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Quicksilver Resources Inc. (NYSE:KWK)

Q3 2009 Earnings Call

November 9, 2009 11:00 am ET

Executives

Rick Buterbaugh - VP of IR

Glenn Darden - President and CEO

Phil Cook - SVP and CFO

Toby Darden - Chairman

Analysts

Ellen Hannan - Weeden & Co.

David Kistler - Simmons & Company

Brian Singer - Goldman Sachs

Adrayll Askew - Hartford Investment

Noel Parks - Ladenburg Thalmann

Michael Jacobs - Tudor, Pickering, Holt

Monroe Helm - CM Energy Partners

Manav Gupta - Canaccord Adams

Scott Hanold - RBC Capital Markets

Jeff Robertson - Barclays Capital

David Tameron - Wells Fargo

Jack Aydin - KeyBanc

Steven Karpel - Credit Suisse

David Snow - Energy Equities

David L. Neuhauser - Livermore Partners

Operator

Good morning. Welcome to the Quicksilver third quarter 2009 Earnings Call. (Operator Instructions). I’d now like to turn the call over to our host Rick Buterbaugh, Vice President of Investor Relations and Corporate Planning. Thank you. Mr. Buterbaugh, you may begin your conference.

Rick Buterbaugh

Thank you and good morning. Joining me today are Glenn Darden, President and Chief Executive Officer; Toby Darden, Chairman; and Phil Cook, Senior Vice President and Chief Financial Officer. This morning the company issued a press release detailing Quicksilver Resources' results for the third quarter of 2009. If you do not have a copy of this release, you can retrieve a copy on the company's website at www.qrinc.com under the News and Updates tab.

During today's call the company will be making forward-looking statements, which are subject to risks and uncertainties. Actual results might differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed in the company's filings with the SEC.

Today's presentation will include information regarding adjusted net income and net cash from operating activities before changes in working capital, which are non-GAAP financial measures. As required by SEC rules, reconciliations of adjusted net income and net cash from operating activities before changes in working capital to their most directly comparable GAAP measures are available on the company's website under the Investor Relations tab.

At this time I will turn the call over to Glenn Darden to review our financial and operating results.

Glenn Darden

Thanks, Rick. Good morning. Quicksilver Resources had third quarter 2009 adjusted net income of $42.7 million or $0.25 per diluted share compared to $69.8 million or $0.40 per diluted share in the 2008 period. As projected, production volumes averaged 311 million cubit feet equivalent per day up 12% year-over-year. Our current volumes are in the 340 million cubit feet a day equivalent range and for the year we are projecting an average rate of over 325 million a day which would result in a 24% year-over-year growth for the company.

As I said in this morning’s earnings release, Quicksilver generated record cash flow through operating activities for the first nine months of the year. The company is on pace to have a record production year while driving production costs down nearly 30%. Our team has done this while keeping capital expenditures inside of cash inflows. We also have started to whittle down the company’s debt and anticipate making more progress on that by year end.

The company’s bank facility, borrowing base was affirmed at $1 billion, with roughly half of that amount drown under the facility. We anticipate maintaining that undrawn cushion throughout 2010. On the commodity pricing side Quicksilver will receive an average floor price of $8.75 per Mcf on approximately 75% of its estimated natural gas production for the fourth quarter of 2009.

In addition we have put in place collars of $7.40 to $9.88 per Mcf on 200 million cubic feet a day for 2010. Derivatives associated with natural gas liquids production covered 10,000 barrels per day or an additional 60 million cubic feet equivalent at a weighted swap price of $33.47 per barrel. Combination of this gas and liquids pricing gives us a well head price of almost $10 per Mcf equivalent for the company’s higher Btu gas in the Southern Barnett area.

On the operational side our Barnett program is really going well. Over the last several years we have put the infrastructure in place both in the field and with personnel to maximize the recovery and margins from our larger acreage position. You are now seeing the results on both the volume growth and cost sides. Having large contagious acreage blocks has enabled us to optimize well spacing, lateral links, and streamline the surface facility.

The importance of natural gas liquids in our Southern Fairway is becoming clearer to the investment community. Our economics are compelling and those higher equivalent prices I mentioned earlier will allow our operating team to begin to work down our uncompleted well inventory in the Barnett South area. We have locked in certain service costs for lease completions for 2010 to ensure very attractive margins. In Alliance and Lake Arlington, Barnett production continues to improve on a per well and total volume basis.

Moving to Canada, our Canadian team has done a great job this year. Horseshoe Canyon production has grown 9% year-over-year despite cutting that budget significantly. We are currently producing about 63 million cubic feet of gas a day from that Horseshoe Canyon project. The biggest news from up there of course is progress being made in our Horn River Basin play. One of Quicksilver's goals entering 2009 was to convert this prospect into our next big development project. We are well on our way to doing this.

The company's initial D-50A well averaged 10 million a day for the first month of production from a 3,300 foot lateral in the Muskwa shale. This is the upper member of a 500 foot thick section of over pressured Devonian shale. We begin completion operations later this month on a second well drilled three miles east of the initial well.

