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Quicksilver Resources Inc. (NYSE:KWK)

Q2 2008 Earnings Call Transcript

August 6, 2008 11:00 am ET

Executives

Richard Buterbaugh – VP, IR and Corporate Planning

Glenn Darden – President and CEO

Phil Cook – SVP and CFO

Toby Darden – Chairman

Analysts

Mike Jacobs

Noel Parks – Ladenburg Thalmann

David Snow – Energy Equities Inc.

Marshall Carver – Capital One Southcoast

Stephen Beck – Morgan Keegan

Gil Yang – Citigroup

Gregg Brody – JPMorgan

John Ragozzino [ph]

Dan McSpirit – BMO Capital Markets

Mike Scialla – Thomas Weisel Partners

Jay McHorn [ph]

Operator

Good morning. My name is Connie and I will be your conference operator today. At this time, I would like to welcome everyone to the Quicksilver Resources second quarter earnings call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator instructions) Thank you. Mr. Buterbaugh, you may begin your conference.

Richard Buterbaugh

Thank you, Connie, 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’s results for the second quarter of 2008. 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 risk and uncertainties. Actual results may 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 net cash from operating activities before changes in working capital, which is a non-GAAP financial measure. As required by SEC rules, a reconciliation of net cash from operating activities before working capital to the most directly comparable GAAP measure is available on our website under the Investor Relations tab. Please keep in mind that all references to per share amounts reflect the impact of the two-for-one stock split affected in the form of a stock dividend, which occurred on January 31, 2008.

For the second quarter of 2008, the company reported net income of $52.4 million or $0.31 per diluted share, which is up 65% from the prior year quarter and up 24% sequentially versus the comparable first quarter 2008 amount. Once again, the continued successful execution of our development program in the Fort Worth Basin Barnett Shale resulted in 121% increase in volumes of natural gas and natural gas liquids from the prior year quarter and up 17% sequentially from the first quarter of 2008.

On a similar note, our Canadian operations, production was up 16% year-over-year, and we were able to keep volumes flat versus the first quarter of 2008 despite the normal lack of drilling activities during the spring breakup period. The combined result enabled the company to achieve our second highest quarterly production volumes despite the sale last November of our Northeast operations, which accounted for approximately 74 million cubic feet per day of production.

Now I will turn the call over to Glenn Darden to review our operating activities in additional detail.

Glenn Darden

Thank you, Rick. Approximately one year ago Quicksilver announced the sale of our production in Michigan and Indiana. At that time we said we would replace the roughly 550 Bcf of reserves sold by year-end with our Barnett drilling, and by the middle of 2008, we would replace the 74 million a day of production that was sold. We have done that and more. Today we announced our second quarter numbers and it is very clear that we have not only increased production 13% over last year’s numbers, which included that 74 million a day of Michigan and Indiana production, we have also lowered our unit cost through diligent cost controls.

When you take out the sold production, we grew company production year-over-year by 75%. By every measure Quicksilver had an outstanding second quarter and 2008 is shaping up to be another great year for the company. We can’t do much about the equity environment, but we can continue to post superior numbers, and we are on track to produce record volumes this year.

As Rick reported, Quicksilver Resources earned $52.4 million or $0.31 per diluted share for the second quarter of 2008. This was an increase of 65% over the second quarter of 2007. Average daily production was 236 million cubic feet equivalent per day. As I mentioned earlier, that was an increase of 13% year-over-year, which included the Michigan and Indiana production.

The 2008 production volumes were comprised of approximately 67% natural gas, 29% natural gas liquids, and 4% crude and condensate. In the Fort Worth Basin, the company drilled 63 wells in the quarter connecting 57 to sales. Our daily production volumes increased 121%, as Rick said, year-over-year. It is important to note the value of the natural gas liquids to our revenue stream was over 35%. And at $9 per Mcf natural gas prices, we are receiving almost $13 per Mcf equivalent.

Approximately one month ago, Quicksilver announced reaching an agreement to purchase certain producing and non-producing leasehold royalty and mid-stream assets in the Fort Worth Basin. This Alliance transaction is set to close this Friday. Phil Cook will talk about the transaction in greater detail in his remarks. This acquisition was truly driven by our engineers. We’ve seen a tremendous opportunity on this 13,000 acre block in a very thick Barnett depositional area. Our team sees similarities to Quicksilver’s Lake Arlington project, which is looking very strong for the company.

In Canada, most operations were suspended for much of the second quarter due to the seasonal fall or breakup period. Our Canadian team has now resumed drilling and completion activities and is on target to drill 265 gross wells or 165 net wells this year, and achieve production growth of 7% to 9% year-over-year. They are also diving into our Horn River Basin project, working on plans for the initial test well drilling for late this year. At this point, our plans are to drill and complete at least two wells to test the Devonian shales in this basin. Several players are offsetting our large acreage position and are accelerating their drilling activity. And we should have more data points to key off of prior to drilling our first wells. There is no question that the Horn River is heating up.

Another area that seems to be getting hotter is the Delaware Basin, as production information is coming out from wells in the area. Our US new ventures team is actively working on this project and we now have a dedicated operating team executing our program with one rig running through the remainder of this year and into 2009. We hope to be talking about results end of this year or first quarter of 2009.

