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Executives

Floyd Wilson - Chairman and Chief Executive Officer

Richard Stoneburner - Founder, President, Chief Operating Officer and Director

Stephen Herod - Executive Vice President of Corporate Development and Assistant Secretary

Mark Mize - Chief Financial Officer, Executive Vice President and Treasurer

Analysts

Michael Hall

Leo Mariani - RBC Capital Markets, LLC

Ronald Mills - Johnson Rice & Company, L.L.C.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Subash Chandra - Jefferies & Company, Inc.

Brian Corales - Howard Weil Incorporated

Gil Yang - BofA Merrill Lynch

Marshall Carver - Capital One Southcoast, Inc.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Petrohawk Energy (HK) Q1 2011 Earnings Call May 5, 2011 10:00 AM ET

Operator

Good day, and welcome to the Petrohawk Energy Corporation's First Quarter Earnings Conference. Today's call is being recorded. At this time, I would like to turn the conference over to Mr. Floyd Wilson. Please go ahead, sir.

Floyd Wilson

Thank you. Happy Cinco de Mayo to 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 disclaimers, see our press release issued today and posted to our website as well as our other public filings.

Today, we announced several important developments. We have added a new core operating area in the Permian Basin. We sold $920 million worth of midstream assets, and we have reset expectations for continued growth through our increased production guidance and report of our first quarter results. We believe that our growth will be best achieved in the coming years by having premier core positions in the best oil and natural gas plays such as Petrohawk.

Our definition of resource play is very specific. This includes repeatable high-return development opportunities with definitive, predictable results. For us, a resource play is right for high-growth production and reserves over a multiyear horizon, with the ability to apply technology to improve performance and drive down costs. And today, that definition includes liquids, not dry gas.

As in the Haynesville and in the Eagle Ford, being early, being central and being scalable are all key factors. Without low-entry cost, it is difficult to preserve cash flow for drilling and pursue the goal of being cash-flow positive in a play, which by the way, we expect to occur in the Haynesville in a few months. Without the best rock optimization techniques, we cannot achieve our full potential. And without a scalable position, it is difficult to ramp up services and economically build out infrastructure; infrastructure with a profit motive, by the way, to accelerate growth and to drive down cost. So we look for all of these.

Over a year ago, we began considering the Permian Basin as a potential new resource play for Petrohawk. While we have managed the aggregate there, with low entry cost, it would be very difficult to replicate today. Our new asset provides important diversification and low-cost future project inventory. Of course, we're looking for product balance and diversification given our outlook for commodity prices today, but adding a new play that is immediately capable of competing for capital, alongside of our existing powerhouse assets, is much more than a simple shift towards liquids.

The Permian Basin, with several thousand feet of hydrocarbon rich shale, adds a new wave of growth to our multiyear plan. It leverages our strength in geological evaluation and optimization of drilling and completion practices. And we are highly confident of these strengths. Our plans for the Permian Basin are robust, as were the growth and growth expectations we reported today, which were driven by the Haynesville and Eagle Ford.

Additionally, today, we announced an extension of our partnership with Kinder Morgan through the sale of our remaining midstream interest in the Haynesville, KinderHawk and the sale of a 25% stake on our midstream business in the Eagle Ford, signaling our total satisfaction with Kinder Morgan as an operating partner in our efforts to achieve superior pricing and placement of the products we produce, not to mention meeting our 2011 divestiture target well ahead of schedule. And as I mentioned, when we open up the Eagle Ford in the Permian Basin, Hawk sales services is on the job.

Now I'll turn the call over to Dick Stoneburner, our President and COO.

Richard Stoneburner

Thanks, Floyd. Before I provide some detail around the Permian acreage position and the potential it provides to Petrohawk, I would like to spend a few moments updating you on our Eagle Ford and Haynesville operations. In the Eagle Ford, we continue to ramp up our operations. We drilled a total of 28 wells, of which 25 were operated. We averaged 10 operated rigs during the quarter, with 4 in Hawkville and 6 in Black Hawk, with a current rig count of 14. We also were able to decrease our inventory of wells waiting on fracture stimulation from 27 to a current level of 17. This all resulted in an increase in production from the fourth quarter 2010 to the first quarter of 2011, up 43% from 109 million cubic feet of equivalents per day to 156 million cubic feet of equivalents per day.

