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Petrohawk Energy (NYSE:HK)

Q3 2010 Earnings Call

November 02, 2010 11:00 am ET

Executives

Floyd Wilson - Chairman and Chief Executive Officer

Richard Stoneburner - Founder, President and Chief Operating Officer

Tina Obut - Senior Vice President of Corporate Reserves

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

Analysts

Michael Hall

Dan McSpirit - BMO Capital Markets U.S.

Chris Pikul - Morgan Keegan & Company, Inc.

John C. Nelson

Stephen Berman - Pritchard Capital Partners, LLC

Brian Corales - Howard Weil Incorporated

Gil Yang - BofA Merrill Lynch

Marshall Carver - Capital One Southcoast, Inc.

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

Leo Mariani - RBC Capital Markets Corporation

Joseph Allman - JP Morgan Chase & Co

Andrew Coleman - Madison Williams and Company LLC

Robert Morris

Operator

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

Floyd Wilson

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

Well, third quarter 2010, our results this quarter were excellent. We achieved all of our targets and did so at our profit to shareholder. Everything is working quite well at Petrohawk. Production grew substantially quarter-over-quarter, and we expect substantial growth next quarter as well. And we will report significantly increased proved reserves at year end.

We are in a high growth phase of our property development where production and proved reserves have been added at tremendous rates, driven largely by lease capturing in the Haynesville Shale. And as our restricted rate program there becomes more meaningful and flattening our PDP decline, the production we add is stacked on an ever higher production base.

In the middle of next year, we will dial down the activity in the Haynesville Shale dramatically. At the time when all of our key acreage there will be held by production, it is hard to overemphasize the importance of our activities to get to that point. Our ability to do so successfully underpins a significant portion of our future value and represents captured highest quality acreage in the play.

The Haynesville Shale is a world-class natural gas play, and we own the heart of that play. The imbalance that we and others have created by continuing to grow in a negative price environment will not last forever, and so we march on for the time being. And this quarter, we marched on protected by hedges, protected by continued operational efficiencies and protected by our solid balance sheet and very strong liquidity.

We accepted much higher-than-expected levels of capital spending from our non-operated partners, as they address their own lease capture issues. And we have accepted higher levels of overall spending today in order to predict future value at a time when we believe prices will be higher, costs would be lower and value will be recognized.

There is more clarity of information in the natural gas market today than there has been on the last year or two. Our realized prices this quarter were $4.20 per Mcf, which is over $1 higher than the realized price during this time last year of $3.13 per Mcf. At a time when last about the shale era was understood, the size and duration of new, major gas plays are more well understood, the size of the course in those plays are more well understood, and the cost to produce the highest quality portions of those plays is more well understood.

Our decision to push to conclude the lease capture phase in and Haynesville Shale was not taken lightly. Our balance sheet affords us this flexibility and that is not an accident. We delivered 100 million more in proceeds from divestitures in 2010 than expected, and our latest borrowing base redetermination, which takes our facility higher by $750 million, shows that even with today's low natural gas prices, we are adding significant value.

We managed our way through severe cost inflation in pressure pumping services, which significantly increased well costs. Although we believe this to be somewhat temporary, we feel that the frac cost inflation we've experienced in both the Haynesville and Eagle Ford Shale has peaked and should improve next year. First, we expect that new equipment coming to existing companies, and some new companies entering these plays will help reduce shortages. Second, we believe our ability to execute our new well-designed, and the Haynesville Shale will garner significant savings. That design is being tested this year with full implementation scheduled for next year.

Lastly, we'll have 16 operated rigs running in the Haynesville Shale in the first half of 2011 versus the planned seven rigs running there in the second half of 2011. Many other operators will also be scaling down as their own lease capture effort issues are addressed. The market dynamic is right for change.

Today, we have outlined an exciting plan for 2011, and we believe the time is right to bring the Eagle Ford Shale into the forefront of our capital spending and production profile. We aren't going to wait for a lower drilling level in the Haynesville Shale to increase our Eagle Ford Shale activity. We'll run 12 or more rigs in the Eagle Ford, all of next year, targeting for the most part, the condensate rich areas of the play, particularly at Black Hawk.

Increased Eagle Ford Shale drilling is the perfect complement to our ramp down in the Haynesville Shale. We've talked to this year about reacting to gas prices and looking ahead to form plans around what gas prices might do in the future. With the visibility created by our lease capture efforts, our hedging program and our divestitures, we are prepared to react appropriately in the future. We have constructed a durable plan for these times.

We planned ahead to have the capital capacity for this important job, and we'll continue to plan ahead and share those plans with the marketplace.

Today's call comes with the significant amount of operational detail, which Dick Stoneburner will discuss. Dick?

Richard Stoneburner

Thanks, Floyd. Petrohawk continues to experience excellent operational results in all areas of the company. With the Haynesville and Eagle Ford being the primary drivers to providing the double-digit production growth from the second to the third quarter. While the escalation of drilling and completion costs during the second half of 2010 has caused the company to increase its overall capital budget, we believe the performance that is being delivered with that capital is amongst the best in the industry.

It's also worthy to note that this historical period of lease capture in two of the best plays in the country is entering its final phases, after which Petrohawk will consider significant adjustments to its capital program that will be in accordance with prevailing commodity prices.

Before speaking to the specific operational results, I would like to address the increase in the 2010 capital budget that we have announced today.

Two components of the total corporate capital budget that are projected to be under full-year guidance are the acquisition and mid-stream pieces. Year-to-date acquisition capital is $455 million, up only $55 million during the quarter, and approximately $45 million under the full-year budget of $500 million.

Year-to-date, Hawk Field Services' capital was approximately $190 million, with current projections indicating that it should be significantly under our announced 2010 budget of $280 million. However, drilling and completion capital at the end of the third quarter is $1.36 billion.

There are three main factors that have driven this aspect of our capital budget. Firstly, non-operated capital through the third quarter is $354 million, which is approximately $70 million higher than we had forecast for the full year, and current projection indicate that it will comprise approximately 50% of the total drilling and capital overage that we are estimating for the full year.

