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Petrohawk Energy (NYSE:HK)

Q2 2010 Earnings Call

August 03, 2010 11:30 am ET

Executives

Floyd Wilson - Chairman and Chief Executive Officer

Richard Stoneburner - Founder, President and Chief Operating Officer

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

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

Analysts

Michael Hall

Dan McSpirit - BMO Capital Markets U.S.

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

Brian Corales - Coker & Palmer

William Richards Kindig

Gil Yang - BofA Merrill Lynch

Leo Mariani - RBC Capital Markets Corporation

Ronny Eisemann - JP Morgan Chase & Co

Anish Patel - Crédit Suisse AG

Thomas McNamara - Impala

Operator

Good day, and welcome to the Petrohawk Energy Corporation's Second Quarter Earnings Call. [Operator Instructions] At this time, I would like to turn the conference over to Mr. Floyd Wilson. Please go ahead, sir.

Floyd Wilson

Good morning, everyone, and thanks for joining. We have a lot to discuss today. This conference call may contain forward-looking statements intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a detailed description of our disclaimer, see our press release issued yesterday and posted to our website, as well as in our other public filings.

In addition to our second quarter earnings release, our company issued a press release today relating to a senior notes offering that we are currently conducting. Due to SEC rules and regulations, we are not at liberty to discuss this subject matter of that release on this call.

Well, I'll start off here. In May, we presented a multiyear plan, which defined milestones and targets ahead of us at Petrohawk. Major milestone is reached in mid-2011, when the bulk of our leasehold in the Haynesville Shale becomes held via production. This is based on our current rig schedule. A second milestone is reached in 2012, when we estimate the company will become cash flow positive.

Several companies in our industry have similar milestones ahead of them due to large new discoveries and leasehold capture requirements. Although there is currently a supply-demand imbalance in the natural gas markets, many good companies have chosen to remain on a path of aggressive spending to hold acreage and protect future reserves and potential. And significant growth is an output of these activities.

Petrohawk's early days in the lease capture phase have been aggressive, and we have had to grow our capital budget beyond current cash flow. Petrohawk and its shareholders endured a period of equity raises in 2008 and early 2009 to capitalize the leasing and lease capture phase of the Haynesville Shale development. Those days are behind us.

While painful, this important and needed capital infusion, as well as $1.4 billion in subsequent asset sales have given us substantial liquidity and ability to make more conservative choices today as we face the lower commodity price environment and face service cost inflation.

One conservative choice we're making today is that we are making significant efforts to maintain our capital spending plan in 2010, 2011 and 2012. Dick will discuss some of the ways our capital spending on drilling and completions will change between the first and second halves of this year. We see no need to increase our capital budget at this time.

We remain on track to protect core positions in both the Haynesville and Eagle Ford Shales. In fact, we believe we own some of the best acreage and the best operating results in both plays. We also believe that among companies who have participated in these wonderful unconventional discoveries, the first companies to have the flexibility to lay down rigs, having captured the majority of their acreage and gained more control over their capital spending, will in some way win. Winning could mean having a higher profit margin and hedge-protected stable cash flow that tracks to cover spending and many years of growth opportunities across the first-class asset base.

Having set out on our course in the Haynesville Shale in mid-2008, we are tracking to have this flexibility by the mid-part of next year which fully intend to be a winning company. There is no gimmick to improving stock price performance, particularly in a retreating commodity price environment. Instead, we are following a thoughtful plan that acknowledges the challenges to our industry, while making it crystal clear how well equipped we are to deal with these challenges.

Importantly, we have a significant focus on capital spending discipline because as I have said, we can. This includes conserving capital at the well level, reorganization at the asset level and removing future capital commitments through divesting noncore properties. We will also move forward with divesting other noncore assets, which may include our interest in the Fayetteville Shale and our Fayetteville Shale gathering system. Not only will these future proceeds further strengthen our balance sheet and enhance liquidity going into 2011 and beyond, but it will free up capital spending which can either reduce future budgets, or can be redeployed in our core areas.

