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Petrohawk Energy Corp. (NYSE:HK)

Q3 2009 Earnings Call

November 5, 2009 10:30 a.m. ET

Executives

Floyd Wilson - Chairman and CEO

Mark Mize - EVP, CFO and Treasurer

Dick Stoneburner - President

Steve Herod - EVP, Corporate Development

Analysts

Jason Gammel - Macquarie

David Heikkinen - Tudor Pickering

Joe Allman - JPMorgan

Subash Chandra - Jefferies & Company

Leo Mariani - RBC Capital Markets

Ron Mills - Johnson Rice

Ben Dell - Bernstein

Marshall Carver - CapitalOne

Chris Pikul - Morgan Keegan

Operator

Good morning, my name is Amanda and I will be your conference operator today. At this time I would like to welcome everyone to the Petrohawk Energy Third 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. Mr. Wilson, you may begin the conference.

Floyd Wilson

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 this disclaimer, see our press release issued yesterday and posted to our website as well as our other public filings. Well, we had a pretty good quarter; production came in well over guidance, in spite of $7 million equivalents per day in curtailments.

Our hedges and high price utilizations gave us the boosts we needed to help, to keep cash flow up, although natural gas prices were quite low. All in all we had the kind of quarter we should have with our high quality assets and our industry-leading operational execution.

This quarter marks the one-year anniversary of the financial crisis we all experienced last fall. On October 1, 2008 Petrohawk lowered its 2008 capital budget from $1.5 billion to $1.5 billion as we and others retrenched the global financial meltdown. At that time we controlled about 300,000 net acres in the Haynesville 150, in the Fayetteville, and it just announced the discovery of the Eagle Ford Shale play in South Texas.

We spent $1.1 billion in 2008 and we're expecting to spend about the same in 2009 even though our assets and opportunities have grown to include larger positions in the Eagle Ford and Haynesville shale and an exciting view of our Bossier shale potential Northwest Louisiana and East Texas.

For 2010, we have set our budget at $1.45 billion, almost to the level of our original 2008 budget. A level we have determined to be appropriate for our opportunities at this time. A year ago we spoke to the market about the flexibility that our assets provide and this flexibility has shown itself to be important this year.

Even with a reduced budget, we were able to accomplish what we needed to, in order to stay on track with our leasehold caps in the Haynesville shale and to grow production at a healthy rate. We were able to grow the Fayetteville production despite a major reduction in our operated rig count.

We were able to de-risk our Eagle Ford position through drilling and expand our lease hold in both the Eagle Ford and Haynesville at reasonable prices. Our operations have become even more efficient, drilling costs have come down and lower operating costs have kept margins healthy, during the time when natural gas prices leave a lot to be desired.

Our production in cash flow growth, hedging and liquidity have collectively put us in a great position to march forward. And we are marching. Our development and drilling programs in our core shale place have outperformed our expansion in the Haynesville and Eagle Ford has been collectively executed by the land team and our geoscience professionals. And we have developed new and better ways of analyzing the explosion of data now available in both of these areas.

To these plays we now have the Bossier shale, which today we quantify as perspective in approximately 122,000 net acres of our existing acreage position Northwest Louisiana and East Texas. Amounting to an additional 4.1 Tcfe in risk, resource potential net to Petrohawk.

Our drilling program and our gathering business together are driving the conversion of Petrohawk's resource potential, now topping 30 Tcfe towards proved value. Production growth drives this conversion and with today's announcement we are on track to grow production 75% over last year and we have set 2010 guidance at 43% over this year.

These production rates are made possible through operational advancements that will be covered by President Stone burner, who by the way is a year older and wiser today, and this performance is supported by our midstream business charged with keeping up with the growth created by our drilling program.

Our activities over the coming years will continue to reveal the tremendous value and growth embedded in these world-class assets. And we continue to streamline these assets we were concentrated before and we are about to become even more so. With the sale of our Permian Basin Properties, we have completed the latest in the series of transactions, the proceeds from which are designed to be redeployed into our higher return high growth shale plays.

We expect divestiture proceeds in 2010 to come to at least $1 billion. We have a highly seasoned A&D team with a track record for getting to the goal line and making the extra point. These actions should clearly confirm that our development plan does not require additional equity. I'll turn the call over to Mark Mize now for a review of our financial results.

Mark Mize

Okay. Thank you, Floyd. As Floyd had already stated the company did experience another good quarter plus operational hand from a financial perspective, before I speak to the results of the operations I'll touch on the credit facility re-determination as well as our liquidity position at the end of the quarter.

This past month we did enter in to the fourth amendment of our senior evolving credit agreement, our goal was to increase our borrowing base from $950 million to $1.5 billion, which does represent an almost 60% increase and we ended up with an oversubscribed syndication. As we said today we would have a $2 billion facility with a borrowing base to $1.3 billion and that does represent the $1.5 borrowing base that we had when we closed the deal less $200 million reduction associated with the sell of the Permian properties.