Secondly, well costs in both the Haynesville and the Eagle Ford has escalated approximately 20% since the budget was formulated. Specifically, assume that well cost at the time that budget was announced were $8.9 million in the Haynesville and between $5.8 million and $6.5 million in the Eagle Ford. While current well costs are averaging $10.5 million in the Haynesville and between $7.1 million and $7.5 million in the Eagle Ford. It should come as no surprise that the vast majority of those cost increases have come as a result of the cost of pressure pumping services in both field areas.

Lastly, there's been a significant component of the budget overage related to cost that cannot be readily forecast.

These include unleased mineral interests in wells that have been drilled that the company has a larger ownership than projected and surface acquisitions related to opulent locations and urban locations, all related to the Haynesville.

Collectively, these items were largely unforeseen when the budget was planned, and did not become readily apparent until the second half of the year. Going forward into 2011 and beyond, we believe that we will have the flexibility within the capital budget to foresee and react to this type of spending.

Petrohawk also announced its 2011 capital budget today. Of the $2.3 billion budget, $1.9 billion is related to drilling and completion. This capital is evenly distributed between the Haynesville and the Eagle Ford at approximately $900 million each, with approximately $100 million allocated for the Fayetteville should the company decided not to divest that asset. It is important to note that while capital is being evenly distributed between the Haynesville and the Eagle Ford over the full-year period, the second half of the year, we are planning for an increase in rigs in the Black Hawk area, and a significant reduction in rigs in the Haynesville. It is the mid-year 2011 period that budgetary decisions made by the company to become more flexible and would be largely dictated by commodity prices at that time.

We have included the well cost assumptions for 2011 in today's press release, indicating that we are not anticipating a substantial reduction in pressure pumping services beyond our ability to deploy the new well design that mitigates some of the higher well costs in the Haynesville. Additionally, we have included a higher contingency component in our 2011 budget, while at the same time modeling well costs that we believe to be realistic to today's inflationary environment. So while we have a sense that the pressure pumping market will loosen, we are not incorporating that belief in our forecast for well costs.

Turning to the drilling statistics for the quarter. In the Haynesville, the company drilled 29 operated and 73 non-operated wells during the quarter, bringing the year-to-date total to 82 and 185 respectively. These data indicate that 40% of the total number of non-op Haynesville wells drilled year-to-date, were drilled in the third quarter, and it represents a 26% increase over the number of non-operated wells drilled in the second quarter.

Additionally, the company decreased its number of operated rigs from 16 at the beginning of the quarter to 13 at the end of the quarter, and we are currently operating only 12 rigs.

In the Fayetteville during the third quarter, there were a total of 149 wells drilled, with all, but two of those being non-operated. These data indicates that 45% of the total number of non-op Fayetteville wells drilled year-to-date, were drilled in the third quarter, and it also represents the same 26% increase over the number of non-operated wells drilled in the second quarter.

To further that point, total non-operated capital increased 15% quarter-over-quarter from the first to the second quarter, and 34% quarter-over-quarter from the second to the third quarter.

In the Eagle Ford, the company drilled a total of 21 wells, in which 19 were operated. Not coincidentally, the capital from this region is in line with budgeted expectations through the quarter and projected for the full year.

As mentioned previously, production from the quarter increased approximately 10% over the second quarter, from $625 million to $685 million. During the course of the year, the growth of all three of our core areas has been remarkable, and I'd like to highlight just a few facts regarding production growth that has been delivered today.

In January 2010, the company was producing 350 million a day from the Haynesville, and is currently producing 481 million a day, an increase of 38%.

In January 2010, the company is producing approximately 40 million a day from the Eagle Ford, and it is currently producing 101 million a day representing 150% increase.

In January 2010, the company is producing approximately 84 million from the Fayetteville, and is currently producing 98 million, representing a 17% increase.

The point of these numbers is to emphasize that while capital spending is being driven in large part by the industry's commitment to holding leasehold, we believe that the leasehold that Petrohawk is defending delivers production that is as good as any company can deliver, and we fully expect that when we announce the year-end reserves in February with our fourth quarter financial results, that the growth and development cost trends will be in line with the production that is being delivered quarter after quarter.

Specifically, we expect 30% year-over-year natural gas growth in conjunction with approximately 220% year-over-year condensate and NGL growth.

There are some specific operational results in both the Haynesville and the Eagle Ford that I think warrants to be mentioned. In both plays, we are continuing our efforts at reservoir optimization. In the Haynesville, that optimization effort continues to offer no surprises, with the possible exception being that the wells might be performing even slightly better than we have recently advised. In August, we made public a vast array of production decline data that has led us to increase the tight curve in the field to an EUR of 10 Bcf, up from previous projection of 7.5 Bcf.

I would like to emphasize that we did not merely attribute this increase to restricted rate production practices. We've also recently made public and extensive amount of analytical frac design data that suggests that it is a combination of production practice and continued modification and improvement of fracture stimulation that have resulted in improved well performance.

Petrohawk is also experimenting with several new completion concepts in the Haynesville, aimed at decreasing completion costs and improving overall well performance. Our zipper frac was pumped for about two adjacent wells of frac in alternating fashion from one stage to the next. This technique allowed Petrohawk to lower completion costs, as well as optimize the effectiveness of the frac. The company also pumped half fracs on four wells, with the intention of spending approximately half the normal cost to frac a well, while at the same time giving performance that is significantly higher than half of a normal completion. This would allow the deferring of additional frac costs to a time when frac costs have returned to a more normal level. The objectives of the concept were met, and these techniques provide alternative completion techniques in 2011 should frac costs remain inordinately high.

Lastly, Petrohawk has refrac-ed one of its oldest wells. This is a technique that has been utilized for more mature gases shale fields to increase overall recovery from a well. Early indications suggests that the operation was economically viable, and the company had several more candidates identified and scheduled in order to more fully test the concept.

While we have completed over 160 Haynesville wells a day and have utilized data from these completions, and production trends to support improved well performance in that play, we are just now seeing some of the positive benefits of reservoir optimization in the Eagle Ford. We are producing most of our Eagle Ford wells on between 15/64" and 16/64" chokes and are seeing what we believe are positive indicators of increased well performance.