The C-60D well will be completed in the lower Klua section of the shale. Although we are still in the early stage of this project we firmly believe that this will be a world class shale production basin. Our 127,000 net acres is now surrounded by significant production from other operators.

We have a requirement to drill eight more oils over the next three years to convert our exploratory licenses to leases and then 10 to 12 years to develop the entire acreage block. Quicksilver has contracted firm transportation agreements to ramp up volumes over the next five years and we are beginning to put infrastructure in place for long-term development. The company has also hedged AECO basis at NYMEX minus $0.45 for approximately $40 million a day of gas in 2010.

One new venture Quicksilver has been working on is in the Greater Green River Basin in Southern Wyoming and Northern Colorado, where the company has assembled an anchorage block of over 100,000 acres. This is an area of very thick deposition of both Mancos and Niobrara shale. The Mancos alone has over 2,000 feet of section.

We have drilled two vertical wells, three townships apart with the initial completion work on the first well currently underway. This well has tested gas from short and completion intervals from both phases at combined rates of over four million cubic feet of gas a day. We have a lot more work to do here but are encouraged with the preliminary results. After completion of both wells we will have a better idea of the potential of this prospect.

Overall Quicksilver is making great progress despite the tough economic environment. We have extended maturities on debt, which allows the company to develop its large asset base. Our low cost structure has gotten even lower. The importance of our high Btu window in the Barnett is becoming clear and we’ve solid price protection locked in for the rest of this year and 2010.

Quicksilver’s position in the Horn River Basin give us more leverage to grow pound-for-pound than any other player in the basin and this project could very well be several times larger than our current reserve base. We can grow production organically at 20 plus percent over the next several years and stay well within the company's cash inflows. We will keep pushing.

Now I'll turn the call over to Phil Cook, our CFO. Phil?

Phil Cook

Thank you, Glenn and good morning everyone. Production volumes met our projection at 311 million cubic feet a day of natural gas equivalent in the third quarter of 2009, down from 331 million cubic feet a day in the second quarter. Keep in mind that the third quarter volumes reflect a sale of 27.5% of our interest in the Alliance properties to Eni.

Excluding those volumes allocable to Eni, production was flat with the second quarter. For the quarter and first nine months of 2009, total production volumes grew by 12% and 34% respectively when comparing the same periods in 2008. Essentially all this growth was fueled by activities in the Fort Worth Basin where volumes grew by 14% and 45% for the third quarter and first nine months of 2009, again compared with same periods a year ago. Drilling and completions activities combined with the August 2008 acquisition of the Alliance properties were the primary reason for the additional Fort Worth Basin volumes.

Our realized natural gas price for the quarter was $7.69 per Mcf after hedging, compared to $7.52 in the second quarter of 2009, up about 2%. You will recall that we had hedged 190 million cubic feet a day of natural gas with collars with weighted average floors of $8.75. Natural gas liquids realized prices were $28.15 a barrel in the third quarter compared to $24.22 a barrel in the second quarter, up 16%. Realized oil prices were $60.55 a barrel in the current quarter, up from $52.48 a barrel in the second quarter, a 15% increase.

Total production revenues were $198.3 million in the third quarter of 2009 flat with the second quarter. On the expense side, unit lease operating expense was $0.56 per Mcf in the third quarter, flat with the second quarter. Keep in mind that about $0.03 of this amount is non-cash and is related to equity compensation for our operational employees. These amounts exclude processing, transportation and production tax expense.

Processing expense, which is the cost to gather and process our gas from the wellhead to the tailgate of our facilities for the third quarter, was $0.14 per Mcfe down a penny from the second quarter. Transportation expense, which is the cost to get the gas from the tailgate of our facilities to market, was $0.32 an Mcfe during the third quarter, down $0.02 from the second quarter.

So just as a quick recap, unit oil and gas expenses were broken down as follows: LOE was $0.56, processing was $0.14, and transportation expense was $0.32, for a total of $1.02, which is down 3% sequentially and down 22% year-over-year. We continue to look for opportunities to further reduce our cost, however, as I've discussed with you previously, LOE is likely leveling off on both an absolute dollar amount and a per Mcfe basis.

Production taxes for the quarter were $0.23 per unit, which is down $0.02, sequentially. We expect recurring taxes to be in the range of $0.22 to $0.25 an Mcfe. The DD&A run rate for the third quarter was $1.56 per Mcfe an 8% decrease from the $1.69 per Mcfe reported in the second quarter of 2009. The reduction principally relates to the impact of recording the full cost ceiling test impairment during the second quarter of 2009.

Recurring G&A was $0.59 an Mcfe, which includes about $0.13 per Mcfe of non-cash stock-based compensation expenses related to LTI plans for non-operational employees. Total G&A reflects legal fees and charges associated with litigation as well. As a brief recap our total recurring cash expenses for oil and gas production and taxes, and G&A were a $1.68.

Adjusted net income, there is a reconciliation of that on our website, for the quarter it was $42.7 million or $0.25 a diluted share as compared to the adjusted net income of $41.2 million or $0.24 a diluted share in the second quarter.