While we have contemplated the possibility and have had a number of conversations, we do not intend to enter into joint venture partnerships with our grade assets at this time. Our divestitures have accomplished the same financial objectives, while leaving our Austin positions in the Haynesville and Eagle Ford Shales intact.

Also, we expect to see a meaningful oil production component grow, fueled from new areas of our portfolio. Our growing Black Hawk area in the Eagle Ford Shale and our Red Hawk project, also in Eagle Ford Shale, should provide for this growth. This could bring the oil component of production to approximately 5% by year end and possibly much higher in future years. We will look for these higher-margin oil areas to meaningfully support cash flow growth and organic reserve growth.

And we hedged. We hedged more than most companies in our space. We hedged to protect cash flow and to bring added security to our ability to execute our plan. We have increased our hedged natural gas volumes for 2011 and '12, with attractive floors of $5.55 and $5, respectively. The updated hedge schedule is posted to our website as of now.

Finally, we rely heavily on our operational expertise and expect to present the results of our operational decisions, particularly in the Haynesville Shale, over the next several months. Dick will give you a preview of some of these in a minute.

We are excited about our completion methods, which we conclude optimized well performance and present value. Our studies at well cost and performance show that we are getting higher returns, experiencing lower development costs and lower decline rates and higher reserves per well than we had expected within these core plays. We believe the data, this real data, speaks volumes on the economics of our program. We are proud of what we have created in the Haynesville and Eagle Ford Shales.

From an E&P company's perspective, the current environment presents a unique set of opportunities to square up our shoulders until market conditions improve. And we have done so.

Before having Dick go into detail on these and other topics, I'm going to turn the call over to Mark to go over the financial highlights of the quarter. And by the way, Mark's steady hand as Chief Financial Officer and partner has put us in the best financial position we have ever been in. Mark?

Mark Mize

Okay. Thank you, Floyd. We reported adjusted earnings per share of $0.09 and cash flow per share of $0.54 for the quarter. These figures were primarily impacted by an advisory fee of $7.5 million related to the KinderHawk joint venture transaction, as well as certain expenditures associated with litigation. These fees with settlements constitute right at $0.02 per diluted earnings per share as well as cash flow per share, and these charges will, not excluded from the results of operations in the Selected Items table in the press release, do result in about a $0.02 earnings per share decrease.

During the quarter, there was a softening in natural gas prices. Petrohawk's realized gas price before hedges was $3.97 per Mcf. However, inclusive of cash collected on our hedge portfolio, the realized price was $5.26.

For the first time, we've now started reporting natural gas liquids separately in our SEC filings, and we've achieved a realized price per barrel on the current quarter of 47% of NYMEX. Oil and natural gas liquids are approximately 4% of our production this quarter. As Floyd had stated, we expect this percent to increase during the second half of the year, as we continue to drill on the Eagle Ford and as more processing of pipeline capacity becomes available.

Production for the quarter was above the high end of our guidance range, coming in at 625 million a day. And during the second half of the year, while we expect to have a slightly reduced rig count from the first half of the year, we are also expecting to start to see a meaningful stabilizing in the PDP decline due to the restricted rate program in the Haynesville. We have included a guidance range for third quarter of between 650 million and 660 million a day in the press release, and we do reiterate our production guidance for the full year.

As Floyd had also mentioned, we have posted an updated hedge schedule to our website. It does reflect additional hedge contracts that were put on for anticipated 2012 production. We now have 68% of expected gas production hedged in 2011, with a floor of $5.55 and a ceiling of $9.66. We felt comfortable that with these levels, we are protecting the capital program expected to be executed next year through the leasehold capture phase in the Haynesville. We have hedged around 23% of total expected production in 2012, and we plan to layer more on as opportunities arise. We are currently hedged at an average natural gas floor of $5 and a ceiling of $7.55 for 2012.

