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Quicksilver Resources Inc. (NYSE:KWK)

Q2 2009 Earnings Call

August 10, 2009 11:00 am ET

Executives

Rick Buterbaugh - Vice President of Investor Relations

Glenn Darden - President and Chief Executive Officer

Phil Cook - Senior Vice President and Chief Financial Officer

Toby Darden - Chairman

Analysts

Mike Jacobs - Tudor, Pickering, Holt & Co.

David Kistler - Simmons & Company International

Adrayll Askew - Hartford Investment

David Snow - Energy Equities

Brian Singer - Goldman Sachs

Noel Parks - Ladenburg Thalmann & Co.

[Steven Carpel] - Credit Suisse

[Mark Crusoe] - Millennium Partners

Operator

Good morning. My name is [Shaday] and I will be your conference operator today.

At this time I would like to welcome everyone to the Quicksilver Resources second quarter 2009 earnings conference call. (Operator Instructions)

Mr. Buterbaugh, you may now begin.

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 second quarter of 2009. If you do not have a copy of the 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 to net cash from operating activities before changes in working capital to their most directly comparable GAAP measures are available on our 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

Thank you, Rick. Good morning.

Quicksilver Resources had second quarter 2009 adjusted net income of $41.2 million or $0.24 per diluted share, up 50% versus the comparable first quarter earnings per share numbers. Our second quarter results were generally as expected and met our stated goals to maintain production volumes this year, which results in a roughly 20% plus growth year-over-year on the production side; also to reduce our unit production costs and reduce our total debt.

Production volumes of 331 million cubit feet of gas equivalents per day in the second quarter were essentially unchanged versus the first quarter, with volumes from the Fort Worth Basin and our Horseshoe Canyon are in Canada both holding flat. These results are a strong testament to the quality of our properties and the abilities of our operating staff given that during the quarter only 11 equivalent wells were brought online in the Barnett and just one well in the Horseshoe Canyon due to the spring breakup in Canada.

In the Fort Worth Basin volumes also benefited from a fully quarter's impact of the Quicksilver Gas Services new Corvette processing plant that came online in February. Increased line compression associated with this facility enabled existing wells to flow at a greater rate and more efficient plant processing maximized recovery of the natural gas liquids.

Of particular note, during the second quarter we announced and completed the sale and joint venture of a 27.5% interest in our Alliance project leasehold in North Texas to Eni. The transaction, which represented an approximate 5% of our total year end 2008 reserves and a cash value of $280 million, provided Quicksilver with additional financial flexibility while retaining more than 90% of the 3.1 trillion cubit feet equivalent of identified potential resources yet to be booked from just the Barnett properties.

Proceeds from this transaction and a new bond offering enabled Quicksilver to completely repay our restrictive senior secured second lien notes and reduce the outstanding balance on our bank credit facility. As a result, we have now extended the first maturity of our public debt to 2015.

Phil Cook will provide further detail on this later in this call. As a reminder, these are the initial steps in our strategy that we laid out at the beginning of the year and the implementation is going well.

Operationally, the Barnett continues to be the focus of our development activity. Despite speculation of its demise, the Fort Worth Basin is alive, well and providing increasing opportunities for Quicksilver. The Fort Worth Basin-Barnett is a proven area of low risk, low cost development with readily available infrastructure and access to services. With more than 1,500 locations yet to be drilled, Quicksilver has a lot of running room remaining to fuel double-digit growth for multiple years in the proper price environment.

Even though we have very attractive hedges covering nearly 80% of our expected gas volumes at $8.83 per Mcf and with the benefit of our firm transportation out of the basin, an average basis differential of less than $0.25 off the NYMEX price for the remainder of 2009, we don't believe that today's natural gas price provides appropriate long-term returns to accelerate our development program at this time. Therefore, we are maintaining our drilling activity at just five rigs this year to conserve both our capital and our natural gas resources. We anticipate that these rigs will drill approximately 100 wells this year, of which we expect to complete approximately 70 of them. As a result, we project our inventory of drilled and cased but uncompleted wells in the Barnett to increase to approximately 150 wells by year end.

Four of our five Barnett rigs are working in the northern portion of our acreage at Alliance and Lake Arlington projects. Keep in mind that Quicksilver now has a 72.5% and a 75% working interest in Alliance and Lake Arlington, respectively, and therefore we only bear about three-quarters of the cost of these wells.

