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Executives

Rick Buterbaugh – VP, IR and Corporate Planning

Glenn Darden – President and CEO

Phil Cook – SVP and CFO

Toby Darden – Chairman

Analysts

Noel Parks – Ladenburg Thalmann

Mike Jacobs – Tudor, Pickering, Holt

Subash Chandra – Jefferies & Company

Brian Singer – Goldman Sachs

Brian Corales – Howard Weil

David Snow – Energy Equities Incorporated

Manav Gupta – Canaccord

Dan McSpirit – BMO Capital Markets

Mike Scialla – Thomas Weisel Partners

Scott Hanold – RBC

Quicksilver Resources Inc. (KWK) Q4 2009 Earnings Call Transcript March 1, 2010 11:00 AM ET

Operator

Good afternoon. My name is Cathy and I will be your conference operator today. At this time, I would like to welcome everyone to the Quicksilver Resources fourth quarter 2009 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 session. (Operator Instructions)

Thank you. Mr. Buterbaugh, you may begin your conference.

Rick Buterbaugh

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

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

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

At this time, I will turn the call over to Glenn Darden for a review of our financial and operating results in a little more detail.

Glenn Darden

Thank you, Rick. Good morning. Quicksilver Resources had fourth quarter 2009 adjusted net income of $46.9 million or $0.27 per diluted share. That’s up 19% from the 2008 period. For the year, Quicksilver reported adjusted net income of $147.6 million or $0.86 per diluted share as compared to $216.4 million or $1.29 per diluted share for 2008.

The company took a non-cash $656 million after-tax impairment charge on our oil and gas properties due to lower natural gas prices earlier in the year, which caused an overall net loss of $557.5 million of the year. Phil Cook, our Chief Financial Officer, will go into detail on the numbers after my remark.

In 2009, Quicksilver produced record volumes of nearly 325 million cubic feet equivalent gas per day, up 23% year-over-year. We replaced 377% of production with the drill bit, excluding price revisions and reduced our unit operating cost to $1.17 per Mcf equivalent. Company's finding and development cost was $1.25 per Mcf equivalent, which compares to our average organic F&D cost over the last five years of slightly less than $1.40 per Mcf equivalent.

Quicksilver increased its reserves to 2.4 trillion cubic feet equivalent despite selling 120 – roughly 120 Bcf in an asset sale last June, an increase proved developed reserves to 68% of total reserves. We also reduced total company debt by $165 million and self-funded all capital investment including proving at least one new growth area for the future.

Quicksilver made great progress in 2009 in a challenging economic environment. What I hope is becoming clear to our shareholders and the investment community is the low-cost production machine we have built. Very few players in this industry can compete with our low-cost structure. It is certainly showing up in the numbers. This year's top priority is to fund – self fund capital expenditures for the company like we did in 2009 and continue to grow our asset base. We are seeing opportunities to add acreage to existing core areas, which will add to the inventory and we will factor those opportunities into the overall plan.

Quicksilver's forecast is to grow production volumes 20% in 2010. We will have a steep incline in volumes as the year progresses, as we have over 80 Barnett wells coming online in the next several months, which includes some wells that were shut in for fracing. But we do have flexibility on our spending decisions due to limited requirements on lease expirations and drilling commitments. If the current gas prices continue throughout the year, we will probably reduce our capital spending appropriately.

As we have disclosed, Quicksilver has hedges on 200 million a day of gas and a – at a price of $7.40 per Mcf and 10,000 barrels per day of natural gas liquids at $33 a barrel for 2010. This covers approximately 65% of our projected gas volumes and 90% of our liquid volumes based on the 20% production growth rate.

Quicksilver is going to four drilling rigs from five in the Barnett and will move capital to more completions in order to work down on uncompleted well inventory. At this point, we anticipate drilling 100 Barnett wells and roughly completing 130 wells. We will more than meet our drilling completion and lease requirements with this plan.

On the Canadian front, as you know, we've got the budget over the last couple of years on Horseshoe Canyon Coalbed Methane project, yet our team has grown volumes. We project a single-digit decline from this development in 2010, but the big project is the Horn River Basin in Northeast British Columbia, which will be bringing much bigger volumes in the next several years. Quicksilver has drilled four wells to date in this Horn River project. As we have disclosed, we completed the first well in the Muskwa, the upper section of the 500-foot thick Devonian shale package. This D-58 well had produced over 1.2 Bcf in a little less than six months.

At the end of the year, Quicksilver completed at second well, the C-60-D in the lower section of the shale in the Klua formation. Although we did not as large and effective a frac put away in this well, its performance over the first 60 days looks good as well. The C-60-D came in at roughly came in at 6 billion cubic feet a gas a day and is currently producing 5.1 million a day. The decline appears a bit shallower than the Muskwa well at this point.

Quicksilver booked a total of 12 Bcf of proved reserves from these two wells in our 2009 reserve report. The company has not booked additional proved undeveloped reserves at this point on this project. Our next two wells were drilled to the shallower Muskwa. In drilling each of the Muskwa wells, we've seen significant gas flares while drilling the horizontal leg in the Muskwa formation. This is certainly an indication of significant fracturing and permeability, not to mention gas content in this formation.