We were pleased to have some new banks come into the facility in a meaningful way as well as have some of the banks that were already in the facility move up to a top tier position. Out of the 18 banks that we now have in our credit agreement, about half of those do represent three quarters of the commitments. And the borrowing base for the first time does include a component of credit extended the Hawk Field Services in the amount of $300 million and that does become available to the company based on 3.5 times midstream EBITDA and it's automatically re-determined on a quarterly basis.

As of September 30, we had liquidity of just over $1.1 billion and that's a position that has been further enhanced by the increase in the borrowing base but again occurred in October, as well as the divestiture of the Permian properties that closed last week.

Turning to the third quarter results of operations, we finished the third quarter with a net debt to total capital ratio excluding the impact of the first quarter full cost for impairment of approximately 30% and as reported we're right at 40%.

Our production came in over the high end of guidance of $512 million a day with 95% of that production being natural gas. As stated in the press release and mentioned by Floyd, the 2009 budget was increased slightly to $1.1 billion and if you look at the cash flow statement, you'll see that we are sitting at $1.2 billion, growing gas expenditures.

However, if you remove the numbers of the leasehold acquisitions and the impact of the capital accrual, that will yield a year-to-date capital spent for the 2009 budget of about $850 million. Natural gas price realizations excluding the impacts of hedges came in at 93% of NYMEX, which is in line with guidance and is also an improvement when compared to realizations reported earlier in the year and we did continue to maintain a robust hedge program in targets to hedge of about 70% of our anticipated production.

This past quarter we collected $108 million in hedge proceed and right at $300 million year-to-date and while we would much prefer to be paying on the contract, it has boosted our realized gas prices from $3.15 at the wellhead to $5.56.

We continue to look for opportunities to layer in callers and have currently locked in an average floor over the next few years that range from $5.60 to $7.60. Needless to say this did have an impact on the capital program. As well as to recall for re-determination that we just went through.

LOE for the third quarter came in at $0.44 per Mcfe of all this is within guidance although at a high end it does represent an almost 30% house production when compared to 2008 guidance. Additionally the divestiture of the Permian properties will be fully baked into this metric in the first quarter of 2010 and that will further improve the overall LOE.

Taxes on division income came in at $0.32 per Mcfe which is a few pennies under the low end of guidance that has increased from $0.29 in the second quarter and that's purely driven by the increase in Louisiana severance taxes which went into affect on July 1.

Gathering transportation and other came in at $0.48 per Mcfe, which is within guidance and continues to show an improvement when compared to periods reported earlier this year. The noted improvement was substantially driven by strong production rate increases but at some point offset by pipeline operating expenses.

G&A is $0.43 per Mcfe excluding the impact of non-cash stock-based comp and this is under the midpoint of guidance and a fairly dramatic result considering our 2008 full year metric of $0.56 per Mcfe. This quarter, our hedge mark-to-market came in at a non-cash loss of $113 million and we ended the quarter with a net hedge receivable $173 million.

As has always been the case the unrealized non-cash portion of this item has been removed from both selected items table that can be found in the financial tables for the press release.

Finally with regard to cash taxes, we really haven't had much of a change since the second quarter call. We still expect to incur an ANT tax liability of approximately $23 million, however, we have already received refunds on a significant amount of previously paid taxes, which will put up in a net cash payment position of around $3 million by the end of the year and our effective tax rate did come in at 38% for the quarter and my final comment on the proceeds that were brought in from the Permian divesture. 100% of those were put with a qualified intermediary and that's where they will reside until they are either reinvested into properties or the company takes them back for operational purposes. And with that I'll turn the call over the Dick.

Dick Stoneburner

Thanks Mark. As Floyd has already mentioned the third quarter provided continued outstanding results from the drilling program, which was primarily focused in the Haynesville, Eagle Ford, and Fayetteville where we drilled 92% of our wells. Today I'll update you on our operations and focus on the key areas of progress that we are making, which is resulting not only in substantially reducing costs, but also improving productivity.

In the Haynesville, the most significant improvement has been in our drilling operations. During 2008, the average spud-to-spud time was 79 days. Many of these wells had pilot holes with extensive coring and logging operations, but we clearly had room for improvement. The average during the first half of 2009 was 69 days, which was improvement but fairly modest.

However, during the third quarter we have seen remarkable improvement. The month-over-month numbers for spud-to-spud during the third quarter were 68 in June, 61 in August and 47 in September and we expect the average for 2010 to be 42 days.

There are a number of factors that have contributed to this improvement. Better understanding of targeting and the implications of the rate of penetration as it relates to targeting have been significant. We have gone through tighter curves which translate into less total footage to drill the curve.

The use of rotary steerable systems in certain applications has shown benefit as well as rotating case in the bottom. However, the most single significant factor has been the development of a PDC bit by our staff-drilling engineers that to this point has only been utilized by Petrohawk.

This bit has shown to increase the rate of penetration in the lateral dramatically. An example of the improved penetration rate is evidenced by the number of days that we have drilled more than 800 feet in a lateral.

In June and July, we only had three days with greater than 800 feet drilled. But during August and September, we had 20 of those days. More recently a 4500-foot lateral was drilled in five days and over 3200-feet of lateral was drilled in three successive days.

