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Quicksilver Resources (NYSE:KWK)

Q3 2011 Earnings Call

November 07, 2011 11:00 am ET

Executives

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

Glenn M. Darden - Chief Executive Officer, President and Director

John E. Hinton - Vice President of Finance

Analysts

Pearce W. Hammond - Simmons & Company International, Research Division

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

James Spicer

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

David Snow - Energy Equities

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

John C. Nelson - Macquarie Research

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Patrick Melia

Gil Yang - BofA Merrill Lynch, Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Unknown Analyst -

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Operator

Good morning, and welcome to the Quicksilver Quarter 3 2011 Earnings Conference Call. [Operator Instructions] I will now like to turn the conference call over to John Hinton, Vice President of Investor Relations. Thank you, Mr. Hinton, you may begin the conference.

John E. Hinton

Thank you, Patrick, and good morning. Joining me today are Toby Darden, Chairman; Glenn Darden, President and Chief Executive Officer; Phil Cook, Senior Vice President and Chief Financial Officer; and Chris Cirone, Senior Vice President and General Counsel.

This morning, the company issued a press release detailing Quicksilver's results for the third quarter of 2011. 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 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 risks may differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed in the company's filings with the SEC. Today's presentation will include information regarding adjusted net income, which is a non-GAAP financial measure. As required by SEC rules, reconciliation of adjusted net income to the most directly comparable GAAP measures are available on our website under the Investor Relations tab. I will now turn the call over to Glenn Darden to review our financial and operating activities in detail.

Glenn M. Darden

Thank you, John. Good morning. Quicksilver Resources reported net income for the third quarter of 2011 of $29 million or $0.17 per diluted share compared to net income of $22 million or $0.13 per diluted share in the prior period. Third quarter 2011 adjusted net income was $6 million or $0.03 per diluted share. Financial results for the current quarter were impacted by noncash gain of $30 million related to mark-to-market impact of long-term derivatives, a noncash gain of $12 million associated with the company's equity interest in BreitBurn Energy Partners' second quarter 2011 derivative adjustments, a gain of $10 million from the sale of BreitBurn units and a loss of $15 million for the acceleration of unamortized debt insurance costs, professional services in connection with strategic transactions, and to settle pending claims associated with the previously disclosed legal litigation. We've made progress on several fronts on the operational and transaction projects, and our investments are beginning to bear fruit.

Starting with the Barnett. Our production continues to grow and this area has the most impact on overall company growth at this point, which will be approximately 18% year-over-year. We had some frac-ing delays in Lake Arlington which reduced our projected production number, but overall, our Barnett operation is running efficiently. As we recently disclosed, Quicksilver's putting certain of the Barnett assets into a newly formed master limited partnership.

The company is on track to file an S-1 registration document with the SEC in the coming weeks which will outline the details of the MLP. In Canada, most of our efforts and budget have been directed to the Horn River Basin project, where we now have drilled a total of 8 horizontal wells into the Muskwa and Klua formations. We have 4 wells online, which are exceeding our early projections, with the best well projected to have an EUR of close to 20 Bcf. Quicksilver will be drilling an additional 4 wells this year before the year end and will plan to complete these by the end of the first quarter of 2012.

These 4 wells will be drilled on 1 central pad and connected to sales. At this point, it looks like we have a high BTU gas well in the 1 Exshaw well we have completed. But we have only completed approximately 30% of the lateral. The well is shut in currently and we intend to complete the remaining lateral section after winter operation. We have recovered just 20% of the frac load, thus far, so we don't yet have a clear picture of what this well can do.

We continue to make progress on the infrastructure side of the Horn River, and recently, we executed a memorandum of understanding with KKR, to team up on a joint venture to develop and build a Midstream business in the basin. The proposed deal structure, which is scheduled to close in the next several weeks, provides for a $125 million upfront payment to Quicksilver and financing for build-out of processing and gathering assets in the initial stages of the business. Quicksilver will contribute its midstream assets that are already in place, which comprised a 20-mile, 20-inch pipeline and compression. The JV expects to complete the first train of processing facilities in 2014, which will require approximately $120 million of capital. Each party will own a 50% interest in the entity and Quicksilver will operate.

We are excited about working with KKR on this venture and believe together we can create a significant business in this huge gas supply area. It is estimated the construction of this infrastructure will save approximately $0.80 per Mcf in gathering, treating and transporting our gas to AECO.