In summary, Quicksilver is exceeding its growth targets in driving down costs. We have a solid hedge position on over 70% of our projected gas production for the remainder of this year and 50% in 2009. All of this is generating significant cash flow to accelerate the program. With the addition of the new Barnett assets, Quicksilver has a reserve target of over 5 trillion cubic feet equivalent in the Barnett alone. Should we have success in any of our new projects, we have the potential to double those reserve volumes. By controlling a significant portion of the gathering and processing through ownership in Quicksilver Gas Services, we have been able to control costs and maintain flexibility in getting gas to market. The net result is Quicksilver Resources will continue to be a high growth, low cost company for many years to come.

And with that, I’ll turn the call over to Phil Cook, our Chief Financial Officer, to discuss the quarterly numbers. Phil?

Phil Cook

Thank you, Glenn, and good morning everyone. I want you all to keep in mind that we sold our Northeast operations, as Glenn said, in the fourth quarter of 2007, and therefore oil production and revenue comparisons that I’ll discuss today exclude the Northeast operations in the prior year. I also want to echo what Glenn said regarding the second quarter. This is certainly one of the strongest quarters that Quicksilver has ever had by many measures. Volume growth is strong, costs were down. And from my perspective, that’s a very good combination.

Sequentially, production volumes grew from 211 million cubic feet a day equivalent in the first quarter of 2008 to 236 million cubic feet a day in the current quarter, a 12% sequential increase. For the current quarter and first half of 2008, total production grew by 76% and 83% respectively when comparing to the same periods a year ago. Production volumes in the Fort Worth Basin grew by 120% and 146% with respect to the quarter and the first half of the year when comparing again to the same periods a year ago. Sequentially, volumes in the Fort Worth Basin grew by 17%.

Total production revenues grew from $158 million in the first quarter of 2008 to $198 million in the current quarter, a 25% sequential increase. Total production revenues grew by 112% and 107% with respect to the quarter and six-month periods when comparing to the same periods a year ago. Roughly three quarters of the increase is attributable to higher commodity price realizations with the remaining quarter being attributable to volume growth. In the Fort Worth Basin, excluding hedging impacts, production revenue grew by 237% and 250% for the quarter and six months periods. Sequentially, excluding the effects of hedging, production revenues in the Basin grew by 48%.

Our realized natural gas price for the quarter was $9.02 after hedging compared to $8 in the first quarter, up 13%. Natural gas liquids realized prices were $54.45 a barrel after hedging in the current quarter compared to $49.36 a barrel in the first quarter, up 10%. Realized oil prices were $88.25 a barrel after hedging in the quarter, up from $77.46 a barrel in the first quarter, a 14% increase.

Net income for the quarter was $52.4 million or $0.31 a diluted share as compared to net income of $42.2 million or $0.25 a diluted share in the first quarter, a 24% sequential increase. Second quarter 2008 net income includes a non-cash pretax loss of $10.3 million or about $0.04 a diluted share on the company’s investment in BreitBurn Energy Partners LP. As you know, Quicksilver owned 32% of the limited partner units of BreitBurn as of the quarter end. Earnings per share would have been about $0.35 without this non-cash charge taken by BreitBurn.

During the second quarter, the company generated approximately $135 million of cash flow from operations before working capital changes as compared to $112 million in the first quarter, a 21% increase in cash flow. Quicksilver also received approximately $20.3 million of cash distributions during the first half of 2008 associated with the ownership of the BreitBurn unit. These distributions are included in investing cash flows for the 2008 year-to-date numbers.

Total operating expense for the second quarter, excluding D&A, was $51.9 million and flat when compared to the first quarter. LOE for the current quarter was $1.03 per Mcfe compared to $1.25 in the first quarter. These amounts exclude transportation, processing and production tax expense. As you can see, our sequential reduction in lease operating unit cost was 17.5%.

Transportation expense, which is the cost to get our gas from the tailgate of our facilities to market, was $0.30 on an Mcfe basis during the quarter compared to $0.23 in the first quarter of 2008. Approximately $0.03 of this increase represents the fuel consumption component of pricing. As the price of gas goes up, the cost of fuel consumed also rises.

The remaining increase as the result of incremental transportation costs incurred due to a decision we made in May to begin selling a portion of our production at Henry Hub as opposed to Katy or Carthage, which is where the production was sold in previous quarters. The increase in revenue from selling at Henry Hub more than offset the increased transportation cost with the positive result for the quarter of approximately $175,000 to operating income. In the first quarter, we sold 100% of our Texas production at either Katy or Carthage. In the second quarter, we sold 60% at Katy or Carthage and 40% at Henry Hub, and obviously this is all – I’m talking Texas production here.

There is no transportation expense on NGL volumes as we effectively sell those volumes at the tailgate of our facilities at net-net pricing. Processing expense, which is the cost to gather and process our gas from the wellhead up to the tailgate of our facilities at KGS, for the current quarter was $0.23 on an Mcfe basis compared to $0.21 in the first quarter of 2008. The increase in these costs on a Mcfe basis is 100% attributable to higher fuel costs.

So, just as a recap, oil and gas expenses were broken down as follows. Transportation expense was $0.30, processing expense was $0.23, and LOE was $1.03 for a total oil and gas expense of $1.56. That’s compared to $1.69 in the previous quarter of this year, which is a 7.7% sequential decrease. As I’ve discussed with you in previous quarters, the trend on LOE is coming down as compared to previous quarters. As we continue to grow our Texas production, we expect to further reduce our unit costs.