These improvements in our drilling operations are prominent in our forecast for drilling and completion costs for Haynesville wells in 2010 to be between $8 and $9 million. The completions in the Haynesville have also seen dramatic improvement. The average completion in January 2010 was $5.3 million, while the average in June had decreased to $3.5 million and had stayed in that range.

The majority of those savings are a result of significant decrease in the service-sector costs, but we have also been proactive in implementing fracture stimulation design changes than in some instances have lower cost and potentially increased productivity. The major changes being tested have been, one an increased sand volume by increasing the maximum sand concentration to 3 pounds per gallon and two, increased number per clusters per stage without increasing the number of perforations which is accomplished by reducing the number of holes per cluster.

Without going in to a lot of detail, the frac design changes that we have made support our theory that the best well performance is a result of contacting as much of the reservoir rock with higher volumes of high strength proppants and clear fluid at as higher rate as possible through a limited number of perforations.

We believe that these completion practices in conjunction with the majority of our drilling being located where the highest quality reservoir rock is present, have contributed to the exceptional results that we have been achieving. Those results are best evidenced by the production growth that we have achieved in a very short period of time.

Petrohawk has averaged operating 11 rigs during the year, has a total of 62 wells on production, at a gross operated rate of 450 million cubic feet a day and total net operated production of 285 million cubic feet per day. As evidenced to the consistency of these wells the average production during the first 30 days for the 53 wells that have at least 30 days of production is 14 million cubic feet per day.

In 2010 we expect to average 16 operated rigs, which will drill another 110 to 115 wells. We have continued to selectively lease acreage in the most respective areas of the play. During the first three quarters of 2009 we have added 36,000 net acres in North Louisiana, 17,000 net acres in East Texas, bringing our total net acres count to 343,000 acres.

The acreage acquired in North Louisiana has been virtually entirely in what we have defined as the tier 1 area of the play where we have been having the most success. The acreage in Texas has been located in the Shelby Nacogdoches extension area of the play where recent well results are confirming our belief that this area has the potential to deliver similar results to what we have experienced in North Louisiana. Not only is the Haynesville proving highly perspective in this area, but the results from lower Bossier activity have been impressive as well.

We are extremely optimistic that the lower Bossier Shale has reserve potential that will prove to be quite comparable to the Haynesville. Our geologic analysis of the area which is based on an industry leading side of digital open hole logs and core data, suggests that while the petrophysical characteristics of the reservoir are slightly less impressive, than the Haynesville.

The overall net thickness in gas and plays data suggests that wells from the lower Bossier could approximate 75% of the reserve for the typical Haynesville well or 5 to 6 Tcf per well. During the first quarter of 2010 we expect to test lower Bossier on the Louisiana and Texas sides of the play.

Moving onto the Eagle Ford and Hawkville field. The field in specific and the play in general have enjoyed break out success during the quarter. Petrohawk has established the type of continuity to its well results that has effectively de-risked the vast majority of our acres position in the Hawkville field.

Additionally the industry is beginning to experience some of the same results that we have, which is adding more and more confidence that this play can have a similar impact as the other successful and more mature shale plays.

During the third quarter we drilled an additional 10 operated wells, seven of those wells have been completed with an average initial production rate of $6.7 million and 220 barrels of condensate per day.

The average initial potential from these, condensate component has increased significantly during the quarter as we have concentrated our drilling operations in the high-yield portion of the field. We currently have 16 wells on production with gross operative production of approximately 55 million cubic feet per day and 1300 barrels of condensate per day. 12 of these wells have been on production for more than 30 days and have averaged 5.3 million cubic feet per day and 110 barrels of condensate per day. All of these production volumes would be greatly enhanced when the prevailing revenue equivalency ratio is used which is currently approximately 15 to 1.

Similar to the operational advances that I spoke to in the Haynesville, there continue to be significant strides made in the drilling and completion of our wells in the Hawkville field, from a drilling perspective we continue to see the excellent spud to total depth trend that we have discussed on previous calls.

Of the nine wells drilled during the quarter that were drilled without a pilot hole the average number of days from spud to total depth was less than 19 days and the average cost of rig release was $2.3 million.

We are also working with some of our surface owners which will allow initial test wells to be drilled in opposing directions from the same pad and will also provide us the opportunity to employ pad drilling when we move into the field development phase.

The most significant improvements made in the field during the quarter were on the completion side. Of the 10 wells drilled during the quarter seven had been completed and we are fraced with 15 stage fracs. During the second quarter we had fraced 2 wells with 18 stages. We then compared these wells with the recent 15 stage completions and have concluded that the 15 stage completions performed as well as the 18 stage completions and both were considerably better than the 10 to 12 stage completions that we used initially.

Possibly even more important in this state than the change in the number of stages pumped during a fracture stimulation, is one, the concentration of profit, two, the overall volume of profit and three the rate that we pumped. The last five wells will be completed with 15 stages had maximum sand concentrations of 3 pound per gallon which is up from previous concentrations of approximately 1.5 pound per gallon.