Quicksilver is making very good progress in Northwest Colorado and our Niobrara oil project. As a reminder, Quicksilver has assembled over 210,000 acres in an area of historic Niobrara oil production with a section of 1,200 feet of potential play. Our scoping economics for this project at $80 per barrel oil pricing and initial production rates of 70 barrels of oil per day are in excess of 30% rates of return for our vertical play. This assumes a decline type curve defined by over 80 historical Niobrara wells in the area and an ultimate recovery of 225,000 barrels of oil per well. During the early stages of this drilling project, having drilled 6 vertical wells and 1 horizontal well, 4 of the vertical wells are in early stages of completion as we are increasing the frac size from the initial 2 wells.

Those first 2 wells are on production with rates ranging from 50 to 100 barrels of oil per day per well. Again, these are early days in this project, but we like what we see. In all the wells, we have seen similar high gravity oil shells with little to no water on testing. Our drilling times have been much better, which will translate into lower development costs. We will be completing our first horizontal well in the coming weeks. And our initial 25,000-acre 3-D seismic shoot is complete. We believe this shoot will allow our team to pinpoint locations with better certainty. We anticipate having all 7 wells online by year end.

In West Texas, the company has added approximately 25,000 acres in Pecos, Crockett and Upton counties in the third quarter, which brings our acreage holdings in West Texas to approximately 150,000 net acres. This area has become quite hot and we anticipate picking up drilling operations on up to 6 wells in the first quarter of 2012.

In Montana, we continue to monitor the activity around our large acreage position before we begin spending dollars up there. As I said in our earnings press release, our goals for Quicksilver remain: to increase production in our core projects; continue to reduce unit operating costs; and to establish new oil and gas production areas; and significantly improve the company's balance sheet. We have announced our plans to significantly reduce Quicksilver's debt, and are moving that forward. Another good asset sale data point came in last week on a large our net transaction. It is interesting to note that the purchaser was an MLP. The company has bought back its $150 million convertible debentures. This will actually decrease our noncash interest, and going forward, our diluted earnings per share calculation will now exclude the conversion effects of 9.8 million shares that were associated with the note. Quicksilver has put in place new bank credit facilities for both the U.S. and Canada and Phil will elaborate on that.

We will bring in outside dollars via joint ventures which will advance new projects and reduce capital expenditures for Quicksilver. We are finalizing our capital budget for 2012 and we fully expect to stay within cash inflows. That budget will include more investment in our Niobrara project and West Texas.

And now with the midstream joint venture in Canada will allow us to focus CapEx dollars on additional drilling in the Horn River.

Quicksilver is definitely moving forward on all fronts. And with that, I'll turn the call over to Phil Cook, our Chief Financial Officer. Phil?

Philip W. Cook

Thank you, Glenn, and good morning. Production volumes for the quarter were 427 million cubic feet of natural gas equivalent per day, a record level for the company and an increase of 2% from the 417 million cubic feet a day in the second quarter of the year. For the current quarter and the first 9 months of the year, total production grew by 18% and 20%, respectively, when comparing to the same period a year ago.

Average realized natural gas price for the quarter was $4.96 per Mcf or $0.10 lower than the second quarter of this year and $1.87 lower versus the prior year quarter. Average NGL realized prices were $38.68 per barrel in the third quarter. Average oil prices were $82.58 a barrel. We have hedges in the fourth quarter covering 190 million cubic feet per day of natural gas sales with the weighted average floor of $5.95 per 1,000 cubic foot and 10,500 barrels of NGL sales with a weighted average price of $38.84 a barrel. Based on commodity trading prices, we would expect our fourth quarter average realized gas price to be about $4.75 and our average realized NGL price to be around $40. These prices include the impact of hedges currently in place.

Total production revenue was $208 million or essentially flat from the second quarter of the year to the current quarter. Production volumes in the third quarter contributed approximately $2 million more than the second quarter of the year, the lower average realized price has offset virtually all of this increase. Lease operating expenses on a unit basis was $0.70 per Mcfe for the third quarter compared to $0.64 for the second quarter of the year. The increase compared to the second quarter is due to higher well work-over activity on older Barnett Shale wells and higher saltwater volumes in the third quarter.

For the first 9 months of the year, lease operating expense was $0.65 per Mcfe compared to $0.67 per Mcfe in the prior year period, while unit costs declined due to higher volumes from additional producing wells, absolute costs are higher due to increased saltwater volumes and freights, and an increase in work-over activity and compression overhauls. These amounts exclude gathering, processing and transportation expense, which is presented separately on the face of our income statement. Gathering and processing expense, which is the cost to gather and process our gas from the wellhead to the tailgater facilities, was $0.89 per Mcfe for the third quarter compared to $0.86 in the second quarter. The increase is caused by an increase in percentage of production from our Lake Arlington wells, which has higher gathering and processing fees compared to our other production areas.