We've been very pleased with the recent operations at Lake Arlington, where initial results from extended laterals, larger fracs and wider spacing appear to be increasing our recovery per acre while reducing total costs.

We're deploying the same strategy at Alliance, where we are in the process of bringing online five new wells in this quarter and expect over 30 by year end. These new wells will help maintain our expected total net volumes of 325 million cubit feet equivalent per day in 2009.

Our remaining rig in the Fort Worth Basin is working on our southern acreage, which not only supports volumes but ensures that we retain all of our core Barnett acreage.

In Canada, spring breakup is over and we are now operating one rig in the Horseshoe Canyon; however, we only expect to drill seven net wells for the remainder of the year. Most of our Canadian efforts are focused on exploratory activities in the Horn River Basin, where we hold a 100% interest in 127,000 acres.

As I discussed last quarter, we drilled two horizontal wells on this acreage during the past winter drilling season. Both of these wells encountered approximately 500 feet of net shale thickness in the Muskwa and Klua-Evie formations. We are currently beginning completion activities of the first of these wells in the upper Muskwa formation. We expect to begin the completion in the second well in the Klua-Evie later this year after the winter freeze begins. Both of these wells will be connected to sales through gathering lines we now have in place.

The Horn River Basin offers a very significant opportunity for Quicksilver and our shareholders. I should add that the Horn River is an area that has had excellent early production results by operators surrounding us in the basin and is of great interest to other players, including international and domestic producers, end users and as a supply source for a possible L&G export facility. Quicksilver has had numerous discussions with various parties regarding a possible joint venture on our Horn River acreage position and we will continue to look at various options in order to maximize the value of this important company asset.

In summary, we believe that the Eni transaction and the expressed interest in Horn River demonstrates the quality of Quicksilver's properties. And our strengthening financial structure and attractive hedge position will enable us to realize the company's true value in time. As commodity prices rise, Quicksilver is well positioned to accelerate growth at minimal cost and maximize value for our shareholders.

And now I'll turn the call over to Phil Cook, our Chief Financial Officer, to discuss this quarter's numbers. Phil?

Phil Cook

Thank you, Glenn, and good morning.

Production volumes were as projected at 331 million cubit feet of natural gas equivalent per day in the second quarter of 2009, flat with the first quarter.

For the quarter and first half of 2009, total production volumes grew by 40% and 48%, respectively, when comparing to the same periods a year ago. Essentially, all of this growth was fueled by activities in the Fort Worth Basin, where volumes grew by 54% and 67% for the second quarter and first six months of 2009, respectively, again compared with the same periods a year ago. Drilling and completion activities combined with the August 2008 acquisition of the Alliance properties were the primary reasons for the additional Fort Worth Basin volumes. Keep in mind that the second quarter volumes reflect the sale of 27.5% of our interest in the Alliance properties to Eni from June 19th forward.

As Glenn mentioned, we also benefited from increased NGL recoveries due to higher efficiencies at KGS's new Corvette processing plant.

Our realized natural gas price for the quarter was $7.52 per Mcf after hedging compared with $7.04 in the first quarter of 2009, up 7%. You will recall that we had hedged 190 million cubit feet per day in both quarters; however, the average floor prices were approximately $0.70 per Mcf greater in the second quarter.

Natural gas liquids realized prices were $24.22 a barrel in the second quarter compared to $21.13 a barrel in the first quarter, up 15%.

Realized oil prices were $52.48 a barrel in the current quarter, up from $34.42 a barrel in the first quarter, a 53% increase.

Sequentially, total production revenues grew from $185.5 million in the first quarter of 2009 to $199.3 million in the current quarter, a 7% increase. For the current quarter and first half of 2009, total production revenues grew by 1% and 7%, respectively, when comparing to the same periods a year ago.

Our continued efforts to reduce costs throughout our cost structure resulted in nearly a 7% reduction in unit lease operating expense to $0.56 per Mcfe in the second quarter compared to $0.60 in the first quarter of the year. Keep in mind that approximately $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 second quarter was $0.15 per Mcfe, also a 6% decrease from the first quarter rate.