We're also pumping 100% 40/70 profit as opposed to 40% 100 net and 60%, 40/70. The result is that on a 15-stage frac we were pumping approximately 5 million pounds of 40/70 sand. We have also increased the average rate that we pumped the frac from 70 to 80 barrels per minute to 95 or 100 barrels per minute. While it is early in an assessment of how these newer wells are performing the results today show significantly improved rates and flowing pressure from these 15 state completions with higher sand volumes and higher concentrations pumped at higher rates.

Also during the quarter we were very successful in adding acreage in the area of the field, the vast majority of the acreage is located in the Northeast end of the field, where we have added 44,000 net acres since we first announced the discovery of the field last October.

Included in this acreage count is the 13,000 acres associated, with the joint venture with Swift Energy where we will be drilling our first well prior to year-end. During 2010 we expect to operate 4.5 rigs throughout the play and drill approximately 60 wells. With that I will turn the call back over to Floyd.

Floyd Wilson

Thanks, Dick. We'll exit 2009 in great shape financially and operationally and with an even larger opportunity set before us. And our plan for 2010 will leave us in even better shape going forward operator, we have time for questions now if there are any.

Question-And-Answer Session

Operator

(Operator Instructions). We'll pause for just a moment to compile the Q&A roster. Your first question is from Jason Gammel with Macquarie.

Jason Gammel - Macquarie

Thank you. I was hoping that you might be able to translate the 2010 capital budget from dollars into number of rigs running or perhaps number of wells you expect to drill in each of the major plays?

Floyd Wilson

Is that included in our press release? We'll post that on our website later today, Jason. We do have that information readily available.

Jason Gammel - Macquarie

Okay. That's great. Maybe if I could just ask a couple of questions on the Eagle Ford then. First of all the Dimmit County acreage, you mentioned that this is oil perspective. This is really the first oil objective that you are going to be drilling in the Eagle Ford. Can you talk a little bit about the rock characteristics? Is it shallower, what type of well costs you expect to see, etcetera?

Floyd Wilson

I can't, but Dick certainly can.

Dick Stoneburner

Yeah first up its not Dimmit County we have not specifically stated where its located in the up dip portion of the play, but we feel like the rock characteristics are very, very similar to what we see in the Hawkville field area. Not quite as thick, but quality, we expect it to be comparable. The biggest question is permeability to oil, versus permeability to gas and that's what we'll have to find out as we test it. We think about $3.5 to $4 million completed well cost. And we'll drill a similar style well that we're drilling in Hawkville.

Jason Gammel - Macquarie

One more if I could, the 42 day average drilling time that you expect to see in 2010, are you hitting some limits here at the 42 days we could expect even forward prospectively past 2010 or Dick are you going to make us start measuring this in hours instead of days?

Dick Stoneburner

I appreciate the compliment we are very proud of the results we have made. I wouldn't say there's a ceiling at this point. I really can't emphasize enough the technology that's been employed by the operational group in the mid-continent. I see these penetration rates continue to improve, so as long as we continue to improve that, that directly translates in to number of days, so, you know, can we knock another 10%, off? Yeah, I think that's very feasible. More? I don't know, but we're working at it.

Operator

Your next question is from David Heikkinen with Tudor Pickering.

David Heikkinen - Tudor Pickering

Just one quick question, Dick, just wanted to clarify your comment about Dimmit County, I was just reading the press release just acquire your additional acreage and then nearly announced the oil perspective there in Dimmit County. So is that acreage not in Dimmit County? Or is not supposed to be in the press release, I guess is the?

Floyd Wilson

You know, it may be a typo and I apologize for that. We're still adding a little bit to the position, there, David, so we're if its in there, it's a typo.

David Heikkinen - Tudor Pickering

Okay. And as you think about the Eagle Ford more back to Hawkville field, then and the liquids yield, can you talk about the uplift in MPV that you see for a dry gas well that you have drilled in Eagle Ford, and now the were you concentrating your 4.5 rigs there next year, into this more liquid rich trend. How does that translate as you set the strip?

Dick Stoneburner

I don't want to diminish the value of the dry gas wells, because they are performing very, very well. But you are right when you look at the revenue equivalency of 1200 BTU gas and 15 to 1 revenue equivalent ratio these days, I've run the math before, and one Mcf in a dry gas well is approximately 2 Mcf in a 50 barrels per million well. I think it's intuitively obvious that we're going to get an uplift, the exact detail of that uplift is, you know, it's hard to speculate exactly what that might be.

David Heikkinen - Tudor Pickering

Okay. And as you think then into next year, with your production targets, can you talk about how much liquids you think you would be able to produce from the Eagle Ford then?

Dick Stoneburner

Well, we're going to still, we're not going to solely concentrate on the Northeast end of the field, so I think the projection of those liquids right now is probably too early to say, but we're seeing dramatic growth in liquid component. So I think it's just going to have to bear itself out. We will continue to accelerate development in the play as I mentioned we're going to an average of 4.5 rigs next year from 2 rigs currently. And we're not exactly sure what the North East of the play holds, it looks like based upon the pioneer results that we're going to continue to have high yield wells as we move Northeast and if that's the case, then we're going to have a significant uplift in the overall liquids we produce.

David Heikkinen - Tudor Pickering

I guess are there I am not going to try to pad on those liquids? Are there any processing constraints or take away constraints, weathered for those volumes?