During the first quarter, we experienced a market decrease in spud-to-spud days in Eagle Ford, most especially in Black Hawk. We had budgeted 38 days for 2011, but during the first quarter, we averaged 30 days. Because of this, we are not planning to bring in the 15th rig, since we should be able to accomplish our desired drilling with the rigs that we currently operate. However, we still have not seen a material change in overall pressure pumping costs and other related services, so we are not currently forecasting a decrease in average well cost as a result of the decline in spud-to-spud days.

We continue to be pleased and optimistic regarding the performance of the wells that have been fracture stimulated with Schlumberger, with the Schlumberger-designed HiWay process. To date, we have stimulated 25 wells in Hawkville and 2 wells in Black Hawk with the HiWay process. The Hawkville wells have shown considerably higher rates on comparable chokes, and with appreciably higher flowing pressure. In support of that statement, while a set of Hawkville wells that were stimulated with HiWay and hybrid frac designs have both been produced on an average choke size of 18/64s, the HiWay wells have averaged a 32% higher rate in million cubic feet equivalent per day, and have averaged 42% higher flowing pressure when compared to Hawkville wells that were stimulated with hybrid designs. The HiWay comparison is even more dramatic when compared to slick water completions. The 2 wells that have been stimulated with HiWay in Black Hawk are only about 30 days into production, and it is too early to make a determination as to whether there will be a material difference in well performance. However, even if the performance of the HiWay wells proves to be neutral to the hybrid process, the costs are about 10% less than a normal hybrid design, the water requirements are approximately 10% less and the sand requirements are about 40% less, which are all substantial benefits from a supply-chain standpoint and from a water-management standpoint.

Turning to the Haynesville, the operational highlight is that we can finally see the finish line right in front of us when it comes to the lease-capture effort. We have actually reached the point of significantly decreasing our rig counts slightly earlier than originally forecast, as we have been successful in acquiring a few low-cost lease extensions that have allowed for us to defer a number of locations for 1 to 2 years. We are currently operating 13 rigs, but by June 1, we should be at 9 rigs and July 1, we should be at 6 rigs, which is the rig count that we will maintain throughout the balance of the year.

However, we have been very active during the first quarter with an average rig count of 16 rigs that drilled a total of 31 operated wells, in addition to 53 wells drilled on non-operated acreage. Like we were able to do in the Eagle Ford, we made a slight reduction to the number of wells that are waiting on frac from 15 at year end to a current account of 14. This increased activity results in a production growth from the fourth quarter of 2010 to the first quarter of 2011 of 22%, from $497 million cubic feet to $607 million cubic feet.

While we are not guiding for a decrease in well cost in the Haynesville, we are experiencing some positive trends in costs that we hopefully can translate into a lower-average well cost for 2011. The most significant component of these savings is a result of a few slight modifications to the fracture stimulation design that we believe could be a significant cost benefit.

These changes are generally a variety of modifications, including less sand per lateral foot, a slightly wider spacing of the perforations leading to fewer stages and using a component of white Ottawa sand along with the Premium Resin Coated sand. We do not believe that these changes will compromise the well performance and could lead to a savings of approximately $500,000 per well.

The last aspect to the Haynesville operation is really more of an economic landmark than an operational one. Based on current strip pricing and our updated capital budget, the Haynesville Shale component of the company's portfolio turns cash-flow positive early in the third quarter of 2010. This has been accomplished in just over 3 years since the inception of production from the field, and during a time that over 200 operated wells have been completed, resulting in net production of the field of approximately 680 million cubic feet per day.

Now moving on to what we have been anxious to talk about for some time. With today's announcement of the acquisition of approximately 325,000 net acres in the Permian Basin, of which approximately 70% are located in the Delaware, Petrohawk believes that it now has a completely diversified asset base that is equally capable of significant growth in either natural gas, oil or natural gas liquids.

Earlier in the call, Floyd provided a definition of a resource play. In addition to low entry cost, we also looked to find oily, moderately de-risked acreage that, very importantly, could be leased in a way that would not put pressure on our capital planning in the prompt [ph] years. I would like to elaborate on each of these components and why I believe we have delivered on this value proposition.

First and foremost, we were charged with finding a play that had a significant liquids component and we are quite confident that is the case. The Permian Basin proper, including both the Midland and Delaware Basins, has produced over 30 billion barrels of oil equivalent over its many decades of production. The Midland Basin, where we have approximately 100,000 net acres, predominantly produces crude oil and associated gas. And there is sufficient history from the primary objective associated with our acreage, the Wolfcamp, to feel confident that, that will be the product mix.