By year-end, we will have almost half of our 20 exploratory licenses validated in our 130,000 net acre position. We are drilling these wells on very wide spacing in order to earn the leases and will then come in with a much denser drilling spacing upon full development. Everything we've seen to date is pointing toward a huge opportunity for Quicksilver in the Horn River Basin.

Another new project we've been working on is in the Green River Basin in the Northern Rockies where we have assembled over 1,000 acres. The target here is a thick deposition of Mancos and Niobrara shales. Because of the thickness and depth of these shales, we believe that it will be a vertical well play. We have – we've drilled two wells, three townships apart. The initial well came in at roughly 4 million a day and the second well, despite some mechanical issues limiting the number of zones fraced, came in at roughly 6 million a day and is currently producing over 3 million cubic feet a day.

We believe this project can be commercial, but we have more work to do on the drilling and completion design. What we have learned so far is we can improve the efficiency of the drilling and completions and we will focus our fracs on the highest potential zones from here forward. Again, more work to do, but very encouraging results so far.

On the oil side, we are working on a couple of projects that look very interesting and could have significant impacts on the company. The first is what is referred to as the Southern Alberta Bakken play where several companies have drilled projects – have drilling projects underway. Quicksilver has an acreage position of over 130,000 net acres held by shallow Cut Bank sand oil production in Glacier and Toole counties in Northwestern Montana.

We will be monitoring results from wells offsetting our block as close as a mile away and at the same time, implementing a plan to drill a couple of horizontal wells to test the Bakken and other formations on our block. We have excellent well control to map the Bakken in this area. What could be significant to the economics is the shallow depth that will hit the Bakken between 3,000 and 4,000 feet.

In our shale exploration in the Horn River Basin, our focus has been on the Devonian Muskwa and Klua shales. As part of our early exploration, we have sidewall cored the upper formations, as well as the deeper shales. In the coring, we have seen very good oil shows in the Bakken-Exshaw section at approximately 4,000 feet. We have had these shows in all four shale wells we've drilled to date.

Analysis of the core samples have shown an 80-foot section to be in a high mature oil window in terms of thermal maturity. All of the core showed mobile oil. We will reenter a seismic monitoring well later this year and drill a horizontal leg for initial testing of this Bakken-Exshaw zone and look forward to fully evaluating this added potential to our large lease block up in Northeast British Columbia.

As previously announced, Quicksilver has reached an agreement pending final documentation to settle all outstanding legal issues with BreitBurn Energy Partners; the publicly traded master limited partnership that Quicksilver has a 41% interest in. As part of the settlement, Quicksilver will appoint two directors on a reconstituted six-person Board of Directors and quarterly distributions will begin again at an annual minimum level of $1.50 per unit. We believe BreitBurn is a valuable holding and we are clearly aligned to aid in unlocking additional upside.

Similar to any asset that Quicksilver holds, we will look to maximize the value for our shareholders, whether it is collecting distributions or monetizing our investment over time. The outlook for 2010 for Quicksilver is bright. We have a strong hedge position, a low-cost business structure, and a flexibility and optionality on spending due to fewer lease requirements and a growing list of opportunities. We will continue our game plan of developing our large inventory at development locations to build asset value while pushing new projects with prudent use of capital.

And now, I'll turn the call over to our Phil Cook, our Chief Financial Officer, to go through the financials. Phil?

Phil Cook

Thank you, Glenn and good morning. The company reported adjusted net income for the year of $148.4 million or $0.86 per diluted share as compared to $216.4 million or $1.29 per diluted share for 2008.

Net loss for 2009 was $557.5 million as compared to net loss of $378.3 million for the prior year. In both years, the company recorded non-cash impairments related to our oil and gas properties. Specifically in 2009, the net loss was primarily attributable to a $656 million after-tax full-cost ceiling test impairment charge due to benchmark natural gas prices in the United States during the first quarter being $3.63 and the benchmark natural gas price for our Canadian properties of $2.92, as well as an impairment related to our investment in BreitBurn also during the first quarter of approximately $100 million. There is a reconciliation in the press release between adjusted net income and net income as reported for GAAP purposes.

Production volumes in the fourth quarter of 2009 were 324 million cubic feet of natural gas equivalent per day. For the full year 2009, total production volumes of 325 million cubic feet per day grew by 23% compared to 2008. Keep in mind, the 2009 volumes reflect the sale of 27.5% of our interest in the Alliance properties to Eni during June of 2009. Volumes allocable to the Eni post sale were 5.1 Bcfe or 14 million cubic feet a day on a full-year basis. Drilling and completions activities were the drivers of the growth.