Transportation expense, which is the cost to get our gas from the tailgate of our facilities to market, was $0.34 per Mcfe during the second quarter, flat with the first quarter.

So just as a recap, unit oil and gas expenses were broken down as follows: LOE was $0.56, processing was $0.15, and transportation expense was $0.34, for a total of $1.05, which is a 5% decrease sequentially and down 32% year-over-year. We continue to look for opportunities to further reduce our costs; however, as I've discussed with you previously, based on our revised capital program and our expected flat volumes, LOE is likely leveling off on both an absolute dollar amount and a per Mcfe basis.

Production taxes for the quarter were $0.25 per unit, which includes approximately $0.10 per Mcfe of first assessments on properties primarily related to assets in the Alliance area and revised estimates for full year property tax burdens. We expect recurring taxes to be in the range of $0.15 to $0.20 per Mcfe.

As projected, the DD&A run rate for the second quarter was $1.69 per Mcfe, a 15% decrease from the $2 per Mcfe recorded in the first quarter of 2009. The reduction principally relates to the impact of recording the full cost ceiling test impairment during the first quarter.

Recurring G&A was $0.64 a unit, which includes about $0.15 per Mcfe of non-cash share-based compensation expenses relating to LTI plans for non-operational employees. Total G&A reflects higher legal fees associated with the BreitBurn litigation and the Eni transaction. In addition, we recorded a $3.3 million after-tax charge related to the settlement of litigation.

As a brief recap, our total recurring cash expenses for oil and gas expenses, production taxes and G&A were $1.66.

Adjusted net income, a reconciliation of which is available on our website, for the quarter was $41.2 million or $0.24 per diluted share as compared to the adjusted net income of $26.6 million or $0.16 per diluted share for the first quarter. Second quarter 2009 adjusted net income does not include unrealized non-cash after-tax income of $12 million related to early settlement of hedges that BreitBurn recorded. It also does not include non-cash after-tax charges related to debt termination of $17.6 million as well as a $3.3 million after-tax charge related to the settlement of litigation and a non-cash after-tax full cost ceiling impairment of $51.3 million related to Quicksilver's Canadian oil and gas properties. That charge is primarily due to a decline in commodity prices at quarter end and the decision to defer capital in the Horseshoe Canyon project into future years.

During the first half of 2009 the company generated approximately $310 million of cash flow from operations, more than double the $137 million generated in the first half of 2008. For the first six months of 2009 we've incurred 2009 capital of approximately $335 million, roughly in line with our internally generated cash flow.

Total capital expenditures, which include changes in working capital, were approximately $440 million. The difference of $110 million is the change in the accrual for capital or, to say it another way, we have funded 2008 capital, which is accrued at year end, in the first quarter of 2009. We expect to incur an additional $216 million of capital expenditures during the second half of 2009, which approximates cash flow generation.

For the six months ended 6/30/2009, we've paid down the absolute debt amount by approximately $120 million since the beginning of the year.

Total Quicksilver debt at June 30, 2009 was approximately $2.3 billion, which excludes $196 million of KGS debt which is nonrecourse to Quicksilver. Of this amount, our revolving credit facility was approximately $770 million drawn on a revised borrowing base of $1.125 billion. You will recall that our borrowing base was reduced by $75 million from the $1.2 billion as a result of the Eni transaction. This leaves the company with $355 million of liquidity in this facility.

Our borrowing base is up for redetermination by our bank group in November, although we do not expect any changes at this time. Our existing bank facility runs through February 2012; however, we anticipate rolling or putting a new facility in place by the end of 2011. Therefore, the maturities on our public debt do not begin until 2015, giving Quicksilver 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 to Rick for guidance for the third quarter.

Rick Buterbaugh

Thanks, Phil.

For the third quarter of 2009 we expect production volumes to be in the range of 310 million to 320 million cubit feet of natural gas equivalents per day.

For the fourth quarter we expect volumes to increase into the range of 320 million to 330 million cubit feet of equivalents per day.

Using the midpoint of these ranges will result in an average daily production volume for the year of approximately 325 million cubit feet of equivalent per day, an increase of about 24% versus the 2008 average. So as we projected at the beginning of the year, we remain right on track for the 325 million cubit feet a day.