In the Horn River Basin, lower volumes in the third quarter have increased the gathering and treating rate as a result of the demand charge obligation to Spectra. Transportation expense, which is the cost to get our gas from the tailgater facilities to market, was $0.41 per Mcfe in the third quarter compared to $0.37 reported for the second quarter of the year. The increase is also caused by a volume shift in our Barnett producing areas. Production and ad valorem taxes were $0.20 per Mcfe for the current quarter compared to $0.22 per Mcfe for the second quarter of the year. The decline is caused by lower average realized prices in the third quarter. For the first 9 months of the year, taxes were $0.21 per 1,000 cubic foot compared to $0.28 in the prior year period. The decline is primarily attributable to the sale of KGS. DD&A for the third quarter was $1.47 per Mcfe compared to $1.44 for the second quarter. For the first 9 months of the year, DD&A was $1.46 compared to $1.60 in the prior year period, again, the reduction is primarily related to the sale of KGS last year.

G&A for the third quarter was $0.70 per Mcfe compared to $0.42 in the second quarter. Noncash stock compensation is $0.11 a 1,000 in the second quarter and $0.12 in the second quarter, essentially flat. Excluding third quarter noncash special items, recurring G&A is $0.43 per Mcfe compared to $0.42 in the second quarter. We recognized one-time charges to G&A of approximately $10.5 million in the third quarter related to a legal settlement and professional fees related to strategic transactions.

For the first 9 months of the year, G&A was $0.55 per Mcfe compared to $0.66 per Mcfe in the prior year period. Excluding noncash and special items, G&A was $0.43 per 1,000 in the first 9 months of the year compared to $0.60 per Mcfe in the prior year period. The decrease is primarily due to the elimination of KGS general and administrative expenses.

As a brief recap, recurring unit cash expenses for LOE, gathering, processing and transportation, production, and ad valorem taxes and G&A in the third quarter, were $2.48 compared to $2.38 in the second quarter. At oil and gas prices for the quarter, our cash margin was $2.81 on an unlevered basis. On a levered basis, recurring cash interest expense is $1.09 and cash margin is $1.72 or 33% on revenue.

In the third quarter, we recognized a gain of $9.5 million on the sale of 600,000 units of BreitBurn, which was the exercise of the green shoot from the previous sale in the second quarter. We own approximately 8 million units of BreitBurn which at Friday's closing price, would generate approximately $135 million of net proceeds.

Adjusted net income for the quarter was $6 million or $0.03 of diluted share compared to adjusted net income of $11 million or $0.07 per diluted share in the previous quarter. In addition to the adjustments we routinely make to our equity method investment in BreitBurn, we also had several other adjustments booked in the third quarter. First, we excluded a noncash gain of $30 million for the mark-to-market impact of long-term derivatives. Second, we excluded the $9.5 million gain on the sale of the disposition of 600,000 BreitBurn units. Again, this was related to the exercise of the shoot. Third, we excluded approximately $3 million for the acceleration of debt issuance costs related to the retirement of some debt. And last, we excluded the $10.5 million to settle legal claims and expense deferred professional services, again in connection with some strategic transactions. Adjusted net income for the second quarter excluded $122 million gain on the sale of 7 million BreitBurn units and a $19 million noncash gain for the mark-to-market impact of long-term derivatives.

Capital expenditures were $165 million in the third quarter and $525 million year-to-date. We expect to finish the year at approximately $690 million for CapEx. Operating cash flow for the year is expected to be in the $290 million to $300 million range, the decline from the full year estimate provided last quarter is mainly the result of lower realized prices on gas sales. We continue to explore options to raise cash through joint ventures and upstream operations. We also are still in our earn out period with regard to the sale of our KGS asset, and are anticipating earn out from that agreement is $45 million, which will be received in the first quarter of 2012.

I would remind you that we have an additional $22 million earn out in 2013 and a makeup provision in 2013 to the extent that we don't collect all of the earn out for the 2012 period.

So to summarize our spending as compared to cash generation for the year, we will generate $300 million of cash from operations. We sold $145 million of BreitBurn units. And we own an additional 135 million of units. And as Glenn mentioned in his comments, we will close our midstream transaction in Canada in the fourth quarter, which will bring in $125 million. In total, that's $705 million of cash generation against the spend of $690 million. Therefore, I expect that total debt as compared to last year end will be flat.