Third quarter 2009 adjusted net income does not include unrealized non-cash after tax income of $6.6 million related to the early settlement of hedges that BreitBurn recorded and $39.1 million of unrealized non-cash to after-tax loss related to the second quarter mark-to-market loss that BreitBurn recorded for commodity derivatives. As you know BreitBurn does not utilize hedge accounting.

Also excluded is $9.5 million of tax expense, which is the current quarter effectively full-year estimated tax rate change to prior quarters. As of the end of the third quarter, we estimated that our tax rate will be 34%, whereas at the end of the second quarter we estimated that the year tax rate will be 35%. This 1% change caused us to book a $9.5 million tax adjustment, which resulted in more expense, so the previous accruals of tax were benefits.

During the first nine months of 2009, the company generated approximately $450 million of cash flow from operations, 65% more than generated in the first nine months of 2008. For the nine months of 2009, we have incurred 2009 capital of approximately $450 million roughly in line with our internally generated funding. This amount is net of approximately $20 million of capital contributed by our partners.

Total CapEx which includes changes in working capital were approximately $560 million. The difference of approximately $100 million is the change in the accrual for capital when comparing year-end at the end of the third quarter. We expect to incur an additional $75 million toward the 2009 capital program during the last quarter of the year, which approximates cash flow generation.

For the nine months in the September 30, we’ve paid down debt, freight payable amounts by approximately $130 million since the beginning of the year. Total Quicksilver debt at September 30, 2009 was approximately $2.3 billion, which excludes approximately $200 million of KGS debt that is not recourse to Quicksilver.

Of this amount our revolving credit facility was approximately $480 million drawn on a revised borrowing base of $1 billion. You may recall that our borrowing base was reduced to $75 million from $1.2 billion as a result of the Eni transaction and was further reduced in October to $1 billion as a result of our regularly scheduled re-determination by our bank group. This leaves the company with $520 million of liquidity in this facility at September 30, 2009.

Our existing bank facility runs through February 2012, however, we anticipate rolling and putting a new facility in place by the end of 2011. Therefore, the maturities on our public debt will not begin until 2015, giving the company significant flexibility regarding cash management over the next few years.

As a reminder, our convertible debenture, which is convertible into Quicksilver stock at a stock price of $15.28, is puttable to the company in November 2011.

Now I'll turn the call back over to Rick for guidance for the fourth quarter.

Rick Buterbaugh

Thanks, Phil.

Just a quick reminder as detailed in our press release this morning. Production volumes for the fourth quarter are anticipated to increase into the range of 330 million to 340 million a day on a gas equivalent basis. Also, keep in mind that about 190 million a day of natural gas is hedged at weighed average floor price of $8.75.

With respect to unit cost, production expense is expected in the range of $0.55 to $0.60; gathering and processing at about $0.15 to $0.18; transportation expense of $0.30 to $0.35; production taxes, $0.20 to $0.25; G&A in the range of $0.55 to $0.60 and DD&A at $1.55 to a $1.60. Again, these are all on an Mcf equivalent basis.

This time, operator, we'd like to open the call to any questions.

Question-and-Answer Session

Operator

Thank you, Mr. Buterbaugh. (Operator Instructions). Your first question is from Ellen Hannan of Weeden & Co.

Ellen Hannan - Weeden & Co.

A couple of questions, Glenn. In the Fort Worth Basin, I believe you have an inventory of 150 wells that have been drilled and not completed. How many of these you plan to complete so to sales in 2010?

Glenn Darden

Ellen, I guess the 150 number will be at year end probably, 2009. Of that number, give or take 50 or so is always in the inventory of uncompleted wells. So, let's take a 100 well inventory to work off. We're estimating roughly half of that number in 2010 and the remaining number…

Ellen Hannan - Weeden & Co.

So roughly…

Glenn Darden

Beg your pardon

Ellen Hannan - Weeden & Co.

Well, 50 wells per sit completed.

Glenn Darden

Yes.

Ellen Hannan - Weeden & Co.

Further in next year, how much capital do you need to devote to fulfilling your commitments in the Eni Alliance in 2010?

Rick Buterbaugh

Yes Phil.

Phil Cook

It's about $150 million.

Ellen Hannan - Weeden & Co.

Okay. Then last one from me, can you say how much money you will spend in 2010. Up in the now Horn River you mentioned that you need to drill a certain amount of wells to hold leases, can you give us an outlook on that?

Glenn Darden

We’ll drill two more wells as scheduled at this point, which are actually converting the exporter licenses to leases. So a part of that requirement and we’ll complete both of those wells and than we'll, as anticipated, we will accelerate in 2011, probably drill as many as four wells up there. So, still just kind of lease holding at this point but learning more about the reservoir and putting in infrastructure for longer-term development.

Ellen Hannan - Weeden & Co.

Right.