Our cash operating margin based on current prices are in excess of 65% across the company. The D&A run rate for the current quarter was $1.81 per unit, a decrease from $1.82 per unit reported in the first quarter of 2008. Our DD&A rate changes during the year have replaced depreciable assets such as our midstream assets into service and as the mix of production changes between our two full cost pools, our US pool and our Canadian pool.

With respect to G&A, both the cash expense and equity compensation in the current quarter were flat compared to the first quarter of 2008. This translates to $0.72 on a unit basis for the current quarter as compared to $0.80 in the first quarter of 2008, a unit cost decrease of 10%.

A little bit with respect to capital and liquidity. Our revolving credit facility at quarter-end was approximately $267 million drawn on a borrowing base of $1 billion. Total debt at quarter-end was approximately $1.3 billion, which translates to a total net debt-to-capital of approximately 58%.

Looking forward, we expect to turn the cash portion of the Alliance acquisition that Glenn talked about through a combination of a $700 million five-year second-lien term loan facility and draw approximately $300 million on our existing credit facility. The credit facility is subject to an intermediate termination on or about September 15, 2008 when we expect to increase our borrowing base.

Just as an update on the pricing of the new $700 million second-lien facility that I spoke of, we’ve completed the syndication process and have commitments for $700 million, at pricing of approximately 7.75% on the coupon side. This note will be issued at a discount at 98% and will find on August 8, 2008, this Friday, contemporaneous with the closing of the Alliance transaction. As some color on this financing, there was significant demand for this note. And as such, we think we’ve got good pricing in a very volatile credit market. This acquisition, as we announced in July, is immediately accretive to unit cost and cash flow per share. In 2009, accretion to cash flow is 30%. As you all know, we’ve committed to sell existing assets in order to pay this note down by $500 million by the end of the year 2009. We expect our debt-to-capital to be around 61% at year-end 2008 and moving down to around 50% by year-end 2009.

Now I’ll make a couple of comments about what to expect in the third quarter of 2008. Production volumes for the third quarter should be in the range of 280 million to 290 million cubic feet a day on an equivalent basis. This estimate includes the uplift we will see from the Alliance acquisition, which we will own for a partial quarter.

With respect to commodity prices during the third quarter, you should note that we have an average of approximately 157 million a day of natural gas hedged with collars and swaps. The collars have a weighted average floor of about $8.22 per Mmbtu and a weighted average ceiling of about $10.33 per Mmbtu. And these hedges cover approximately 78% of our expected gas production. For the remainder of the year, we have collars on 1,000 barrels of oil a day with a floor of 65 and a ceiling of 75.68. Additionally, for the remainder of the year, we have swaps in place for 3,000 barrels a day of NGLs with an average swap price of $43.82.

On the unit costs side, obviously these costs are as much affected by volumes as they are absolute cost. With the volume expectations that we’ve given, the following run rates – range of run rates should be expected for the third quarter. Please note these assume consummation of the Alliance property acquisition later this week.

On the LOE side, it should run in a range of $1.00 to $1.05. Transportation expense should range from $0.29 to $0.31. Gathering and processing expense should be in the range of $0.21 to $0.24. Production taxes should be in the range of $0.13 to $0.15. And G&A should be in the range of $0.65 to $0.70, to give us total cash costs to be in the range of $2.28 to $2.45. In addition to that, DD&A run rate will rise as a result of the Alliance acquisition. DD&A range should be $2.15 to $2.20 in the third quarter.

Now I'll turn the call back over to Rick for questions.

Richard Buterbaugh

Thank you, Phil. Connie, at this time we’d like to open the call to any questions that may exist. But please ask the participants that they limit their questions to one at a time so that all participants may have an opportunity to talk.

Question-and-Answer Session

Operator

(Operator instructions) Your first question comes from the line of Mike Jacobs.

Mike Jacobs

Thank you. Good morning guys.

Glenn Darden

Hi, Mike.

Mike Jacobs

I want to start off with the – I actually have a two-part question. I want to start off with the question on Barnett infrastructure. ETP’s press release yesterday suggested roughly 500 million a day of additional capacity by the first quarter and some Barnett operators have limited production because of infrastructure concerns. Do you have any agreements in place currently to secure additional capacity on the Paris loop [ph]?

Glenn Darden

Mike, we are currently working on that in conjunction with the Alliance acquisition and we have secured sufficient takeaway capacity to more than accommodate that acquisition and expansion in the Lake Arlington area. We haven’t been curtailed yet. We don’t plan to be curtailed in the future. And I think that’s just a result of our team looking ahead of us as to what’s coming. So – but we have a great relationship with ETP and they are working with us very well.

Mike Jacobs

That’s great. And then the follow-up is, do you have any kind of high level thoughts on peak production in terms of when you see production peaking and kind of aggregate amounts, I think we’d all appreciate any high level thoughts you have?

Glenn Darden

You are talking about the overall field?

Mike Jacobs

Right. (inaudible).

Glenn Darden

Just we are seeing numbers – years anywhere from 2013 to 2015. Internally we are projecting roughly in that range about 2014 to 2015 for our peak production. But truly we don’t have as good a handle obviously on the other players.

Mike Jacobs

Thanks, I’ll –

Toby Darden

That being said though, Mike, the technology is still evolving. So we’ve been surprised so far by the robust nature of this play.

Mike Jacobs

Thank you very much.

Operator

Your next question comes from the line of Noel Parks.

Noel Parks – Ladenburg Thalmann

Good morning.

Glenn Darden

Good morning.

