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Quicksilver Resources Inc. (NYSE:KWK)

Q2 2007 Earnings Call

August 8, 2007, 11:00 AM ET

Executives

Richard C. Buterbaugh - President of IR and Corporate Planning

Glenn Darden - President and CEO

Philip W. Cook - Sr. VP and CFO

D. Wayne Blair - VP and Controller

Analysts

Gil Yang - Citigroup

Jeffrey Robertson - Lehman Brothers

Robert Lynd - Simmons & Company

David Heikkinen - Pickering Energy

Ellen Hannan - Bear Stearns

Michael Scialla - AG Edwards

Stephen Beck - Jefferies & Company

David Tameron - Wachovia

Noel Parks - Ladenburg Thalmann

Joseph Allman - JP Morgan

Starr Spencer - Platts

Presentation

Operator

Good morning. Welcome to the Quicksilver Resources Second Quarter 2007 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. [Operator Instructions]

I would now like to turn the call over to our host, Rick Buterbaugh, Vice President of Investor Relations and Corporate Planning. Mr. Buterbaugh, you may begin your conference.

Richard C. Buterbaugh - President of Investor Relations and Corporate Planning

Thank you and good morning. Joining me today are Glenn Darden, Chief Executive Officer; Phil Cook, Senior Vice President and Chief Financial Officer and Wayne Blair, Vice President and Chief Accounting Officer.

This morning, the Company issued a press release detailing Quicksilver's record results for the second quarter of 2007. If you do not have a copy of the release, you can retrieve a copy of it on the Company's website at www.qrinc.com.

Please keep in mind that 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 material differences is detailed in the Company's filings with the SEC.

Today's presentation will include information regarding adjusted EBITDA, a non-GAAP financial measure. As required by SEC rules, a reconciliation of adjusted EBITDA to the most directly comparable GAAP measure is available on our website under the Investor Relations tab.

For the second quarter of 2007, the Company reported net income of $31.7 million or $0.38 per diluted share. Diluted earnings per share increased 31% from the prior year quarter and were up approximately 35% sequentially from the first quarter of 2007.

These results reflect higher commodity price realizations coupled with the efficient execution of our development program in the Fort Worth basin and our continued focus on controlling unit costs.

Total volumes for the second quarter averaged a record 208 million cubic feet of gas equivalents per day, exceeding the upper end of our initial guidance range. Total volumes were up 27% from the prior year quarter and up 11% sequentially from the first quarter level.

Now I will turn the call over to Glenn Darden for some additional color on these record operating results.

Glenn Darden - President and Chief Executive Officer

Thank you, Rick. We are extremely proud of our operating team delivering these record results despite exceptionally heavy rains this spring throughout the Fort Worth basin and one of the longest and wettest break-up periods in Canada since we have been operating up there.

As a result of their dedicated efforts, we have produced record volumes and what is more important, we remain on track to achieve our expected 25% organic production growth for the year.

Our second quarter volume growth of 27% was driven by our expanding activities in the Fort Worth basin, Barnett Shale project, where we drilled 64 new horizontal wells and connected 44 wells during the quarter.

As a result, total production from the Barnett of nearly 77 million cubic feet equivalent per day increased 50% from the first quarter of 2007 levels and on a year-over-year basis, was up 148%. The Fort Worth basin is now the Company's largest contributor to production volumes, representing approximately 37% of our total.

We have been very pleased with the performance to date of these newest wells in the Barnett, the bulk of which are being drilled with approximately 500 feet between the laterals or approximately 55 acre spacing. Wells from the newest pods have demonstrated IP rates ranging from 2 million to 3 million cubic feet per day.

Additionally, we are seeing similar type decline profiles for these wells as our earlier wider spaced wells, which may improve ultimate recoveries. Although we are encouraged by these early results, we have not yet modified the average expected ultimate recoveries of roughly 2.4 Bcf per well within our core fairway in the basin, but it does look like we will be drilling more wells and we will recover more gas from this fairway.

Keep in mind that the vast majority of Quicksilver's production in the Barnett is high BTU gas where natural gas liquids add significant volumes and value to our revenue and margins.

By product, our second quarter net production from the Barnett was approximately 54% natural gas, 44% natural gas liquids and 2% condensate. You will recall from our first quarter conference call that 125 million cubic feet per day expansion of the Cowtown facility came online late in the first quarter.

This new expansion enables more efficient stripping of the liquids from our rich natural gas. These improvements have increased recoveries of NGLs to more than 110 barrels from each million cubic feet of natural gas processed. You can see that the NGL value associated with our Barnett production adds significant value to our leasehold position.

As I mentioned, we drilled 64 wells in the Fort Worth basin in the quarter bringing our total for the first half of the year to 116 wells. The Company's high grading of our drilling fleet has helped to reduce the average drilling days approximately 15% from our 2006 average.

As a result, we are currently ahead of schedule for our planned drilling of 160 to 180 wells here in the basin in 2007 and expect to finish the year above the upper end of the range.

For the third quarter, we expect to have an average of 15 rigs working in the basin. This includes one rig working at our Lake Arlington project in Tarrant County. To date, we have drilled six wells in this project and first sales are anticipated during the fourth quarter.

In Michigan, additional drilling activities have confirmed the extension of the Richfield formation in the Garfield/Beaver Creek area. In addition, a recent completion in the Prairie du Chien formation achieved payout in just four days. The Michigan team has done an excellent job of creating new opportunities to squeeze more value out of this important producing area.

As is normal for Canada during the second quarter, the spring break-up period coupled with abnormally wet conditions restricted any meaningful development activities. However, this was anticipated and does not impact our expectation of achieving 10% organic production growth for the year from this region.