Total debt at September 30, 2011, was approximately $2.1 billion. We had 2 significant events related to debt since our last earnings call. First, we terminated and replaced our previous $1 billion senior secured credit facility, 2 separate 5-year indicated senior secured revolving facilities for the U.S. and Canadian operations. The new facility has a borrowing base of $1.1 billion and has approximately $600 million available at November 1. Second, we redeemed approximately $150 million of convertible notes that were put to us on October 31. The bond redemption was funded with the U.S. credit facility and the available capacity of $600 million includes this payment.

Just to recap on debt reductions over the past 12 months and projections to year end. At the end of the third quarter of 2010, we had debt of $2.4 billion. And at the end of this quarter, our debt level is $2.1 billion, a $300 million reduction or 12.5%. I expect to end the year at about $1.89 billion, down another $200 million, and a total reduction of $500 million or 21% over the 15-month period. If we look at into next year, we expect our debt levels on a consolidated basis to continue to decline, and for next year, my estimate would be that debt will be down another $500 million by year end 2012. I'll now turn the call back to John for fourth quarter and full year guidance and for the question portion of the call.

John E. Hinton

Fourth quarter 2011 production volume is expected to be 425 million to 435 million cubic feet equivalent per day. And the oil production is expected to be between 415 million and 420 million per day, which should be an 18% increase from 2010. Average unit costs on an Mcfe basis are expected as follows: LOE between $0.68 and $0.72; gathering, processing and transportation, $1.28 to $1.32; production taxes, $0.23 to $0.25; general and administrative between $0.42 and $0.45; and depletion, depreciation and accretion, $1.46 to $1.48. We'll now open the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Kim Pacanovsky from MLV and Company.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Just a couple of questions on the Permian. Can you just go over the total acreage in each county and where you added the most acreage in the 25,000 acres you just tapped on? And also, it's -- the map on your presentation on the website, it's hard to read the writing, so if you could just kind of go through where you're most concentrated and where the initial drilling will be, and maybe who, if you're near EOG, or who else you're near, that would be great.

Glenn M. Darden

Yes. Kim, for ease of understanding, we have 3 primary blocks that we are focused on. One is in Reeves in Jeff Davis County, one is in Pecos and one is in Reagan and Upton counties, with some in Crockett, but in that corner. And they're fairly -- we've got about 55,000 in Pecos, 27,000 in Crockett Upton and 24,000 in Jeff Davis and Reeves. And we plan to do some drilling across each of those blocks during the early part of next year.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

And your Reagan and Upton acreages is, I don't know if you have the presentation open, I don't know what color it's in, it looks like what you're showing is in pink is other people's acreage.

Glenn M. Darden

Well, there are various colors for different operators, but our acreage is outlined in yellow.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. All right. That makes sense. Okay. And so, but the first well is going to go down where?

Glenn M. Darden

Well, we have wells planned on each of the blocks and so you'll see us testing, drilling resources at wells in each one of the blocks to establish what we want to do from that point forward.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. And on the Niobrara, can you just go over again, you said $80 a barrel economics with 70 barrels a day, what was the return on that?, And did I hear you correct that you said you're seeing between 15,000 barrels a day on the first 2?

Philip W. Cook

You heard that correctly. And our scoping economics, is the well cost is roughly $2.9 million, including facilities. The cost per barrel or price per barrel received $80 or starting with a baseline of $80, we deduct transportation out of that, et cetera. And we base it on a decline curve, based on 80 wells that are in the area of historic production, so we have a pretty good baseline we think, a nice decline curve.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

So there's very much a possibility that this could be developed vertically?

Glenn M. Darden

We think so. And we like what we see on the vertical side, but we are going to be testing horizontally as well. And we like that well will be completed over the next couple of weeks. So we'll be able to compare. As I said in the prepared remarks, it's early days, but we've got a pretty good head start on it.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

And can you just remind me, is there any upside from any of the other formations in that region, the Frontier or the Shannon?

Philip W. Cook

It's primarily a Niobrara play.

Operator

Our next question comes from David Heikkinen from Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just following up on that Niobrara theme, what is the difference in frac size from the first 2 wells that you said were smaller to the next 2 wells?

Glenn M. Darden

We're really not disclosing that at this point. We are in a bit of a science experiment right now and we're trying some pretty significantly different techniques there. And at a certain point, we will disclose it, but I would say it's significantly bigger in the next few wells.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then going up into Canada, first, I wanted to hit the Exshaw where you said you encountered wet gas. Does that change your expectation of oil potential, and then will this well, what type of processing would be required to actually produce wet gas from the Exshaw?