We are also seeing enhanced well performance as a result of pumping hybrid-style fracs in Hawkville, as well as tighter pro cluster spacing and higher profit concentrations in both field areas. Specifically, the last four completions in Black Hawk had as much as 1,300 pounds of profit for lateral foot, and six per clusters per stage, and all other wells appear to be significantly better than the initial set of completions in the area.

Three of those wells had IP rates ranging between 3 million to 4.5 million cubic feet of gas per day, and between 1,400 and 1,580 barrels of condensate per day on 15/64" choke, and the last of the wells has an IP of 4.0 million cubic feet of gas per day and 1,800 barrels of condensate per day on a 16/64" choke, with 6,400 pounds flowing casing pressure.

Similar results have occurred in Hawkville, with the condensate wells ranging between 3.8 million and 6.5 million cubic feet of gas per day, and between 200 and 560 barrels of condensate per day on 16/64" choke, with between 4,700 pounds and 5,000 flowing casing pressure. Additionally, the early data suggests that the decline rates have decreased appreciably, as a result of both frac design and producing the wells on a more restrictive chokes.

There's been a lot written and spoken to regarding the number of unfrac-ed wells in the industry, with some referencing numbers into the thousands. While we cannot and will not speak to the entire industry, Petrohawk believes that the best course of action is to complete its wells as expediently as the availability of frac crews will allow. To that end, we currently only have 20 unfrac-ed wells in the Haynesville, and 21 unfrac-ed wells in the Eagle.

We believe that this approach provides the best and most predictable rate of return, does not burden future capital budgets with deferred capital, and does not provide future overhang in the gas market that good adversely affect the gas supplies we move from lease capture period in the area of more capital flexibility.

Finally in the Red Hawk prospect, we will start our third well later this month. The well has been designed to cost approximately $4.5 million, and is targeting between 150,000 and 175,000 barrels of oil. Should we be able to accomplish both goals, and we believe the project is commercially viable, particularly at a time when we're able to get some relief from pressure pumping costs.

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

Mark Mize

Okay. Thank you, Dick. Most of the details for the financial performance for the quarter can be found in the press release, but it's important to recognize two major themes that dominated the current period, one being strengthening of the balance sheet and the other is, the impact of the hedge program along with price realizations, and the bolstering of cash flows result.

During the third quarter, Petrohawk refinanced its senior notes that we're doing in 2013. Prior to the refinancing, we had an outstanding principal on those notes of just under $775 million at an interest rate of 9 1/8%. These notes were callable, but we first tendered for the notes and then if we reissue the principal plus financing costs on the go forward rate, on the new issuance of 7 1/4%. We were able to tender right at 85% of the 2013 notes that were outstanding and then we've follow through by calling the remainder of the notes.

You'll notice our interest expense line in this quarter does reflect costs associated with the refinancing. It's about $47 million in total, and then only a portion of that was actual cash cost. And we did exclude that number from the financial results in the selected items table in the press release.

Another recent development, which has implications for the balance sheet, as well as serves as an indication of the strong reserve growth, was the redetermination of the oil and gas borrowing base, which was raised to $1.75 billion and previously had been set at just over $1 billion. And that the redetermination was based on the internally generated estimate of our reserves at September 30. This, coupled with the borrowing base associated with Hawk Field Services brings the total borrowings base to just over $1.8 billion.

We now have a total of 25 banks that participate in our facility, and we did see a strong appetite as we work through the redetermination processed. As part of the process, we did address the potential divestiture of the Fayetteville. And upon the completion of such a transaction, if that occurred, we would expect the borrowing base reduction somewhere around $200 million.

So with the full redetermination now behind us, we have a fairly transparent view of our liquidity position, and we feel that we're very well-situated to more than satisfy the capital needs of the company for the foreseeable future.

Turning to hedging, as previously stated, Petrohawk continues to target, to hedge about 70% of our anticipated production. Based on recently announced guidance, we currently have about 60% of 2011 production hedged with gas at a floor of about $5.55, and then we also have 5,500 barrels of oil hedged at a floor 78.

We've recently added several contacts to our 2012 position. And right now, we have 265 million a day of gas hedged about a $4 or $5, and 10,000 barrels hedged at a floor of $77 and we'll continue to monitor the market and layer an additional contracts, kind of opportunistically. And then we've also posted an updated hedge schedule to our website.

A few more comments regarding price realizations and hedging and then we'll move on to operating expense. Price realizations and hedging are two areas that we consider to be of great importance here at the company and their areas where Petrohawk has done a good job. We did continue to realize high NYMEX price realizations for both oil and gas. And we posted realizations this quarter of 96% of NYMEX for both commodities. We posted natural gas liquid realizations of 46% in NYMEX, which is in line with expectations. Hedging did afford us almost $1 [ph] on natural gas this quarter and just over $2 on oil. The combination of the realizations and the results of the hedged portfolio, in particular, which yielded about $60 million of cash proceeds in the current quarter, has kept cash flow healthy, and continues to protect the capital program.

On a per unit expense basis, we're pleased with the results of lease operating expense. They continue to trend lower in the current quarter, and that is driven by increased production, but also our divestiture of properties that have, historically, had higher operating costs. For example, we did divest the Mid-Continent package for $123 million this quarter. And keep in mind, that divestiture occurred right at the end of the third quarter, so the effect of lower LOE would be foreseen in the fourth quarter of this year fully baked-in.

G&A does include a certain level of legal expenses that we have accrued on cases of the ongoing operations of the company. They were expenditures that were not foreseen at the beginning of the year went through our forecasting processes. So G&A will be over at the high-end of guidance, as we close out the year.

We also continue to collect severance tax refunds, which are going to be an ongoing part of the business. The timing and the magnitude of this refund is difficult to predict. We do not recognize the impact of those refunds until we have approval from the State of Louisiana. You will note though, in the current quarter, the severance tax refunds more than offset current period expense, and it did result in a credit balance on this line item of right at $3.2 million.

