d say the main reason it hasn’t changed is kind of related to your second part of your question is, we really haven’t had the luxury of fully developing a section yet. We are -- there is one area where by virtue of some offset development by one of our peers and some development of our -- we are going to have some information through 2010, not as much as we would like, but we do know that Exco has plans to develop a section. I know EOG is actively developing an area in our Nacogdoches County area. So through the balance of ’10, whether it be some of our, what I’d say, kind of partial development and then some of our partners and peers. I think we’ll know a lot more by the end of the year, but it’s just still hard to say right now that we’re just sticking to 80 because it seems to be right based upon gas inflation or recoveries, but it’s still a hard answer. Dan McSpirit – BMO Capital Markets: Got it.

Dan, on the restricted rate part of your question, that could have some really interesting implications for future development of these sections where you are maintaining a much higher reservoir pressure throughout our part of the field and kind of an orderly withdrawal. It’s really a value equation that we are thinking about quite all the time. Dan McSpirit – BMO Capital Markets: Understand, understand. And then in today’s press release, you highlighted the difference in recoveries per location of those wells that you operated versus that was the averaging in 2009 in terms of your reserve bookings. What explains or what drives that delta, that difference? Is it more a function of the rock as it is the operator?

You mean, did we just lucky? Dan, it’s a combination of things. Of course, we have some wells that we drill that don’t meet that high. We have some wells that are much higher, and it follows through with our non-operating partners. We are fortunate to be in a great part of the real estate there with much of our land. And that part is really good for us. I think that early execution results from Petrohawk were perhaps as good or better than most in the field. And now that we are all sharing data, I think many operators will continue to catch up or do well. There have been some great wells drilled by other people that we are partners in. And keep in mind that the non-operated wells that we are partners in, we generally are only going to own 15% or 20% or 30% of those wells as opposed to 80% or 90% or 100% of our operated wells. Dan McSpirit – BMO Capital Markets: Right. Okay. And then lastly here, quickly turning to the Eagle Ford, you mentioned that your plans to lease were still ongoing. Can you comment at all what’s available, what should we expect in 2010 in terms of leasehold increase? And then on seismic, what’s covered today and what’s -- what will be covered by the end of 2010?

I think we’ve got about 100 squares of 3D in hand and we are shooting another 300 or 350 -- 350 squares during the year. Some of these (inaudible) our own and some are with (inaudible) I think.

We are actually the primary underwriter of that whole 450 [ph] miles. That will cover the whole Hawkville Field. And by year-end, that should be pretty much done. Really in terms of additional acreage, I think my answer would be that in Hawkville there is very little. We’ve been active in expanding the play to the northeast. We saw an opportunity there, and I think we took it. We’re looking at various parts of the play. There is just more information coming out daily that is getting us interested in other areas that initially we weren’t sure are going to be commercial. So I think as we learn more, we may add a little bit more, but not aggressively.

Dan, the parallel would be what we did last year, we did our big leasing push in the Haynesville in 2008 and we did a lot of what I call mop-up in what have become defined as the core part of the field in 2009. We are essentially finished with that now. There is a few little odds and ends to mop up, but we have so much. We don’t feel driven to add anything that’s just really strategic to our current -- our near-term drilling plans and that the value equation is there. We just got so much on hand in both fields. Dan McSpirit – BMO Capital Markets: Very good. Thank you again.

Your next question is from the line of Chris Pikul from Morgan Keegan. Chris Pikul – Morgan Keegan: Hey, thank you. Floyd, I think the strong reserve report and growth profile we’ve seen speaks for itself as far as the asset quality that you guys have. But from a funding perspective, could you give us a sense of generally how you expect to fund the Haynesville through 2011 and beyond within the context of how aggressive you’re going to have to be on the drilling side to keep leases next year, as well as any CapEx implications of a midstream transaction? And then finally, what other assets do you view in your portfolio as candidates to perhaps raise additional funds?

Chris, we made know -- we haven’t shy about telling people exactly how we expect to fund. 2010, 2011 is a combination of cash flow and current liquidity and then aided by the proceeds by these divestitures. And we are still totally on track with that estimation in that plan. And I repeatedly said, we have no need to go to the equity markets. I think that the implications on CapEx with the sale of partial interest in Hawk Field Services in the Haynesville would be that at some point in the year Petrohawk would no longer need to fund those directly. The entity would have its own ability to fund. So I think that you might actually see a decrease in needs from mothership, if you will. Beyond that, we have -- we've spent the last few years really converting our asset base from some really good albeit mature assets that were fairly developed in cycling that cash into acreage and drilling in these great -- in these two or three great shale plays. We do get asked about the Fayetteville, and we would sell it that we don’t have a need to sell it. And it’s a great field, and we’re kind of on cruise control there with our really good partners out there doing heavy-lifting last year and this year with all the acreage being HBP held by production. So we don’t have any real need to do anything there. I don’t know if that helps with your question. I hope it does. Chris Pikul – Morgan Keegan: Yes. Have you bracketed what you think some of these three packages may bring in the door as far as cash goes?