Our realized natural gas price for the quarter was $7.46 per Mcf after hedging compared to $7.69 in the third quarter of 2009, down 3%. You will recall that we had hedged 190 million cubic feet a day with a weighted average floor of $8.75. NGL realized prices were $36.60 a barrel in the fourth quarter compared to $28.15 a barrel in the third quarter of 2009, up sequentially 30%. Realized oil prices were $68.79 barrel in the fourth quarter, up from $60.55 a barrel in the third quarter, a 14% sequential increase.

Total production revenues grew from $198.3 million in the third quarter of 2009 to $215.5 million in the current quarter, a 9% increase. For the current quarter and full year of 2009, total production revenues grew by 5% and 2% respectively when comparing to the same periods in 2008.

Lease operating expense on a unit basis was $0.62 per Mcfe for 2009 compared to $0.88 for the prior year, a 30% year-over-year decrease on a unit basis. Keep in mind that approximately $0.04 of our LOE is non-cash and is related to stock compensation for our operational employees. These amounts exclude processing, transportation, and production tax expense.

Processing expense, which is the cost to gather and process our gas from wellhead to the tailgate of our facilities was $0.13 per Mcfe for 2009 compared to $0.18 for the prior year, a 28% decrease on a unit basis. The decrease reflects additional volumes on KGS systems, reducing unit operating cost recognized at Quicksilver. Transportation expense, which is the cost to get our gas from the tailgate of our facilities to market was $0.33 per Mcfe for 2009 compared to $0.34 for the prior year.

Just as a recap, unit well and gas expenses for 2009 were broken down as follows. LOE was $0.62, processing was $0.13, transportation was $0.33 for a total of $1.08, which is down 23% year-over-year. Production taxes and ad valorem taxes were $0.20 per Mcfe for 2009 compared to $0.19 for 2008. The DD&A run rate for 2009 was $1.70 per Mcfe, a decrease from the $1.96 per Mcfe recorded in the prior year, which principally relates to the impact of the full-cost ceiling impairment non-cash charges.

Recurring G&A for 2009 was $0.61 per Mcfe compared to $0.65 in the prior year. Approximately $0.14 of this is related to non-cash stock-based compensation. As a brief recap, our total recurring cash expenses or oil and gas expenses, production taxes, and G&A for 2009 were $1.71, which is down $0.36 or 17% compared to 2008.

Adjusted net income from the quarter was $47.3 million or $0.27 a diluted share as compared to the adjusted net income of $42.7 million or $0.25 a diluted share in the third quarter of 2009 and $39.3 million or $0.23 per share in the fourth quarter of 2008. Fourth quarter 2009 adjusted net income does not include the mark-to-market activities of BreitBurn for commodity and interest rate swaps, which totaled $4.1 million after-tax for the quarter and $1.4 million of after-tax loss related to the sale of assets for BreitBurn. It also does not include an after-tax non-cash full-cost ceiling test impairment charge of $9.3 million related to our Canadian oil and gas properties.

In 2009, the company generated $612 million of cash flow from operations, 34% more than in 2008. We incurred 2009 capital of approximately $600 million, roughly in line with our internally generated funding. Total capital expenditures, which include changes in working capital, were $693 million with a difference of $93 million driven by changes in the accrual for our capital program. Or to say it in other way, we funded 2008 capital in 2009. This capital was accrued at year-end 2008 and was paid for in the first quarter of 2009. We also expect our 2010 capital program to approximate cash flow generation.

For 2009, we paid down the absolute debt amount by approximately $165 million. Total Quicksilver debt at December 31, 2009 was approximately $2.3 billion, excluding $125.4 million of KGS debt, which is non-recourse to Quicksilver. Of this amount, our revolving credit facility was approximately $467 million drawn on a borrowing base of $1 billion. This leaves the company with approximately $500 million of liquidity in the facility.

As a reminder, in January 2010, we sold our Alliance Midstream assets to KGS for $95 million and utilized those proceeds to reduce borrowings outstanding under our credit facility. Our existing bank facility runs through February 2012. However, we anticipate putting a new facility in place by the end of 2011.

With respect to our absolute debt levels, although higher than some of our peers, we believe that the best measurement of our debt is debt as a function of reserves. When you look at debt net of our two marketable securities, those being KGS BreitBurn, our net debt for proved developed reserves at year-end 2008 was $1.39 per Mcfe; and at year-end 2009 is a $1.07 per Mcfe, which is a 23% improvement year-over-year and getting closer to our target for $1 per Mcfe or less of proved developed reserves.

As you know, our 10-K is due on March the 1st, 2010, which is today. However, the SEC's new rules for disclosure of oil and gas reserves require that we provide detailed disclosure of BreitBurn's reserves within our 10-K. BreitBurn is not an accelerated filer and has indicated that they will not publicly release their reserve information until they file their 10-K, which they approximate will be March 11th. Because of the different filing deadlines, we will delay our filing until BreitBurn does release the reserve information. They will file a 12b-25 filing with the SEC, which indicates our intent to delay this filing. We expect to file our 10-K on or before March 16 of this month.