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

Floyd Wilson

Thanks, Mark. Well, we presented a strong story today to match our third quarter. Our assets will provide shareholder value for decades to come. And recent events have shown as never before, we are in a race today to protect this national treasure, homegrown abundant, clean, natural gas. And Petrohawk continues to protect these gas assets. We recognize the disconnect between our asset value and our trading value, and we always have considering the opportunities and alternatives to bring this value forward.

I think it's time for questions, if there are any now. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Michael Hall with Wells Fargo.

Michael Hall

Just quickly on the 2011 growth outlook, looking at the kind of liquids' percentage of total implied by the Eagle Ford, $175 million a day that you put in the release, if I think that 50% of that is liquids, like you said, that's a little lower than maybe it was in the Analyst Day presentation. Is there a meaningful amount of liquids coming from anywhere else that would bump total corporate liquids higher? Or is there something slowing the growth there relative to prior expectations?

Richard Stoneburner

I don't know the slowing. It's just we're 98%, 95% natural gas today. It takes a while to reverse that trend, I guess, if I'm following your question. But most of the growth is from the Eagle Ford. All of the growth is from the Eagle Ford.

Operator

Our next question comes from Joe Allman with JPMorgan.

Joseph Allman - JP Morgan Chase & Co

In terms on the 2010 budget, I know the total budget's $2.55 billion, could you give us the details on what's the drilling and completion part of that? And then, could you break that up by Haynesville, Eagle Ford, Fayetteville and then what remains in terms of other in mid-stream?

Richard Stoneburner

Sure. The total drilling and completion budget is a little bit over $1.8 billion. It's about $1.3 billion Haynesville, of which about $335 million of that is non-op; it's about $350 million in the Eagle Ford; it's about $135 million in the Fayetteville; which is virtually all that $115 million of that's non-op.

Joseph Allman - JP Morgan Chase & Co

And so that leaves $750 million for other and so what...

Richard Stoneburner

$750 million for op -- with the non-drilling and completion?

Joseph Allman - JP Morgan Chase & Co

Yes.

Richard Stoneburner

Okay. Yes.

Joseph Allman - JP Morgan Chase & Co

That seems higher than what you've previously thought earlier in the year. Could you talk about that a little bit?

Floyd Wilson

No, I believe we've set the expectation for about $500 million in acquisition for the year. And I think it was $280 million for mid-stream.

Richard Stoneburner

And there's another $40 million of just miscellaneous other in there that I didn't mention. But again, it's about $18 million, $25 million on the drilling and completion.

Joseph Allman - JP Morgan Chase & Co

And the Eagle Ford, I think, that appears to stay the same since the beginning of the year. I'm surprised with that -- with the increase in costs.

Richard Stoneburner

Some of that is the inventory of fracs that are still out there. That's kind of mitigated the -- in that particular case, a lot of the increased well costs.

Joseph Allman - JP Morgan Chase & Co

And then for your 2011 budget, and I know you've talked about the average Haynesville well costs at $9.8 million per well. Does that assume some efficiency gains from the new well design?

Richard Stoneburner

It does some. I think we're trying to make a fairly conservative forecast on that number. It's got some troubled days that we had baked-in just to make sure that we acknowledge that there are a few wells that go over the number of days we had forecast, but it has some efficiency -- we hope it's more efficient than what we have forecast. I think we're just trying to be realistic as we see here today, what those well costs are going to be, but hopeful that pressure pumping does mitigate.

Operator

Our next question comes from Leo Mariani with RBC.

Leo Mariani - RBC Capital Markets Corporation

Floyd, you made a comment at the end of the prepared comments about you guys would consider opportunities to bring value forward, and there's a big disconnect between the asset values and the equity value. Are you guys kind of taking a hard look at any of those right now, or investigating that? Could you give us a little bit more color there?

Floyd Wilson

Leo, we are constantly evaluating all facets of value at the company, and we're just always in that processes. I can't say anything different than that. There's nothing startling to report here other than there is quite a large disconnect in our opinion between our asset value and how the stocks' trading these days. And we think that this natural gas is going to be extremely valuable in the future, and we intend to hold those assets. We're always looking at various ways to bring that value forward.

Leo Mariani - RBC Capital Markets Corporation

Jumping over to the Eagle Ford, you guys talked about getting your well costs down around $4.5 million. Is there something different that you're doing with that well? I mean, it seems like a lot of the costs at Eagle Ford is kind of been moving up. What's kind of the new strategy to sort of get some of the oil underground there?

Richard Stoneburner

Did I hear your question being $4.5 million?

Leo Mariani - RBC Capital Markets Corporation

Yes. Is that what you said? Maybe I got the number wrong.

Richard Stoneburner

No, maybe I misspoke. I'm sorry, Red Hawk, yes. That's specific to Red Hawk prospect. Average wells in Black Hawk are about $7.5 million, average wells in Hawkville, about $7.1 million.

Leo Mariani - RBC Capital Markets Corporation

I guess my question is related to the fact, how are you guys going to get the well costs down in Red Hawk? That's what I'm trying to figure out.

Richard Stoneburner

A little shorter lateral. We pumped 22 stages on the second well. We're hopeful that we can change the design just a little bit by virtue of profit per foot in our spacing without adding frac costs. So we can redesign the frac to be cheaper, but we think we've learned enough over the last several months to be more efficient with that frac, plus we're only doing a 5,000-foot lateral instead of a 5,800-foot lateral. So we'll just see. We think we can improve efficiency, reduce cost, and that's our target.

Floyd Wilson

Leo, the wells are just generally more shallow anyway at Red Hawk. There is a few, fewer rigs days involved as well.

Leo Mariani - RBC Capital Markets Corporation

And hopefully, it will get to be economic at the end of the day on those new parameters of the $4.5 million and 150 to 175.

Floyd Wilson

That's our target. We're certainly optimistic along those lines. We're going to give it a workman-like shot. That's a very large area up there with a lot of oil in play. So we just need to figure out how to get it out.

Leo Mariani - RBC Capital Markets Corporation

I guess just jumping over to the Bossier, it looks like you guys had a first well resolved there, looks pretty solid. How does that kind of help you think about Bossier prospectivity on your acreage, and do you have an estimate of the EUR for that first well?