Glenn Darden

One think I would like to back up on the Barnett side, what you are going to see on the budget and we haven’t gotten that approved at the Board level yet but soon to come. You are going to see a more balanced approach across the Barnett sell like Lake Arlington and Alliance more so than this year

Ellen Hannan - Weeden & Co.

Any idea how much capital you spend in Horn River next year?

Phil Cook

No, that’s probably $50 million range something like that, which includes infrastructure.

Operator

Your next question is from Dave Kistler of Simmons & Company.

David Kistler - Simmons & Company

Real quickly looking at your production guidance for Q4, if I am not mistaken in your ops, I think last week you were producing about 340 million a day and your guidance is 330 to 340. Should be anticipating some maintenance downtime or are we putting some cushion in there for, who knows whether there would be potential for involuntary curtailment of what now what with the system relatively full?

Glenn Darden

David what that are really represents is as you saw we averaged 311 for the third quarter. We brought on noticeable amount of wells late in October, which is where we are at the 340 million currently. But on average for the quarter we expect to be in that 330 to 340 range. There will be some additional wells brought on later this quarter, but as those wells are brought on you also take some of the nearby wells offline during the completion and flow back period. So we still expect to average in that 330 to 340 range.

David Kistler - Simmons & Company

Great, that clarification is helpful. Then on Ellen's question relative to the 50 wells or so that you are looking at completing that are in inventory. Is that going to be evenly spaced throughout the year? How should we think about building that out in our models?

Glenn Darden

I would expect those to be even throughout the four quarters so, roughly 12 wells or so per quarter.

David Kistler - Simmons & Company

That's helpful. And then kind of just can you walk me through the present value decision of not completing as many of them as you can this year versus pushing some out to next year. Is that infrastructure related? Is that just kind of scheduling related, because it would seem to make it would have a higher present value effect to bring those on right now barring any change in the commodity price going forward?

Phil Cook

David this is Phil. It's really more trying to stay within cash flow for the year. And really we have seen completion cost come down 30% or so this year, so on a present value we haven’t lost too much. Well, and not only are we seeing cost come down, we’ve seen gas prices come up. So we’ve layered in hedges for 2010 that give all of those wells better economics than had we completed them and brought on incremental production in 2009.

David Kistler - Simmons & Company

That makes sense, I appreciate that clarification. Then the last question from me I’ll hop off. Can you give us any kind of indications on where you think the cost of those Mancos and Niobrara wells would be or at least when you start talking about four million a day on the verticals that you drilled, what the cost of those were right now?

Toby Darden

It’s early on that. I mean, obviously our initial wells are going to more expensive with querying and all kinds of testing, but these are going to need to be in the $5 million or less from a vertical standpoint going forward on the development side.

David Kistler - Simmons & Company

And you had.

Toby Darden

That will depend to a large degree on the stimulation required across those zones. So it’s somewhat additive per stimulation, so there is a lot to learn yet.

Operator

Your next question is from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs

Wanted to follow-up on just your earlier comment on a more balanced approach to the Barnett when looking at Johnson County, Lake Arlington and some of the other counties. Can you talk a little bit more to that and then I also was trying to make sure I interpret it correctly when we think about the timing of bringing on the uncompleted wells, whether they were the only wells that are being brought on over the course of the year or whether they are being mixed in with wells that are also being drilled next year?

Glenn Darden

We are anticipating keeping our rig fleet flat at five rigs, so what is different is accelerating the completion work in the southern and across the board. So it’s just a more balanced approach. This year we made a concerted effort in the Alliance area because of our Eni deal and that was contractual, but a decision we made prior to signing that deal up, but overall this is just developing out our total asset base and the capital is spread, a little more balanced, little more equally balanced.

Phil Cook

Excuse me Glenn, but just to add to that, so what you should anticipate with respect to drilled and cased wells that are uncompleted is that inventory that will have which is 150 at the end of the year roughly will be declining even though we're drilling with five rigs next year.

Brian Singer - Goldman Sachs

Then how are you thinking about the potential for additional joint ventures that are potentially in the Horn River Basin?

Glenn Darden

Well, we've had discussions on that Brian and it's all about value and so we're not in a big hurry to do that. We don't have to do anything. The more we learn about the Horn River, the more we like it. Obviously, a lot of activity is happening around us, which makes us even prouder of our position there. So we're not going to be in a big hurry. If we can get the right structure and the right price, I guess we would be willing to do something. But at this point, there is not a big hurry to do that.

Brian Singer - Goldman Sachs

Lastly, with regards to the Mancos, when you look broadly at exploration opportunities, do you see other opportunities in the Rockies? Do you see Quicksilver taking a bigger position in the Rockies or do you see that Mancos is maybe a one more to one off opportunity?

Glenn Darden

I guess it depends on success. We have oil operations in the Rockies. We've always looked for opportunities in the Rockies. It's not a concerted effort to move to the Rockies by any means, but it's something that Toby and his team have been working for a couple of years now.

Toby Darden

There is a lot of gas there and we like that. The Manco section alone has 2,000 feet of gas bearing rock. So, that’s a lot of meat to play with.

Operator

Your next question comes from the line of Adrayll Askew of Hartford Investment.