For the third quarter I would remind you that approximately 83% or 190 million cubit feet a day of our natural gas volumes have been hedged for the remainder of 2009 at a weighted average floor price of about $8.80 per Mcf and a weighted average ceiling price of $11.20.

With respect to unit costs, the following run rate should be expected for the third quarter: Lease operating expense of about $0.55 to $0.60 per Mcfe; gathering and processing expense of $0.15 to $0.18; transportation expense of $0.35 to $0.40, for total operating expense of $1.05 to $1.18. Production taxes are estimated at $0.15 to $0.20; G&A of $0.62 to $0.67, for total costs of $1.82 to $2.05.

Keep in mind that about $0.18 of these costs are non-cash costs.

DD&A expense is estimated at $1.65 to $1.70.

[Shaday], at this time we'd like to open the call for any questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Mike Jacobs - Tudor, Pickering, Holt & Co.

Mike Jacobs - Tudor, Pickering, Holt & Co.

I hate to start things off with a tedious modeling question, but I've got a quick one for Phil. If I start with the cash flow statement, it looks like you received $233 million in proceeds from Eni while $47 million was attributable to a gas purchase commitment. Is that just an accounting treatment or are there additional liabilities that were assumed to get the purchase price up to $280 million?

Phil Cook

Well, we got $280 million in cash and was assumed the liability that you just mentioned for the gas purchase contract, so that's the accounting for it.

Mike Jacobs - Tudor, Pickering, Holt & Co.

Can you just elaborate a little bit more on that?

Phil Cook

Eni's portion of gas from these assets we're buying for the next 18 months. So through the end of 2010 we're buying their gas at the fixed price of $8.60.

Mike Jacobs - Tudor, Pickering, Holt & Co.

On the CapEx side you spent $325 million in the first half and you plan on spending another $216 million. Can you help us reconcile where the additional $40 to $50 million is coming from versus the $500 million in the most recent presentation?

Phil Cook

Are you talking about the difference between $500 million and $550 million?

Mike Jacobs - Tudor, Pickering, Holt & Co.

That's right. Is that the gas purchase agreement or is there another way to think about that?

Phil Cook

No. We're spending more on putting pipe in the ground and building facilities at Alliance, for one place. But from our perspective, being within 10% of budget is pretty close.

Rick Buterbaugh

The $50 million increase is really all dedicated to our Texas properties and to drilling, completion and a little bit of gathering system related to those properties.

Mike Jacobs - Tudor, Pickering, Holt & Co.

And then in Canada, can you break out 2010 spending for Horseshoe Canyon versus Horn River?

Rick Buterbaugh

We're currently in the process of going through our capital program and expectations for 2010. We'll announce those results at year end or what our 2010 budget is at that point.

Phil Cook

And certainly at that point we can break out the exploration and spending in Horn River versus Horseshoe Canyon. We do expect Canada, however, not to borrow this year or next year with regard to capital program.

Operator

Your next question comes from David Kistler - Simmons & Company International.

David Kistler - Simmons & Company International

Diving into Horn River a little bit, obviously very early but I'm guessing with people talking to you about JV structures there and whatnot you're starting to put some estimates around at least what you think well costs are going to be and anticipated EURs. And whether it's through the wells that you're already starting to work on through looking at some of the competitors' information, can you give us any color on what you're thinking there so we can better model that out?

Toby Darden

Sure. We're still relying on competitor data, published data, for our estimates, but what we've seen in our own drilling has conformed pretty well to what we've seen in the acreage offsetting us, but you've probably seen some of the competitors looking at recoveries between 7 and 10 Bcf per well. And we're looking at costs coming down to a point that should achieve about 750,000 per stage of frac with 10 to 14 stages of frac and about 1 Bcf per stage of frac. Those are the rules of thumb we're using at this time. They seem to be bearing out. The more data we get, the closer those numbers seem to be. So that's what we're looking at in our own assumptions.

Glenn Darden

Total cost below $10 million per well down to maybe $8.5 million or so.

Toby Darden

And that'll depend on the length of laterals and the number of stages, of course.

David Kistler - Simmons & Company International

And then just thinking a little bit in terms of CapEx, you say you want to live within the cash flow that comes out of Canada, so really as we model this out we should be thinking about not moving into an aggressive drilling mode until maybe 2012?