Two days ago, we priced the initial public offering of our midstream master limited partnership, Quicksilver Gas Services LP. The offering of 5 million common units representing approximately 21% of the entity... it was priced at $21 per unit and at the top end of our expected pricing range.

Keep in mind that Quicksilver Resources has retained an approximate 75% interest in this entity, including 100% of the general partner interest. As such, results of Quicksilver Gas Services will be fully consolidated on our financial statements.

The strong market demand for these units spotlights the value that we have created with these assets and recognition of this value through the creation of the master limited partnership. Similarly, we are currently evaluating opportunities regarding other assets of the Company, which we believe are underappreciated by the market.

On the exploration front, we have drilled three additional vertical wells during the second quarter on our large acreage leasehold in the Delaware Basin of West Texas. This brings our total wells in the play to six. We've completed one initially and will be completing three of these vertical wells very shortly.

Keep in mind that the Delaware Basin covers a very large area across West Texas. The Quicksilver acreage is located in the southern portion of the play, which appears to have significantly different characteristics than acreage further north.

In addition, we are constructing a 10 mile gas line to tie these wells into a sales pipeline in order to sell gas while we are still in the testing phase of this project. We expect that line to be in service by early fourth quarter.

For the year, due to the efficient execution of our operating teams, we are ahead of schedule on our total capital program. To underpin our capital expenditures, we have approximately 70% of our expected gas production for the remainder of the year covered by derivatives, which have an average floor price of approximately $8 per MMBtu.

It has been a busy and successful 2007 so far and we continue to push at all areas to be a leader... an industry leader in organic production growth at a low cost. We believe this combination will distinguish Quicksilver and create more value for our shareholders.

And now I will turn the call over to Phil Cook, our Chief Financial Officer, to discuss the numbers for the quarter and we will be available for questions following his remarks. Phil?

Philip W. Cook - Senior Vice President and Chief Financial Officer

Thank you, Glenn and as all of you saw in the press release, we really had a very good quarter from a production and earnings point of view. Glenn discussed production volumes with you as did Rick, so I will go into the numbers.

Total revenues for the second quarter were approximately $136.4 million, an increase of more than 50% from the prior year quarter of $89.5 million. Roughly two-thirds of that increase is due to volume growth with the remaining one-third relating to increased gas price realizations.

For the six months ended June 30, oil and gas revenues grew from $187.2 million in 2006 to $247.3 million in the 2007 period, a 32% increase. Sequentially, oil and gas revenues grew by 18%. Realized natural gas prices were up 26% for the quarter when compared to the second quarter of last year. Our realized gas price for the quarter was $6.96 compared to $5.54 last year.

For the six months ended June 30, gas price realizations were $6.86 compared to $6.23 in the previous six month period. Realized oil prices on the other hand were down about $5 a barrel for the six month period from $60.39 a barrel in 2006 to $55.25 a barrel in 2007, a 9% decline. Natural gas liquids prices were also down in the 2007 period, averaging $38.16 a barrel compared to $41.12 a barrel in the 2006 period, a 7% decline.

For the quarter, the Company generated $94 million of adjusted EBITDA as compared with $59.4 million in the previous year quarter, a 58% increase. As you know, adjusted EBITDA is a non-GAAP measure of cash flow and is defined as net earnings before income taxes and interest expense adjusted for non-cash charges and credits. A reconciliation of adjusted EBITDA to GAAP is available on our website.

Net income for the quarter was $31.7 million and $0.38 per diluted share as compared to net income of $23.6 million and $0.29 a diluted share in the year-ago quarter. Net income for the six month period ended June 30 was $54.6 million or $0.66 per diluted share compared to $51.1 million or $0.63 a diluted share in the year-ago period.

When comparing both periods, prices were higher as were some of our costs. The breakdown of the change in earnings is made up of the following increases and decreases on a per-share basis. Earnings per share in the previous year was $0.63. Production increases increased that on an earnings per share basis by $0.18. Prices increased that by $0.13 and that is all offset by some changes in operating unit costs and here are those changes.

Interest was higher by $0.11 a share, which reduced earnings per share. We had a higher DD&A rate in the six month period in 2007, which reduced earnings per share by $0.05. We had higher unit operating costs that decreased earnings per share by $0.09 and we had a higher federal income tax rate, which decreased earnings by $0.03 to give us $0.66 for the six months ended.

Total operating expenses for the quarter, excluding DD&A, were $46.8 million as compared with $32.2 million in the prior year quarter and $43.5 million in the first quarter of 2007. The sequential increase of $3.3 million is primarily related to an increase in internal labor costs in the field and costs directly related to increasing volumes.

The increase in labor costs is a direct result of increasing headcount due to our expanded drilling program through 2006 and continuing into 2007.

Oil and gas production costs, which is commonly referred to as LOE, was $1.69 per Mcf for the second quarter, which is flat on a unit basis with the first quarter of this year. LOE on a unit basis for the year will be up about 5% to 6% year over year by the time we reach year-end. The majority of the increases in LOE are related to personnel costs in the field.

Production taxes were $0.22 on a Mcfe basis as compared with $0.27 in the first quarter of 2007. The decrease in production taxes is related to accrual adjustments in the first quarter relating to Canadian freehold taxes. Our cash operating costs for 2006 were approximately $2.20 and Mcfe and during the first half of this year, they are $2.50. Our cash margins based on current prices continued to be in excess of 50%.

The DD&A run rate for the quarter was $1.47 per unit, essentially flat with the $1.46 per unit reported in the first quarter of 2007. Our DD&A rate changes during the year as we add depreciable assets.