Floyd Wilson

We don't anticipate any. We're certainly working through those in advance of capacity estimates that we have and we don't anticipate to have any constraints.

David Heikkinen - Tudor Pickering

Is Hawkville services going to be building any processing plants is that part of the CapEx or can you split that out in the $250 million of CapEx for Hawkville?

Floyd Wilson

We haven't split it out publicly but there certainly is space in that budget for trading. There is a certain amount of CO2 down there and for some sort of low tech liquids recovery.

Operator

Your next question is from Joe Allman with JPMorgan.

Joe Allman - JPMorgan

Just a clarification, the $1 billion in potential asset sales, is that over and above the Permian Basin asset sale?

Floyd Wilson

Yes, it is.

Joe Allman - JPMorgan

Okay. And is that an amount of money that you actually expect to receive in 2010? Did you say that earlier, Floyd?

Floyd Wilson

Yes, I did. And yes, we do.

Joe Allman - JPMorgan

Okay. Helpful. And what's your interest in growing bigger position in the Haynesville, Eagle Ford, and Fayetteville? Is it limited to the $100 to $300 million of leasehold you expect to spend per year or what is the possibility that you might actually try to grow even more than that in those areas or some other areas?

Floyd Wilson

Well, our focus today is down at the Eagle Ford and the Haynesville in terms of the growth. There's not a lot of leasehold available, so that's our best estimate of what we think we can do based on the recent, several months of activity. We would like to continue to grow, but I have to point out that it's highly selective. It's not a shotgun style. We have got to spend the bore with a scope and we're really looking at very specific acreage right in the middle of the field.

Joe Allman - JPMorgan

Okay. That's helpful and then what is your interest in growing outside of these three core areas? Are you pretty actively looking at some new things, looking at more oily stuff or could you help us with that?

Floyd Wilson

Well, we don't talk about that. We're very interested in the developments that these new applications and newer technologies have allowed, companies like Petrohawk to make very economic, investments in areas, but we're always interested in what's going on around the country for sure.

Joe Allman - JPMorgan

Okay. That's helpful. And then lastly, in terms of Hawkfield services, if you are interested in monetizing some of that, would you limit that to selling 50% of Hawkfield services?

Floyd Wilson

It's highly unlikely we would sell more than 50 and it's even conceivable that we would sell less than 50, but 50 is sort of a nominal target, 49% or whatever.

Operator

Your next question is from Subash Chandra with Jefferies & Company.

Subash Chandra - Jefferies & Company

Yes hi, Floyd or Dick, I was curious in McMullen County in this last quarter, other than the wells that was in your latest presentation, if any were brought on and what type of IPs you might have experienced.

Dick Stoneburner

Well we are not talking about specific well performance but we're seeing some very, very good wells in that part of the field, we're seeing liquid ratios approaching 100 barrels per million, so as we move up to the Northeast, we're seeing the same sort of results we were seeing throughout the play on an equivalency basis, so just higher yield. I think we had one well that actually had about 120 barrels per million.

Subash Chandra - Jefferies & Company

How many McMullen County wells did you bring on this quarter?

Dick Stoneburner

I don't have that at my fingertips. You know, we drilled 10 and completed seven, some number of them, I'm not really sure.

Floyd Wilson

Probably about half.

Subash Chandra - Jefferies & Company

Yeah. So I guess Joe asked the question, you know, ask it may be a bit more precisely on additional plans on the Eagle Ford, but in the budget that you put fort, you know, stuff like pioneer expiration company, I think Conoco got a deal done. A lot of acreage up there for JV/sale. Are we talking about a desire to sort of expand in the Eagle Ford specifically?

Floyd Wilson

Well, having discovered the entire play, we're quite interested in all of the activities that are occurring out there. We're very, almost supernaturally focused on our original prospect area at Hawkville field and trying to fill in what little is available there. We are with interest reviewing what some of these other great companies are doing down here, and we are looking for add-on opportunities.

Again, we're very selective. Most of this is occurring in the up-dip portion of the, what we call the up-dip portion of the play. And we're very selective in that too in terms of size, it has to be sufficient to be of interest and it has to have the qualities, as Dick described it, this newer prospect that we have announced similar profit, you know, similar characteristics to what we have at Hawkville itself. So, yeah, we are looking but we're very, very selective about it.

Subash Chandra - Jefferies & Company

Okay. The new production numbers for the year. You still feel comfortable that reserves will outpace the production growth?

Floyd Wilson

That, Subash has been my personal estimate, we don't really have those numbers in hand yet, but intuitively, we're having a great year in terms of both production and reserve growth and we will next year as well.

Subash Chandra - Jefferies & Company

Okay. And one final one for me, the $1 billion in asset sales, assuming it's a $1 billion, what kind of net can you get out of it? And what just sort of deducting the cost basis.

Floyd Wilson

What kind of net proceeds?

Subash Chandra - Jefferies & Company

Yes.

Floyd Wilson

Would be about $1 billion. And what was the second part of that?

Subash Chandra - Jefferies & Company

Oh, yeah, so I guess any type of basis you had you can probably defer taxes or eliminate taxes from ongoing IDCs and so on?