Glenn Darden

Well, that's one of the benefits of our lease position up there; we don't have to move at a fast rate. Obviously infrastructure needs to be built out on the transportation side, gathering and transportation side. As I mentioned in my remarks, we will be tying in these initial two wells into sales after completion. But our total commitment from here is about eight more wells over the next three years to validate all the exploratory licenses and convert to leases, and from there our commitment over the next 10 years is maybe another 70 or so wells to hold all of that acreage.

So one of the things we're looking at is certainly we don't want to drill a whole lot of wells before there's infrastructure to take the gas away and it's just an advantage, I think, of that Horn River position and the acreage terms for the company not to move very fast. It parallels what we've done in the Barnett development early on as well.

David Kistler - Simmons & Company International

And then just looking at production ticking back up in the fourth quarter of '09, can you talk a little bit about what's going to be driving that or are you going to be looking at just completing more of the drilled uncompleted wells or is that purely coming from just the production associated with the five rigs that'll be drilling?

Rick Buterbaugh

It is really just a timing issue associated with when the wells are being completed and brought online, depending upon the size of the individual pads. But based upon individual expectations of when those wells will be completed we'll see volumes start kicking up again late in the third quarter and early in the fourth quarter.

Operator

Your next question comes from Adrayll Askew - Hartford Investment.

Adrayll Askew - Hartford Investment

The five wells that you drilled in the quarter on [Leiski], speak to the total cost there and what you're seeing so far as production, initial production rates out of those wells.

Rick Buterbaugh

We're in the process of fracking those wells. As you know, we drill them on a pad style of development so you drill all the wells and frac all the wells before bringing them on. And we're just in the process of finalizing the last couple of fracs and we're close to bringing those on shortly.

Glenn Darden

We're encouraged cost wise. We're down 25% roughly year-over-year on Barnett wells, no matter where we're drilling, south or north.

Adrayll Askew - Hartford Investment

And then, so far as your EUR estimates on Lake Arlington and Alliance, can you remind where exactly you stand there from an EUR standpoint?

Phil Cook

Well, what we have booked is less than perhaps what we're seeing currently, so there may be and adjustment down the road upward on reserves. But we fully believe that Lake Arlington and Alliance are going to be north of 4, probably close to 5 Bcf per well. And the southern acreage is still in the 2.2 to 2.5 Bcf equivalent with 30% plus natural gas liquids.

Operator

Your next question comes from David Snow - Energy Equities.

David Snow - Energy Equities

I wondered if you had any pithy comments on the macro view of prices on natural gas?

Glenn Darden

Well, we have our views, David.

I think overall we're going to see some declines here with the rig count coming off so hard, but I there are several basins that are still quite active, particularly Haynesville. But our projection is that prices will improve as production drops off.

I think when you cut out 50% to 60% of the drilling rigs drilling for gas you're going to see an effect, certainly by later fall, year end.

David Snow - Energy Equities

A small detail - there was a $3.3 million liability charge for settling something. What was that?

Phil Cook

It was litigation that we had with CMS. It goes back many, many years to a fixed price purchase contract that we had that we had agreed to stop performing upon. We had a court ruling that went against us. We had a settlement in place with them already that said that had we lost we'd pay them $5 million gross and had we won they would have paid us $5 million.

Operator

Your next question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs

Apologies if you mentioned this earlier, but I think you'd highlighted your expectation for about 150 drilled and completed wells at year end in the Barnett and I was wondering how that compares to a normal level of backlog and then your expectations for what price and when that would come online, ostensibly over the course of 2010.

Glenn Darden

I think normally we'd have 60, maybe a high of 70 wells, something like that with this pad drilling style that Toby talked about, Brian.

One of the things that it does give us is flexibility on our capital going forward to complete these wells, so we could certainly keep a flat recount at five and increase the production significantly higher by directing capital toward completion.

So we haven't formulated the exact game plan, but we do anticipate working off that inventory over the next couple of years.

Brian Singer - Goldman Sachs

I know you're not ready to provide specific guidance, but how are you thinking about that at various gas prices next year? If gas prices stay low in, let's call it, the $5 to $6 range, what are the implications for how you're thinking about investment in drilling versus completion versus neither versus if we're more in a $6 to $8 environment?