In the Delaware Basin, where we have approximately 225,000 net acres, the primary objectives that we are targeting -- the Avalon Shale, the Bone Springs Sand and Shale, and the Wolfcamp Shale, all have slightly variable liquid yields across the basin, but they are typically gas-condensate reservoirs with very significant NGL yields.

The second component that we considered necessary was that it needed to be at least moderately de-risked. Our geologic staff has been performing extensive petrophysical analysis of the potential reservoirs, while at the same time, our reservoir engineers have been evaluating the performance of wells drilled by our peers in the basins. Without naming those companies, there are no shortage of experienced resource-style companies that have tested all of these reservoirs with what appears to be highly commercial results that are consistent with what the geological evaluation would predict.

Another key aspect of these basins, particularly the Delaware, is the multipay component. While the industry is clearly in the early stages of establishing the aerial extent of each play, there are many portions of the basin that appear to have horizontal potential in all 3 of the respective intervals.

The third requirement was that it had to have a relatively low entry cost, which is generally pretty hard to do when a basin has been relatively de-risked. However, we believe we were successful in timing our entry into both of these basins. In a play with the apparent reserve potential that exists in both, a weighted average cost of approximately $1,400 per acre should have nominal effect on the overall F&D costs. Additionally, an incremental increase in our 2011 acquisition capital of $400 million should not affect the company's liquidity over the next few years.

Lastly, a requisite condition to acquiring a significant position in the resource-style play was that we would be able to acquire sufficient term to the leasehold that there would not be any appreciable pressure on the drilling and completion capital budget for several years, as we completed the lease-capture process in the Eagle Ford and the Haynesville. We were able to accomplish that with the vast majority of the leases being 4- or 5-year term. The drilling and completion capital to the Permian in 2011 is only $75 million, with a contemplation of capital in 2012 not being a significant increase over that. It is not until 2013 and beyond that we anticipate a significant ramp in capital, at which time the majority of our other capital needs become discretionary.

While we have studied the results to date in both basins extensively, both from a rock quality and a reservoir-quality standpoint, and our view of reserve ranges and economic returns are very favorable, we believe that it's most prudent to establish production from our own operations before we provide any guidance regarding reserves and economics.

With that, I'll turn the call over to Mark.

Mark Mize

Okay. Thank you, Dick. Production really headlined the quarterly results coming in at $826 million a day or $56 million a day higher than expectations. That does represent an almost 10% quarter-over-quarter increase. Revenues were 22% higher than fourth quarter 2010 at $492 million. Price realizations for oil and natural gas were within our guidance range at 96% of NYMEX for natural gas and 91% in NYMEX for oil. And then above our expectations for NGL is realizing about 50% of the price of the barrel. We did achieve product pricing of $4.90 in Mcf and right at $85 a barrel, taking into account the effect of hedges this quarter. Our cash operating expenses were in aggregate within guidance ranges, and this translated into cash flow per share of $0.81, which is above the consensus cash flushed on a 68 [ph].

A couple of quick data points on our selected items table. We did have a mark-to-market noncash charge of approximately $115 million. And while this noncash item has historically been dominated by movements in the forward curve of natural gas, oil is now becoming much more significant as we continue to grow our liquids production and later on crude oil positions. We also had an amortization of a deferred gain of about $48 million due to the accounting treatment of the first 50% ownership sale of KinderHawk in May of last year. Both of these are noncash and if you eliminate their impact, we report earnings per share of $0.15 versus consensus of $0.13.

Looking at some of our expense line items, lease operating expense is $0.01 lower than our guidance range at $0.17 in Mcfe. However, going forward, we do expect to still be within the previously published guidance of $0.18 to $0.25 in Mcfe. Workover expense, as mentioned in the press release, was higher in the first quarter due to a planned tubing project that has now concluded. And DD&A, while we don't guide on it, was a bit higher than normal, coming in just over $2 in Mcfe this quarter. And that was a result of the impact to the full cost pool following the closing of the Fayetteville sale last quarter.

Turning to capitalization and liquidity. Several events during the quarter were positive for the company's liquidity on accessible capital. First, we had strong support amongst our lending group during the spring borrowing base redetermination, and we increased our credit facility and borrowing base. The facility was increased from $2 billion to $2.5 billion, and the borrowing base was increased to $1.9 billion, which is comprised of $1.8 billion associated with the E&P assets and $100 million associated with the midstream assets.