Now turning to the cost side. We provided guidance for all cash operating costs earlier in the year, and we're within or just under the low end of guidance of the range, all metrics except for G&A. G&A came in at $0.65 per Mcfe. And the high end of the guidance was $0.50. The advisory fee of $7.5 million and the additional legal fees and settlements mentioned a minute ago in the call equate to a per Mcfe charge of $0.17, have been excluded, puts us within the guided range.

Current quarter, lease operating expense came in at the low end of the guidance at $0.29 per Mcfe. The decline is due to an increase in production from our resource-style plays, which have lower per Mcfe operating cost, as well as the divestiture of certain noncore properties with cost structures in excess of our shale plays.

The final two cost items that I'll touch on are taxes other than income and gathering, transportation and other. Gathering expense, which we had guided higher due to the KinderHawk JV transaction, came in at $0.61 which, while under the low end of our guidance, should continue to trend upward into the range of published guidance once we have a full quarter of expense. Now keep in mind that transaction closed on May 21. We have included a detailed description of the accounting associated with the KinderHawk JV at the end of yesterday's press release.

Finally, taxes other than income came in at $0.09 per Mcfe, which is under the low end of guidance of $0.15. And the decline is the result of severance tax refunds in the amount of $11 million. Now these refunds are associated with Haynesville wells. And while we expect to continue to receive refunds in the future, we cannot predict the magnitude or the timing of those at this point.

We have had a few questions come up regarding the cash tax impact of our asset divestitures. And while we're still fine-tuning these calculations today, we believe we'll have a AMT cash tax bill of just under $90 million related to WEHLU [West Edmond Hunton Lime Unit], Terryville and KinderHawk divestitures, with the majority relating to KinderHawk. Additionally, we expect cash taxes related to the ongoing operations of the company to be right around $5 million.

The final item that I'll touch on before turning the call back over to Dick and Floyd, is the HK credit facility. Recently, we underwent our spring re-determination and then subsequent to that, a credit facility amendment which went effective yesterday. The result, among other items, was a one-year extension to the facility and the reduction to the pricing grid, which now puts us at L [LIBOR] plus 200 to 300. The E&P portion of the facility is just over $1 billion and the HFS [Hawk Field Services], or the Hawkville service portion, is limited to $100 million, and that is re-determined each quarter based on a 3.5x multiple of EBITDA. At the end of the quarter, we were undrawn on the facility, and we reported it all in cash number of $340 million, which does include $57 million that is in like-kind exchange fund. The cash at the end of the quarter represents proceeds remaining from the KinderHawk JV. And it does put our liquidity at quarter end right at $1.4 billion.

Richard Stoneburner

Thanks, Mark. Petrohawk continued to achieve outstanding results from its operations during the second quarter of 2010. The success in the two primary operational areas for the company, the Haynesville and the Eagle Ford, were driven primarily by Petrohawk's dominant operated position in both plays; while the Fayetteville achieved excellent production growth, primarily as a result of its significant nonoperated position.

In the Haynesville, the company operated an average of approximately 16.5 rigs during the quarter and drilled 28 wells, which is the highest number of wells drilled in any quarter in the two years that we have been drilling in the play. In addition, there were a total of 66 nonoperated wells drilled, which is also the highest number of nonoperated wells during any quarter.

In the Eagle Ford, the company operated an average of 7.5 rigs during the quarter and drilled 19 wells, 11 in Hawkville, seven in Black Hawk and one in Red Hawk. This again represents the highest level of operated activity that Petrohawk's experienced in the Eagle Ford.

In the Fayetteville, the company saw an unprecedented level of nonoperated activity. While we averaged less than one operated rig during the quarter and drilled only two wells, there were 111 nonoperated wells drilled, which is the highest nonoperated well count for any quarter in the three years that we have been active in the play.