Glenn Darden

I think if gas prices stay low we'll be directing more dollars to completion, so I would anticipate we wouldn't accelerate the drilling and keep a flat rig count. We have contracts for a certain amount of rigs that start dropping off, actually, at the end of this year and accelerate more in 2010, so we could even drill less wells. Our maintenance cap is probably $250 million to $300 million or so to keep production flat at today's rate.

So we could do that, spend more efficient dollars probably on the completion side, maybe even spend a little less.

Brian Singer - Goldman Sachs

I think in your previous response you mentioned that you could end up going through the inventory over a two to three year period. Is there anything just from a people perspective or infrastructure perspective that would prevent you from bringing the at least excess inventory on more quickly?

Glenn Darden

No, not at all. No, we're well staffed and we have one of the things - in fact, at the end of this year we'll have most of the Alliance infrastructure in place if not all, and so we've really spent a lot of the midstream dollars across the board, across all of Quicksilver's acreage. So the dollars will be more efficient toward bringing on production next year and beyond.

Operator

Your next question comes from Noel Parks - Ladenburg Thalmann & Co.

Noel Parks - Ladenburg Thalmann & Co.

I was thinking about the Barnett. A year or so ago people were speculating that the play as a whole would peak within just a very few years and of course things have changed so much since then. But, to the degree we think of it as a maturing play if not mature, you just mentioned in the last question that a lot of the infrastructure expense is already a sunk cost, it's done. What sort of long-term economics do you assume for the Barnett, say, over a five-year period?

I'm thinking about, you know, you have your drilling completion costs and then you have the transaction costs, and I was wondering have we given enough power to the scale of the past infrastructure expenses as far as the production that's going to keep being generated going forward?

I guess I'm just wondering how we think about those gathering and transportation costs against the long-term economics of the play.

Glenn Darden

Well, I can't speak to everyone's economics, but we have spoken to ours and I think Quicksilver's in a unique position where we own most of our infrastructure through our subsidiary, Quicksilver Gas Services. So we have a cost advantage and most of our acreage ties in to that infrastructure, of course.

So I think going forward we have very attractive economics. As I said earlier, essentially all of our infrastructure will be in place by year end with the Alliance additions, so, number one, we see attractive economics; number two, we see growth for our company for the next half a dozen years depending on how hard we push the accelerator. But we've got 1,500 locations to drill and we have excellent economics with our own infrastructure and further enhanced with our firm transportation out of the basin.

So I think we're set up well to bring this on, as we said earlier in the prepared remarks. It just depends on at what price we want to accelerate the push on production. So I think we're set up well in regards to the overall decline of the basin.

We're not too concerned with the overall decline. We're concerned with our production growth and we've got plenty of growth to go.

Noel Parks - Ladenburg Thalmann & Co.

Drilling down a little bit, on a unit basis looking forward what are your current assumptions for how drilling complete costs come out on a per unit transportation cost component?

And then, considering that service costs have come down a good bit, what do you think is your unhedged breakeven price in this environment with [inaudible] lower service costs?

Rick Buterbaugh

Well, obviously, that's going to be very dependent upon all those factors that you talked about. As I went through on our guidance for the third quarter, you can see that our cash piece is very low. Now, that's certainly not what we're running economics on. We think that in a more normalized environment we're going to be in the $6 to $8 value for natural gas and that the NGL pricing will recover some, too.

Depending upon that is one of the reasons why we're deferring some of the completions right now. We think we will actually be paid to wait on the completions of these wells. Even though we have a little bit of the sunk cost associated with the drilling and casing of those wells in place, the value of the production coming out if we return into the $6 to $8 gas price is going to more than offset the holding cost for the next year or so on that.

In that normalized environment we're certainly expecting a 40% plus return [break in audio] capability to generate those types of returns.

Toby Darden

And, Noel, to add to that just a little bit, we look at the cost to develop in the Fort Worth Basin and, of course, as Glenn mentioned, we're uniquely positioned to compete very well cost-wise in this existing basin in the Barnett.

But to compare Barnett costs to other basins that are currently under development, our costs are significantly lower per Mcfe than other basis. So we'll be developing at a lower threshold than our competitors in other basins.

Rick Buterbaugh

When you factor in all costs.

Glenn Darden

Yes, I think the bottom line, maybe, to your question, Noel, is that on a cash basis our cost is about $2 and on an all-in basis it's, call it, $3.50 economic breakeven, which I think is what you were asking us for.