Floyd Wilson

Leo, one thing I'm kind of proud to say is that Dick and his staff, their estimates and vision of the Bossier haven't changed since we first put it out sometime back. And we believe we have well over 100,000 acres that;'s perspective for the Bossier. That Bossier well that we drilled, our first one, of course, is one of quite a few wells drilled by the industry. It is a well that's acting just like one of our very good Haynesville Shale wells on a restricted rate basis. I don't know if we've come to an EUR guess on it, but it's probably in the 7, or 8, or 9 Bcf range.

Operator

Our next question comes from Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

Could you talk about the dynamic -- where you said that you were working interest, or your interest in some of the wells in Haynesville, are higher than you'd expected? What's going on there?

Floyd Wilson

There's a small portion of that, Gil, that has to do with, a tiny portion that has to do with non-consent interest that we take up. The larger piece of that has to do with the interests that are unleased by the time we drill. And usually, in these days, the expectation of a lease amount is higher on the lessor's part than our ambition there. So just go ahead and drill the well and essentially carry the portion of the cost attributable to that lease owner. We own more of the well, through 100% of payout, and then the interest reverts back to the lease owner, the mineral owner.

Gil Yang - BofA Merrill Lynch

And that's the bulk of the 50% increase?

Floyd Wilson

The 50%...

Richard Stoneburner

The comment was about 50% of the drilling and completion overage as attributable to the non-op piece, then the balance of that is a combination of increased well costs and some of these other items that we could not forecast with confidence when we put the budget together. That number was, I think, somewhere probably in the $50 million range that was not in anticipated cost at that time we put the budget together, just as Floyd has described.

Gil Yang - BofA Merrill Lynch

And can you just comment quickly on the people that are going non-consent, what's going on there? Are they just running out of capital, or they just don't want to be in the well?

Floyd Wilson

We can't say, or know that, Gil. We don't have much of that going. In fact, occasionally, Petrohawk will go non-consent on a well if we don't like the geology, or don't like the AFE,[ph] Or something. That's not a big piece of it. So I'll have to say that where our wells are located, we get to -- it's a minuscule part, it's an actual non-consent by our industry partners.

Gil Yang - BofA Merrill Lynch

With the wells on restricted rates, can you comment on what the LOE, does it have any effect on LOE for other company?

Richard Stoneburner

I don't think so. The general gross production volume increased, but I don't think the restricted rate practice. And again, I accuse myself of doing this as well, it's really reservoir optimization. It's a combination of our production practice and our completion practice. So all in all, we're just seeing better performance, and I guess indirectly, it does affect LOE but not directly.

Gil Yang - BofA Merrill Lynch

And finally, you may have mentioned this, I may have missed it. You said that, you've stated the $1 million in the frac costs for redesigned wells, but when you first presented it, you also said the wells might costs a fair amount. Was the $1 million offset on the frac job, was the increase in cost that you are realizing?

Richard Stoneburner

The way the well is designed, the cost of the well to the point of fracture stimulation is neutral. You run less production casing, but you run more expensive intermediate casing, so there's a few trade-offs in the wellboard design as is drilled and cased. But those offsets are basically neutral. So the savings is basically entirely from result of lower frac costs.

Gil Yang - BofA Merrill Lynch

So that the net $1 million savings is for the whole well?

Richard Stoneburner

That is the target, correct.

Operator

Our next question comes from Brian Corales with Howard.

Brian Corales - Howard Weil Incorporated

A couple of questions more on the Eagle Ford, on your 2011 budget, it doesn't look like you all are assuming any efficiencies. I mean, is that something that you could probably drive costs lower? And you all are just being conservative? Or you all seeing continued cost escalation?

Floyd Wilson

We certainly are seeing cost inflation in the Eagle Ford just as we've seen it in the Haynesville. So we're not really projecting any real improvements for 2011. We do think that frac costs may moderate sometime next year and certainly, beyond. But that hasn't happened yet, so we're not projecting it. I don't know if we're being conservative, or just trying to be realistic about what we expect to happen there.

Richard Stoneburner

Brian, let me just add an anecdotal comment, I guess, in terms of how costs have increased in the Eagle Ford, because about a year ago, call it the summer of '09 when the rig count was quite low and we were just one of a few that were drilling in the Eagle Ford, our frac jobs are very comparable frac jobs than what we do today. It was around $600,000. That same basic frac job today is about $3.5 million. And that just gives you a pretty glaring example of where pressure pumping has gone over the last 12 to 15 months.

Brian Corales - Howard Weil Incorporated

Do you all see a reprieve in that in the next several quarters?

Floyd Wilson

We can't say for sure. We do say that in a general sense in the dry gas plays, we anticipate our sales and a few others will be running less rigs. We understand that many of the large suppliers and service providers are bringing new equipment to the plays. And we've had discussions with any number of new entrants, new frac companies joining the plays. So I think the combination of all of that tells us that somewhere in the future, there's going to be less of a shortage, thereby maybe less pressure on the price being so high. It hasn't happened yet, and we're certainly not counting on it within our 2011 budget.

Brian Corales - Howard Weil Incorporated

And then one final question, can you all maybe run through timing of the Fayetteville Shale? Is that likely in just early next year?

Floyd Wilson

Well, it's hard to say. We have hired a bank and we have got a data room open, and we're going through that process. As I've mentioned before, it's very good property. We're price-sensitive, so we don't feel the need to take just any amount for it. We're going to let the process play out. You would have to say at this time of the year, it's more likely, it would be a 2011 transaction as far as the closing, is there was to be one.

Operator

Our next question comes from Marshall Carver with Capital One Southcoast.

Marshall Carver - Capital One Southcoast, Inc.

Just a little more color on the Fayetteville Shale. Is there a certain time when bids are due and you mentioned the data room is open now.