The pricing grid came down 50 basis points for a new grid of 150 to 250. And also during the quarter, we closed about $250 million leasehold commitments related to the Permian Basin, and we've either closed or obligated ourselves to another right around $200 million of leasehold.

We had $364 million drawn on the credit facility at the end of Q1, which with the new credit facility yields first quarter end of liquidity of just over about $1.5 billion. And finally, the transaction with Kinder Morgan, which we did announce today, is expected to deal proceeds to the company of around $855 million, and that is expected or scheduled to close on July 1. And that would further increase Q1 liquidity up to about $2.3 billion if you back out any cash taxes expected with that transaction.

Before I conclude my comments, I wanted to make a -- take a moment to address the going-forward financial impacts of our decision to dissolve Petrohawk's marketing company around the Haynesville marketing activities, which will be effective July 1. This is a topic that came up on the 2010 year-end earnings call. I just want to make sure that there isn't any ambiguity around the matter. Historically, we've reported revenues and associated expenses of marketing activity in 2 line items on the face of the income statement titled Marketing. Due to the decision to dissolve the marketing company, this activity will no longer be reflected on those line items, but will become part of our overall operating cost structure. Additionally, to be more consistent with our peers, we've elected to combine lease operating expense, workover and gathering transportation and other into a single line item on the face of the income statement called Operating Expense. This is merely a change of presentation and is substantially P&L neutral to the bottom line.

The current marketing lines will remain on the face of the income statement till the historical periods roll-off. So beginning with the third quarter, the only bookings or activity that you would see on those line items would be any type of true-up activity from prior periods, and we would expect that to be minimal.

So for modeling purposes and future guidance, we're going to provide operating cost information under this new convention that I just explained.

Finally, we will be posting an updated schedule of our hedge positions to our website following this call. We have added oil contracts for 2012, as well as some gas contracts for the later half of this year and for 2012. The additional gas hedges in 2011 have allowed us to remain approximately 60% hedged for the year, in step with our increase in full year production guidance.

And with that, I'll turn the call back over to Floyd.

Floyd Wilson

Thanks, Mark. I believe the information that we have shared with you today identifies Petrohawk pretty well. We don't own so-so properties, and we don't deploy so-so technology. We own an acreage in a lot of different plays, and we have stayed close to home within areas where our technical expertise is leveraged. We have demonstrated the optionality that our assets and staff have provided to date, and this has enhanced our announcements today. Risk, opportunity and reward are how we measure what we do, and I believe we stack up quite well using these measures. We have assembled a world-class staff and a world-class asset base with decades of economic growth ahead. Our annual report suggests that the answer to our great country's energy future lies right beneath our feet. We believe this, and we're excited to play our part in producing the homegrown crude oil and natural gas that our nation needs to change that energy future. And this is America, so we intend to make money while we're doing it.

Operator, we're ready for questions, if there are any.

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question from Mr. Brian Corales of Howard Weil.

Brian Corales - Howard Weil Incorporated

A couple of questions. Are you all mostly done leasing in the Permian and, outside of just infill stuff?

Floyd Wilson

Brian, we're substantially complete. We're, of course, doing a little fill-in work for this year, but we're substantially complete.

Brian Corales - Howard Weil Incorporated

Okay. And are you all going to disclose your location, exact locations, I guess, in the presentation soon?

Floyd Wilson

No.

Brian Corales - Howard Weil Incorporated

Okay.

Floyd Wilson

It's very competitive.

Brian Corales - Howard Weil Incorporated

Okay. And then looking at the cash flow neutral or cash flow positive in the Haynesville in the third quarter, is that assuming the 6 rigs running?

Floyd Wilson

It's assuming the rig count that we have that Dick described for you for the year.

Brian Corales - Howard Weil Incorporated

Okay. And can you keep production flat with 6 rigs in the Haynesville?

Floyd Wilson

I believe we've run that calculation for today's call. Production is going to continue to increase through this year because of the momentum created by the first-half drilling and the execution of completions during the second half.

Brian Corales - Howard Weil Incorporated

Okay. All right, guys.

Operator

And we'll take our next question from Leo Mariani with RBC Capital Markets.

Leo Mariani - RBC Capital Markets, LLC

Just a couple of questions around the Permian. Just curious if you guys have added a lot of staff to get out there and drill that up? And have you put any rigs direct to work? I know you talked about, I guess, 4 rigs. Are any of those there at this point in time?