Glenn M. Darden

Yes. I wish we were farther along on that completion, David, and we're not trying to send any different or mixed signals here. It's 1,200 BTU gas that we've tested, analyzed out of the well. We're not making a lot of product right now. Of course, the well is shut in as I said. But because of we've only recovered, only, I guess, 20% of our load back. So it is shut in and we've got some weather issues up there. We need to move that into all-weather operations. But it would have to have some processing, but we'll see the volumes. And we're not getting too excited at this point until we see the full result.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I wanted to ask one other question on the Niobrara. What's the length of the horizontal that you're going to be drilling just to compare that to 1,200 feet of vertical thickness? Is it a couple of thousand, 3,000-foot lateral or do you have plans on that?

Glenn M. Darden

Yes, it's longer than that actually. Yes.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

4,000 feet, is that a fair number?

Philip W. Cook

No.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

No, you doubt it. 2x or 3x is a fair estimate. And on the numbers, just on the Horn River Basin joint venture, you said you expect to reduce overall gathering, transportation, processing, was it by $0.80 per Mcfe or to $0.80 per Mcfe?

Glenn M. Darden

$0.80 an Mcfe, David.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

It will be at $0.80. It's to or by, I'm sorry.

Glenn M. Darden

No, we are reducing it an additional $0.80.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

At what level would you expect then for that overall gathering, transporting and processing, what costs would those be?

Philip W. Cook

It's about $0.80.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. It's cutting it in half?

Philip W. Cook

Yes, so the alternative to what we're doing is about $1.60 and we are reducing it $0.80.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then so you said you had expect to continue to reduce debt next year and mentioned that you'd expect the $500 million debt reduction by year end. If you're living within cash inflows on the capital budget, how do you get there? What are the mechanisms?

Glenn M. Darden

Well, as we've discussed with you and we can't say much about it, but we're creating an MLP that will generate cash for the company.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. So the MLP is the primary driver?

Glenn M. Darden

Yes.

Operator

Our next question comes from Noel Parks from Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Just a few questions, I'm going to head back up to the Niobrara. You mentioned that you'd completed, I guess, a 25,000 3-seismic shoot up there, and do have a sense whether seismic is going to be necessary uniformly across the play, so it's just going to be the cost of doing business? Or is this more just part of your early science up there?

Glenn M. Darden

Yes. We've utilized 3-D seismic in every area that we've gone to on these resource plays and it has been a great tool to identify fracture systems, et cetera, and we think it will be -- it will enhance the prospectivity of this play.

Philip W. Cook

And Noel, we have 1,200 feet of vertical section of Niobrara that's oil-bearing in that area. We are drilling them vertically initially, but we're drilling on horizontal to see and if we go horizontal on a regular basis, that 3D will be extremely helpful.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. So it sounds like you anticipate, over time, extending that 3D across the complete position?

Glenn M. Darden

Yes.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. And In the Exshaw up in the Horn River Basin, if I remember right, when you first were talking about possibly of oil and not finding more like wet gas, I think you expected that it was only right in your immediate area that you are going to see the liquid contents and that it wasn't occurring in the larger part of the plays. Is that still the case?

Glenn M. Darden

Well, I'm not sure what's occurring in the larger portion of the play. I think there are a couple of other operators up there. I've mentioned they've had oil shows and what we've talked about is we've had oil shows in all of the wells we've drilled. So thus far, so we haven't defined the limits of this, but and again, it's pretty early in the completion of this well or the results of this well. So we need just more data to hang our hat on.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Sure. And just a question thinking about the financials going forward, do you have any sense directionally of what DD&A might look like next year, just with what you assumed your year-end bookings are going to be?

Glenn M. Darden

I think you can expect DD&A to be about flat next year where it is this year.

Operator

Your next question comes from Pearce Hammond from Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

Just curious, what are your current net backs in the Horn River Basin?

Philip W. Cook

I'm trying to think through the mechanics of it. $4 gas and probably $0.50 of AECO and $0.20 of deduction for the stature flag price. I'd say the rough math expect $1, $4 gas with no hedging.

Glenn M. Darden

Yes. And we have hedged some of those volumes up there.

Pearce W. Hammond - Simmons & Company International, Research Division

Okay. And then for that 20 Bcf potential EUR well on the Horn River, what's the well cost on that kind of a well?

Philip W. Cook

It's less than $1, on a finding and development cost, it's less than $1.

Glenn M. Darden

Yes, but those wells -- that well was probably $12 million on a 20 Bcf well.

Philip W. Cook

Yes.

Pearce W. Hammond - Simmons & Company International, Research Division

Okay, great. And then moving to the Permian, thank you for the breakout of the acreage, that was really helpful. Can you also split it by the prospectivity per zone, how much is prospective to the Bone Springs and then how much is prospective to the horizontal Wolfcamp?