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

Rick Buterbaugh

Thanks. Bill. In regards to the first quarter, Quicksilver anticipates production volumes from the base assets to be in the range of 310 million to 320 million cubic feet of gas equivalent per day.

As a reminder, the company has 200 million cubic feet per day of our expected natural gas production for the first quarter hedged at a weighted average floor price of $7.40 with a ceiling weighted average price of $9.88. As Glenn mentioned, we also have an additional 10,000 barrels a day of NGLs hedged at an average price of roughly $33 per barrel.

With respect to unit cost, the following run rates are expected in the first quarter. Production costs in the range of $0.60 to $0.63, gathering and processing $0.13 to $0.16, transportation of $0.32 to $0.36, for a total operating cost in the range of $1.05 to $1.15. Production taxes are expected in the range of $0.25 to $0.30, general and administrative expense in the range of $0.60 to $0.65 and DD&A of $1.50 to $1.55.

Cathy, at this time, we would like to open the call for any questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Noel Parks with Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann

Good morning.

Rick Buterbaugh

Good morning, Noel.

Noel Parks – Ladenburg Thalmann

Just a couple of things. About the first quarter guidance, sorry if I missed this, it looks like it's going to be down sequentially compared to fourth quarter. What's the main driver of that?

Phil Cook

Well, primarily as we said, we have quite a few wells offline as we are fracing new wells. So we are bringing probably 80 or so wells back or online and that includes new wells plus wells that have been shut in for fracing offsetting wells. So it's just kind of the softer nature of our production growth, but we projected still a 20% growth rate for the year. It's just going to be a little soft in the first quarter as these new wells are coming on.

Noel Parks – Ladenburg Thalmann

Okay. And can you tell me roughly what the current production rate is for the company?

Phil Cook

Yes, it's in the 320 range.

Noel Parks – Ladenburg Thalmann

Okay, great. And looking at Canada, realizing you had the impairment there, do you have any thoughts about sort of given your various drill bit priorities and your exploratory plays, do you assume that Horseshoe basin in Canada has continued to just get minimal additional resources from here on?

Glenn Darden

Well, that's true. It's been living within its cash – own cash flow for the last couple of years and in fact, actually less than that because we pulled money from that project to fund some of our Horn River Basin projects. So it's – it will continue, we've still got some reserves to add there. We think maybe as many as a couple hundred Bcf by infill drilling, but today is not the time to be doing that at today's prices.

Noel Parks – Ladenburg Thalmann

Sure. And in the Barnett, I noticed that you said you plan to do the 100 wells this year using four rigs and if I remember right, from a couple of months ago when you first discussed your budget for 2010, your plan to accomplish that same number of wells with the five rigs. Is that efficiency gain – an efficiency gain that's indoor or is it just a matter of just the different kind of locations you planned now?

Glenn Darden

It's primarily efficiency. It's primarily efficiency, Noel. We of course have drilled the first quarter with the five rigs. So we will be dropping that off and the rest of the year will be at four.

Rick Buterbaugh

Thanks, Noel. I'd like to remind participants to please try to keep your questions to one question with one follow-up so that we can all participants to ask their questions.

Operator

And your next question comes from the line of Mike Jacobs with Tudor, Pickering, Holt.

Mike Jacobs – Tudor, Pickering, Holt

Thank you. Good morning.

Glenn Darden

Good morning.

Rick Buterbaugh

Good morning, Mike.

Mike Jacobs – Tudor, Pickering, Holt

Just wondering, can – you may have touched on this, I was kind of jumping back and forth between calls, but can you give us what your anticipated production rate is going to be at the exit of the first quarter?

Phil Cook

We haven't given that. I don't think we will. It's ramping up as the year progresses, Mike. So second quarter jumps significantly over first quarter, but overall number is roughly a 25% increase for the year.

Mike Jacobs – Tudor, Pickering, Holt

Okay. And are Horn River volumes included in your full-year guidance of 20 plus percent?

Phil Cook

Yes.

Mike Jacobs – Tudor, Pickering, Holt

Okay. And how much capital do you think you will spend outside of the Barnett and Horn River and Horseshoe Canyon and midstream kind of the other plays, if you will?

Phil Cook

You are saying outside of the Barnett? Outside all midstream just on new ventures, is that what you are –

Mike Jacobs – Tudor, Pickering, Holt

On new ventures is right.

Phil Cook

Say it's about $70 million.

Glenn Darden

Thanks, Mike.

Operator

And your next question comes from the line of Subash Chandra with Jefferies & Company.

Subash Chandra – Jefferies & Company

Yes. Hi, good morning. So Glenn, on this reduced CapEx, if gas prices stay here, just for some clarity, are you talking about sort of a sub $5 or is that $5 and above you stay with the current plans and below $5 that you cut, what's the red line?

Glenn Darden

Yes. And I'm not sure there is the full red line. We make money at $5. So I think my point was that we will be monitoring this as the year goes on. If gas prices are $4, $4.25, $4.50, we are probably cutting our CapEx. But I guess another point that I tried to make was that we've got a lot of flexibility, we don't have a lot of lease obligations and we can maintain our asset base and actually grow even by cutting our CapEx from here. So as you see from cost structure, we make money in $4, but it's – it would be more at $5 of course and beyond.