Floyd Wilson

We haven't said an exact bid date. We normally don't do that in the early stage of a property that's significant. Theoretically, if all goes well, we'll try to have bids in sort of before Thanksgiving, or by December or so, and take it from there. We just don't have that clarity quite yet. As you know, Steve Herod is very experienced in this, and his running that process. He's not sitting here today, but it will be an orderly process. We just have to let it play out in the way that we know is the highest chance for success.

Marshall Carver - Capital One Southcoast, Inc.

And moving to the Black Hawk wells, you had a big improvement in the IP rates, have those wells been on production very long at all? Do you have any feel for EURs? Or how long have those wells been on production?

Floyd Wilson

I think the one that was the first, I would call, reservoir optimization success was the Atlantic B[ph] , and I think that was somewhere in mid-August range. So it's probably been on running for about 2.5 months. I would tell you that these four wells that I referenced in the call are liable to drive our assumed EUR for the field up, but we haven't made a decision to change that in the same fashion that we have the Haynesville. But it wouldn't surprise me if at some point in the future, we do make a change in the assumed EUR for the field.

Marshall Carver - Capital One Southcoast, Inc.

But it's safe to say it's probably towards the high end of the range that you've provided in your recent presentation?

Floyd Wilson

They're probably over the range that we provided, but I don't want to do that as a field-wide assumption. But those wells are at or better than what we had as our field-wide assumption.

Marshall Carver - Capital One Southcoast, Inc.

And just one quick question on the severance tax refund in the third quarter, you said it's hard to predict heading forward. Do you any clarity on what it would be for the fourth quarter or not?

Mark Mize

The reason it's hard to predict, that is because we do not recognize any of those refunds in our financials until we have approval from the State of Louisiana. So I would need to try to predict how their process is going to run. So that's the difficult. But for modeling, you could probably -- we had about $14 million booked this quarter, and that would probably be a fair number for you to use.

Operator

Our next question comes from Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Question number one, I guess, concerning your lease capture timeframe of mid-2011 in the Haynesville, does that schedule or go at all involved, allowing certain leases to expire from now until then?

Floyd Wilson

Not necessarily so many right now, Dan, but we've said all along, that we have some leasehold along the fringes of the play, particularly on the north side that we don't value highly, that we didn't pay a lot for, and we intend to let those expire under their own term, unless new developments dictate otherwise. We have always risked our acreage in the play significantly. And it looks like that risking that we've reported any number of times publicly is still about where we would say it is -- about where we would agree it is today as well.

Dan McSpirit - BMO Capital Markets U.S.

And then at what NYMEX price, I guess, do you need to see or realize to put your foot back on the drilling accelerator in the Haynesville?

Floyd Wilson

That would be a really unpopular thing to contemplate right now, Dan. We said earlier this year that, we think that once the lease capture phase is done in the Haynesville, that it's almost incumbent on us and others to keep the drilling at a slower pace, even if gas prices rise a bit. We like to make sure that gas prices have risen due to a demand increase rather than just a momentary supply decrease. So it's a really complicated issue, of course. Higher gas prices, the field is extremely profitable, but we would intend to display that out as the macro picture emerges. We don't see that in the strip today so much. So we're planning on these lower levels in the dry gas regions and the higher levels of drilling in the condensate-rich regions for the next few planning periods.

Dan McSpirit - BMO Capital Markets U.S.

You state that you expect 2010 accrued reserves percentage growth to be in line with the expected full-year production growth rates. What are you assuming as far as offsets both for per producing location? And should the PUD percentage change much from last year's figure?

Floyd Wilson

I don't believe the PUD percentage is going to change much materially. And I don't think we'll have any different in the number of PUDs per well than we had last here. I think it was three. Last year, mathematically, worked out to 2.6 PUDs per producing well. And I don't know that we would expect that to be any different this year. I think it was a few more in the Eagle Ford, maybe five, was it or...

Tina Obut

A little bit higher than three, I think.

Floyd Wilson

Yes, it was higher than three. But it is a complicated equation and you really have to go through the whole year process to have that answer.

Dan McSpirit - BMO Capital Markets U.S.

Back to the Haynesville and reserve bookings, you talked about an average recovery of I think it was about 10 Bcfe per location. Should the same be expected at year end this year? And by how much will this be influenced by the restricted rate program, recognizing that the sample set of drilling results by year end this year is that much larger?

Floyd Wilson

Dan, keep in mind that at each year end, we go through a very rigorous process with an outside reserve firm, and we adopt their numbers to start each new year off with. We don't really have that study from them at this time. Our internal projections in the past have always been very close to what we end up with from our outside engineering consultant. We think the data suggests that these, our internal numbers are accurate, and we'll just have to see how the process plays out. It's quite likely, I'll just say this, a little out of school, that there'll be some conservatism around this whole Reservoir Optimization business, both on restricted rate size and the optimal amount of propline [ph] and the optimum number of per clusters et cetera, until there's a little more history. So we don't really know what to expect this year. But we're highly confident that the data will direct towards higher estimates of recoverable reserves than in the past.

Operator

Our next question comes from Bob Morris with Citi.

Robert Morris

Dick, you mentioned the encouraging economic results from the refracs in the Haynesville. Can you give us a little more detail on that as far as maybe the pump up in the rate, once you did that refract and if that might be additive to the reserves per well that you booked in those locations?

Richard Stoneburner

I think in general, it was a positive result. It's a one sample set right now, and so it's hard to really put a number to it other than the fact that what we did was clearly, economically viable. I would add that we think we can do it a whole lot better than what we did. There were some things that we learned that would allow better diversion, better comp rates, other kind of engineering aspects of the job, that we really think we can do a lot better. But to speak specifically, I think it will be a little bit too much to get into right now.

Robert Morris

So you'd continue to do more of those as you compete on an economic basis, with drilling Bossier wells or new Haynesville wells, or is it just something you're experimenting with right now?

Richard Stoneburner

We've got a group we call a strategic planning group and they are always looking at ways to optimize the value of our field. These are test cases, these are things that we want to learn about, if we will implement them across the board? No. What we do a couple of more, if the budget allows, yes.

Floyd Wilson

I think that's fair. It's one of these things that we do to provide a full set of data to ourselves for the future development and optimal production of the field. And it will be one of those quivers, one of those eras in the quiver for some future point in time when it will be really valuable. We got to get our data down though first, and that's why we do these tests. And then we report on them as well.