Philip W. Cook

Right now, we're looking at both plays as material contributors to it and we are drilling resource assessment wells, which will give us a clearer picture on what we believe we can allocate to each zone. But we'll be looking at both obviously as we go through it.

Pearce W. Hammond - Simmons & Company International, Research Division

Okay, great. And then I apologize for making you repeat the Niobrara wells, but so there were the first 2, the rate there was what? And then the second 2 verticals, what was the rate, I think I heard 1,500 earlier?

Glenn M. Darden

No, we have completed -- we're in the process of completing 6 wells. 2 are online and are producing at rates ranging from 50 to 100 barrels a day of oil, that includes a little bit of gas, but very little, mostly oil. The other 4 have not come online, we're still in the completion phase.

Pearce W. Hammond - Simmons & Company International, Research Division

And then the well cost on those 2 that are already online, that's $2.9 million?

Glenn M. Darden

No. That's in our scoping economics. These wells will be -- these are more expensive because we've done some science, a fair bit of science on that. But we think, comfortably, we'll be below that $3 million level on the development side on vertical wells.

Pearce W. Hammond - Simmons & Company International, Research Division

Okay. Did you quote an EUR for those?

Glenn M. Darden

We have not quoted that, what the EUR number that we mentioned in the earlier remarks was based on our scoping economics of a type curve defined by 80 productive wells in the area that were drilled from the 60's on.

Pearce W. Hammond - Simmons & Company International, Research Division

And then lastly, your current thoughts on the Alberta Bakken?

Glenn M. Darden

Well, we're watching like a lot of people and we are in a fortunate position where we have -- most of our acreage is held by production. But there does seem to be an increase in activity or certainly more talking about some results. So we're with a tight budget, that's an area where we just decided not to spend dollars until we got more clarity.

Operator

Your next question comes from Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Can you talk about, are you going to be drilling kind of those horizontal Wolfcamp wells in the southern midland basin? Is that kind of what the first few wells you all be doing?

Glenn M. Darden

Officially, we'll drill vertical wells because of the thickness of the total pay package there. And then we'll make determinations based on those results on what we do horizontally from that point forward. But our initial round of resource assessment will be done on a vertical basis.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then also, I noticed the company NGL production declined in the third quarter. Is that just the make-up of completions in the Barnett and how does that look kind of going forward? There's a lot in the backlog, I mean, if I recall, it's been relatively balanced between Lake Arlington and the kind of liquid-rich area. Is it more balanced going forward or how should we think about the Barnett production?

Philip W. Cook

This is Phil. It's balanced between 18% and 20% for this year, and I would expect it's going to be around there in the fourth quarter. We have clearly drilled more in Alliance and Arlington than we have in the south, but liquids production continues to be very strong in the South, then it's a function of a number of things, including wells being shut in for drilling and other things. So we don't think that it's changed dramatically in terms of percentages.

Brian M. Corales - Howard Weil Incorporated, Research Division

If I can ask one final question, I know you're still kind of working through the budgeting process, can you maybe talk about how much capital you spent this year on land and infrastructure?

Glenn M. Darden

Yes, we'll get those numbers for you, Brian.

Philip W. Cook

Yes, so acreage cost was a couple of hundred million dollars, and pipe and other was another $140 million. Drilling and completion capital, this is expectation for the full year, drilling and completion capital was about $365 million.

Operator

Your next question comes from Gil Yang from Bank of America.

Gil Yang - BofA Merrill Lynch, Research Division

The $125 million you will get up front, is that just that covered capital or are there any type of consequences from that?

Philip W. Cook

There's no cash tax consequences from that.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And I guess, as well, for the go forward build out financing, would you need to contribute something or would they be carrying you the whole way?

Philip W. Cook

They're actually carrying us.

Gil Yang - BofA Merrill Lynch, Research Division

And is it for next 3 years or 2 years?

Philip W. Cook

Well, we've only agreed to the first treating facility which is the next $120 million of capital that will be spent up there. KKR will contribute that.

Gil Yang - BofA Merrill Lynch, Research Division

For the Niobrara well development program, is there any specific -- I mean, obviously, you're one of the most expensive today, but is there any expected improvement in well design or well costs beyond just sort of getting to development program that is built into that rate of return or is it just removing all the science and drilling the wells as it is.

Philip W. Cook

Basically, the model was developed from '60s and '70s managed wells. So our production projections for the play were based largely on vertical, fully stimulated Wild Horse, but that established our projection for what a typical well will do and we've given no credit for increasing production from better stimulation and better completion. Right now, we're going through the process to determine what is the best but we're pretty encouraged that the first wells we tried look like they're within that commercial window with good returns and we should get better from here, we hope.