Adrayll Askew - Hartford Investment

As it relates to completion costs in the Barnett and based on what you guys had locked in, what do you have in the budget on a per well basis for completion costs?

Phil Cook

We don’t have that number today for you. We are not finished with our budget process we are right in the middle of it. We’ve got to get Board approval next week.

Toby Darden

Those completion costs are related directly to length of lateral and the length of lateral can be from 3,000 feet to 7,000 feet in some of the wells. So those number of stages are somewhat proportion of the length.

Adrayll Askew - Hartford Investment

But you said that they have come down 30% year-over-year?

Phil Cook

Yes, on a per stage level and just overall.

Operator

Your next question comes from the line of Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

I wanted to start with the Green River Basin, could you just talk a little bit more about the target you talked about Mancos and Niobrara. I think Niobrara is being present in a huge, huge area up there. So I was just interested in what you saw in this particular area that made it attractive.

Glenn Darden

Well its early stages, Noel and without disclosing kind of propriety information of how we attack these things. The section the thickness of the section obviously the gas in place, but you are right Mancos covers a big area as well, but this area looked particularly good to our group.

Noel Parks - Ladenburg Thalmann & Co.

Okay. What are the pressures like where you are trying to target it?

Toby Darden

It's significantly over pressured now and that's one of the attractive features…

Noel Parks - Ladenburg Thalmann & Co.

Okay.

Toby Darden

…in this area.

Noel Parks - Ladenburg Thalmann & Co.

Just mechanically as far as getting the wells down very challenging or pretty straight forward given the pressures?

Glenn Darden

Well, we have earned some things with this initial drilling that will reduce our cost going forward. So it's not too terribly difficult drilling conditions.

Noel Parks - Ladenburg Thalmann & Co.

Okay. The completions as far as what's your thinking Phil look like going forward right now?

Phil Cook

Well. They are going to change. We have fraced a few stages in each zone at this point, not completely covering the section at all. We are encouraged by what we see, but the evaluation of frac technology there will continue for several years we estimate, we have not finalized by any means.

Glenn Darden

Yes Noel just to backup for a minute, it's been very early as we said in the evaluation of this. Rick has been getting a lot of questions. The wells have shown up on public data and so we thought it was appropriate to talk about it. But it's very early in this process, but we are encouraged.

Noel Parks - Ladenburg Thalmann & Co.

Okay, and just your thought at this point is, it will likely stay a vertical player or do you see some adding the indicator that the horizontal would be feasible?

Glenn Darden

We think just due to the thickness of these pay zones that it will remain a vertical play.

Noel Parks - Ladenburg Thalmann & Co.

Okay great and then my last one regarding cost next year. Of course, we’re just entering winter so no real idea what gas demand is going to look, price is going to look like and so forth.

What are your assumptions about the cost environment throughout 2010? Are you just assuming they stay roughly flat, or you’re assuming that if we say we get back in the more of at least to $5 gas environment that you’ll see them creeping up and its still kind of what point in the year would your start modeling when we are going to start to see some, some incremental increase?

Phil Cook

I think that what we’re anticipating from a budget perspective is that gas prices will be where the curve is and that the service industry is anticipating that and the cost will stay where they are right now.

Operator

Your next question is from Michael Jacobs of Tudor, Pickering, Holt.

Michael Jacobs - Tudor, Pickering, Holt

Glenn, I think can you go through the Barnett real quickly. Can you talk a little about the completion backlog and whether that’s going to come from the southern acreage or the northern acreage in 2010 and a little bit more on the completion techniques, does lateral length depend on where you are in the basin?

Glenn Darden

Yes. I think overall, the completions are going to be spread across, probably, percentage wise a little more in the south with the liquids pricing that I talked about earlier in the call. So, we are motivated in that regard. In terms of lateral length we have probably pushed the laterals to longer lengths in the northern area in Lake Arlington and the Alliance area but we’re experimenting with that down south as well. Overall, we’ve made some gains in that regard and certainly in these consolidated lease blocks where we can push those lateral lengths a little farther.

Michael Jacobs - Tudor, Pickering, Holt

Okay. Then moving to the Horn River, how do you think about a typical well in the lower Klua/Evie, when you kind of reconcile the deeper shale but it also thinner pay, are you modeling that, it's going to look like the Muskwa?

Glenn Darden

Well, we have a lot to learn there. While drilling that rock actually the penetration rate was a bit better. So, we think it could be a little with better rocks although it is a bit thinner. We're anticipating some very good production results. We have a little longer lateral length to play with. We're getting more stages of frac in this initial well, but I think based on data from other players in the play, now the Klua/Evie is very good producer.

Michael Jacobs - Tudor, Pickering, Holt

Then can you talk to us little bit about takeaway and kind of which locked in firm? What you can sell forward [haul] right now and how that progresses over time given pretty good industry activity in the area?

Glenn Darden

Yes. We've contracted with Spectra for firm transportation out of the basin. It starts at about 3 million a day and ramps up over five years to a 100 million a day of takeaway. So we're continuing to work on that on the downstream side and we anticipate moving gas by a couple of directions over time because of the size of this play.