Floyd Wilson

Go ahead, Dick.

Richard Stoneburner

Yes. As far as the staff is concerned, it's really very timely, the fact that we ramped down our Haynesville operations so significantly at about the same time we're ramping up the Permian. So we've assigned the Permian operations and geological work to our Mid-Continent division out of Tulsa that has been handling the Haynesville. So we're pretty much staff-neutral, and it's fortunate in that regard. We do have one rig on location. We have another one heading that way. Probably by -- certainly by the end of the second quarter, we'll have those 4 rigs in place, and that will remain constant through the balance of the year.

Leo Mariani - RBC Capital Markets, LLC

Okay.

Richard Stoneburner

All of those, by the way, are heading to the Delaware Basin. The predominant activity for this year will be in the Delaware.

Leo Mariani - RBC Capital Markets, LLC

Okay. You guys talked about industry activity at the Delaware Basin at the preponderance of your acreage. Just trying to get a sense of how much of that, I guess, 225,000 acres you think has been de-risked at this point in time?

Richard Stoneburner

I think from a combination of a geological perspective and from industry-activity perspective, I'd say the vast majority has been.

Leo Mariani - RBC Capital Markets, LLC

Okay. And I guess jumping over to the Midland Basin, same question, how much of that you think has been de-risked by those same 2 factors?

Richard Stoneburner

Well, as we mentioned in the press release, the northern area of the Midland Basin has not been. The southern, we feel like has been with the activity by our peers. But we also, from a petrophysical analysis in comparing the northern and the southern, we see them very similar. So while there hasn't been activity in the northern yet, we feel good about the chances of success, we just have not seen any yet.

Leo Mariani - RBC Capital Markets, LLC

All right. So I guess, I imagine you guys have been doing a great deal of G&G work. Is that something that started way back in early 2010? Did you guys came up with this plan to add acreage here and just trying to get a sense of how much work you've done prior to buying a lot of this acreage?

Richard Stoneburner

A lot. And it has been a while. I don't remember the exact date, but it's been a better part of '10 and into '11. But to evaluate the basins such as the Permian, and the 2 primary basis within the Permian, it takes a lot of work. But we've done it and we feel good about it.

Leo Mariani - RBC Capital Markets, LLC

All right. I guess, any just comments on infrastructure in the Midland Basin and your kind of thoughts there? I imagine -- I don't know exactly what your acreage is, but is there any infrastructure issues that you guys foresee? Just curious as to why you're not drilling there earlier and you're doing everything in the Delaware this year?

Floyd Wilson

Leo, we at Petrohawk and Hawk Field services, we view these infrastructure issues as opportunities. And that's how we're going to attack the Permian Basin. There's some infrastructure in the, of course, in the southern part of the Midland Basin with a lot of mature production, and there's some infrastructure out in the Delaware. But we've got a very "up and running" plan on how to deal with these things.

Operator

We'll take our next question with Jason Wangler with SunTrust.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

On the Permian, are all the wells this year going to be horizontals or will you be drilling a few verticals as well?

Richard Stoneburner

A couple of verticals, mainly for science purpose. I think we need to be able to get a good suite of wells with pilot holes and also get a feel for how these wells react to pressure stimulation before we drill horizontally. So a very small amount of capital allocated toward vertical, so majority of it horizontal.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Okay. And just trying to get kind of my head around the wells in the CapEx. Is the majority of -- it looks like it's almost operating obviously 90%. What's your average working interest in the play there?

Richard Stoneburner

I don't think we're really prepared to release that. We have a very -- like you said, a very, very high percentage of acreage that will be operated. And therefore, by definition, the working-interest average will be quite high. But we're really not prepared to talk about averages across the basin at this point.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Okay. And then just if I could, last one. Is there a current production number out there that you'd be able to release or not yet?

Floyd Wilson

No. We're just getting going.

Operator

We'll take our next question from Marshall Carver with Capital One Southcoast.

Marshall Carver - Capital One Southcoast, Inc.

A question on your expectation on differentials versus WTI with the new production handling agreements in the Eagle Ford? I mean, if you're going to be selling that into Louisiana, where do you, what percentage of the Eagle Ford production could be getting better prices?