Philip W. Cook

On the cost side, Gil, I think that the most encouraging sign is if it's taking a lot less time to drill these wells, and we feel confident our drilling teams and completion team feels confident that we can keep these costs on a vertical play. It's all contained.

Gil Yang - BofA Merrill Lynch, Research Division

How much vertical pay did you complete in those 2 test wells?

Glenn M. Darden

Well, we covered the entire 1,200-foot section. But I think as we go forward, we'll be more surgical and breaking it into more stages, et cetera, like we have in most of the other unconventional plays we've been in. But even with those early frac designs, we're seeing results of that, very encouraging, and on track to be very commercial.

Gil Yang - BofA Merrill Lynch, Research Division

Have you identified any particular horizons that look more viable as candidates for horizontal drilling than others?

Glenn M. Darden

We've just drilled our first horizontal. We have obviously had good shows in it, but we are waiting on the completion of that to determine how well we selected our horizontal plays to see how that will work versus the vertical.

Gil Yang - BofA Merrill Lynch, Research Division

And sort of at the development plan, what's your sort of case or expectation for the EUR and the cost multiple for horizontal program?

Philip W. Cook

Well, It's early days, Gil. And we'll get those costs. But when we've finished this first well, we'll have a better idea, but looking at the performance, et cetera, we'll probably be drilling several others and then get better handle on cost and the EUR, et cetera.

Glenn M. Darden

Gil, we have a large sample of vertical wells to establish a type curve from. We have virtually no horizontal completions to establish a similar type curve, so we'd rather not comment on that yet.

Gil Yang - BofA Merrill Lynch, Research Division

Okay, fair enough. Then just one last housekeeping item. Does the 9.8 million shares that are no longer in your average, because they were taken out on November 1, do we have 1 month of them averaged in or will the weighted average not have any of those shares in?

Philip W. Cook

Actually, because of where the strike price was relative to the stock price, it won't be in there for the whole year.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. So there is doubt totally?

Philip W. Cook

Yes.

Operator

Our next question comes from David Snow from Energy Equities.

David Snow - Energy Equities

How close would you space the verticals if you go that route on the Niobrara?

Glenn M. Darden

Well, we're still determining drainage radius from these wells, David. But I think it's reasonable to expect that certainly, we'll start drilling on wider space in the whole acreage. But ultimately, and certainly, it could go to 80s or 40s.

David Snow - Energy Equities

How did they do it in the old days?

Glenn M. Darden

Well, in the old days, there were more random wells drilled largely on single leases. And so there wasn't a lot of unit-type look at this play as a stratigraphic unconventional play. So determining what the appropriate spacing will be, still is in flux, I think.

Operator

Your next question is from John Nelson from Macquarie Holdings.

John C. Nelson - Macquarie Research

I was just wondering if we can get an update on how we should be thinking about the Horn River ramping up? I thought you guys has expanded about 30 million of take away capacity, it was actually down a slight bit in 3Q just if any sort of guidance on how we should be thinking about that?

Glenn M. Darden

Yes, we're going to be ramping that up as I said in my remarks. We'll be able to focus our dollars more on the drilling side so we have a target of 100 million a day by the end of '12, first half of '13.

Philip W. Cook

The take away capacity goes up to 75 a day starting on May 1, and so the wells that we're going to be drilling and completing this year are going to be brought online in conjunction with that step up in capacity and then the capacity steps up again in 2013 to 100 million a day on May 1.

Glenn M. Darden

So we will drill to match those pipeline requirements.

John C. Nelson - Macquarie Research

Was there any sort of unplanned downtime in 3Q that bought the average for 3Q down sequentially or how should we think about the ramp up prior? Is this baseline a good level to start from?

Glenn M. Darden

Well, we started our drilling program a little later in the year, so probably you saw the effects of some decline between drilling programs without bringing new volumes on.

Operator

Our next question comes from Patrick Melia from Koch Supply & Trading.

Patrick Melia

That's actually Koch Supply and Trading. I think this might be for Phil Cook. As you were running through, sir, some your hedging commentary, you had mentioned the 190 a day of gas and the 2.5 of NGLs for the remainder of the fourth quarter of '11. The question I have, sir, you have currently, I think, 4 a day on in cal '12 and with the price level that you mentioned, which was, I think, $38.84 a barrel for your balance of, is that a blend of some frac spread within the NGL stream or is that specifically on one or more components of the NGLs, the liquid-rich stream in your nat gas?

Philip W. Cook

The $38.84 is for our calendar '11, mark for average price in '12, is of course like a $45.

Unknown Analyst -

Okay. And again, I'm sorry, is that when you just referenced it as NGLs hedging, is that on ethane and propanes, butanes condensate?