Floyd Wilson

Well, some of the properties have some basis and some would have very little because we have held them for a long time. We really haven't made a calculation of that just yet. As always we'll try to do things in a tact-efficient manner as we can.

Subash Chandra - Jefferies & Company

So if we think of $1 billion as a net number that would be a pretty good place to start?

Floyd Wilson

Yes, that's our target.

Operator

Your next question is from Leo Mariani with RBC Capital Markets.

Leo Mariani - RBC Capital Markets

Yeah, good morning. Question on your Hawkfield services subsidiary, just trying to get a ballpark of how much capital you guys have invested in there at this point in time.

Floyd Wilson

Mark is going to get that number. We have had a very active year in terms of running laying pipeline both in the Haynesville and Eagle Ford. What is the number, Mark? About $400 million in all areas for the year, 2009 so, that's cumulative. That would be 2008, three quarters of 2009, and a little bit in 2007.

Leo Mariani - RBC Capital Markets

Okay. All right. Also just trying to get a sense of, you know, some of the parameters around some of these other assets like WEHLU and Terryville, just curious as to what the production reserves are associated with that object in those areas, it seems like you haven't focused on in a while.

Floyd Wilson

We haven't, and it's really a great way to think about it. These are great properties, but our focus has been on the early-stage development in the Haynesville and the Eagle Ford, and these properties deserve more activities than that. We haven't really broken out the production from those as of yet. Steve Herod, our own Mr. Wolf here is going to be selling these in a way that he feels is the right way and as each one becomes known in the schedule, he'll publish some data on these things.

Leo Mariani - RBC Capital Markets

Okay. You guys talked about your acreage out there in the Haynesville area, about 120,000 acres being perspective for the Bossier here. Can you give us a little more detail how you got to that number and what type of well in geological that you are looking at?

Floyd Wilson

Yeah, I would like Dick to answer that, but I can tell you that if you can track where we are in our analysis of the Bossier Shale with where we were in the our early analysis of the Haynesville, we have 100 times more data available to us than we had back then and the data is actually exploding this year, so much data on both Haynesville and Bossier, we have a tremendous amount, our scoping of what we view as the potential for the Bossier Shale we're highly confident in. And what would you add to that Dick?

Dick Stoneburner

Yeah, the key is having that tremendous data set. I made a comment in the call that I consider industry leading and I really do. We have established relationships with every player in the field to trade data and I don't think anybody has more data some may have as many but nobody has any more than we do, and it's simple mapping project, once you get the digital data and incorporates your petrophysical assumptions into that digital data.

We can map a net isopack for the Bossier and then simply look at our acreage within what we think is the commercial limit of that isopack and that's essentially how we did it. Like Floyd said we had so much more knowledge right now with that 122,000 is pretty well high graded within our overall acreage set. So even though we are risking it fairly substantially we do feel like the acreage is pretty well confined to geologically defined area.

Leo Mariani - RBC Capital Markets

Okay. Jumping over to your Shelby, Nacogdoches area, in Haynesville, I'm curious as to how many wells you guys have drilled or participated in at this point in time? And have you seen any noticeable differences in costs there, versus what your traditional North Louisiana program is?

Dick Stoneburner

Actually its been a pleasant surprise even though its deeper we are kind of in the call it 13/5 TVD range not appreciably higher, maybe a little bit, but that will probably come down with more experience. We're a partner with EOG in that particular play we are letting them lead the public release of that data, which I suspect will be coming fairly soon. We're very pleased with the results we have had in the area. Obviously everybody has seen what Devon released the other day and numerous other companies have released information in that particular trend. It's not de-risked by any means, but its certainly having a pretty good amount of data defining where the best area is. We think it's very comparable to Northwest Louisiana.

Leo Mariani - RBC Capital Markets

Okay and roughly how many wells have you guys participated in at this point?

Dick Stoneburner

We completed one well in our JV with Noble and we completed four wells in our JV with EOG and we completed two of our own wells further to the North in the Harrison County area.

Floyd Wilson

And beyond that, we have small non-operated interest in a few other wells that, again, when we add all of this data together, it really paints a picture that the de-risking of that area, if you'll accept it, there is a boundary to it, that is quite far along.

Leo Mariani - RBC Capital Markets

Okay. And roughly how much anchorage do you guys have in that area and are you still buying?

Dick Stoneburner

We are still buying. It's highly competitive. There is not much available down there and I don't believe we have publicly broken out or holdings separately between East Texas and Northwest Louisiana yet.

Operator

Your next question is from Ron Mills with Johnson Rice.

Ron Mills - Johnson Rice

Good morning. I will just ask a couple questions I have. One on the Eagle Ford, Dick, just to clarify, the roughly $6 million a day equivalents for your 30 day average for the wells, that you have 30 days of production, is that using the 6 to 1 or the 15 to 1?

Dick Stoneburner

Well I'm sorry. Go ahead. I'm going back to my script. It depends, it's $5.3 million and 110 barrels and I will let you use. I think if you use 15 to 1 you are at about I think its $7 million a day if you use the 6 to 1 you are at about $6 million a day. So it's between 6 and 7, depending upon the ratio you use.