Floyd Wilson

Well, our expectation is it's a lot more complex than just the kind of the simplistic idea that the Cushing, and the Louisiana light markets have diverged. We were actually expect that differential to shrink over time as Cushing becomes a little more fluid. The important thing to us is getting as close to the best end use as we can for this product, which if you find the best end use, you get the highest price. So we think pointing it towards the Gulf Coast and the shift channel in St. James is the right way to go. Right now, the prices are pretty good. But the infrastructure is sorely lacking to get it over there, which is why we've made all these arrangements with pipelines and trucks and marine facilities to move our crude in that direction.

Marshall Carver - Capital One Southcoast, Inc.

Okay. Do you know about how much of your production would be sold via the trucks then to the barge on a liquid side?

Floyd Wilson

No, it's hard to say. Yet, as this becomes more mature, we would like to think that the trucks and barges would be more of an interim solution compared to a pipeline arrangement.

Marshall Carver - Capital One Southcoast, Inc.

Okay, that makes sense. And one final question. You talked about the Haynesville becoming free cash flow positive in the very near term. Do you have an estimate on when the whole company would be free cash flow positive assuming trip prices?

Floyd Wilson

We don't have for the call today. We're going to program all of our Permian Basin efforts into that and recalculate that for some time later this year.

Operator

We'll take our next question from Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

Going back to the Haynesville, your rig count 7 versus -- 6 or is it 7 taking a -- what are the specific drivers that let's you drop the rig count a little bit lower? And what does that do to CapEx? I think you mentioned that there's no effect to CapEx. Do you disagree with that?

Richard Stoneburner

Yes. The main driver for the reduction, further reduction in rig count is the lease extensions that we were able to acquire on some of the wells that we have forecast for 2011. Very nominal capital, but it allows us to shove some of those wells out into '12 and even into '13, which just spreads our capital over a much longer period. So we thought that was a wise decision. And it was essentially just kind of the reallocation of capital between the Haynesville and the Eagle Ford that we're trying to strive for. So as you can see, it's been fairly neutral to capital right now.

Gil Yang - BofA Merrill Lynch

Well, can you talk about the amount of capital that shifted out of the Haynesville into the Eagle Ford from that?

Richard Stoneburner

It's really just the way we describe it in our press release. We have about $950 million in each play right now forecast for the year.

Gil Yang - BofA Merrill Lynch

Okay. All right, so there's no efficiencies or anything that are driving the need for lower rig count?

Richard Stoneburner

Not really. It's just being able to hold our leases in the time line that we want to hold them and not put any additional pressure on the capital budget because of it.

Gil Yang - BofA Merrill Lynch

Okay. And if you maintain the 6 rigs in 2012, how much would 2012 production be versus 2011?

Richard Stoneburner

Well, there's no sense that we'll be at 6 rigs during 2012. We haven't released that. And that would be market-driven. We'll allow our budget to be driven by what the market situation is with commodity prices. So that's a "to be determined" situation.

Gil Yang - BofA Merrill Lynch

Would your goal be to maintain cash flow neutrality in the Haynesville in 2012 or to be actually positive -- potentially very positive in cash flow?

Floyd Wilson

Those would be positive in all of our plays.

Gil Yang - BofA Merrill Lynch

Okay. And back to your guidance. You had a nice bump up in production guidance of about 7% versus previous guidance. Could you talk specifically about what are the drivers there, regional drivers or performance drivers that are letting you do that?

Richard Stoneburner

I'll start with the answer and let Floyd follow-up. But it's well performance. It has nothing to do with any bottlenecks within the field. It has nothing to do with infrastructure or services. I really believe it is primarily well performance.

Gil Yang - BofA Merrill Lynch

In the Eagle Ford or other areas as well?

Richard Stoneburner

Well, it's primarily driven by the Eagle Ford. The way we produce our wells and forecast our wells in Haynesville, it's pretty tight. We produce some on fairly restricted chokes. We don't have a wide range of production out there. It's very predictable. But with the HiWay results that we've seen, particularly in Hawkville, and just the phenomenal reservoir characteristics and well performance that we see in Black Hawk, we're just making really, really good wells.

Operator

We'll go next to Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc.

First, on the Permian. Could you sort of compare the new Permian opportunities to Wayloo [ph] and your legacy experience in the Permian, how this might compare? I know size wise, there's a lot bigger, but in terms of resource potential, sweet spots and EURs?

Floyd Wilson

Dick, I'd like Dick to answer that, but I don't think you can compare several thousand feet of shale distributed over hundreds and hundreds of square miles with our prior more shallow production in the Permian from conventional reservoirs nor certainly at Wayloo [ph]. I don't know, Dick, what do you have to say?