Instead of spending time speaking to specific well results, which are well documented in our press release and very consistent with the results we've been enjoying for the last two years, I would like to spend the balance of the call addressing what Petrohawk has been doing to achieve these results; because I truly believe the public does not fully realize the extent of the operational research that we perform and the results that are achieved from this research.

Most of the results that I will be discussing are attributable to our work in the Haynesville, because we have so much more data to work with in the Haynesville. But suffice it to say, the same scientific approach to comparative analysis is underway in the Eagle Ford, and we expect to be able to present a similar story in the near future in that area.

We have been utilizing the term "restricted rate" for almost a year now to explain our efforts at testing the Haynesville wells on more restricted chokes, in order to maintain back pressure on the reservoir with the hope of optimizing well performance. I will get into some of the specific results on the program in a few minutes. But I would like to acknowledge that while this production practice appears to have resulted in substantially higher EURs we, by no means, believe it is the only driver to the continued improvement in well performance. Equally important has been the constant refinement of the completion design.

After almost two years of methodical testing and comparative analysis, we believe that there is sufficient evidence to verify that the completion and specifically, the frac design, also has had a tremendous effect in improving our EUR. For this reason, we prefer to refer to our overall effort at maximizing well performance as "reservoir optimization," with the improvements that we were seeing being in combination of superior production and completion practices.

The production practice side of the equation began exactly a year ago, with the decision to produce four newly completed wells on a 14/64" inch choke, instead of the conventional method of producing on a 24/64" choke. There have been a number of members of the investment community that have looked upon this practice as merely a means of deferring production during periods of low commodity prices. This has never been an element in our decision. However, when gas prices eventually do recover, it does provide us with a very interesting capability.

The decision was based on sound reservoir engineering. It is not like this was the first effort in the history of the oil and gas industry to manage reservoir pressure, and consequently exhibit improved well performance by introducing back pressure to the reservoir. The fact is that this practice has been employed by the industry for decades all across the world. The presence of higher back pressure, particularly in low-permeability shale reservoirs that have moderately high clay content and require massive hydraulic fracturing to produce commercially, is a very credible reason to believe that better well performance could result from this practice. After a full year of testing this concept, we believe that the data is extremely compelling, and it suggests that the practice has contributed to significant increases in EUR.

We do plan to announce specific EUR data as we gather more production history on these wells, in an effort to further quantify the positive effects of these practices. However, I will point out that we now have four wells with over 360 days of production, 13 wells with over 180 days of production and 22 wells with over 120 days of production. Based on the extent of this database, we now believe that restricted rate practices support a change in the average first year decline from approximately 80% to 85% to a first year decline approximating 45% to 55%, with some wells displaying declines that could be as low as 25% and 30%.

It should come as no surprise that with these types of improved and sustained decline parameters, that we believe significant increases in EUR should result. Up to this point, we have focused our public comments on the restricted rate practice as being the primary driver of the increase in EUR. However, we have been undergoing a long-term effort in pinpointing what the most optimum components of the completion are, specifically the fracture stimulation.

It has taken many months, many varying frac designs and extensive comparative analysis to land at what might be the optimum design. I intentionally state might be because in reality, we will probably never find the optimum design. We will be continually tweaking certain aspects of design, new technologies will develop and we will be in a constant mode of analyzing new data. However, we are confident that what we were doing is working toward optimizing well performance. And the benefit is that we are creating overall well results that we believe are the best in all of the Haynesville trend.

The main variables of a well and its frac design that generate the most variance in well performance are lateral length, number of stages, total profit and clusters spacing. In the analysis of wells that we have participated in 2010, both operated and nonoperated, the Petrohawk-operated wells had longer laterals, more profit per foot of lateral length, tighter cluster spacing and more stages per well which, by definition, translates into higher cost frac jobs.