G&A was $0.54 on a unit basis for the quarter as compared to $0.36 in the year-ago quarter and $0.59 in the first quarter of 2007. About $0.12 of the $0.54 is non-cash and is related to equity awards. We expect G&A to average for the year between $0.47 to $0.50 on a unit basis. Headcount has increased by approximately 20% year over year due to our increased capital program and drilling activity.

During the six months ended June 30, we have spent about $430 million of capital, which is about 70% of our capital for the year. On the debt side, we have added approximately $300 million of debt to the balance sheet in the six month period.

Our revolver was at $720 million at quarter-end. We expect to use the distribution to Quicksilver Resources from the IPO of Quicksilver Gas Services to reduce borrowings under our credit facility. We anticipate this amount will be approximately $87.5 million net.

With this distribution and cash generation through the next two quarters, we will have approximately $365 million of liquidity through year-end. In addition to that, we requested an increase of our revolver from our bank group. This increase, along with our cash generation, will give us approximately $500 million of liquidity for the remainder of the year.

Now I will make a few comments about what to expect in the third quarter of 2007. Production volumes for the third quarter should be in the range of 215 million to 225 million a day on a gas equivalent basis.

With respect to commodity prices, it should be noted that for the rest of the year, we have approximately 127 million a day of natural gas hedge with collars, which have an average weighted average floor of $8.08 per MMBtu and a weighted average ceiling of $11.12 per MMBtu. These hedges are on approximately 70% of our budgeted gas production.

Additionally, I would remind you that we continue to have $20 million a day of physical gas sales contracts in Michigan, which have an average price of $2.49 per MMBtu. For the remainder of the year, we have collars on about 1000 barrels a day of oil with a floor of $65 and a ceiling of $81.95. In addition to that, we have swaps in place for about 2700 barrels a day of NGLs with an average swap price of $41.69 a barrel.

On the unit cost side, obviously unit costs are as much affected by volumes as they are absolute costs and with the volume expectations that we have given, the following run rates should be expected for the third quarter. LOE should average somewhere between $1.67 and $1.72 and as I pointed out for the first two quarters was $1.69.

Production taxes should be in the range of $0.22 to $0.25. DD&A, run rate should be $1.45 to $1.50 and of that, depletion is $1.20. G&A should be in the range of $0.48 to $0.52 and I would expect even though G&A has been a bit higher in the first half, I would expect by the time we get to year-end, we will be around $0.50 a unit.

And with that, I will turn the call back over to Rick.

Richard C. Buterbaugh - President of Investor Relations and Corporate Planning

Thanks, Phil. At this time, operator, we are ready to open the call to any questions.

Question and Answer

Operator

[Operator Instructions]

Your first question is from Gil Yang with Citigroup.

Gil Yang - Citigroup

Good morning. Could you just comment on what is going on in West Texas in Culbertson County, Reeves County, that area? I think EOG has made some comments about that area and was wondering what you were thinking... your updated thinking there?

Glenn Darden - President and Chief Executive Officer

Gil, this is Glenn Darden. I said a few things in the prepared remarks. First of all, I think you need to remember West Texas is a very large area and where we are is miles and miles away from where EOG is. I don't really know what they have said about it.

What we are seeing in the field is a very thick section of Barnett. We have had initial gas rates in the one well that we have completed on a horizontal side and now we are focused in our initial work this year on drilling in this thickest area that we have found, about 800 feet of Barnett thickness.

So we are drilling some vertical wells there. We have drilled three. We are starting completion work this month on those three and we hope to have some results to talk about perhaps by year-end or first quarter.

Gil Yang - Citigroup

Okay. Thanks. I apologize that I got on late. Sorry to make you repeat that.

Glenn Darden - President and Chief Executive Officer

Thank you for the question.

Operator

Your next question is from Jeff Robertson with Lehman Brothers.

Jeffrey Robertson - Lehman Brothers

Thanks. Glenn, at Lake Arlington, I think... did I hear you right that the six wells you have drilled so far, you will have first production in the third quarter or was it the fourth?

Glenn Darden - President and Chief Executive Officer

Early in the fourth quarter is what we are looking at.

Jeffrey Robertson - Lehman Brothers

Are there infrastructure issues that you all have to put in place to move that gas out and if so, can you talk a little bit about what you are planning for in terms of capacity?

Glenn Darden - President and Chief Executive Officer

Well, there are infrastructure issues. It is our most urban setting, not fully in the city, but certainly some urban issues. Quicksilver Gas Services... well, I guess Quicksilver Resources is putting in the system and it is a dry system.

The gas will be dry there and that Quicksilver Gas Services, the MLP, has the right to buy that system at a certain point.

So we... we have got a little bit delayed probably just with the density of the situation out there, but we will have gas online. The sizing of it... I don't know if we have talked about that, but at this point, Rick and Phil are nodding no, but it is sized for significant production there.

Philip W. Cook - Senior Vice President and Chief Financial Officer

What we have said publicly, Jeff, is that we are going to drill 50 to 70 wells.

Jeffrey Robertson - Lehman Brothers

And to Phil, over how long a time do you think you will be drilling there?

Philip W. Cook - Senior Vice President and Chief Financial Officer

Roughly 2 years, Jeff.

Jeffrey Robertson - Lehman Brothers

Glenn, what is the total acreage you all have in the Barnett Shale now?

Glenn Darden - President and Chief Executive Officer

It is still about 270,000 net acres and that includes the 4500 in Lake Arlington.

Jeffrey Robertson - Lehman Brothers

Do you see that changing much in the next six months or so?

Glenn Darden - President and Chief Executive Officer

No, not significantly. Probably... we have added pieces. We have filled in areas where we have a consolidated position. So we will add 160 acres here and there, but you are not going to see us add big chunks we don't think. We would love to, but the price of poker is pretty high.