Richard Stoneburner

Well, I mean, if I was going to compare [ph] to anything, I'd compare it to the Mississippi line. I mean it's a totally different animal than what we're doing in the Permian. Like Floyd says, this is a true resource play, basin-centered, shale-driven, much like what we're doing in the Eagle Ford and the Haynesville. But with just a little few more nuances to it in terms of the multipay component and very, very, very thick section of oil saturated rock.

Subash Chandra - Jefferies & Company, Inc.

So in terms of productivity, you put it much closer to a shale play than what we've, I guess, historically experienced in the Permian?

Richard Stoneburner

Absolutely.

Subash Chandra - Jefferies & Company, Inc.

Okay. And then in the Haynesville, what is -- I know you said it was market-driven next year but what is sort of the 5-year annual CapEx required to keep the 1.5 Ps [ph] or whatever of Haynesville PUDs on the books?

Floyd Wilson

I don't think we have that for today's call.

Subash Chandra - Jefferies & Company, Inc.

Okay. And if you have it off the top, your 10-K says 704 PUD locations, I wasn't sure if it was a net or gross because then you refer to 100 net wells. So do you know off hand if that 704 is a net or a gross number?

Richard Stoneburner

That's a gross number.

Subash Chandra - Jefferies & Company, Inc.

Gross number, okay. All right. And I guess, Kinder Morgan, reading the press release, 50,000 barrels per day of condensate they're reserving for you guys. Is there a time frame attributed to it? Do you have to sort of pay a reservation fee until you get there? How does that work?

Floyd Wilson

We're going to -- we'll stage up to that number. But our volumes are growing geometrically out there as we speak. We're just really anxious for them to get that thing in service, which I think they're still projecting for the second quarter of 2012. Is that right, Steve?

Stephen Herod

Yes.

Operator

We'll take our next question from Michael Hall with Wells Fargo.

Michael Hall

Curious, in the Permian first. Are you willing to give any disclosures around which counties the acreage acquisitions are in?

Richard Stoneburner

No, we're in the majority of the basin.

Michael Hall

Okay. And then as it relates to what your initial thinking is on targeted intervals, is it predominantly -- it sounds like the shales as opposed to more of the sands or carbonates that others are targeting?

Richard Stoneburner

Well, I think we're targeting what appears to be the primary targets for the industry. And it is the -- and I don't want to get too geological here, but these shales are much like the Eagle Ford in that they have a very high carbonate content in many cases. Really, the Wolfcamp, the Lower Wolfcamp and the Avalon Shale, we feel probably are our 2 most prospective objectives, but we also have some acreage that we feel like is very prospective for the Bone Springs, which is really a combination of sand and shale within the interval. I hope that answered your question.

Michael Hall

No, that's helpful. And then, I guess, just quickly in the Eagle Ford. Can you talk about any cost trends? I mean, are you seeing the escalation costs flatten out at all? And then you talked about the application of the HiWay frac potentially helping the logistical side of things in Black Hawk, if not the recoveries. Is there any cost implications there? And then have you looked at using white sands in any parts of your acreage as opposed to high strength proppants?

Richard Stoneburner

Well, going backwards, we don't use high-strength proppant in the Eagle Ford, we use all white sand. The overall trend in the Eagle Ford from a cost standpoint, as I mentioned, we look at it being fairly neutral. We haven't seen any increases in pressure pumping costs over the last 6 months or so. But by the same token, we don't see any forecast for decreases in the near future. We have most of our services tied up, whether it be pressure pumping or rigs or tubular. So we look at it pretty flat right now. So I think what we're forecasting for well cost, we don't see any great deviation from that.

Michael Hall

Okay, that's helpful. And then I guess one last one on the Eagle Ford. Have you run up against any constraints around the trucking recently? We've heard some other operators talking about tightness in that part of the logistical chain.

Richard Stoneburner

Floyd? Okay. No, we've acquired some trucks on our own account and we're employing those as they come in. So yes, we know it's a bottleneck to a degree, but we haven't experienced any significant curtailments. I would add that a curtailed well in Black Hawk is still one that's producing 1,200 or 1,300 barrels a day instead of 1,600 barrels a day. So we may have to achieve that type of reduction in what the well is capable of producing. But we're modeling that within our guidance. And therefore, we don't see any infrastructure issues that will affect our guidance at this point. Did that answer your question?