So I just – the point I was trying to make was we are flexible, we are watching commodity prices, and we may cut if prices stay below $5 let's say for an extended period of time.

Subash Chandra – Jefferies & Company

Okay. And as my follow-up, the production I guess for Q1, did – what is the weather impact if there is a way to quantify and is there – I thought there was a bunch of wells in Alliance were completed at the end of Q4, I thought completed and that – actually fractured and online. And so any commentary on perhaps there were delays there or if there was a weather impact involved?

Glenn Darden

There has been some weather impact as we talked about. There has also been some delay on certain pipe-up in Alliance to get more wells online, connections and we've had wells offline fracing adjacent wells. So it's kind of that combination, but it's really the nature of the beast of drilling the dense spacing that we are doing in the Barnett, it requires taking wells offline before you bring more production on. So it is the sawtooth kind of shape to the curve, but overall, it's a little like – for the first quarter, obviously we'd like to be stronger, but for the year, it looks very good.

Operator

And your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer – Goldman Sachs

Thank you. Good morning.

Rick Buterbaugh

Good morning, Brian.

Brian Singer – Goldman Sachs

Just going back to the timing of production trajectory, when you are looking at the Barnett well completions coming on, is that something where it's you just waiting on the calendar with the completion crews or are you waiting for improved gas price environment before moving forward with bringing that on?

Glenn Darden

We weren’t waiting on gas prices there. It's just operational issues and timing of bringing wells online.

Brian Singer – Goldman Sachs

Got it. Thanks. And then can you give us your just thoughts on developing the Horn River Basin, where you stand if at all in terms of considering your joint venture partner and who are these – whether you see the gas going south or whether you see yourself participating in potential NG export?

Glenn Darden

I'll let Toby take that one.

Toby Darden

Yes, Brian, we are going to prove up the block primarily. First, we are going to establish our infrastructure in conjunction with improving portion of the play. Infrastructure is going to be the driver for this play as you have correctly identified. We think in the short run, it's probably incumbent upon us to go south and east on the trans-Canada system. We do have a keen interest in the Kitimat project and we think it's a good one, but it probably has a little longer term startup than we want for our initial production.

We have 100 million a day firm capacity on Spectra, which will get us through the earning and beyond the earning period of conversion of exploration licenses to leases. So we are in good shape in the short run for transportation and are marketing our gas from our two test wells every day.

Glenn Darden

Yes. And I will say – just add one thing, Brian, on the JV side. We continue to have discussions. What we've seen is the longer we've waited, the more valuable our position is and that's what we believe and now we for the first time booked reserves for 2009 a small amount for Horn River. There are billions of dollars of capital being committed to this play by a large number of players.

So this is getting more valuable as time progresses and that maybe in the cards, but we have relatively minimal capital commitments relative to the size of this project to validate all these leases as Toby talked about. So we are in the business of proving up reserves and would rather sell a JV as proved reserves than acreage.

Brian Singer – Goldman Sachs

Great. Thank you for the color.

Toby Darden

Thank you, Brian.

Operator

And your next question comes from the line of Brian Corales with Howard Weil.

Brian Corales – Howard Weil

Hey guys. Just talking about your acreage in Montana, can you maybe give us a little bit more insight on what you've seen with some of the historic wells that you drilled? I can't remember if those were more shallow and/or what other industry participants are doing up there.

Toby Darden

There have been some announcements from some of the producers offsetting our acreage block and I'll leave those announcements to their announcements, but they've seen oil over a number of test wells. That corresponds well with initial looks we had at the Bakken in the 3,000 to 4,000 foot range when we looked at it a couple of years ago and we are watching their progress with interest, but are planning for our own testing at the Bakken as well.

Glenn Darden

Yes. Brian, as you know, the techniques for recovering this oil have really moved quite rapidly over the last couple of years. So we took a look at this maybe four years ago or so, something like that, knowing that we've got the Bakken in our lease block of course, the deposition there and some interesting zones above and below the Bakken. We just have it really put a lot of capital toward that project as you can see with our other projects.

But we are looking at it, we are going to spend some money this year to drill some wells on our leases, but again, we are in a nice position of having all this acreage held by production. So we don't have any time fuse burning. So we will watch what's happening around us as well.

Brian Corales – Howard Weil

And just kind of a follow-up more on the – all of your exploration plays, can you maybe talk about, I guess, a big picture time frame for – if successful with the exploration side when these assets could go into – how would they compete for capital versus the Barnett like in the Green River or in Montana or even some of the shallow oil up in Canada?

Glenn Darden

Well, of course oil has different economics than gas. So we love to just perhaps have some potential on the oil side in our core competency of drilling shales. But the Barnett is tough to compete with, I think, for any play. So that has our highest priority and that's what's bringing the volumes on. We are moving Horn River now at a little faster pace, if you will, but it’s still relatively slow, but we are running our leases. Green River is a little different animal in that we've got some good gas production at this stage of the game.