Michael Jacobs - Tudor, Pickering, Holt

Okay. If I can move to Colorado, what's you 2000 Mcfe pay to [Makos] is nice, buts what's you porosity cut off in calculating net feet to pay?

Phil Cook

We haven't disclosed that. We just need to get little farther down the road. We'll talk about it when we have some real hard data.

Michael Jacobs - Tudor, Pickering, Holt

Okay. Do you have an estimate of gas in plays and what you think is recoverable?

Glenn Darden

We do and it’s a lot, but its so early that it's tough to talk about it, at this stage.

Operator

Your next question is from Monroe Helm with CM Energy Partners.

Monroe Helm - CM Energy Partners

Just to clarify for me some [old ones] about the number of wells still to be completed in the Barnett, how may of those will be at the end of the year and you’re sort of going to I think complete 50 during the course of 2010, unless I compare to the old account that you are going to drill and complete there are going to be new wells?

Glenn Darden

Right, well, lets just take the existing inventory and by year-end it will be roughly 150, 140 to 150 wells. Of that 150 roughly, 50 is will be completed and those will be spread out. The majority of those will be completed in the southern area we are anticipating. We will as Phil said, we have five rigs running next year, so we’ll be completing other wells also. So we will whittle down roughly third of that inventory in 2010, may be a little bit more.

Phil Cook

Yes. So Monroe to make it easier to think about may be we anticipate that our well inventory at the end of 2010 will be roughly 100?

Monroe Helm - CM Energy Partners

Okay. Just in terms from your present value standpoint the cost to complete these 150 wells will not be less than the costs that it going to be to complete the new walls you are going to drill? So why wouldn’t just complete these 150 and not drill some of the new wells?

Phil Cook

Well because we have got rig contracts for one thing and wells we are holding acreage and we also have commitments at Alliance. So we are running five rigs in the Barnett, which as you know is substantially down.

Monroe Helm - CM Energy Partners

All right.

Phil Cook

Then as we said earlier, while intuitively lets say the PV, we are loosing PV as we haven't completed these wells, but if you look at cost reductions that have occurred in the last call at 12 to 18 months, as well the gas price cycle that we just went through and compare that towards the future's curve, you'd be surprised at what the PV looks like. It's not completely intuitive.

Monroe Helm - CM Energy Partners

Okay. I guess this is what I didn't get. Thanks for the clarification. Since, since you brought up the rigs, are these five rigs, do any of them come of contract in 2010? Would you have any sort of guess if they do as to what differentially you get on rig rates going forward?

Phil Cook

They do, they are coming off several. I think we'll have three under contract by year end 2010 and we'll probably drop that cost 35% maybe a little bit more on new rigs.

Monroe Helm - CM Energy Partners

Okay. Thanks for your answers. Can I ask one another one? You mentioned 20% production going forward for quite as few years. Does that include I assume that includes something from the main coast and something from one river or could you just do that out of the Barnett?

Phil Cook

Just out of the Barnett.

Monroe Helm - CM Energy Partners

Okay. For the next five years 20% of your spending less than your cash flow just out of the Barnett?

Phil Cook

Yeah. We didn’t say five, it’s several years so at least three and perhaps more than that.

Monroe Helm - CM Energy Partners

Okay. Thanks for the clarification.

Operator

Your next question comes from the line of Irene Haas of Canaccord Adams.

Manav Gupta - Canaccord Adams

Hi. Congratulations on the great quarter this is Manav for Irene. I know its a bit early but can you give us some guidance about your 2010 CapEx and what percentage of this will go to the Barnett production?

Toby Darden

We expect to announce our 2010 capital program by mid December possibly a little earlier. At that time when we announce the capital program we'll give a little more detailed guidance on our production expectations for 2010 as well.

Phil Cook

In any case we’ll stay within cash inflows.

Manav Gupta - Canaccord Adams

Any guidance from the number of wells that you would do plan to drill in Fort Worth Basin next year, looking at the inventory you already have there?

Toby Darden

As Glenn mentioned we are going to have still five rigs running in the Fort Worth Basin. Those five rigs will do roughly a 100 wells next year, which is similar to what we drilled in 2009, however, we expect to complete every well that we drill in 2010.

Manav Gupta - Canaccord Adams

What’s your current average well cost right now in the Fort Worth Basin for horizontal wells?

Toby Darden

It’s different between the different portions of the basin that we’re drilling and it is very dependent upon the length of lateral.

Operator

Your next question is from Scott Hanold from RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Can you give us a couple of data points, how many well were drilled in the third quarter and how many wells were completed?

Toby Darden

Yes. During the third quarter we drilled 32 wells, the actual [segment] under completions, there are only 11 wells that were brought on.

Scott Hanold - RBC Capital Markets

Okay, so 11 completed, 32 wells drilled. So you actually had a pretty good drilling quarter. I mean in the five rigs, the 100 well target for next year do you think you could exceed that?