Ron Mills - Johnson Rice

Okay. And then from the EUR standpoint, given you have 30 days of production on a couple of dozen wells now, how are those wells tracking relative to your 5 to 6 Bcf EUR?

Dick Stoneburner

They are favorable. You know, we're very early in the curve here. We have actually just started tubing up some of our wells. We have seen a tremendous increase in productivity as we tube these wells up. As you can imagine, with this much liquid, whether it be just load water on the dry gas side or the condensate yield on the rich side, when we get tubing in these wells, we're seeing a dramatic increase. So I think a lot of the operational aspects of our analysis are coming in to play to the appoint point where, yes, we're still comfortable that that 5 to 6 Bcf range is what we're going to end up at.

Ron Mills - Johnson Rice

And in the Haynesville as you track through Shelby, Nacogdoches County, I think a lot of people are using the old Amoco well as a pretty important data point. Have you continued to as you extend your leasing in that area, focus more in towards the Southwestern portion of that expense or are you just targeting anything you can in what you have defined at that core.

Dick Stoneburner

Well, there is a number of key data points. That's obviously one, but it's not the only one. So we're just letting the data drive our decisions and it's not just the Southwest and is really everything as you wrap your way through Nacogdoches, Shelby and back in to Louisiana.

Floyd Wilson

Ron, on the map that we have published several times, it shows our view of the extension down in to that area is essentially where we're concentrating our efforts.

Ron Mills - Johnson Rice

Okay. And one last one. Just on the Bossier, you talked about some lower pressure in different rock qualities, at least based on your initial look. Given that it's thicker and the amount of net pays is probably pretty similar is there any way to break down how much of that may be pressure related versus lower porosities confirmed?

Dick Stoneburner

No and if I made a comment about a pressure differential between the Haynesville and the Bossier, I misspoke. They are only about 300 or 400 feet apart. They are essentially in the same pressure regime. It is really just a slightly higher increase in clay content therefore slightly lower gas saturation and effective porosity. But I'm only talking slightly. I mean these are still very good rocks. So it early time it's our best guess. There is not near enough production history to support where we are landing our estimate. It is mainly based on petrophysical and volumetric assumptions. And so we'll have to let time steer us in to the actual number, but the rock is good.

Ron Mills - Johnson Rice

All right. Thanks. I may have misunderstood. I appreciate it.

Operator

Your next question from Ben Dell with Bernstein.

Ben Dell - Bernstein

I just had a follow up question to one of the comments you made on the Haynesville, you said moving from 15 to 18 fracs, you hadn't seen a material improvement in flow rates. Does that suggest to you that the linear relationships you have been seeing between IPs and fracs basically tops out around 15 stages or do you believe there's something else at play?

Dick Stoneburner

Well, first off, that was in the Eagle Ford. I think you mentioned the Haynesville, but those 15 to 18 stage fracs are in the Eagle Ford. I am not exactly sure of the nature of the question but I would just tell you that we think that 18 stages produced a little bit of overkill. You never know until you try it. They are very good wells. Don't get me wrong. The 18 stage wells are excellent. We just don't think the added cost associated with those three extra stages is cost beneficial. The whole idea is to maximize present value in your completion in your drilling costs. So we think the higher concentration is over 15 stages of about slightly less than 300 feet per stage is the right recipe today. We will keep tweaking and keep playing with it. As far as IP plateau, if I'm understanding what you said, you know, I'm not sure, Floyd?

Floyd Wilson

We're trying to think of this more in the overall length the effective length of a lateral and try to get as much rock contact as we can across the whole length of that lateral. The idea if it's a 15 or 12 or 18 really has to do with how much of that lateral you really get drilled. We're trying to drill the maximum length in these areas that we can. Both technologically speaking and regulatory speaking and we are as Dick said our focus now is on stage lengths of bit less than 300 feet and shorter intervals between frac clusters, but with fewer holes per cluster, so as to get more of your frac fluid in contact with the rock face at the well bore and give you the best shot at busting the whole thing up.

Ben Dell - Bernstein

Okay. And just to tell you that from the Eagle Ford to the Haynesville, what do you think the peak number of fracs will be in the Haynesville?

Floyd Wilson

Well, again, most of this land in the Haynesville, particularly in Northwest Louisiana, our governmental section, 640 acres a mile square, there's a 330 foot standoff on each end. We drill most of these north and south or south to north, so you have about a maximum length of around 46, 4700 feet of effective frac able lateral and so that's sort of the limitation right now. It's quite a process to get the approval to drill across lease lines in this area for longer lateral.

So right now I believe the whole industry is just been trying to get as much effective horizontal lateral open within the constraints of the regulations and then contact are certainly Petrohawk contact as much of that rock as you can, so if you just take a little less than 300 feet and divide it in to 4600 to 4700 feet, that will give you the number of frac stages and what we would say is now our view of the optimum frac job. We are pumping, you didn't ask this, but this is quite important. We are pumping higher concentrations of profit. We are using both resin coat and ceramic in various wells and pumping at higher rates as well. So we think that all this adds up to our current view of the optimal completion practice.