We are still analyzing completion techniques and those types of things, but I think at a certain point, it's not out of the realm to bring in a partner to help us develop one or more of these, but we will see what happens. We don't have a big fuse burning on Green River either. So it's – we are kind of trying to move these down the path to the proving stage or to the proved stage with – without spending a lot of capital and maybe getting some help from our friends surrounding us.

Brian Corales – Howard Weil

Okay, guys. Thanks.

Operator

(Operator Instructions) Your next question comes from the line of David Snow with Energy Equities Incorporated.

David Snow – Energy Equities Incorporated

Yes, I'm wondering if you could tell us what is the takeaway situation on oil up in the Horn River as well as the Bakken in Canada in the closer to the (inaudible) basin and what's your expected price you had realized?

Glenn Darden

It's very early in the Horn River. So we are at a very early stage and we are looking into that. We are not producing oil at this stage of the game, but we will – that's part of our analysis in beginning our drilling up there in the shallow side. As far as the Southern Alberta Basin as it's referred to in Montana, we are selling oil every day. So that market gets a bit of a discount to, I guess, normal crude prices. Rick, what is that – or Phil, maybe $5 a barrel, something like that?

David Snow – Energy Equities Incorporated

So in the Horn River Basin, you would have build infrastructure to get the oil out?

Toby Darden

Well, David, in the Horn River Basin, there are oilfields on either side of the Horn River Basin that are currently selling oil and oil pipeline servicing those. So there is takeaway from Horn River for oil and – but prior to doing a lot of work on infrastructure there, we probably will do some testing and proving of our own acreage to plan that infrastructure.

David Snow – Energy Equities Incorporated

And what do you think your oil production volumes will be this year versus last year?

Glenn Darden

It's not appreciably increased over last year.

David Snow – Energy Equities Incorporated

Not appreciably?

Glenn Darden

No.

David Snow – Energy Equities Incorporated

Okay. Thank you very much.

Glenn Darden

Thank you, Dave.

Toby Darden

Thank you, Dave.

Operator

And your next question comes from Irene Haas with Canaccord.

Manav Gupta – Canaccord

Hey guys, this Manav for Irene. Just wanted to ask something, you have acreage in the Glacier County, Montana. We wanted to know whether you think this play extends into Canada and are you looking at any Canadian opportunities to exploit this play since you already have Canadian operations?

Toby Darden

Well, we try not to comment on any ongoing acreage acquisition or review. So we really would rather not comment at this time. It is very early and there aren’t any results yet of commercial nature to report. So just know that we are aware of the extent of the Exshaw-Bakken play in Alberta and keep our eye on that.

Manav Gupta – Canaccord

Okay. Thank you, guys.

Toby Darden

Thank you.

Operator

And your next question comes from Dan McSpirit with BMO Capital Markets.

Dan McSpirit – BMO Capital Markets

Gentlemen, good morning and thank you for taking my questions. On the Alberta Bakken, can you speak to the history behind your 130,000 net acre position there today, how it's held by production, and maybe the cost basis per acre? And then as a follow-up, specifically your plans in second half 2010, how many wells capital commitment?

Glenn Darden

Capital commitment for?

Phil Cook

Which wells?

Dan McSpirit – BMO Capital Markets

For the Alberta Bakken.

Glenn Darden

Okay. I'll speak to – this is Glenn. I'll speak to the history. These properties were bought in the middle '90s prior to Quicksilver going public from Unocal [ph] – our predecessor company bought Unocal out of the Northern Rockies of Wyoming and Montana. This Cut Bank field is a mature oil field that's been under waterflood for many years. We've had it again since 1995 or so.

These leases are held by production in large units and we actually have a bigger area in what is termed the wells agreement beyond this 130,000 acres that we have the oil rights and Montana Power has the gas rights and there is a successor to Montana Power from the sale of Montana Power sold several years ago. So that was formed by Union and Montana Power back in the late '40s. So as far as the basis, it's very low. I don't have it on a per-acre basis.

And your – the second part of your question, what is our budget, we may drill as many as two wells, but it won't be a large budget for that this year. Again, we don't have a fuse burning. So we will watch what's happening around us, but again, try to use current techniques to unlock that oil.

Dan McSpirit – BMO Capital Markets

Thank you.

Glenn Darden

Thank you.

Operator

Your next question is a follow-up from Noel Parks with Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann

Hello. Just wanted to get you to talk a little bit about the possibility of the Bakken-Exshaw in British Columbia. Along the lines of what you described for Montana, as far as just the legacy wells and just a sense of maybe what the old thinking was up there about accessibility or commerciality of the Bakken and what's changed? Is it completion side, geography side, seismic, or what have you?