Richard Buterbaugh

Good morning.

Noel Parks – Ladenburg Thalmann

Just have a couple of questions. Do you have any update – and excuse me if I missed this because I had to drop off for a minute. On the downspacing in the Horseshoe Basin, and I realize you’ve just been getting back up to speed after the breakup.

Glenn Darden

Yes, we have a couple of downspacing projects, pilot projects already on line and we should know we should have a good handle on that later this year. But we have initiatives on six different areas in the Horseshoe Canyon on pilot programs for the downspacing. So I would say at the present time it’s looking good based on the initial two projects.

Noel Parks – Ladenburg Thalmann

Okay. And in the Barnett, as you put together another quarter I guess going into more than a year now is the pad drilling approach out there. Do you have any comments on what sort of variables you see I guess within a given pad or from location to location? And is that process pretty much – does that pretty much have all the things [ph] worked out? Do you still see there a lot of variability, and if so, based on what factors?

Glenn Darden

Certainly I think it’s the way to drill these. And do we have everything ironed out in terms of efficiencies? We think there are still some efficiency gains to be made. So this is certainly the way to go in our mind and we are trying to drill everything we have on pad drilling. But are we 90% of the way as an industry on efficiencies? I’m not sure. I wouldn’t say that at this point. But what we see is producing better results and certainly on tighter pricing more reserves per acre than in the past. So, we are definitely on the right track.

Noel Parks – Ladenburg Thalmann

And just one last one. Could you just update us on your steel, your pipe situation?

Glenn Darden

We are in good shape on steel and pipe. We have a couple of months' inventory in our yard ahead of our drilling program, and we source through multiple outlets, so enough pipe to conduct our program this year and beyond.

Noel Parks – Ladenburg Thalmann

Okay, great. Thanks.

Operator

Your next question comes from the line of Gil Yang. Mr. Yang, your line is open. Your next question comes from the line of David Snow.

David Snow – Energy Equities Inc.

Hi. Following up on that pad question, what spacing and what types of reserves per well are you achieving, and are you using simul frac?

Glenn Darden

We are simul fracing where we can, certainly simultaneous flow-back. It would depend on the area and now we have quite a broad area in the Barnett. But in our core Hood County area, we are drilling 500 feet between wells at this point. We are doing some testing on 250 feet between horizontal wells. In our Lake Arlington project, we are on 250 feet between wells and we are doing some spacing inside of that, some testing on inside of that right now. And we anticipate this new Alliance project to be drilled on 250-foot spacing and perhaps we’ll do some testing inside of that. But it depends on the area on recoveries. Lake Arlington is 5-plus Bcf of dry gas. The Alliance, we’ll see – at this point, we’ve modeled 3 Bcf, but we do see similarities with the Lake Arlington project. In our Hood County area, we are recovering roughly the same that we’ve been talking about for the last two years and that’s about 2.4 Bcf equivalent. And over a third of that equivalent is in natural gas liquids.

David Snow – Energy Equities Inc.

And that’s per well?

Glenn Darden

Per well, yes, all those numbers are per well numbers.

David Snow – Energy Equities Inc.

And how do you translate the–?

Glenn Darden

And those are net numbers. Those are net –

David Snow – Energy Equities Inc.

Yes. How do you translate the feet between two-acre spacing? The 500 feet is how much and 250 feet is how much?

Glenn Darden

It depends on the length of the lateral, but roughly 40 to 50-acre spacing, something like that on 500-foot spacing.

David Snow – Energy Equities Inc.

So you are actually going down to 20 or 25-acre in your tests in your Lake Arlington?

Toby Darden

We are looking at that, David. We are trying a few tests in that range.

Glenn Darden

Maybe closer to 60-acre spacing in the 500-foot.

David Snow – Energy Equities Inc.

60-acre?

Glenn Darden

It just all depends on the length of the lateral. So we are truly – we look at it feet between wells.

David Snow – Energy Equities Inc.

And so you must be shooting to get 30% recovery or better with that type of density?

Glenn Darden

We are not that high at this point, but may be eventually.

David Snow – Energy Equities Inc.

Okay. And what’s happening in Hood – I mean, up in the Horn Basin compared to – how does that look compared to your other plays in the non-conventional area?

Glenn Darden

The Rock looks very attractive. And on paper, it looks similar if not perhaps a bit better than the Barnett. It’s certainly thicker than the Barnett. It’s slightly more over pressured, higher silica content, some of the things, the critical things that we’ve seen in the Barnett that have let themselves to high productivity. But we haven’t drilled our first test wells yet. Surrounding producers offsetting us have come in with some pretty nice gas production rates. So, we think that this is a very, very solid play for us, but it’s a little bit early for us to talk about it since we haven’t drilled our first test wells. That will happen later this year.

David Snow – Energy Equities Inc.

What kind of IPs have you heard?

Glenn Darden

Between 4 million and 10 million a day.

David Snow – Energy Equities Inc.

Can you get that stuff out of there easily or is it a end of the world up there?

Glenn Darden

Well, we are working on that, but there is takeaway right now and additional takeaway is being built.

David Snow – Energy Equities Inc.

And what acreage do you have?

Glenn Darden

We have 127,000 net acres up there.

Toby Darden

And David, our immediately adjacent competitors are going to drill 170 wells around us this year. So there are going to be a lot of data points.

David Snow – Energy Equities Inc.

Can you give us a color as to who is that – who the players are?