However, when you normalize the data against the average completion cost of our partners, the costs were essentially equal. The next question to be asked to determine whether the extra cost was justified, was what effect did the longer laterals, more profit and more stages have on performance. The answer was in a metric analysis of these variables. Our results indicate that Petrohawk-operated wells had a substantially higher EUR per foot of lateral length, a higher EUR per frac stage; and most importantly, a lower completion cost as measured against EUR per foot of lateral length when compared with results of certain wells not operated by Petrohawk.

In the near future, we will be presenting data behind the studies and trends previously mentioned. We firmly believe that the quality of the well performance, which is a by-product of both geology and engineering, supports the quality of the asset base that Petrohawk has in the Haynesville and the Eagle Ford.

We feel that it is very important to convey to the public, with specific data, what we have been doing over the past two years in an attempt to make sure we are investing our drilling and completion capital wisely. In the Haynesville and Eagle Ford, our plays that we are currently creating the unique challenge of needing to develop the asset base during a period of low commodity prices, while also being in a high-service sector cost environment, which is a function of the extremely high demand for those services. We firmly believe that we are making the right choices with our capital.

Speaking of capital, our 2010 drilling and completion budget was significantly front-end loaded. The primary driver for lowering capital in the second half relative to the first half is the reduction of rig count in the Haynesville from a high of 17 to a current count of 14.

We have also chosen to carry an increasing number of uncompleted wells during the second half in both the Eagle Ford and Haynesville, in lieu of completing all of our wells at the current cost of stimulation. However, our current view of production guidance is such that we do not believe this inventory will adversely affect that guidance.

There are also completion modifications being implemented in both the Haynesville and the Eagle Ford. The modified well bore design that we have initiated should gain headway through the second year, bringing a meaningful reduction in frac cost to an increasing number of Haynesville wells in the second half.

We are also progressing toward hybrid fracs in all areas of the Eagle Ford. These fracs used half of the water a slick-water frac does, which not only reduces pump time and therefore reduces cost, but they are also more environmentally friendly. We have now pumped hybrid fracs on three Hawkville wells and all of the Black Hawk and Red Hawk wells, and we believe that well performance has improved.

In the Haynesville, we are no longer drilling back-build wells because we have been very successful in securing off-unit locations. This allows us to place the surface location in the adjoining unit and drill a laterals to the maximum legal distance of approximately 4,600 feet. This has caused us to totally abandon the concept of back-builds which should reduce average well cost.

We are also seeing drilling efficiencies, increased drilling efficiencies in Black Hawk; continued low spud-to-spud days in Hawkville; and a recent consistent decrease in spud-to-spud days in the Haynesville that we believe we can carry forward for the balance of the year.

In summary, we are working very hard to accomplish meaningful cost reductions in many areas of our drilling and completion operations in an effort to offset the cost increases that we have seen in the service sector.

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

Floyd Wilson

Thanks, Dick. And right here, I need to point out that Dick's leadership as President, Chief Operating Officer and partner has allowed our technical team to really examine these new and important reserves; and our operating teams to put this knowledge into action, even while drilling and completing wells at a eddy pace.

Having said too much today about Hawk Field Services, and Eagle Ford Hawk Field Services is doing a great job of keeping up with the rig and keeping up with all the new oil and gas that we're producing down in the South Texas area. And KinderHawk, our joint venture with Kinder Morgan, is doing a wonderful job of getting our gas to markets in the Haynesville Shale.

Our assets provide our shareholders with decades of growth potentials. Our operating and technical advances ensure that our activities are durable. And our conservative financial management and outlook will keep us out of trouble.

We are ready for questions at this time.

Question-and-Answer Session

Operator

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

Gil Yang - BofA Merrill Lynch

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

Richard Stoneburner

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

Gil Yang - BofA Merrill Lynch

End of 2010, you mean?

Richard Stoneburner

Correct.