Jeffrey Robertson - Lehman Brothers

And then lastly with the increase in production in the Barnett, will that do anything for you in terms of price realizations just by having more volume to market and more NGL volumes to market?

Philip W. Cook - Senior Vice President and Chief Financial Officer

Yes, our differentials in Texas are certainly not as high as they are in Canada, so it is going to help gas price realizations overall for the Company. I don't know that it specifically helps gas price realizations with respect to just Texas on a quarter-to-quarter basis. We do have some basis hedges that we put in place in Texas for the rest of the year that earned about $0.29, so we have hedged that.

Jeffrey Robertson - Lehman Brothers

Thank you.

Operator

Your next question is from Robert Lynd with Simmons & Company.

Robert Lynd - Simmons & Company

Good morning.

Glenn Darden - President and Chief Executive Officer

Good morning.

Robert Lynd - Simmons & Company

Phil, you mentioned that you are kind of ahead of pace on capital spending based on what you spent in the first half of '07. Can you give us an idea of what your plans are for the second half of the year? Are you going to slow down in a particular area or should we expect an increase in the budget?

Glenn Darden - President and Chief Executive Officer

Yes, I will take the first part of that. We are on track on our forecast of 25% production growth overall company and most of that, as you know, is driven by the Barnett. I will turn the spending over to Phil, but we will be talking with our Board on this. We may slow a little bit, but we are on track to hit 25% anyway on production growth.

Philip W. Cook - Senior Vice President and Chief Financial Officer

Yes, I guess what I would say is we have spent $430 million, that 70% of our capital budget. Increasing our capital budget is a Board decision and we will have a meeting later this month. Certainly we have enough liquidity to get through the end of the year sort of regardless of what decision comes down. We have got about $500 million of liquidity.

Glenn Darden - President and Chief Executive Officer

And remember, that over $80 million of that spending in the first half was on midstream, which is now over on the AGSE side.

Robert Lynd - Simmons & Company

Right, right, thanks. And Glenn, you mentioned that you are evaluating other assets that may be underappreciated by the market. Can you tell us which properties fit into that category and what you are considering for those options or what options you are considering?

Glenn Darden - President and Chief Executive Officer

I think what we have said in public is, first of all, number one on the play was getting our MLP launched, which we did have a very successful launching and now that is on its own.

We look at all our assets and if we believe some are undervalued and we certainly thought the midstream was. But we have a pretty big portfolio of mature to new exploration projects. So obviously we are looking probably at the more mature, but we haven't made any decisions at this point. We are just in the study phase.

Robert Lynd - Simmons & Company

Okay. What about the New Albany Shale? Are you still holding on to that or are you reconsidering to maybe put that back on the market?

Glenn Darden - President and Chief Executive Officer

Well, that is one asset that we have had on the market and we didn't receive I guess sufficient bids for us to sell it. We have had discussions with some parties regarding those assets and at the right price, we would sell those.

Robert Lynd - Simmons & Company

Okay. And final question... service cost environment in Canada has improved based on where it was in early 2006. Can you kind of talk about what you are seeing there? Are you still staying with your current program or would you accelerate or what price would it take you to want to accelerate there?

Glenn Darden - President and Chief Executive Officer

You are correct. The service side has improved for us. That picture is good. We have had a particularly rainy breakup period as you know and on into the summer. So it slowed things, which has further hurt the service utilization I guess.

But overall, we are living within our cash flow up in Canada. That is number one priority. But we are looking at some opportunities up there and will we drill more wells with the same amount of cash? We have that flexibility.

Robert Lynd - Simmons & Company

Okay. Thanks, guys. That's all I had.

Glenn Darden - President and Chief Executive Officer

Thank you.

Operator

Your next question is from David Heikkinen with Pickering Energy.

David Heikkinen - Pickering Energy

Good morning, guys.

Glenn Darden - President and Chief Executive Officer

Good morning.

David Heikkinen - Pickering Energy

You had a great first half of the year and the second quarter with hooking up wells now in the Barnett. What is your backlog of wells awaiting hookup?

Glenn Darden - President and Chief Executive Officer

I think we have 30 wells that have been fracked that are awaiting hookup. So that is the number that we are pushing on right now to get those wells hooked up because we have spent the money.

David Heikkinen - Pickering Energy

So the ramp from first quarter of 17 wells tied to sales to 44 in the second quarter, you're going to kind of average about 30 from here forward or do you have pods that are coming in as you go through the year in the Barnett?

Glenn Darden - President and Chief Executive Officer

Yes, we should be on pace of about the second quarter pace.

David Heikkinen - Pickering Energy

Okay. Very good. And then thinking about the Lake Arlington gas pipeline assets, you are allocating about $32 million of capital to those assets and it is about the same amount as the Cowtown plant as far as part of the KGS had about $29.5 million.

Would a similar capacity to Cowtown be unreasonable for 50 to 70 wells in that area given the capital allocation analogy?

Glenn Darden - President and Chief Executive Officer

Well, remember that this system isn't tied to Cowtown.

David Heikkinen - Pickering Energy

Right. They are completely different. I am just doing a capital-to-capital allocation.

Glenn Darden - President and Chief Executive Officer

Yes, capital allocation, okay.

Philip W. Cook - Senior Vice President and Chief Financial Officer

Well, it is also different kinds of assets. We are not extracting liquid, so there will be no cryogenic facility. So really it is just all gathering and compression in Lake Arlington.

David Heikkinen - Pickering Energy

Okay. So thinking about 50 wells, I mean are you designing it for a stable production rate, 100 million a day or peak production, how do you think about designing a system for Lake Arlington?