Glenn Darden

The players who have announced large acreage positions that are adjacent to our blocks are EOG on the west side; Apache, EnCana to the south and east, Nexen, those – Exxon Imperial, they have announced an acreage block as well – or that they are up there. So –

David Snow – Energy Equities Inc.

Okay, great.

Glenn Darden

Lots of company.

David Snow – Energy Equities Inc.

Thank you.

Glenn Darden

Thank you, David.

Operator

Your next question comes from the line of Marshall Carver.

Marshall Carver – Capital One Southcoast

Yes. I have a question about planned capital expenses. What are you all planning for the third and fourth quarter?

Phil Cook

Marshall, we have a Board meeting later in August to get approval to change our capital budget. As you know, our capital budget for the year was about $885 million. We’ve been public on a couple of different calls about the fact that cash flows were a couple hundred million higher this year than we anticipated when we put that budget together. And my expectation is even though we don’t have approval yet that we will go over that budget by a couple hundred million dollars.

Marshall Carver – Capital One Southcoast

Okay. That’s helpful.

Phil Cook

Most of that, just so everyone knows, is related to drilling more wells, acceleration of capital, and the increase of steel prices on the pipe side.

Marshall Carver – Capital One Southcoast

Okay, thank you. And one question on your fourth quarter guidance versus your 2009 guidance, your fourth quarter rates for this year are expected to be 370 million to 380 million a day, and then 2009’s 390s, so not a lot of growth there. Would you expect not much growth in the first half due to well timing or is 2009 particularly conservative, or what’s your color around those rates there?

Phil Cook

I think it’s a conservative number. And we’ll have just more color on it as the year progresses for ’09.

Marshall Carver – Capital One Southcoast

Okay. Thank you very much.

Phil Cook

Thank you.

Operator

Your next question comes from the line of Stephen Beck.

Stephen Beck – Morgan Keegan

Hi, good morning.

Glenn Darden

Good morning.

Stephen Beck – Morgan Keegan

Yes. I was just hoping that maybe you could give us a little bit of color on the – at least your preliminary thoughts on development on the Alliance project, maybe how many rigs you anticipate and wells and so forth?

Glenn Darden

We have talked a little bit about this, but initially – and we close this Friday, but we’ll move one rig up there fairly properly within the next couple of weeks. And by year-end, we’ll have a total of three working that area.

Toby Darden

Yes. Stephen, we have – there is one rig running currently on the property. We’ll add one more fairly quickly and we’ll have three running by the end of the year.

Stephen Beck – Morgan Keegan

Okay. And given the increase of steel costs, is that impacting your – or what is the impact on your drilling costs in the Barnett?

Phil Cook

It depends on where we are drilling, of course, because these are different sized wells. But from a drilling point of view, we are saying that our Hood County, Summerville wells are still about $3 million in terms of all-in costs for those wells. Arlington, those wells are a little more and have much longer laterals, so those wells are anywhere between 4 million and 4.5 million. Where we’ve really seen the biggest impact is in the midstream business and it is higher steel cost on line pipe as well as compressors and other facilities that we are buying.

Stephen Beck – Morgan Keegan

Okay. And then last one for me, given the situation with takeaway capacity discussions related to that, I would not anticipate any real concerns of long-term or – say, with the Alliance area. Can you comment on the existing infrastructure and near-term expectations?

Glenn Darden

Stephen, we don’t have any transportation issues of any kind. We control all our gathering and processing. And we have made prior arrangements because of that. To have takeaway downstream on the larger pipes, they go to Carthage, and as Phil mentioned in his remarks, as far as Henry. So we made arrangements planning for this two years ago and it looks like a good decision.

Stephen Beck – Morgan Keegan

Great. Thank you very much.

Glenn Darden

Thank you.

Operator

Your next question comes from the line of Gil Yang.

Gil Yang – Citigroup

Hi, do you hear me?

Glenn Darden

Yes, we hear you.

Gil Yang – Citigroup

I don’t know what happened last time. All right. Could you give us an idea – you commented on [ph] West Texas some very good results. Could you maybe give us an idea of what you’re hearing about and where that is versus your acreage?

Glenn Darden

I think maybe you should talk with the players who are producing that, and that’s primarily Chesapeake. But we have just heard field numbers, so we’re not prepared to talk about that today. But it does sound like it’s moving the right way. And as we’ve talked about before, we’ve seen gas volumes in every well we’ve completed and we are putting a little more pressure internally to get some answers there, Gil. So –

Gil Yang – Citigroup

Okay. Maybe – let me ask it the different way, given that you don’t want to – you can’t or shouldn’t comment about Chesapeake. Have you yourself seen the results in your wells (inaudible) regardless of what Chesapeake says, that would make you continue to invest in the area?

Glenn Darden

But what we’ve seen is encouraging. And we are investing more in the area. So – but we haven’t tested the Woodford at this point, and so that’s a key part of this testing program that we are going to be doing for the rest of the year. And as we’ve talked about before, possibly combining Woodford in, Barnett, most – all of our testings thus far have been in the Barnett.

Toby Darden

Gil, there is an evolution going on in the treatment out there. And much like we did in the Barnett, we marked time for the last three months studying the treatments that were being executed. They definitely are improving the production. We see improvements overall in the strategy and we are putting a rig to work in September to run through the end of the year. So we now have enough encouragement to go forward and spend some dollars on our shareholders back.