Robert Morris

On the Fayetteville, you mentioned you want to take any price. If you end up not getting any acceptable bids for that and don't sell it, how would that impact the $2.3 billion budget for next year?

Floyd Wilson

No impact. We're well set for this year and next, and with the liquidity we've provided ourselves, it has no impact, whatsoever. I should have put in my call notes that our current capital plan for 2010 and 2011 is not dependent on future divestitures, period. We also, period, do not intend see if we need to raise equity, or raise any new debt beyond what our bank revolver provides for, period.

Operator

Our next question comes from David Heikkinen with Tudor, Pickering, Holt.

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

Just thinking about your budget for next year and your slowdown in the Haynesville, are you committed to spending less in the second half of next year than you are in the first half?

Floyd Wilson

Yes, of course. The budget works exactly that way and it's strictly an outgrowth, an output driven by the input of the rigs that we have running.

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

And then in 2012, you'd had a multi-year plan out that had your overall budget basically, coming down again. If we pursue a run rate what you talked about in Haynesville, not increasing even with gas prices, makes me think that Eagle Ford kind of runs continuously out of whatever your third quarter or fourth quarter run rate is, is that a fair way to think about '12 now?

Floyd Wilson

Yes. Let me say this. The figures that we put out at Analyst Day, we've made sure to catch those as directional. And the ones that were that far out, our budget for 2011 is fully loaded and evaluated and we're very comfortable with that number. Beyond that, there've been so many changes during the course of 2010. We don't really feel comfortable about projecting beyond, in other words, our gas price deteriorated further in '10, during part of '10. Our costs really accelerated, and we know much more about our leased capture abilities and needs now than we did early this year. So directionally, I would say that the Eagle Ford is going to march on and that the Haynesville will be emphasized a bit less than it has been in the past.

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

And just thinking directionally, kind of there's a path of the free cash flow neutral, or basic cash flow neutrality without anymore asset sales. Do you still see the company on that path?

Floyd Wilson

Yes, that's still our goal. We'll have to point out that the lower-than-expected realized gas price for 2010 puts a little pressure on that calculation, probably pushes it out another quarter, another financial quarter.

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

And then just on the Fayetteville Shale and if you kind of went through a lot of details around that, selling everything there, would you continue to sell your Midstream business? I mean what other things are out there that you're actually mulling over, where there's a disconnected value between the stock price and what you perceive?

Floyd Wilson

Well, David, there's a disconnect in value with everything that we have in the stock price.

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

So would you sell the Midstream, or the remaining Midstream? I mean, are there any other things, some modifications of the Eagle Ford assets? I'm just trying to get an idea of how you thinking about the sum of the part?

Floyd Wilson

Let me tell you how we're thinking about what's going on this year and in the future. It all has to do with properties that we define as non-core. And as soon as we define them that way, they're possible divestiture candidates. The Fayetteville is that for us, as our midstream assets. In each case though, we prefer that our midstream asset build out, be largely complete, so as to provide for the orderly development of the field in terms of the infrastructure. So the Eagle Ford Shale is a bit immature for that, so far. We probably need another year or two out there and yes, the remaining portion of the Haynesville infrastructure is something we might consider selling at some point in the future.

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

So just on the midstream side, what I think about the Eagle Ford, so you're building up volumes, you're reached more volume whenever you're not investing a lot of capital and you have volumes in the system so, you wouldn't do anything with that until probably '12 at the earliest?

Floyd Wilson

Well, I can't say. I would just say that certainly, right now, i think it would be -- the system isn't mature enough for us to really pursue that. It's going really well down there. We don't want to tamper with a winning formula that's allowing us to get our wells drilled, frac-ed and online quicker than anybody in South Texas.

Operator

Our next question comes from John Nelson with Macquarie Caps (sic) [Macquarie Capital].

John C. Nelson

Your acquisition capital spend for 2011 was actually bumped up from the Analyst Day estimate. I'm just wondering if that's consolidating properties within your current operation? Or if you guys were perhaps working on something else?

Floyd Wilson

I think it's just a more accurate appraisal of sort of the day-by-day small opportunities that come our way during the course of the year. And as I've said, we've try to make sure that the 2011 budget is fully evaluated and fully explained to the best of our abilities.

John C. Nelson

And then just on a clarification on the 30% to 40% production growth for 2011, does that assume a timing for Fayetteville divestiture, or is that an ex-divestiture number?

Floyd Wilson

That's without the divestiture figured in.

Operator

Our next question comes from Andrew Coleman with Madison Williams.

Andrew Coleman - Madison Williams and Company LLC

One, looking at this $8.4 million charge here for interest, is that the KinderHawk kind of add back? The management fee?

Mark Mize

Yes, on the statement of operations, if you recollect, KinderHawk is accounted for under the equity method. So you will see the equity investment income line, I assume that's the 8.5 [ph] that you're referring to.

Andrew Coleman - Madison Williams and Company LLC

Yes.

Mark Mize

That is correct. That's just the Petrohawk portion of the operational results of that JV.

Andrew Coleman - Madison Williams and Company LLC

And I've read somewhere that was $881,000 per month until 2015. It's just a lot higher. Should we think about that as a run rate, going forward or is that a...

Floyd Wilson

You're thinking of the management fee. There was a management -- for the KinderHawk were still employees of Petrohawk. There was a management fee being charged. That end though at the end of October. And those individuals now went over to KinderHawk and their employees of the JV. So that fee will not be charged. But that being said, that JV, under the equity method, to the extend there's income or loss at that JV, which is a completely separate third-party, we pickup our portion of that income or loss, and that's what you're going to see flow through on the face of the Petrohawk income statement. So there's a lot more to it than just that management fee you're referencing.

Andrew Coleman - Madison Williams and Company LLC

And then, I guess, stepping back to the reserve question here a little bit. Given that we're still in the acreage capture mode, when do you guys think about, I guess, for the two things, as I look at our -- you got potential to get higher EURs from your restricted rate and also potentially to look at down spacing options, I guess, so we've been looking at the first option, when do we start looking at the second?