Operator

We'll take our next question from David Heikkinen with Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

A couple of mechanical questions. The Kinder Morgan deal, $855 million in cash, the cash tax expectations or net proceeds are what?

Mark Mize

We're estimating cash taxes around that transaction of around $120 million.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. And then as you look at the third quarter CapEx, maybe Dick or Floyd, what's the split by region for Haynesville, Eagle Ford, Midstream leasing kind of and I guess there's 40-or-so million for Permian but can you walk through that?

Richard Stoneburner

Well, we really don't break out or quarterly capital. But it's clear that when you look at what we've spent and you look our forecasted rig counts, it's extremely front-end loaded. We decrease capital significantly as we go through the year. Again, intuitively obvious from the rig counts that we projected for the year. So I think, without giving you a chance to model it quarter by quarter or month by month, you can certainly prorate that capital based upon our announced rig counts and probably come to a decent answer. And when it comes to the acquisition capital, like Floyd said, we have -- we're substantially done with what we've accomplished in the Permian. There will be some cleanup opportunities, really, across the board. We still clean up some things in the Haynesville on occasion. But from an acquisition capital standpoint, it's even more front-end loaded than the drilling and completion.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. And then can you walk through the mechanics of leasehold conversion to help live production for the Permian properties just how wells get drilled and how things actually get held out there?

Richard Stoneburner

Well, it's a very diverse basin with different products and therefore, different field rules and different size units. So I don't think I could walk it through in 30 minutes, much less 30 seconds. So we are working the matter. We feel confident. Most of our acreage being in the Delaware, which is gas condensate primarily with high NGLs, we should be able to hold gas size units. So that's the approach we're taking. That's the approach some of our peers have been able to accomplish through field-rule processes within the Railroad Commission. So it gets back to what I and Floyd stated that we really don't see any pressure on the capital budget in the next couple of years. And once we become a bit more discretionary in the out years in the Eagle Ford and the Haynesville, we really feel like it shouldn't be a difficult exercise to hold this acreage over the 4- to 5-year period that we have in front of us.

Operator

And we'll take our final question from Ron Mills with Johnson Rice.

Ronald Mills - Johnson Rice & Company, L.L.C.

Just a question on the Eagle Ford infrastructure going forward. On the Eagle Ford infrastructure, especially going forward, you sold a 25% interest. Did you sell that in what your existing infrastructure is? And as you go forward, I know, Floyd, you had talked in the past about expanding everything from potentially trucking to rail to pipes to plants. How are those plans impacted by today's Kinder Morgan announcement, if at all?

Stephen Herod

Yes. Ron, this is Steve Herod. The transaction we announced today with Kinder is a 25% interest in the existing infrastructure and in the ongoing or future infrastructure build out in the Hawkville and Black Hawk areas. It does not include any activity in the truck or barge, rail pipe area, just strictly around those 2 fields and the gas gathering and condensate gathering and stabilization in those areas.

Ronald Mills - Johnson Rice & Company, L.L.C.

Okay, great. And then in terms of expected investments, as you talk about the leasing on the land on the Gulf Coast, is all of that -- is that what's driving the increased CapEx on the midstream side, as you fully start to flush out your midstream CapEx from your prior budget?

Stephen Herod

No, I'm assuming when you say Gulf Coast, you're referring to the Point Comfort facility. That's a relatively small part of the total Eagle Ford stream CapEx. The increase we mentioned in the press release is just acceleration and inactivity around our production group in the Hawkville and Black Hawk area. They just need more pipe and more treating sooner than we had forecast earlier.

Ronald Mills - Johnson Rice & Company, L.L.C.

Okay, great. And then in the Permian, I think, Dick, you answered most of one of my questions. When you talked about the primary targets, at least initially, it sounds like Wolfcamp and Avalon are the primary targets with at least this year's drilling program. And then looking ahead to next year, do you begin to start testing some of the concepts in your Midland Basin as opposed to the Delaware focus this year?

Richard Stoneburner

That's fair, Ron. We've got a -- 70% of our acreage is in the Delaware, so that seemed like the logical place to start. It's a more complex basin. I think it may take us a little longer to really get our science done. What we see in the Midland, it seems very straightforward. We have activity over there by our peers that will essentially help us understand it without having to spend capital. So that's kind of the approach we're taking with the initial focus in the Delaware.

Ronald Mills - Johnson Rice & Company, L.L.C.

Great. All right, guys.

Richard Stoneburner

Okay, I think that completes the call. Thank you very much.

Operator

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

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