Toby Darden

We could exceed it again it depends on where you are drilling, the length of the lateral. You've seen year-over-year, we've been able to become more efficient with the rigs and bringing our average days per well down, but that again is dependent upon the length of lateral that you're drilling. As Toby mentioned, we're tending to drill longer laterals because of our contiguous leasehold position allows us to be able to do that and that ends up being a more efficient way to drill.

Phil Cook

It's actually there's pretty big range as rigs because of the length of lateral issue; the range is probably a 100 to 150 wells? It depends on where you're drilling.

Scott Hanold - RBC Capital Markets

Okay, thanks.

Glenn Darden

We haven't got significantly more efficient now with those rigs. I mean, we've lowered our average time for drilling across the northern part to 15 days for the spud.

Scott Hanold - RBC Capital Markets

Okay. Well then maybe actually maybe a little more color on those 32 wells that you gave me. Rick, how many of those were in sort of the core of the Barnett versus the Southern part?

Glenn Darden

I don't have a split with me. I'm sorry, if I can get back with you on that.

Scott Hanold - RBC Capital Markets

All right. That's fair enough. One last question, when you look at sort of the higher liquid content in some of the southern acreage and clearly there's an [event] to that. Can you all talk about the pricing you're seeing down there right now with some of the NGL’s, you see that strengthening a bit. It seems to be fairly flattish over the past several quarters.

Glenn Darden

Liquids price has improved certainly over the year. Today it's we've locked in as I’d talked about earlier, kind of in our latest hedges are in the $36 per barrel for actually 2011. But we have probably $34 or so in 2010 at this point but ethane has certainly strengthened which has lifted that pricing.

Phil Cook

Well, in the third quarter we've realized $28.05 a barrel compared to the second quarter of $24.22. So it was up 16% quarter-to-quarter.

Operator

Your next question comes from Jeff Robertson of Barclays Capital.

Jeff Robertson - Barclays Capital

Glenn I’m not sure if you talked about this earlier. But can you talk a little bit about what your plans are in the Green River in 2010?

Glenn Darden

We are working on that and it looks like certainly we want to get both of these wells completed and fully tested. So that’s going to take some time. So we are working on that budget we will be presenting to our Board next week, but it's not going to ramp up significantly I won’t say that, but we maybe drilling couple of more wells there.

Jeff Robertson - Barclays Capital

So your plan is to continue to evaluate the two wells that you have drilled before you start doing a lot more drilling?

Glenn Darden

Yes.

Jeff Robertson - Barclays Capital

On your acreage block is it fairly contiguous.

Glenn Darden

It is.

Jeff Robertson - Barclays Capital

Can you talk about the time you have on those leases?

Glenn Darden

We have got nice term on those leases.

Operator

Your next question is from David Tameron of Wells Fargo.

David Tameron - Wells Fargo

Back to Green River, the first half of the year is [bank yield] budget. Back to shale, wells I guess seven more than [quest star] but is this is similar type formation here [Jason]?

Glenn Darden

It is.

David Tameron - Wells Fargo

Okay and is E or G right around you in the same area?

Glenn Darden

I don’t know, I don’t think too close, no.

David Tameron - Wells Fargo

Okay. Everything else I guess has been answered. But one, actually one follow-up question in the backlog. Everybody spoke on the backlog, can you give us a run rate of what it has been in like ’07, '08, just on an normalized basis what your typical backlog is?

Phil Cook

In ’08, it was probably a 100 wells and in '07 it was probably half that, what I guess I'd say is that it’s going to be 50 sort of regardless at this point with 105 rigs just because of the way we are drilling the play and the pad drilling scheme.

David Tameron - Wells Fargo

So I mean if there’s a base level if you are around five rigs the base level of 50 completion that you are -- will be there…

Glenn Darden

We always have an inventory.

Operator

Your next question is from Jack Aydin of KeyBanc.

Jack Aydin - KeyBanc

You haven't mentioned anything about, no comments about the West Texas Barnett workforce. Could you give us an update what's going on there if anything?

Glenn Darden

We are continuing to evaluate that Jack and we have a couple of other completion procedures that we are going to be doing this year, we are not going to spend a lot of capital there. It's been a head scratcher for us, we’ve had some very good indications of potential there, we just haven't made it – haven’t moved it into the commercial zone. So we are working on some different fracing styles, but I think we'll probably spend less than $5 million out there this year something like that, but we haven't given up on the play.

Jack Aydin - KeyBanc

Okay. The other question I have is a more or less balance sheet question. I am looking at your press release and at the year end 2008, you had deferred taxes of $234 million, now I am looking at the 930 of this year you have that deferred taxes about $36 million. What happened over there can you Phil, can you explain it to me, what happened to the money or the numbers?

Phil Cook

Yeah. So, we had deferred taxes, which is a payable a long-term payable on your balance sheet. We took $1 billion write-off during the year which created deferred tax receivables if you will from the government, so those are offsetting the deferred tax liability that was there.

Operator

Your next question is from Monroe Helm of CM Energy Partners.