Yes. We told everybody that our target was $1 billion or more during the course of these divestitures, and we see no reason to change that target, certainly not lower. Chris Pikul – Morgan Keegan: So if we anticipate similar levels of spending in 2011, obviously there is going to be a higher cash flow component and then again borrowing under the revolver in additional asset sales, where you’re leading us?

No, I don’t know that we will have -- we have no need for additional asset sales beyond what we’ve targeted here for 2010. Keep in mind, we have a -- our production profile yields a pretty nice revenue stream as well. So I think between current liquidity and by divestitures and cash flow that we’ll be in pretty good shape. And that’s my estimation, of course. Chris Pikul – Morgan Keegan: Great. Thank you for taking my question, Floyd.

Your next question is from the line of Michael Hall with Wells Fargo. Michael Hall – Wells Fargo: Thanks. Good morning. Just a quick question on Eagle Ford or a couple, I guess. Have you done any work looking at any potential issues surrounding retrograde and the higher condensate window?

We’ve certainly studied it and observed our well performance to see if we had anything that would be a retrograde condensate issue. I think in terms of what we’ve observed, we’ve just observed our wells to be getting better and better with time, just the opposite of what you might expect if there was any kind of a permeability degradation due to the dropout of condensate. So we’ve studied it. We’ve looked at a lot of papers, STE [ph] papers, other various trade journals. There seems to be a consensus in the community that reservoirs with this permeability, particularly when they drill horizontally, do not exhibit a retrograde condensate issue. So while we’ve got our eye on it, we’re not going to take our eye off of it. Everything suggests that it’s not an issue. Michael Hall – Wells Fargo: Okay, great. That’s helpful. Thanks. And then on the B-factor, is there any variability in what you're seeing along those lines with the dry gas portion of Hawkville versus the higher condensate or any meaningful difference in the shape of the decline curves there?

Not really. Again, they both -- what we did I think most importantly, as we got these wells tubed up, meaning we ran our tubing stream, the wells that were able to unload themselves much more efficiently. And I think that as much as anything has shown us to have a change in the slope of the curve. So it’s kind of a combination of reservoir performance and operational efficiencies and just field common practices that have kind of resulted in the -- and I think a change in the curve. I think we’re going to do everything we can to get these wells tubed up early in their life and hopefully see the break-over in the curves even earlier. But again, it’s all early time. We’ve only been producing for a little over a year now, and we are learning that we just really are very, very enthusiastic about the way the curves are breaking over. Michael Hall – Wells Fargo: Okay. Great, that's helpful. And then just on a more housekeeping item, the transport guidance -- transportation guidance, does that include the midstream expense that was reported and broken out this quarter?

Yes, that guidance is an all-in number for both E&P and HFS. Michael Hall – Wells Fargo: Okay. And then any guidance on the revenue line then?

No, we haven’t typically given data from the revenue line item and didn’t anticipate doing so (inaudible). Michael Hall – Wells Fargo: Okay. That’s all I’ve got. Thanks very much.

Your next question is from the line of Nicholas Pope with Dahlman Rose. Nicholas Pope – Dahlman Rose: Good morning, guys.

Good morning. Nicholas Pope – Dahlman Rose: Quick question -- you made the comment earlier on some of the issues with the permitting in the Haynesville, and I was trying to get a little clarification. Just reading in the 10-K, it read like there was two items. I guess one related to more discharge and then one related to permitting. I was just trying to get a little clarification on kind of what the difference is, if there is any. And I just see with the EPA getting involved versus the Army Corps of Engineers if there's anything that we should be concerned about there?

I think the last part of your question is, no, there is nothing that we feel like we need to be concerned about. We’ve reacted to all of the issues. We’re being much more -- being very proactive in getting them resolved and going forward with proper practices. So I don’t see any issues. Nicholas Pope – Dahlman Rose: All right. That’s very helpful. Thank you.