Returns, obviously, are going to vary depending on what the gas price is and what the oil price is.

Operator

Your next question comes from [Steven Carpel] - Credit Suisse.

Steven Carpel - Credit Suisse

Where are you comfortable with the revolver balance? Maybe that goes to what the update is on some of these KGS potential transactions.

Phil Cook

Well, I'm comfortable with the revolver balance today. We have $350 million of liquidity. It'd be nice to have more, but we don't today.

And then with respect to KGS, we don't have Board approval yet to do anything but we certainly have talked about potentially dropping the Alliance asset down into KGS from Quicksilver. I don't know exactly what the purchase price will be but it's somewhere between probably $50 and $70 million, which would generate cash for the parent.

Steven Carpel - Credit Suisse

And that would be funded through equity?

Phil Cook

There's a combination of things that we could do to raise capital in KGS.

Steven Carpel - Credit Suisse

And kind of just general capital raise, I guess, given the second lien is out is there any change or any view or any thoughts on monetizing more hedges or is the status kind of how we are?

Phil Cook

I don't think that there's any thought today to monetize any hedges.

Steven Carpel - Credit Suisse

And then finally, I was trying to pick through here with the balance sheet a bit. What's the current value of the Eni liability based on where the curve is today?

Phil Cook

It's about $50 million.

Operator

Your next question comes from Mike Jacobs - Tudor, Pickering, Holt & Co.

Mike Jacobs - Tudor, Pickering, Holt & Co.

I just wanted to follow up on the additional CapEx. How much of that $50 million is upstream spending?

Phil Cook

Probably 80% of it.

Mike Jacobs - Tudor, Pickering, Holt & Co.

Is there going to be any material carrythrough on production impact for 2010 or is that not the right way to think about it?

Phil Cook

You mean production that comes on in 2010 that we drilled in 2009? Certainly there will be. It won't be as significant as it was in 2009 because we were spending a lot more capital in 2008.

I think the way you should think about our production, though, is that for 2010, given gas prices and given cash flow generation we're probably going to be flat from 2009 to 2010 short of something changing in the macro environment, gas environment.

Mike Jacobs - Tudor, Pickering, Holt & Co.

And then just going back to Alliance just to make sure I understand the actual assets that were sold, should we think about the 27.5% working interest in Alliance going for $230 million and then selling the 860 hedges, those were worth $50 million, to get to the $280 million of total value?

Phil Cook

Sure, you can think about it that way. Economically that's what happened.

Mike Jacobs - Tudor, Pickering, Holt & Co.

And then on the reserve side, you indicated that if we think about Quicksilver buying the properties, the 3 Bs per location, you sold 27.5% assuming 5 B location, with those expected higher recoveries, do you have an initial estimate of what reserve revisions could look like ex price affects?

Phil Cook

Not at this time, Mike. Let those engineers tell us.

Operator

Your next question comes from [Mark Crusoe] - Millennium Partners.

Mark Crusoe - Millennium Partners

Just a clarification question. Earlier you talked about you guys were in the process of completing your Horn River well and I missed it earlier if you'd mentioned when we would hear an update on that or what you're thinking strategically?

Glenn Darden

We'd like to get some production behind us, but it's probably fourth quarter when we talk about that.

Operator

(Operator Instructions) Your next question comes from Adrayll Askew - Hartford Investment.

Adrayll Askew - Hartford Investment

In your prepared remarks you highlighted some of the changes that you made to your latest Lake Arlington wells. Can you expand on that comment, provide some more detail there?

Glenn Darden

Well, we've been working on optimal spacing in all of our areas and we have actually widened the spacing in the Lake Arlington and we're doing the same at Alliance and it looks like getting the same reserves with less capital spend on a per acre basis.

I don't want to tell you or our competition exactly what we're doing, but we have increased the number of stages and tweaked our fracs, if you will.

Operator

You have no further questions at this time. Do you have any prepared closing remarks?

Rick Buterbaugh

Yes, thank you.

Just as a reminder, Quicksilver will release our third quarter 2009 earnings on Monday, November 9th before market open.

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

Operator

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

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Source: Quicksilver Resources Inc. Q2 2009 Earnings Call Transcript
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