Gil Yang – Citigroup

It doesn’t sound like it’s quite there yet, but it’s moving in the right direction.

Glenn Darden

Yes, I would say that’s right. That’s right.

Gil Yang – Citigroup

Okay. And then just sort of related to that is that, where Chesapeake is versus where you are, I think you’ve said that what you like about your acreage is that it’s relatively shallow and Chesapeake is in some of the deepest parts of the basin. So can you actually draw any conclusion about your acreage based on what Chesapeake is seeing?

Glenn Darden

We’ve done a lot of coring. And we’ve got plenty of gas in place and the pressures are different, but costs are different. So we are in a shallow area that’s a lot less cost to attack. So we still think we are in a pretty good position.

Gil Yang – Citigroup

Okay, great. Thanks.

Glenn Darden

Thank you.

Operator

Your next question comes from the line of Gregg Brody.

Gregg Brody – JPMorgan

Good morning.

Richard Buterbaugh

Good morning, Gregg.

Gregg Brody – JPMorgan

Just wanted to get a little bit more detail about the asset sale process in terms of if you have started down that path and maybe a little bit more specifics around timings?

Glenn Darden

We don’t have any specifics to talk about today, but we have in our portfolio quite a few assets, some mature oil properties out in the Rockies. We have obviously a large Canadian base that perhaps certain assets could be sold there. We have BreitBurn assets or BreitBurn units. We have KGS units. So I don’t know that you would see one big sale that takes care of everything. I think you might see smaller sales, but who knows. We are in discussions right now on that, but we haven’t formulated a firm game plan yet.

Gregg Brody – JPMorgan

Okay. And then you mentioned your credit metrics for ’08 and ’09, and you (inaudible) the debt-to-cap, the other three metrics that you mentioned when you announced the transaction last month, those are still in place, is that correct?

Glenn Darden

Yes, that’s correct.

Gregg Brody – JPMorgan

All right. And then just finally in terms of the acquisition market, do you see any bolt-on opportunities that – are you seeing bolt-on opportunities in other areas and are you open to those kind of [ph] things?

Glenn Darden

I think we made our big acquisition here, but we have seen some opportunities to pick up leases where leases are expiring, farm-in in areas, so not big dollars upfront, but just adding to our inventory in our base area in the Barnett. And we may see some opportunities up in the Horseshoe Canyon as well.

Gregg Brody – JPMorgan

I appreciate the color. Thanks guys.

Glenn Darden

Thank you.

Operator

Your next question comes from the line of John Ragozzino [ph].

John Ragozzino

Hi, good morning guys.

Glenn Darden

Good morning.

Toby Darden

Good morning, John.

John Ragozzino

I kind of ramped in my whole list here, but one big picture question for you. Can you talk a little bit about just the NGL market and where do you see the relationship between crude prices and NGLs going forward?

Phil Cook

John, this is Phil Cook. The crude price has got to $145 a barrel. That was a gapping out between NGL prices and crude prices. We are still seeing pretty robust NGL prices in the market $55 a barrel, which is very nice relatively to the Mmbtu value in the gas. That’s sort of – whatever that percentage is, at where crude is today, I don’t know where crude is trading today. I think that as long as crude prices stay about where they are, $120 to $100 a barrel, that relationship is going to hold. I think as crude gets above $120 a barrel, we’re going to see a gap out again.

John Ragozzino

Okay. That’s very helpful. I appreciate it.

Phil Cook

I think relative to natural gas prices though, there is going to be a premium for NGLs.

John Ragozzino

Okay. Thanks very much.

Operator

Your next question comes from the line of Dan McSpirit.

Dan McSpirit – BMO Capital Markets

Gentlemen, good morning.

Glenn Darden

Good morning.

Dan McSpirit – BMO Capital Markets

The Horn River Basin, can you discuss the ready market for that gas? I recognize it’s very early innings, but given the location of the basin relative to other markets, I’d like to get a better handle on what the end market is for all that gas. And then, does any of that find its way to feeding the oil sands?

Glenn Darden

We certainly think it will. And our view at this point is most of that gas stays in Canada. As we touched on earlier, we’ve been in discussions with some pipeline companies up there in terms of expanding systems. This gas will need to be processed. So, processing will need to be added there too. But there is some existing takeaway. I think it’s roughly a couple of hundred million at this point that’s getting committed – being committed pretty quickly. But overall I think that gas stays in Canada. Probably a big chunk of it does feed the oil sands.

Dan McSpirit – BMO Capital Markets

Perfect. Thank you.

Operator

Your next question comes from the line of Daniel Guffey.

Mike Scialla – Thomas Weisel Partners

Actually it’s Mike Scialla with Thomas Weisel. Hi guys.

Glenn Darden

Good morning.

Phil Cook

Good morning.

Toby Darden

Hi, Mike.

Mike Scialla – Thomas Weisel Partners

I just had one more question, I guess for Phil. Looking at your DD&A jumping up, I assume that reflects the acquisition being added into the full cost pool. And if we get a full quarter there, where would you expect the DD&A to go for fourth quarter? We’re assuming it’s going to be bumped up a little bit more, is that correct?

Phil Cook

Probably at the top end of that range that I’ve discussed.

Mike Scialla – Thomas Weisel Partners

Okay. Easy enough. Thanks.

Phil Cook

Welcome.

Operator

We have a follow-up question from Mike Jacobs.