Gil Yang - BofA Merrill Lynch

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

Floyd Wilson

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

Gil Yang - BofA Merrill Lynch

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

Richard Stoneburner

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

Floyd Wilson

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

Gil Yang - BofA Merrill Lynch

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

Floyd Wilson

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

Gil Yang - BofA Merrill Lynch

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

Floyd Wilson

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

Gil Yang - BofA Merrill Lynch

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

Floyd Wilson

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

Operator

We go next to Dick Kindig with Keeley Asset Management.

William Richards Kindig

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

Floyd Wilson

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

William Richards Kindig

This is by year end 2010?

Floyd Wilson

That's correct.

William Richards Kindig

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

Floyd Wilson

That's correct.

William Richards Kindig

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

Floyd Wilson

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

Richard Stoneburner

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

Operator

We go next to Michael Hall with Wells Fargo.

Michael Hall

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

Richard Stoneburner

You mean capacity for Petrohawk, Mike?

Michael Hall

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

Floyd Wilson

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

Richard Stoneburner

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

Michael Hall

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

Floyd Wilson

All of it?

Michael Hall

All of it.

Floyd Wilson

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

Michael Hall

Co: *** Optimize start

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

Richard Stoneburner

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

Michael Hall

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

Richard Stoneburner

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

Michael Hall

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

Richard Stoneburner

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

Operator

Next is Leo Mariani with RBC Capital Markets.

Leo Mariani - RBC Capital Markets Corporation

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

Floyd Wilson

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

Leo Mariani - RBC Capital Markets Corporation

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

Richard Stoneburner

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

Leo Mariani - RBC Capital Markets Corporation

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

Floyd Wilson

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

Leo Mariani - RBC Capital Markets Corporation

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

Richard Stoneburner

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

Operator

We go next to Thomas McNamara with Impala Asset Management.

Thomas McNamara - Impala

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

Richard Stoneburner

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

Floyd Wilson

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

Thomas McNamara - Impala

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

Mark Mize

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

Thomas McNamara - Impala

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

Mark Mize

To the AH [ph] growth.

Operator

Next is Brian Corales with Howard Weil.

Brian Corales - Coker & Palmer

Have you all looked at, maybe, restricting wells in the Eagle Ford, or any other trends for technologies, from what you've learned from the Haynesville to the Eagle Ford?

Richard Stoneburner

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

Floyd Wilson

Brian, Dick failed to mention one of his exciting initiatives here at the company have been to create a formal venue for technology transfer between the groups. And while we have separate operating teams, then he's on a regular basis to describe new findings and historical stuff and just, bat the ball around and see what the design engineers come up with. So I think Dick's group is going an awfully good job of making sure that those groups are up on the intricacies that each one may find out about.

Brian Corales - Coker & Palmer

Could we assume, maybe that Black Hawk is going to see similar declines as Haynesville, with the restricted rate there? I mean, you're calling at 50ish percent, not the 70-plus?

Richard Stoneburner

I think it's too early to say that, Brian. We just now mentioned that today, the first time we really spoken to first-year declines, and there's a reason. We actually have a handful of wells that have been on for a year. So we don't want to outrun our coverage and make statements that aren't based on actual data. That's one of the reasons we've been hesitant to come out and, specifically, give any kind of range of increases in the EUR, but I do use the term significant anytime I can. And I think that conveys that it's not any significant. Anyway, we're going to wait until we make any comments about the declines, but we certainly see a diminishment in the decline with the tighter chokes and what we hope is going to be an increase from the EUR.

Brian Corales - Coker & Palmer

One final one on the Eagle Ford, I mean you all done a good job staying in the infrastructure in front of drilling, and how does that stand specifically at Black Hawk and Hawkville? Are you all mostly there? I mean is infrastructure, at that stage, ahead of the drilling?

Stephen Herod

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

Operator

Next is Ronny Eisemann with JPMorgan.

Ronny Eisemann - JP Morgan Chase & Co

In the Haynesville Shale, do you still have about 2/3 of your frac jobs hedged?