Ben Dell - Bernstein

And just, one last question if I could. There has been some discussion in other plays while the increase in fracing increases IPs the EURs may not grow in a linear relationship. So that while the IP goes up, the EUR may not go up. Are you seeing any evidence of that in that in the Haynesville or what are your current thoughts on that?

Floyd Wilson

Well the good news for Petrohawk, we have had a very consistent completion practice for ourselves. We can't really speak to others and we are never trying to jack up the IP rates, because it just isn't effective and it could be dangerous. In fact, we have heard of several instances where people get collapsed casings from trying to overproduce the wells initially. So for Petrohawk's wells, the IP rates are very correlative to EUR based on our current research.

Dick Stoneburner

I would just add that all IPs are not created equal. And that's what Floyd, I think is referring to, is that we try to keep our fairly standardized with the choke we put the well on and allow it to stabilize and its particular IP. The other thing I would add is that we are in a program of testing restricted rate production practice keeping our smaller choke, smaller lower rate and watch that decline curve as it compares to the to the wells that we have produced on a higher rate.

So we are not convinced that we know everything about the play whether the completion or production but we are trying the things that intuitively would suggest you make a better well and that is keeping your well fairly well under constraint as you are producing it and possibly under quite a bit of constraint and we will know as we get further down the road with testing this reduced production practice.

Floyd Wilson

Ben, we're the first to suggest to everyone that 30 day rates and 60 day rates and 90 day rates are much more relevant than IP rates. So that's why Dick has been diligent about reporting those average rates beyond the first day because that those can be all over the board sometimes.

Ben Dell - Bernstein

I appreciate that. If you could just convince all of your competitors and compatriots to do the same thing, it would make life a lot easier.

Operator

Your next question is from Marshall Carver with CapitalOne.

Marshall Carver - CapitalOne

Yes in terms of the asset sales in 2010 I know you don't have the productions broken up by area but do you have a feel for the total production that might be sold and also just a general feel for timing? Would that be beginning of the year, middle year, end of year?

Floyd Wilson

Steve is sitting here, and I'll ask him to correct me. I believe he is going to space these groupings out through the course of the year and some of it will occur in the first half, and some in the second half. We haven't really put out the production associated with these, but we will as we actually announce each one is ready to go. What would you add to that?

Steve Herod

Yeah, I think, we haven't firmed up the details yet, but we do plan a program over 2010 and do expect some activity in the first half, and we'll be forthcoming with the additional information on timing and which assets first and second, etcetera in the future.

Marshall Carver - CapitalOne

And a quick question on the EBITDA, the 2010 EBITDA for the midstream and the general growth rate for that?

Floyd Wilson

Well, we certainly haven't published those numbers as you can imagine, the EBITDA is exploding at Hawkville services in the Haynesville field and it's a really, very attractive asset and of course it plays a significant role in this $1 billion divestment that we have announced for 2010.

Marshall Carver - CapitalOne

Okay. Thank you. One final question. The bit design, who is making the bits for you and will you, be able to keep that proprietary?

Dick Stoneburner

It will not be proprietary, but the rate at which they are being produced is at the rate in which we are using them, so until their production outpaces our utilization, it will remain proprietary. But I am not at liberty to discuss the company that is building them for us but just it's very innovative and what I would say, game-changing technological change.

Operator

Your last question is from Chris Pikul with Morgan Keegan.

Chris Pikul - Morgan Keegan

Floyd could you just add your comments on I'm still having trouble differentiating some of these well costs getting thrown around for the Haynesville? We area hearing below $6 million to your $8 to $9 million target are there different completion techniques we should be thinking about or could you add any color on that?

Floyd Wilson

Well Chris, we certainly don't wouldn't intend to address, what other people put out. We will say that our view is that the Haynesville, both in terms of the it's an aggressive environment to drill in terms of pressure and temperature and that's demanding. So we don't think that cutting corners makes any sense there and economically we don't think that it makes any sense either. If you are going to make a 5 or 10 Bcf well, you are going to spend a certain amount of money and if you are going to make a 2 or 3 Bcf well, you might spend a lot less money.

So for Petrohawk we're just trying to reach that equilibrium between benefit and cost and try to get there. Most of what we have anticipated in terms of future cost, the part that stays with us is the fewer rig days on the well and the rest of the costs are going to kind of go up and down with commodity prices, so I think that our target is reasonable for us and we don't put out targets that we don't think we can achieve and the rest of the industry Petrohawk is certainly not in a position to drill one of these wells for $6 million, I can promise you that.

Dick Stoneburner

I would just add by definition when you get in the higher rate, higher fume areas of the field, where the like Floyd said the pressure is higher and the rock is better, it's inherently going to be a bit more expensive but I would much rather spend $8.5 million to find 10 Bcf than something less to find a lot less. And I think that's basically where we are in the play.

Floyd Wilson

Listen, everyone. Thanks for dialing in. Feel free to call in if you think of something that we didn't cover and we'll be talking to you in another 90 days.

Operator

This concludes today's conference call. You may now disconnect.

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Source: Petrohawk Energy Corp. Q3 2009 Earnings Conference Call
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