Mike Jacobs

Hi. Just going back to your comments on West Texas and kind of trying to put the pieces together, can you provide some additional color on how you see the play developing in terms of vertical versus horizontal? And on the commingled wells, do you have any sort of guesses on what F&Ds could look like?

Glenn Darden

Well, we are certainly working on the horizontal versus vertical. And we’ve done some testing. It looks like, and we’ve talked about this on the road before, that perhaps the Barnett with the sickness there can stand alone with the vertical completion. Without data on the Woodford, it’s pretty difficult to say whether this is going to be a horizontal or vertical. We think it probably will be a combination, but it’s just too early to tell. It sounds like that’s what’s happening north and east of us. But – Toby, do you have anything to add there?

Toby Darden

Yes. The stimulation is evolving on the vertical side and that gives us a lot of encouragement, because obviously if you can make this a vertical play, it’s going to be much more efficient cost wise and F&D comes down significantly. So, yes, we are interested in the vertical side and we’ve got a lot of vertical thickness. So, between the Woodford and the Barnett, we have upwards of 600 to 800 feet of target in a vertical well bore at depths of 9,000 up to 6,000 feet. So we are in pretty shallow area. And if we can make verticals work, it’s going to be a very efficient play.

Mike Jacobs

Okay. And I hate asking this question, but just kind of looking at the balance sheet, can you just remind us how you think about the balance sheet as it relates to managing debt, and when internally you start to feel uncomfortable? What are kind of your guidelines for managing balance sheet?

Phil Cook

We’ve been pretty clear with the Street on what our guidelines are. Where I get uncomfortable I guess is a different number than where our guidelines are. Guidelines tell us that we want to be at less than 50% debt-to-cap. We certainly don’t want to have debt more than four times EBITDA and we are looking at ranges for debt for proved and proved developed at $1.00 and $0.65 respectively. So that’s where we want to be. That is not where we are today. That’s not where we will be at the end of the year, but we’ve got a plan to go there. And as I said, we’ll be at 60%, 61%, 62% debt-to-cap at the end of the year is our estimate today and about 50% at the end of next year. At the end of next year, on a proved and proved developed metric, we probably still won’t be there, but by 2010, we will be. And so, am I uncomfortable with where our debt levels are? Absolutely not. Our coverage ratios are just fine. And I think we’ve got a solid plan to bring these debt levels down. And we are using capital that is costing us collar 8.5% to develop projects that have 40% and 50% IRRs and I think that’s a pretty good economic strategy.

Mike Jacobs

That’s the way we think about it, you just – thanks.

Phil Cook

You’re welcome.

Glenn Darden

Thank you.

Operator

Your next question comes from the line of Jay McHorn [ph].

Jay McHorn

Hi, good morning.

Glenn Darden

Good morning.

Jay McHorn

Not to beat a dead horse, but so many other producers have reported an increasing number of wells or waiting pipeline connection at the quarter-end. I guess how does the takeaway compare to the future growth in Barnett? I think it was mentioned around 750 million feet per day per year growth?

Glenn Darden

Well, we hear that, but we don’t – we are not affected by it. And we certainly – I think a portion of it may be due to processing tightness as well. And not just pure takeaway, and it may be timing of midstream companies tying in. So that may not be a takeaway issue, it could be just a timing issue. So, at this point, as Toby said, when we’ve put our plan in place early on four years ago, we’ve put in our own gathering. We’ve added to that, we’ve put in our own processing, we’ve made long-term commitments to midstream companies takeaway, pipeline companies to take this gas out of the basin. We’ve made commitments to take it all the way to Henry Hub. And we are in pretty good shape at this point. And we are always looking out and things could change. But fortunately, I think the overall basin players have been fortunate that we’ve had aggressive midstream players that are continuing to build high. So – but at this point, and we don’t foresee any takeaway issues on Quicksilver Gas.

Toby Darden

Jay, just to reinforce what Glenn said, we learned a long time ago that if you can’t control your gas downstream and aggregate volumes that are large enough, it’s hard to play unconventional resources. And as a result, we’ve done that from Michigan on and we are doing that currently in Horn River even though we haven’t drilled our first test well there yet. And we are working hard on the takeaway there. So we know we are planning for success. And I think we’ve got enough evidence that there will be some success up there. And we are planning for that right now.

Jay McHorn

Do you think the growth of 750 per year is conservative, or is that possible or achievable, or is it – would be a day [ph] that’s potential for the whole play?

Glenn Darden

We’re probably not the best source, but we’ll see. We certainly what our growth rate is and it’s pretty high.

Jay McHorn

Okay. Thanks. Thanks for your time.

Glenn Darden

Thank you.

Operator

Your next question comes from the line of Noel Parks.

Noel Parks – Ladenburg Thalmann

Hi, just wanted to follow up on a couple of other things. Do you have any thoughts about the non-core or the considerably further out parts of the Barnett, either to the north or more further to the east and southwest? I mean, either in terms of taking a closer look at those or in the opposite direction divesting some of your acreage that’s the furthest out, that isn’t high priority for attention right now?

Glenn Darden

Yes, we’ve said on the road and publicly that we’ve kind of high graded our overall acreage position from give or take 270,000 net acres down to 160,000. This is basically in the Hood County, Summerville area, Hill County areas. And so we have high graded. That doesn’t mean that we are going to just let all of that other acreage outside that, that the additional 100,000 acres expire. We are doing some testing and will be, although we are focused on bringing on the production in our core area. As far as acreage to the far north, and maybe you are referring to the oils window, and to the east, we are not in those plays or portions of the basin. As far as monetizing acreage, we are not looking at doing that at this point, but we might down the road.