Glenn Darden - President and Chief Executive Officer

Well, that has been a head-scratcher because, as you know out there, those volumes from offsetting wells are pretty significant. So we size it for anticipated production and we really haven't given a lot of guidance per se on Arlington. We will be able to do that when we bring our first wells on and get a little more history here, but we have sized it anticipating some pretty significant production.

David Heikkinen - Pickering Energy

Okay. I guess we are not going to get that volume. That's fair enough. Thinking about what you are doing in Canada now with hookup schedule and number of wells and capital allocation there within cash flows, the amount of growth to hit the 10% target, thinking about third and fourth quarter, should it be a steady ramp quarter over quarter or should it actually be more in the fourth quarter versus first quarter?

Glenn Darden - President and Chief Executive Officer

Pretty much a steady ramp. The weather is improved and we have got rigs running and hooking up wells that we previously drilled.

Philip W. Cook - Senior Vice President and Chief Financial Officer

And we will still be on the 10% guidance.

David Heikkinen - Pickering Energy

Yes. And then taxes overall, thinking about second quarter, a little lower rolling into third quarter, what do you think your corporate tax rate will be?

D. Wayne Blair - Vice President and Controller

32% across the board, consolidated... probably 32%.

Glenn Darden - President and Chief Executive Officer

That was Wayne.

David Heikkinen - Pickering Energy

And the second quarter down at 29%, that had some of the Canadian taxes and what ended up happening there was a clean --.

D. Wayne Blair - Vice President and Controller

We got the benefits of about $1.3 million in scientific research and experimental development credit and also the Canadian federal government decreased their effective rate or their tax rate by 1.5%. So that benefited us about $750,000.

Philip W. Cook - Senior Vice President and Chief Financial Officer

So when you add them together on an earnings per share basis --

D. Wayne Blair - Vice President and Controller

It was about $2 million... about $0.02.

David Heikkinen - Pickering Energy

Perfect. Thanks a lot, guys.

Glenn Darden - President and Chief Executive Officer

Thank you.

Operator

Your next question is from Ellen Hannan with Bear Stearns.

Ellen Hannan - Bear Stearns

A quick question, Glenn, is it too to think about what your outlook for CapEx for '08 and potentially how many rigs you might be running in the Barnett Shale then?

Glenn Darden - President and Chief Executive Officer

Well, what we are certainly thinking about, Ellen, we haven't talked about it. We've talked I guess... publicly we have said 20 plus rigs, something like that and we're still thinking along those lines.

One of the things that is impacting that a bit, as I talked about in my earlier remarks, is we are getting more efficient with the rigs that we have, so we are drilling more wells with let's say 12 to 14 rigs in the first half of the year than we anticipated.

So that is great. That is good news because it is cost effective. So do we have to get to 20 to drill at a 220 rig pace? No, we don't and that was kind of our thinking a year ago that we would need to do that. So we anticipate drilling more wells next year than we are this year. We just haven't settled on that number of rig count.

Ellen Hannan - Bear Stearns

Fair enough. I just want to circle back again if I could on your earlier comments about looking at some your assets that you think the market under-appreciates the value in potentially in an MLP. Are you looking at further midstream assets or upstream or some combination?

Glenn Darden - President and Chief Executive Officer

Oh, I think more probably upstream and as I've said, we haven't made any decisions, but with the MLP E&P companies out there and getting good valuations, obviously our eyes are open to that. Whether we do that is one option that I think we have now, but again we haven't made any decisions there.

Ellen Hannan - Bear Stearns

Great. That's it for me. Thank you.

Glenn Darden - President and Chief Executive Officer

Thank you.

Operator

Your next question is from Michael Scialla with AG Edwards.

Michael Scialla - AG Edwards

Good morning, everyone.

Glenn Darden - President and Chief Executive Officer

Hey. How are you, Mike?

Michael Scialla - AG Edwards

Just fine, thanks. I apologize. I missed the first part of your prepared remarks, so if you have already addressed this, I apologize. But wondered if the wet weather affected you at all during the second quarter and if it will affect third quarter at all?

Glenn Darden - President and Chief Executive Officer

Well, it didn't affect results. We had very good results, so our teams fought through it. We were probably most affected in Canada, just the length of the breakup period, the rainy season after breakup, but overall, we are on track both in Canada and the US and particularly in Texas, we got a lot of rain here, but we had a very good quarter of adding production. So I don't think we are looking at any delays at all for third quarter.

Michael Scialla - AG Edwards

Okay. And then to get back again to the undervalued assets, are you considering... would Michigan be one of the potential options there to either go into an MLP or possibly to divest?

Glenn Darden - President and Chief Executive Officer

It is one of the options, yes.

Michael Scialla - AG Edwards

What do you think the timing could be given the strength in the Barnett now at this point?

Glenn Darden - President and Chief Executive Officer

We will see. I mean don't have to be in a hurry. We will do things at a measured pace and if it makes sense to do something with those assets, we will, but they are continuing to be... they are a third of our production today and a significant contributor.

Michael Scialla - AG Edwards

I mean would it be unreasonable to think of something before year-end or is it more likely a next year event?

Glenn Darden - President and Chief Executive Officer

We will see. We just haven't made any decisions, Mike.

Michael Scialla - AG Edwards

And on the Delaware Basin wells, the vertical wells, are you drilling those primarily with the thought of eventually going horizontal or are you going to try and attempt to make a vertical play out of it at this point?

Glenn Darden - President and Chief Executive Officer

Well, we are looking at both horizontal and vertical because we have the thickness at this area, this Northern area of our acreage that is very thick, almost double the thickness we had in some of our test wells, but 800 feet thick in total.