Monroe Helm - CM Energy Partners

Glenn, can you kind of tell us how you think about the tradeoff when production grows in deleveraging your company?

Glenn Darden

Well we’re certainly focused on staying within our cash flows and we say it just about every chance we get. That perhaps has changed certainly from two years ago, but one of the things we’re kind of approaching it two ways. We’re growing into our debt and our capital structure, but we’re also whittling it down as well. So we certainly are looking to further reduce the debt over the next several years, but our asset base is growing alongside of that. Phil, do you have anything to add there?

Phil Cook

Yeah. I guess what I’d say, of course, I’ve spent time on looking into the future with respect to what the company is going to look like short of any other transactions and as we continue to grow the Barnett production, forget about the Horn River, forget about Colorado, obviously, include Horseshoe Canyon, but over the next three to five years, from our balance sheet perspective we’re in fine shape without doing any other transactions.

Operator

Your next question is from Steven Karpel of Credit Suisse.

Steven Karpel - Credit Suisse

Yeah, following up on Monroe’s question. Regards to the balance sheet you mentioned that the Horn River, nothing I guess imminent there, I don’t know are you. Two questions then, one, is there a formal process going on there and then secondly, I think Phil you eluded to reducing debt on the balance sheet before the end of the year. Can you talk about what you're referring to or what options you have now? I guess part of it revolves around Quicksilver Gas and the equity price areas move pretty substantially?

Phil Cook

Well, we don't have a firm process going on in the Horn River to answer your first question. Second question is, we've continued to talk about various ways to reduce the debt. On the balance sheet, we specifically talked about dropping down assets from Quick into KGS which is certainly would generate cash to come back to the parent.

Steven Karpel - Credit Suisse

What's the timing on that?

Phil Cook

I think what I said in my comments that it will be within the year.

Steven Karpel - Credit Suisse

Just to clarify switching focus on the rig count, and what is your total number of wells you have to drill for the (inaudible) leases for the company?

Phil Cook

It's probably somewhere between 50 and 70 maximum. I think it's quite closer to 50.

Steven Karpel - Credit Suisse

In over what timeframe?

Glenn Darden

On an annual basis.

Phil Cook

Yeah, Annually.

Steven Karpel - Credit Suisse

Annually, okay.

Phil Cook

Keep in mind, you don't necessarily have to drill those wells, you might extend leases. I mean there's other ways to hold leases other than just drilling.

Steven Karpel - Credit Suisse

Right, I understand.

Glenn Darden

Well, we've had and that number maybe up to 80 some years but that's about the run rate.

Operator

Your next question is from David Snow of Energy Equity.

David Snow - Energy Equities

I came on a little late. The 2,000 feet, is that both Mancos Shale and Niobrara sands?

Glenn Darden

That's just the Mancos. There's a total of about 4,000 feet of section in both of those formations.

David Snow - Energy Equities

Okay and is Mancos. Do you envision eventually stimulating and proliferating the whole 2000 or just selected intervals or how do you approach that?

Glenn Darden

Well, that's what we're working with right now. So we’ll be able to tell you more on that as we finish our completion work.

David Snow - Energy Equities

So, if you drill two more next year, it might expand the amount that you perforate in and stimulate or…

Glenn Darden

I would bet that would, yes.

David Snow - Energy Equities

Can you give us a idea how many feet you are going to stimulate per share?

Glenn Darden

We really can’t right now

David Snow - Energy Equities

Okay. When do we get to know sometime in the next conference call?

Glenn Darden

Well, I think, this is very early stages and so we are going to get results and it's probably going to change next year with the drilling as we talked about here in the completions. But at a certain point the appropriate we’ll announce that.

Operator

Your last question is from David Neuhauser - Livermore Partners.

David L. Neuhauser - Livermore Partners.

I know you guys are doing a excellent job, really in optimizing your assets in this weak economy. Given that do you see that there is going to continue to be this disconnect that’s going to help your margin by, we have a weak economy and we have obviously commodity prices have come way off the low. Do you think that bifurcation is going to continue moving forward, which will help your margin or do you think there is going to be some leveling off in that?

Glenn Darden

Well, our margins were better when gas was $10, but our margins are fine today. I guess my anticipation for 2010 and what we are planning for is where the gas curve is today and where capital costs are as well as service costs are sitting today.

Operator

At this time, there are no more questions. Mr. Buterbaugh, would you like to make any closing remarks.

Rick Buterbaugh

Yes, thank you, operator. Just as a reminder this call will be available on the company's website in replay mode for 30 days. Quicksilver expects to release its fourth quarter 2009 earnings on Monday March 1, 2010 prior to market open. Members of the company's executive management team will be presenting at various Investor Conferences over the next several months. Details regarding these presentations will be available on the company's website at www.qrinc.com.

I’d like to thank you for your time and interest in Quicksilver this morning. This concludes our call.

Operator

Thank you for participating in today's Quicksilver third quarter 2009 earnings conference call. You may now disconnect.

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Source: Quicksilver Resources Inc. Q3 2009 Earnings Call Transcript
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