Noel Parks – Ladenburg Thalmann

And with the new acquisition that you have in the Barnett, I recall that before the acquisition you had quite a big fleet of wells to drill to hold acreage in your current position. Does the acquisition sort of change your focus as far as those or is it just something else to add on to the plate to the wells you have to do anyway?

Glenn Darden

Yes. I think it was just a great addition. What we looked at – and our requirement to hold leases is less than 100 wells a year. So we are drilling at a pace double that and accelerating that probably over – perhaps next year and beyond. But the Alliance assets, we just – what we had learned from Lake Arlington, our engineers really wanted and believe that we can apply to this Alliance area. It’s a large acreage block. It’s not urban. That fits with our core strategy of developing in non-urban areas. And it looks to be in a very sweet spot of the Barnett. So, that was opportunistic. It was driven by our engineers, but it doesn’t slow down or affect us holding leases in other areas.

Toby Darden

Noel, the Alliance acquisition on its own requires 1.25 rigs to keep up with all the drilling commitments there. And we’ll be drilling with three by the end of the year. So we are not too concerned about any. And as Glenn said, we have 100 or less drilling commitments on our other acreage to keep that going, and we are drilling at twice that rate.

Noel Parks – Ladenburg Thalmann

Okay, great. And again, I apologize if I missed this. Do you have any thoughts on when you will be closer to having something to say about remaining stealth play you have that you mentioned back at the March analyst meeting?

Glenn Darden

We are not going to talk about it today, and we are working on it. It’s another project. It’s at a much earlier stage than the projects we talked about today. But we hope to talk about it next year. We’ll see. Maybe a touch earlier, but we shall see.

Noel Parks – Ladenburg Thalmann

Okay. I think that’s it for me. Thanks.

Glenn Darden

Thank you.

Operator

(Operator instructions) Your next question comes from the line of David Snow.

David Snow – Energy Equities Inc.

Yes, hi, just a follow-up question. I got a little lost on the arithmetic. On the – it seems to me that if you were talking about your having 250-foot laterals or I guess 25 or 30-acre spacing, you would be putting about something on the order of 20 wells per section. And at 5 Bcf, that’s like 100 – I thought there was 160 to 200 in place. What am I doing wrong? I’m not getting 30% or less. Hello?

Phil Cook

David, this is Phil Cook. I’m not sure I understand your question. Ask that again.

David Snow – Energy Equities Inc.

Okay. Well, you had said that a 250-foot lateral was probably–

Phil Cook

250-foot spacing.

David Snow – Energy Equities Inc.

Yes, spacing – I’m sorry – should be about a 25 or 30-acre spacing.

Phil Cook

About 250-foot spacing between wells.

David Snow – Energy Equities Inc.

Yes.

Phil Cook

And it depending on the lateral, depends on how many acres that well is going to cover.

David Snow – Energy Equities Inc.

Okay.

Phil Cook

And those laterals are from 2,500 to 4,500-foot.

Glenn Darden

And we have some 5,000-foot laterals, David. So, it does vary on a location-by-location basis. But it’s just mathematical length versus a box around the 250 – or 125 feet on either side of the lateral.

Phil Cook

And you can’t drill every single acre across the play continuously. There is going to be gaps.

David Snow – Energy Equities Inc.

What’s the average per section that the density – how many wells per section would you be looking at on average?

Glenn Darden

Unfortunately we don’t have just clean sections in this play. The lease position is not square that, but – what we’ve talked about is we’ve got an inventory of 1,800 wells to drill. So I think that may be the better approach just to look at it from that way, and that’s without Alliance.

David Snow – Energy Equities Inc.

Okay. I was just trying to get an idea of what’s in place, 150 to 200 –

Glenn Darden

Excuse me, that is with Alliance, the 1,800 wells to drill.

David Snow – Energy Equities Inc.

Okay. So the in-plays would be something (inaudible) 150 to 200 Bcf per section?

Glenn Darden

That varies from area to area, David, considerably. And that will vary with the thickness. Hood County is thinner. Tarrant County is thicker. And so the gas – and depending on the depth of burial, there are about five different criteria. We have 16 different type curves across the play.

David Snow – Energy Equities Inc.

Okay.

Glenn Darden

So I guess it’s a little complex to just answer it. One side doesn’t fit all.

David Snow – Energy Equities Inc.

You are in some of the thicker sections. So, are you having more to start with in-plays than that on average?

Phil Cook

No, I would think 150 Bcf per section is a pretty good number.

David Snow – Energy Equities Inc.

Yes. Okay, thank you very much.

Phil Cook

Thank you.

Glenn Darden

Thank you.

Operator

There are no further questions at this time. Are there any closing remarks?

Richard Buterbaugh

Yes. Thank you, Connie. Just as a reminder, a replay of this call will be available on the company's website for 30 days. Quicksilver will release our third quarter 2008 earnings on Wednesday, November 5, prior to market open. In addition, the members of the company’s Executive Management team will be making presentations at various investor meetings. Details regarding these presentations will also be available on our website at www.qrinc.com. Interested parties can listen to these presentations through the webcast links that will be available on this site. Thank you for your time and interest in Quicksilver this morning. This concludes our call.

Operator

This concludes today’s Quicksilver Resources second quarter earnings call. You may now disconnect.

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