Toby Darden

Sure, Noel. In – as you've seen, as many companies have been reporting from the Eastern Bakken plays in North Dakota and Saskatchewan, the laterals are very long, the number of stages in the laterals now are many, 30 plus in some cases. And so the style of treatment has changed remarkably. It's expanded the fairway for the Bakken on the eastern side of Montana and North Dakota and Saskatchewan. So it's technique largely that has driven that increase in aerial extent and increase in production by multiple operators.

So I believe that the companies who have taken positions just west of us in the Cut Bank area are planning to exploit that new technology in their testing programs. They have drilled largely vertical wells, I think, to date to validate the – and identify the section they have reported oil in the Bakken-Exshaw section as we saw in our testing about four years as Glenn mentioned.

So the reservoirs there, it's now how do you exploit it commercially and that's the trick in most of these unconventional plays, but this is really playoff, what's been developing on the east side of Montana and in North Dakota and Saskatchewan.

Yes, go ahead.

Glenn Darden

As far as Horn River Basin, this just could be lanyard for us with our large shale gas play, and we are seeing some consistency across all the wells that we've drilled so far and definitely in a thermal maturity window, that is oil mobile oil, and as far as infrastructure, we spoke to that – answered some of those questions, but those – there are more questions to ask ourselves. So that's early, but we are encouraged and we like the looks of that, it would be great to have an oilfield on top of a gas field. We'll see.

Noel Parks – Ladenburg Thalmann

Great. Just to follow up, is it just as simple as really in the past no one considered it feasible to do horizontal drilling out there and that's really the key as opposed to looking to do – I suppose I guess the well control we have from vertical penetration at this point?

Toby Darden

Yes, it's all keying off the technology evolution on the east side of the state, Noel. And that's been fairly rapid. Really, the last two years have seen the biggest ramp-up in technology there and so I think the goal is to bring some of that technology west and hopefully northwest in the HRB area to exploit that area as well.

Operator

And your next question comes from the line of Mike Scialla with Thomas Weisel Partners.

Mike Scialla – Thomas Weisel Partners

Hi, guys. One on Tarrant County, what you were able to book in terms of proved reserves per well and what kind of EURs you are seeing there now in well cost?

Glenn Darden

In Tarrant County?

Mike Scialla – Thomas Weisel Partners

Yes.

Glenn Darden

That would encompass our Lake Arlington project and our Alliance project. I don't know that we have an average – I don't – we don't have it with us, we can get that for you. They are higher on average and it's dry gas than our southern area, which is probably still running at 30%, 35% liquids content.

Mike Scialla – Thomas Weisel Partners

What do you see there in terms of well cost now? And are there any pressures on that going – moving up?

Toby Darden

Well, yes. Mike, we are doing it more on a cost per foot of lateral length because the lateral lengths vary dramatically from about 3,000 feet, probably a low of 2,400 feet to upwards of 8,000 feet now. So the well cost is proportional to the lateral length because of the number of stages of frac which are proportional to that lateral length.

Glenn Darden

But overall, our costs have been flat to actually down a little bit. We are starting to see it perhaps tick up a little bit on the fracing side after the first quarter, but we've been able to contain our cost pretty nicely there.

Mike Scialla – Thomas Weisel Partners

Okay. For the – say, the longer lateral, 7,000 to 8,000 feet, can you give us an idea, I mean they are still in the $4 million range or – ?

Glenn Darden

Probably, yes.

Mike Scialla – Thomas Weisel Partners

Okay.

Glenn Darden

Yes.

Mike Scialla – Thomas Weisel Partners

And then just lastly, can you give us an idea of what the inventory looks like there now in terms of locations and if you have it – how many of those are still unbooked at this point?

Phil Cook

I don't know that we have that breakdown here, Mike. But we probably got another 30% to book, 40% in Lake Arlington and maybe the same in Alliance.

Toby Darden

Maybe a little more.

Phil Cook

A little more in Alliance.

Toby Darden

Yes, 50% plus or so.

Mike Scialla – Thomas Weisel Partners

Okay. Thank you.

Toby Darden

Thank you.

Operator

And your next question comes from Scott Hanold with RBC.

Scott Hanold – RBC

Yes, it's Scott Hanold with RBC. And good morning.

Toby Darden

Good morning.

Glenn Darden

Good morning, Scott.

Scott Hanold – RBC

The old shows or at least the Bakken formation out there in the Horn River, I mean, how much of that comes as a surprise you? I haven't heard a lot of people talking about that? Is that some other operators have seen or is this sort of more of an isolated area where you are all situated?

Glenn Darden

We've heard a little bit to the great bond, but I don't think anybody has talked about it publicly. We had good core analysis and it's something that we will investigate and talking about our capital, we wanted to let you know we are spending a little money up there on that.

Scott Hanold – RBC

Okay. And did you also – you could drill a well so just to kind of test it and get a little bit more information there and if so, when would you expect it to be?

Glenn Darden

Yes, we are going to reenter a seismic monitoring well and drill a horizontal leg in the Bakken-Exshaw later this year.

Scott Hanold – RBC

Yes. What depth did you say that was? I'm sorry if I missed that.

Glenn Darden

Roughly 4,000 feet.