Floyd Wilson

No, the coverage ran out on that particular safety feature we had tried to built in. So right now, it's just -- we're getting these jobs priced as we go.

Ronny Eisemann - JP Morgan Chase & Co

With maintaining the CapEx budget, how much -- is the new wellbore design factored in, in keeping the CapEx flat from previous guidance?

Floyd Wilson

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

Operator

Next is Ron Mills with Johnson Rices.

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

Just following on the slide on your Analyst Day presentation. If you've passed forward 12 months and you have your leased capture issues in the Haynesville pretty much behind you. What would you forecast in terms of above rig allocation between the Eagle Ford and Haynesville given the relative IRR curves that you provided at the Analyst Day?

Floyd Wilson

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

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

I'm just curious, a little bit more activities all else being equal just at the relative prices.

Floyd Wilson

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

Richard Stoneburner

I would just add just one thing to that, or I would add one thing. we did have a decrease in Haynesville rig count by one go into 12, which is just like Floyd said, we don't really know what you're going to do and we did suppose if I decrease, but time will tell in terms of how much that actually becomes.

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

Business for Mark, just in terms of clarification on your guidance, nothing's really changed, including your initial cut that is that 2010 that you provided in the analyst they.

Mark Mize

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

Operator

We go next to Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Given the contemplated sale of your Fayetteville Shale properties, any thoughts on the value of trends, or Bcfe that you booked at year-end last year and 1.5 Tcfe of improved reserves that you estimate?

I would give you a number except for the Steve Herod. continually outperform anything that we can dream of. You have as much knowledge of that as we do. It's vary the property basically, just have to tell you I'm a defense about it. It's not to us but it's they operated by our partner there is doing such a great job. It's growing development costs are well in line with our outlook for gas prices. So 300 of these, or 85 million a day are thereabouts should command a nice price if that's the direction we choose to go. And I think we have miles of pipe the ground there, or 110 miles of well located pipe in the ground that has some great value as well.

Dan McSpirit - BMO Capital Markets U.S.

And then revisiting the restricted rate program in Gainesville, this ever makes sense to reverse that program? Should we ever see the day of higher commodity prices for natural gas? And what would that price be, or what price is necessary to maybe again, reverse that program?

Well, we're running some sensitivities of that just here recently, and we're finding that you'll have to be faced with the real dilemma somewhere north of $6 an m if you're going to have to make a choice between PV and ultimate reserves, if you feel like you're actually impacting the ultimate reserves favorably with these back pressure on the reservoir, you might give up some of that favorable impact by going for PV. So there is a point in the price cycle when your PV is better at unrestricted rates, and that number is a little bit north of $6.

Dan McSpirit - BMO Capital Markets U.S.

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

Floyd Wilson

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

Richard Stoneburner

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

Operator

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

Unidentified Analyst

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

Floyd Wilson

Leasehold in the current quarter was $100 million.

Unidentified Analyst

And just with the balance sheet, just looking at the current liabilities, in terms of the crude oil and natural gas capital cost, should we expect that accrual, of the capital cost to the flat point or what's driving the increase their like it used to be creeping up each quarter? When should we expect that to flatten out, or how should the model but going forward?

That accrual, honestly really does get back to the timing and operations of the company, and it will be very difficult for me to kind of forecast that accrual account number.

Anish Patel - Crédit Suisse AG

And then just with the acreage acquired, how much of the acreage you're acquiring is the newly sold versus I guess extension of current leases and kind of maintenance of the acreage position that you already have? You have that number?

Richard Stoneburner

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

Unidentified Analyst

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

Floyd Wilson

If I look at that, I think that's not only right. But let me see.

There was $854 million spent on drilling and completion year-to-date, and there was about $406 million that have been for the acquisitions year-to-date and then again, $100 million in the current quarter.

Floyd Wilson

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

Operator

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

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Source: Petrohawk Energy Q2 2010 Earnings Call Transcript
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