We felt like we wanted to try the vertical. Whether this works horizontal or vertical, we will see, but we are going to have some test results from vertical and horizontal by the first quarter of next year.

Michael Scialla - AG Edwards

Are you doing anything differently in these vertical wells versus the horizontal well that you drilled? I mean designing the well differently at this point?

Glenn Darden - President and Chief Executive Officer

The fracs will be a bit different and the fracs... our subsequent fracs on horizontals will be a bit different from what we initially put in, but we will see. We are just trying to learn from our initial results and I think that we feel encouraged from our first horizontal and we will see what happens with these verticals.

But we will continue testing. It is just a big project out there and I know we all want answers very quickly, but we are trying to get some by the end of the year first quarter to really see what we have.

Michael Scialla - AG Edwards

Okay. And then one last one for me. Sorry to jump around here, but back to the Fort Worth, based on the number of wells you have now, how much of your acreage would you say is in sort of the core area where you think your 2.4 Bcf type curve would apply?

Glenn Darden - President and Chief Executive Officer

I would say 165,000 acres or so is probably what we consider our core, which is 60% of our acreage. And we are not giving up on that other 40%; we just think that that is... that we are in full development mode.

Michael Scialla - AG Edwards

Right. Thanks, Glenn.

Glenn Darden - President and Chief Executive Officer

Thank you.

Operator

Your next question is from Stephen Beck with Jefferies & Co.

Stephen Beck - Jefferies & Company

Good morning, guys. Got a couple of questions. Most of mine have been answered, but I have a couple. In the Barnett, with the wells that you have on backlog, can you tell me how many well pads those are on?

Glenn Darden - President and Chief Executive Officer

I don't have that number, but most of our drilling now, all of 2007, probably 85% of our drilling has been on pads. So a chunk of that obviously would be from that drilling.

Stephen Beck - Jefferies & Company

Okay. And then just one last one. You have 15 rigs operating in the Barnett. It was wondering how many of those are fit for purpose rigs?

Glenn Darden - President and Chief Executive Officer

I believe two.

Stephen Beck - Jefferies & Company

Okay. That is all I have got. Thank you.

Glenn Darden - President and Chief Executive Officer

Thank you.

Operator

Your next question is from David Tameron with Wachovia.

David Tameron - Wachovia

Hi, morning. Congratulations and good outlook in the Barnett. A couple quick questions I guess. Can you guys talk about -- maybe this is an Andy question, but the HP flex-foot you brought in, what kind of efficiencies are you seeing from that particular rig?

Glenn Darden - President and Chief Executive Officer

It is probably more of an operational question and so I will defer to that team and we can get back to you with that answer. What we are seeing is more efficiency on our overall rig fleet and most of that rig is the traditional rotary unit. We have seen, as I said earlier, 15%.

We have probably drilled wells... our fastest well we have drilled is about 14 days, but our overall average of every well we have drilled this year is 20 or less. So we are probably drilling in the 17 to 20 day range, something like that at this point, but... and we will probably utilize some more of those rigs at this point as we beef up our rig fleet in number... the flex rigs.

But at this point, we are getting pretty efficient with the rotary or just the standard rotary.

David Tameron - Wachovia

All right. And I will go ahead and fess up here and say I thought I was on a different conference call. So I asked the wrong question, but still that was a question I was going to ask of you anyway. So I apologize about that.

Another question just in the Barnett exploration, where do you stand as far as leases? Are you guys comfortable right now with what you have got held by acreage or do you have anything expiring that you need to chase in the next few months?

Glenn Darden - President and Chief Executive Officer

No, we are in very good shape in that regard.

David Tameron - Wachovia

All right. And then finally, final question. If I look at big picture, hypothetical, go down the road, you sell something, you saw some Antrim Shale, you sell other properties, get a big influx of cash, how much faster can you go in the Barnett? Would that cash be used to pay down debt and then any remaining funds for acceleration or is that more than you could handle for 2008 as far as acceleration?

Glenn Darden - President and Chief Executive Officer

Well, hypothetically, first we would pay down debt, but we... our game plan and we have talked to the public about this is continue to ramp up our drilling program in the Fort Worth Basin. So do we flip the switch and double that rate? No, but we will continue to ramp it up. We are at 15 rigs today and we could be at 20 next year.

David Tameron - Wachovia

All right. That's all I've got. Thanks.

Glenn Darden - President and Chief Executive Officer

Thanks.

Operator

Your next question is from Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Good morning.

Glenn Darden - President and Chief Executive Officer

Good morning.

Noel Parks - Ladenburg Thalmann

I had a few questions. Could you maybe talk a little bit more about the progress in the pad drilling? Obviously it was a much increased focus this year and I was just interested in some comment on the efficiency you have seen.

You were talking just a minute ago about the number of days getting wells done. So just wondering sort of what you have learned to this point with the pad drilling?

Glenn Darden - President and Chief Executive Officer

I guess the first thing that we have learned is drilling down pace wells... it appears that we are increasing our overall reserves from the acreage block simply because we will drill more wells.

Now what we haven't determined is will those new wells on roughly 55 acre spacing or 500 feet between wells, will they cannibalize from each other. It doesn't appear that way today, but we don't have enough runtime to determine that.

If that is the case and we are still on this 2.4 Bcf roughly gas recovery or 2.5 Bcf equivalent recovery, we are really onto something. If we can do that, we will drill twice as many wells. On the cost side... but that's yet to be determined, but it is looking promising at this point.

On the cost side, we really haven't reduced the cost unfortunately simply because we have added stages to the fracs, we have more directional work from this pad drilling.