Scott Hanold – RBC

4,000 feet? Okay. And one last question, could you all give us what is your pretax PV-10 value is using the SEC run, and if you could break that between PUD, PV-10 and PDP as well?

Rick Buterbaugh

Scott, I don't that have that with me at this point. I'll try to get back to you later today on it.

Scott Hanold – RBC

Okay. So could you just lend a – just a general color – I know it's obviously something that's come up in other conference calls and you went through the reserve booking process, were there PUDs on the – is there PUDs on the book with negative PV value?

Phil Cook

Not that are reported in our proved reserves.

Scott Hanold – RBC

Not that you report on the proved reserves? Okay.

Phil Cook

Right. They would have fallen out.

Scott Hanold – RBC

Okay. All right. Thank you.

Operator

And the next question is a follow-up from Mike Jacobs with Tudor, Pickering, Holt.

Mike Jacobs – Tudor, Pickering, Holt

Thanks. In the 700 Bs of reserve adds, I believe those included performance-related revisions as well. Can you give us an idea of the breakdown between drill bit adds and performance related revisions?

Phil Cook

There is about a 120 Bcf of performance related positive revisions net.

Mike Jacobs – Tudor, Pickering, Holt

Okay.

Glenn Darden

So 5.80 or so.

Mike Jacobs – Tudor, Pickering, Holt

Okay.

Glenn Darden

Of drill bit.

Mike Jacobs – Tudor, Pickering, Holt

And on the – I'm sorry if you mentioned this early, on the Horn River JV, just kind of your updated thoughts on that? Are you pushing back your timing on the JV until you get results from the wells that you are going to complete this summer?

Glenn Darden

Yes. And we still have some discussions ongoing, but what I did say, Mike, is the longer we wait the higher the value is.

Mike Jacobs – Tudor, Pickering, Holt

All right. Thank you.

Glenn Darden

Thank you.

Operator

And the next question is a follow-up from Subash Chandra with Jefferies & Company.

Subash Chandra – Jefferies & Company

In the Alberta Bakken play, just I really couldn’t – could never make heads or tails of Rosetta's press releases. What do you think the lithology – I mean, could you describe and talk to the lithology as to Bakken there, other than depth in terms of lithology and thickness? Is it 100% shale or what's the constitution?

Toby Darden

We have shale packages that are identified as clear shales and some carbonaceous and siliceous material between. So it's encouraging from a lithology standpoint, Subash. We just – we want to make sure we got about it the right way technically to exploit it.

Subash Chandra – Jefferies & Company

Okay. And frac barriers?

Glenn Darden

We think they are there. Yes.

Subash Chandra – Jefferies & Company

Okay. Thank you. That's all I had.

Toby Darden

Thanks.

Operator

Your next question is a follow-up from David Snow with Energy Equities Incorporated.

David Snow – Energy Equities Incorporated

Yes. Hi, I'm trying to get a comparison of the IPs of the two zones in Horn River and do you favor the upper one or is that just weighting too much into your next two wells?

Glenn Darden

We are favoring it right now on the development – on the earnings side, but we certainly believe that the Klua is economic and will add meaningful reserves over time.

David Snow – Energy Equities Incorporated

What does it look like the IPs will be on the two wells – the two zones?

Glenn Darden

Well, it's –

David Snow – Energy Equities Incorporated

What was it on the upper ones?

Glenn Darden

About 13 million a day is what it came in at. The second one, the Klua, the lower, came in about 6 million a day, but we had some issues on getting on all of our frac put away. So I don't know if that's a definitive test across the entire block. So we've got more work to do up there, David, and in the end, we believe we will produce – be producing significant gas from both formations.

David Snow – Energy Equities Incorporated

What do the other ones do in the lower formation? Do you have any idea? Other guys?

Glenn Darden

I'm not sure that other companies break it out separately. I mean, there are two packages of shale and a lot of it – the nomenclature gets a little bit fuzzy. We are trying to distinguish between the two, but there may not – I don't know that industry is right now.

Toby Darden

Yes, I think the encouraging thing, David, is that both wells are commercial. There are first stabs at this Horn River Basin and it's nice to start off earning what we will earn and what we do see is in the subsequent two wells we drilled, very encouraging gas shows while drilling the laterals, which indicates we are in a good province for completion. I don't think the Klua, the single Klua completion is indicative of the entire acreage block. I think it was partially of earning curve situation.

David Snow – Energy Equities Incorporated

Great. Sounds terrific. Thank you.

Toby Darden

Thank you.

Operator

And at this time, there are no further questions.

Rick Buterbaugh

Thank you, Cathy. Just as a reminder, a replay of this call will be available on the company's website for 30 days and the company does plan to release its first quarter 2010 earnings on Monday, May 10th. Members of the company's executive team will be making presentations at various investor conferences, which are detailed on our website as well.

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

Operator

And this concludes today's conference call. You may now disconnect.

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Source: Quicksilver Resources Inc. Q4 2009 Earnings Call Transcript
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