Floyd Wilson

Well, it's under evaluation all the time and I guess the good news or bad news about that is we're just not in a position to start drilling those development wells yet. When we are, you might recall that the early analysis done in the very early days of the drilling of the field. We thought that the spacing might end up being about 80 acres. I don't know that we've done enough work dramatically change that. We are hopeful we can drill fewer wealth than that over time, maybe five or six wells in the section instead of eight, but the answer is not just out there just yet.

Richard Stoneburner

That me add, Andrew, that, we do have a joint development project with Questar on a section down in 13-11, I think it is. Very good area of the field that we've owned 50-50 and we elected to share operations there. So we've drilled three or four wells. They drilled three wells, I think. It's a total of seven wells in that section. It will be completed by year end. So it's the only area that we, as a company, have elected to commit capital to a development plan to get more knowledge about just what Floyd mentioned, what is the optimum spacing. So we won't be totally blind to it, but we don't have that flexibility to do a whole lot more than what that one section in the near-term.

Andrew Coleman - Madison Williams and Company LLC

Then thinking about, I guess, reserve bookings in this year, still I guess the biases for just organic drilling with maybe some of the improved EURs offset a little bit by the increased cost of getting services out there with potential then for their revision portion of reserve bookings to be improved in 2011, 2012 as you have a chance to get more data on such rates and/or drills on the wells once the acreage is captured.

Floyd Wilson

The outlook is that that balance between the cost and the EURs improving and eventhough the costs have gone up, the other component of that equation has gone up even more in proportion. So I think it's a pretty good picture we're looking at, going forward.

Operator

Our next question comes from Steve Berman with Pritchard Capital Partners.

Stephen Berman - Pritchard Capital Partners, LLC

Very impressive $0.25 per LOE. Can you maybe break that down between the Haynesville, Eagle Ford and Fayetteville to kind of give us a sense for where that might be heading in 2011 with the rapid growth in the Eagle Ford and the Fayetteville maybe not in there?

Floyd Wilson

Let me see if anybody here at the table has those numbers. I can tell you that the 0Haynesville is the least expensive deal of over three to operate. The Fayetteville is the more expensive of the three to operate and the Eagle Ford somewhere in the middle. They're all very inexpensive to operate. Keep in mind that in our corporate LOE number, we still have a significant component of conventional production coming from Cotton Valley and Hosston production at Elm Grove and that tends to drive up the average a little bit all on its own. I think we've reported in the past numbers of $0.10 and $0.15 and some of these fields for LOE, and maybe just a little higher than that in the Fayetteville.

Stephen Berman - Pritchard Capital Partners, LLC

Directionally, do you think they can keep coming down in 2011 even with the Eagle Ford growing faster? Of course, the Fayetteville may not be in there as well?

Floyd Wilson

Yes, at some point in time, we expect those fields to pay us to take the gas out. We expect a little more improvement along these lines. It's pretty darn good as it says.

Stephen Berman - Pritchard Capital Partners, LLC

In Red Hawk, can you talk about the second well you drilled, the one that went on pump relatively quickly, how that well is continuing to perform and is further drilling there, at least, in the near term dependent on how this third well does?

Richard Stoneburner

Our answer is the well, the second well is pretty much on forecast. It's a solid well. We have to get the costs down to make it a commercially viable well, and that's what we're going to try to do with the number three well. I'll get something along the same lines from a reserve standpoint and drive the cost down. And like I said earlier, the play has, that just got 100 million barrels of potential net to the company and a ballpark cents, and we're frac-ing wells at the 2x to 3x what a normal price would be. They're going to be normal time sin here when we can drill a well for $3.5 million, $4 million. So it's a kind of play you got to keep in play and that's exactly what we're doing. But we're only spending a normal amount of capital to do that. So I think it's the right decision for the company to continue to test it, learn more about it, these wells always get better with time, historically. And we're just hopeful and believe that will occur.

Floyd Wilson

Steve, our belief is that all of the wells in that particular area will need artificial lift. It's relatively low gravity crude with not too much gas in the reservoir and all those wells will go on the pump early in their life.

Stephen Berman - Pritchard Capital Partners, LLC

Next to -- in Frio County, there had some success with the budda below the Eagle Ford, is there any evidence that you have budda on your Red Hawk acreage?

Floyd Wilson

No, I mean those are nice wealth but pretty limited geologic footprint to that Buddha production.

Operator

And our last question comes from Chris Pikul with Morgan Keegan.

Chris Pikul - Morgan Keegan & Company, Inc.

Just ask a different way, you reserve growth comment about matching production growth this year, if that's going to run about 35%, it just seems to me that, that suggests you'll be adding less total the reserves this year than last year, which kind of seems counterintuitive, given your level of drilling activity. Are there other things we should be thinking about, as you look at that year-end number?

Floyd Wilson

Yes, Chris. Keep in mind that the year-end reserves calculated using the SEC guidelines have a limitation of the -- you have the -- they get them drilled within a five-year timeframe, and that tends to dramatically change some year, some reserves that you might have had booked before. In other words, last year, we lost, I think, a couple of hundred Bcf of Cotton Valley reserves as far as booking than just because of that five-year rule. So you have a kind of some ins and outs that go with that reserve calculation. So our reserve growth this year is going to be very, very strong. It's really good.

Chris Pikul - Morgan Keegan & Company, Inc.

I guess, did you front-load? Because you had a 1.9 Bcf last year, obviously, those are coming from the Haynesville. Are you sort of managing the number moving forward to stay within the five-year limit? I mean, certainly, it really doesn't seem like there's any performance issues.

Floyd Wilson

Well, we don't have any performance issues. Those rules were new last year, and this will be just a second year with those new guidelines. So I think the whole industry is kind of working through a database on all of that. I would like to characterize our reserve growth as anything but spectacular though..

Well, I think that's last question. Thanks, everyone for calling in and if you think of something we didn't cover, just give us a call. Thank you.

Operator

This concludes today's conference. Thank you for your participation. You may now disconnect.

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