So we haven't really increased, but it's not more cost effective. It probably overall long term it will be because of production monitored from one central facility, etc. So I think overall it will improve our efficiency there, but it certainly is working on the production side going the right way.

Noel Parks - Ladenburg Thalmann

Along the same lines, just wondering if you have any progress or any trends you can point to as you get more expertise with doing the fracs out there either in terms of what you are doing to the formula or how it is affecting recoverability.

Glenn Darden - President and Chief Executive Officer

Well, our team has certainly changed the way we have been doing it over the last two years and we have improved. As a result, the pad drilling is an obvious improvement as well, but the recipe keeps getting tweaked and fortunately, the reservoir keeps responding favorably.

So at this point, where does that end? We are not sure. I am sure you have read about or heard about the Devon tests on 20 acre spacing. So I think a lot of that is vertical, but there is more work to be done in this formation and we hope more improvement to gain.

Noel Parks - Ladenburg Thalmann

Okay. And currently what is your typical number of frac stages that you are doing now on the wells on the pad drilling?

Glenn Darden - President and Chief Executive Officer

Well, it depends on the length of the lateral that, in some cases, depends on the lease situation, but we could have as many as 10 stages, 7 to 10 stages in a well in a 3000 foot lateral.

Noel Parks - Ladenburg Thalmann

And just shifting a little bit, it appears that you've, in recent months, taken the Hill County acreage that you had and moved it more into the category where you consider it more core or a core part of your fairway. Could you talk about a little bit about what you have been seeing there and just what led you to recategorize it?

Glenn Darden - President and Chief Executive Officer

Well, we've always thought it was very promising, Noel. We have had now results from our own tests and we have monitored results from offsetting production. It is a bit different in that it is dry gas, so a little bit lower BTU than our core area, so we won't be tying it back to the Cowtown system. But overall, we are seeing IP rates very similar to what we have seen in our core area, just without the liquids.

Noel Parks - Ladenburg Thalmann

Okay. And do you have a sense of say looking forward on the next 12 month basis how many wells you might be doing in Hill County?

Glenn Darden - President and Chief Executive Officer

Not really today. It is just part of our overall program that we will be getting to, but we are enthusiastic about the area.

Noel Parks - Ladenburg Thalmann

Great. Thanks a lot.

Glenn Darden - President and Chief Executive Officer

Thank you.

Operator

The next question is from Jeff Robertson with Lehman Brothers.

Jeffrey Robertson - Lehman Brothers

Thanks, Glenn. Just a follow-up in the Barnett. Of the wells that you all are drilling this year, how many of those are in what you all consider your core area versus areas where you are trying to maintain your lease position and test some of the new areas?

Glenn Darden - President and Chief Executive Officer

Yes, 80%, 85%, Jeff, something like that. Most of our drilling is in the development phase.

Jeffrey Robertson - Lehman Brothers

And will that stay... will that increase in 2008 do you think as you start to make those plans?

Glenn Darden - President and Chief Executive Officer

We will always be doing some test work outside that core area, but I think that it will remain that percentage or perhaps a little higher.

Jeffrey Robertson - Lehman Brothers

Okay. Thanks.

Operator

Your next question is from Joe Allman with JP Morgan.

Joseph Allman - JP Morgan

Hey, good morning, everybody.

Glenn Darden - President and Chief Executive Officer

Good morning.

Joseph Allman - JP Morgan

Glenn, could you give us some updated thoughts on the Manville play in Canada? I know you signed a farm-out agreement a week or so ago.

Glenn Darden - President and Chief Executive Officer

Yes, and that was a relatively small farm-out that we signed. We are continuing to test there and we are working on it. We have not a lot to report just because of how wet everything has been in Canada. We really haven't gotten much work, so we hope to have some results here at the end of this quarter on some of our latest testing.

Joseph Allman - JP Morgan

Okay. And I know you are deemphasizing Canada and focusing more in the Barnett, but are you looking at anything else up there? I know some folks are talking about some shale plays in Canada. Anything else to talk about up there?

Glenn Darden - President and Chief Executive Officer

I wouldn't say we are deemphasizing it. I would just say obviously the Barnett is a bigger driver of our growth right now, but the Canadian team is working on several projects, so we are looking at some new things on the unconventional side that perhaps we can talk about next quarter.

Joseph Allman - JP Morgan

Okay. That's helpful. And then in West Texas, I mean what have you seen specifically that has been encouraging or even discouraging for you. Of course, like an 800 foot Barnett Shale, that seems pretty encouraging, but what other factors have been encouraging or discouraging for you?

Glenn Darden - President and Chief Executive Officer

Well, gas production is encouraging and from our first test... I just have to caution everyone that we will be getting a lot more results here the second half of this year and so not a lot has changed from when we talked last quarter except that our team has had their heads down working on a game plan, a fracking plan, completion plan for these new wells.

So we have drilled three vertical wells as we talked about and we will be completing those, but we also will be looking at the horizontal side and trying to improve the completion there.

So I guess we are encouraged the fact that we have got a very thick section that is gas bearing, that is gas productive. We have got to move it to the commercial stage by getting rates a bit higher, costs a bit lower, but it is not too different than any of our startup unconventional plays. It just takes a little while to move it down the road.

Joseph Allman - JP Morgan

Okay. That's helpful. And then on the previous question regarding the pad drilling and you indicated you need more time to determine whether the wells are cannibalizing each other, what kind of time period do you need to kind of determine that?

Glenn Darden - President and Chief Executive Officer

The engineers would love years, but I think that a couple of several months of good production data, six months of good production data and I don't want to take words from our reservoir engineers, but we just need some runtime on these wells, but right now, from what we see, the wells on 500 foot spacing are acting very similarly as 1000 foot spacing, which is very, very encouraging.