Just to clarify, there is no environmental. We’re only concerned with the permitted process here. So I think you may have mentioned the word discharge or something like that on your question. Yes, it’s more of a permitting problem.

Yes, we did mention Endangered Species Act, Clean Water Act violation in Arkansas. We’ve put that in our filings for the last few quarters, and that may be what you’re referring to as far as a discharge. That’s also (inaudible) towards the resolution of that item. Nicholas Pope – Dahlman Rose: Okay. The comment in the K talks about the discharges in Bossier, Kado and Red River. That's why. And I didn’t know -- that must be the wording of the permits, I guess. I think that makes sense.

Your next question is from the line of Steve Berman with Pritchard Capital Partners. Steve Berman – Pritchard Capital Partners: I think maybe a follow-up to the last question. The $17.8 million of accruals, Mark, I don’t know if you went into detail on that one when you were speaking, but is that for the permit issue or is that covering a bunch of other things as it’s laid out in your legal proceedings section in the 10-K?

Yes. The accruals that were included in G&A in the fourth quarter were related to two separate lawsuits. And there was a third much smaller one, but there were two that made up the majority of that number, neither of which were related to the permitting topic. We do not currently have anything that we’ve accrued related to any other permitting. Clearly we believe there is the possibility of some type of fines at some point, but we don’t expect them to be material. When you’re making disclosures in the front part of the K, there is an SEC rule that hasn’t very low level materiality. I think it might be around $100,000 or something of that nature. So we did feel it was appropriate to put this in, but we’re not expecting any type of significant amounts that have to be expended based on it. Steve Berman – Pritchard Capital Partners: The $17.8 million you feel covers whatever these legal issues are and the guidance going forward for G&A seems to be kind of a more normal level.

Yes, that’s correct. And that $17.8 million, for the most part, does refer that actual agreed-to settlements. So we wouldn’t really anticipate much movement in that --

: Steve Berman – Pritchard Capital Partners: Okay, great. That’s it for me. Thank you.

Okay.

Your next question is from the line of Subash Chandra with Jeffries & Company. Eli Kantor – Jefferies & Company: Hi, this is Eli Kantor in for Subash. Have you guys come across any buzz or reports on the terms of the Eagle Ford JV between BP and Lewis Exploration?

Well, we’ve heard rumors like everyone else has. I don’t think we need to comment on it. Eli Kantor – Jefferies & Company: Okay. And then just going back to the Fayetteville investigation that’s disclosed in the 10-K, will that have any kind of impact on the midstream sale?

No, it won't. The Midstream assets that are involved in the JV don't include the Fayetteville, but once again, that matter, we're hopeful will be concluded here rather shortly. Eli Kantor – Jefferies & Company: Okay, great. Thank you.

Your next question is from the line of Marshall Carver from Capital One. Marshall Carver – Capital One: Yes. A question on the shape of your production growth profile this year. From third quarter to fourth quarter of ‘09, you had the growth plus $80 million a day. The guidance for 1Q is only up about $20 million a day from the fourth quarter. Is that -- is there a shift in well timing or what do you think changes that growth profile or do you think it's just conservatism or does it have something to do with the Boardwalk pipeline in Fayetteville? Just if you could give a little color there, that would be helpful.

It has nothing to do with the Boardwalk pipeline. It’s just our estimation of the -- when we get these wells completed and get them on and so on, it’s -- when we start out a new year, as we started out last year, we always start with what we think is the reasonable estimation. And as we advance through the course of the year, we will make adjustments to that number if it becomes apparent that we should. It’s -- we had a big quarter between the third and the fourth quarter. I recall we put on quite a few newer wells. And then of course we are doing this restricted rate program in 2010 on more wells. And as we’ve reported, that has sort of in a year timeframe, our estimation is that has sort of a front end impact with little impact through the whole course of the year. Marshall Carver – Capital One: Right. What percentage of your wells in the Haynesville do you plan on doing on the restricted chokes, or what number of wells?

No, we said we would do more wells restricted than not in 2010. I think our plan is to drill about 115 or so -- or 120 operated wells. So 50, 60, 70 of those are going to be on restricted rate at least. Over time, as this continues to work, as Dick pointed out, 75% or 80% of everything we do, our plan would be to shift over to that, but we are not -- it's still early to go quite that far just yet. Marshall Carver – Capital One: Okay, that’s helpful. Thank you.

There are no further questions at this time. I would now like to turn the call back over to Floyd Wilson for any closing remarks.

Well, thanks for calling in, everyone, and we’ll report further as the year gets along. Bye.