Philip W. Cook

That's our composite mix on our basket. So we had you took the individual components.

Patrick Melia

Very good. Comprised of currently that 4 a day, at least at the end of your 2Q report, which I've been looking at. That's some blended components of all 4 of the NGL stream?

Philip W. Cook

Yes. And we're up to 6 a day for cal '12 at this point.

Operator

The next question comes from James Spicer from Wells Fargo.

James Spicer

When you talked earlier on the call about absolute levels of debt reduction going forward, and particularly in 2012, did those numbers and targets include potential debt that you would have at the MLP level that would presumably be consolidated?

Glenn M. Darden

Yes, it does. However, I will tell you that debt obviously will be nonrecourse to the parent. But yes, that's a net number.

Operator

Our next question next comes from Steven Karpel from Crédit Suisse.

Unknown Analyst -

This is actually Brian Echeverria [ph] on behalf of Steven. Also kind of following up on some of the debt commentary. You discussed some debt repayment in the quarter. Is it possible to elaborate on that and potentially provide us with an updated breakout of your outstanding debt?

Philip W. Cook

Yes. So our 825s, originally, that was a $475 million issue. We've bought back $37 million of that, so outstanding on that tranche is $438 million. On the 1175s, that issue was originally $600 million and we've bought back $9 million of that, so the outstanding is $591 million. And the 998 tranche was originally $300 million and we bought back $2 million of that so for a total of $48 million of senior note buybacks.

Operator

Our next question comes from Richard Dearnley [ph] from Longport Partners.

Unknown Analyst -

Was the acreage acquisition in the quarter just the 25,000 in the Permian?

Glenn M. Darden

We had other acreage, but small amount, most of that was West Texas.

Unknown Analyst -

Okay. And then the sale in the Barnett recently to EDP, was the pricing of $0.92 and $8,600 a day of production seem to be in line with of the $400 million goal of raising money? Is that as you see it, as well?

Philip W. Cook

Again, we can't speak to the MLP value, but it was another good marker. It was a comparable marker, on lot of flowing end to the range sale over a year ago or in the past year. And that would value Quicksilver's asset, apart from the MLP, at roughly $2.8 billion. So I don't think we're valued like that today in the stock market. But anyway, we felt like it was another confirmational point that Barnett assets have good value.

Operator

Our next question comes from Marshall Carver from Capital One South.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

A couple of questions. I know you said you gave the Niobrara rates -- a couple of quick things outside of that, in the Horn River, how much -- this was supposed to be a JV for the midstream, how much will you own after this transaction or were you selling it? I'm just trying to get a feel for what the percentage ownership will be after the MLP transaction closes.

Glenn M. Darden

You mean, you're talking about Horn River midstream JV where we are 50-50 partners with KKR.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. 50-50. And then on 4Q, you lowered that on some well delays. What about -- do you have a 2012 target and where does that stand?

Glenn M. Darden

Well, we're working on that, Marshall, and we haven't announced a budget and we will later this year. But it all depends on how much we direct toward oil projects probably. So I think it's a question of can we do it? Yes. We can grow at similar rates, roughly 20% a year out of the Barnett alone. But is it better to grow more efficiently via or from the earnings perspective, via some of these new oil projects? We shall see. So we just -- we're working on it, but we haven't baked it yet.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

And when do you expect to publish that? Would that be at the end of this year or beginning of next year? When do you plan on doing that?

Glenn M. Darden

At the earliest, at the end of this year.

Operator

Your next question comes from Mike Scialla from Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Just a follow up on Marshall's question. I realize you haven't formalized a budget yet but if you look at that 20% type growth that you talked about, Glenn, out of the Barnett, what kind of spending would that require? Would it be similar to what you spent this year, I assume?

Glenn M. Darden

I think we could probably grow 20%, if we didn't acquire additional acreage during the year, we could grow at 20% with cash flow from operations.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And the $500 million debt reduction you talked about next year, Phil, can you say even conceptually, does that contemplate more or less spending than what you did this year?

Philip W. Cook

What it would contemplate is, to the extent that we were spending beyond cash flow from operations, we would be bringing in capital to fund any of that exploration drilling or development of exploration plays. And so our analysis is any cash that we did receive from sales to the MLP would go to specifically pay down debt.

Operator

And at this time, there are no further questions. Would you care to make any closing remarks, Mr. Hinton?

John E. Hinton

No. I think this concludes our call today. We appreciate your interest in Quicksilver and look forward to talking to you again. Thank you.

Operator

Thank you for participating in today's Q3 2011 earnings conference call. You may disconnect at this time.

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