Joseph Allman - JP Morgan

Okay, great. And then lastly on the MLP front, if you are considering an MLP as say some of your upstream assets, some of your peers have indicated that they are not going to do an MLP for various reasons... conflicts of interest or governance issues. Are those issues that might hinder you from considering an MLP of upstream assets?

Glenn Darden - President and Chief Executive Officer

I don't think so. No, and I think obviously the Antrim is an ideal type reservoir for just very, very slow declining, long life reservoir that is ideal for the MLP structure. Whether we do that or not, we haven't made a decision, but it is a great asset for the Company and we are going to maximize it in whatever we do.

Joseph Allman - JP Morgan

Okay, that's very helpful. Thank you.

Operator

The next question is from Starr Spencer with Platts.

Starr Spencer - Platts

Hi, Glenn.

Glenn Darden - President and Chief Executive Officer

Good morning.

Starr Spencer - Platts

Good morning. I want to make sure I understand. Are you looking at the New Albany assets as potential candidates for sale or for a possible upstream MLP?

And also a second question, are you doing any work in New Albany to ramp up the assets because it looks like, at least from the 10-K anyway, it looks like production there is about half what it was a few years ago. Are you trying to ramp it up or what are you doing there?

Glenn Darden - President and Chief Executive Officer

Well, I guess to the first question, we are looking at both possibilities just to maximize the value of that asset. We are... we have slowed down our activity, but our volumes... I guess we are about 4 million net, something like that a day. So we haven't done a lot of activity simply because of our focus on the Barnett and our dollars.

But we see some opportunities there and we will try to pursue them. It just depends on what we do with the asset truly and I don't mean to say we are treading water, but we have got some opportunities up there, but we have capital allocation issues and most of that capital is coming to Texas.

Starr Spencer - Platts

Thank you.

Glenn Darden - President and Chief Executive Officer

Thank you.

Operator

Your last question is from Gil Yang with Citigroup.

Gil Yang - Citigroup

Hi. I have two questions. Just a follow-up on the pad drilling issue in the Barnett, the 500 equivalent to 1000 four now, just 500, is that sort of on an equal life basis in terms of number of lateral lengths and number of fracs.

Glenn Darden - President and Chief Executive Officer

Yes.

Gil Yang - Citigroup

Okay. And presumably... can you characterize the differences if there are any in the IPs? I know that you don't have enough material to know if there is a decline rate cannibalization, but what do you see on the IPs?

Glenn Darden - President and Chief Executive Officer

Very similar rates, Gil. That is what is encouraging.

Gil Yang - Citigroup

Do you have enough data... do you have enough of a sample set to know whether this is just regional variation or do you have to drill those particular wells versus the ones you are comparing to or is it a big enough set or not?

Glenn Darden - President and Chief Executive Officer

Well, we always like more, but everywhere we have drilled a 500 foot spacing and this has been over a broad area of our acreage, it appears to be the way to do it. Now, does it go inside of that? We don't know. We may do some experimentation on that on even denser spacing than the 500 feet between wells, but at this point, in all of our down-spaced drilling, it appears to be the way to drill it.

Gil Yang - Citigroup

Roughly, how many wells do you have that are 500 space?

Glenn Darden - President and Chief Executive Officer

We have got probably 50 wells now that we have drilled, but with obviously not a lot of length of production time, runtime on some of these, but we are seeing good IP rates and we have encouragement... we are certainly drilling most of our wells on down spaced 500 foot spacing.

Gil Yang - Citigroup

And then the last question is just in the Antrim Shale, you talked a little bit about the MLP potential there. The field I guess was down about 7% year on year. Do you think that it is sustainable if there is enough capital injected into it to keep it flat and you just didn't put that capital in?

Glenn Darden - President and Chief Executive Officer

Yes, we think so.

Gil Yang - Citigroup

Okay. To keep it flat, how much capital would you have had to put in with the current operations do you think?

Glenn Darden - President and Chief Executive Officer

Well, I think we are spending $25 million or so in Michigan and it is not just Antrim. We have some other assets up there that we have had some good success with, some very shallow decline in oil production as well.

So again, the capital allocation issues we wrestle with and most of it comes to Texas right now, but I don't have an exact calculation of what it would take to keep it flat. It is still a declining asset. We might not be able to keep it flat, but it is a very shallow decline.

Gil Yang - Citigroup

All right. Good luck.

Glenn Darden - President and Chief Executive Officer

Thank you.

Operator

You do have a follow-up question from the line of David Heikkinen with Pickering Energy.

David Heikkinen - Pickering Energy

Hey, Glenn, just thinking about Lake Arlington versus your core Barnett, would you have a different spacing assumption on either of those areas?

Glenn Darden - President and Chief Executive Officer

Yes, that's a great question and it is one that our team is working with right now. We will probably experiment with a couple of different densities there, David. It is just so early, but obviously we are not doing this in a vacuum. There are a lot of other players pushing the edges there as well and so we will monitor those players, but we probably will experiment with some down spacing.

David Heikkinen - Pickering Energy

Okay. Thank you. I appreciate that.

Glenn Darden - President and Chief Executive Officer

Thank you.

Operator

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

Richard C. Buterbaugh - President of Investor Relations and Corporate Planning

Yes, thank you. Just as a reminder, a replay of this call will be available on the Company's website for 30 days. Quicksilver will release third quarter earnings on November 7, 2007. Thank you for your time and interest in Quicksilver this morning. This concludes the call.

Operator

Thank you for participating in today's Quicksilver Resources second quarter 2007 earnings conference call. You may now disconnect.

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