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Executives

Thomas F. Darden - Chairman, Chairman of MSR, Chief Executive Officer of MSR and President of MSR

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

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

John C. Nelson - Macquarie Research

Luke Gittemeier

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

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Anne Cameron - BNP Paribas, Research Division

Gil Yang - BofA Merrill Lynch, Research Division

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Andrew Venker - Lazard Capital Markets LLC, Research Division

David W. Kistler - Simmons & Company International, Research Division

Andrew Gazso

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Quicksilver Resources Inc. (KWK) Horn River Basin Midstream Partnership with KKR Announcement January 5, 2012 9:00 AM ET

Operator

Good morning. My name is Debbie, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Quicksilver Resources Conference Call. [Operator Instructions] Thank you. Mr. John Hinton, Vice President of Finance and Investor Relations, please go ahead.

John E. Hinton

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

On December 27, 2011, the company issued a press release announcing the formation of a Horn River Basin midstream partnership with KKR. This call is to discuss that announcement and other matters. 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. We will be discussing slides today, and those slides are available on our website under the Investor Relations Events and Presentations tab.

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

I will now turn the call over to Glenn Darden.

Glenn M. Darden

Thank you, John. Good morning. I would like to lead in this morning with an introduction before we dive into more detail on recent company transactions and activity.

Quicksilver is continuing to follow the unconventional resource path we started down 20 years ago in Michigan, where we were one of the early pioneers of shale resource development. Since that time, Quicksilver has successfully found and developed large-scale commercial projects in 5 separate basins across North America, and we believe we are poised to increase that to 7 basins in the near future.

In every case, the company has followed the same strategy, which is outlined on Slide 4 of this morning's presentation. We start with early entry, with large acreage positions at lower costs per acre and lower royalties. We next move to resource assessment wells and then to validation wells to determine the size and commerciality of the projects. We then build infrastructure to ensure lower gathering, processing, transportation and operational costs, and finally, we go to full development.

As I said, we've used this successful strategy in multiple basins. Historically, the company has monetized assets as they mature to reload for future projects. Examples of these monetizations are the sale of our Michigan and Indiana assets to BreitBurn Energy Partners for roughly $1.3 billion and the sale of our Barnett midstream entity, Quicksilver Gas Services, or KGS, to Crestwood for roughly $1 billion in cash and assumed debt. Both of these asset bases were sold as they near full maturity in their respective areas.

Currently, Quicksilver has the largest inventory of projects in company history. I direct your attention to Slide #5, which shows our current inventory of projects along a maturity curve versus time. As you can see, each of our projects is at a different level of maturity, with West Texas being the newest and Horseshoe Canyon being the most mature. We recognize with our debt position that selling assets is important to reduce overall debt in order to free up more cash flow for growth. For this reason, we have chosen to monetize Quicksilver's Barnett position. We are entering our ninth year of activity in the Barnett, and while still some distance from the full maturity, the Barnett is of a size that can meaningfully reduce this debt.

The company has chosen to do this in the form of a master limited partnership, which we believe will realize the best value for Quicksilver shareholders. After studying the asset sale versus public yield vehicle markets, we believe the company will be -- will receive a better price for the assets, and we'll still have ownership in the growth of the Barnett unbooked resource of over 1 trillion cubic feet of gas equivalent and also participate in the gas price recovery over time by forming a master limited partnership.

In our earnings call on November 7, 2011, we targeted the filing of the S-1 registration with the SEC by the year end. The timing of this has lagged by about 30 days, but we should be filed relatively soon. Quicksilver has experienced -- has experience in running this type of entity, and we have a very efficient operational team that will continue to harvest this asset over the long term.

What we will show you today is the progress Quicksilver has made on each of the new projects we have and our plans to develop and fund these projects. As I said earlier, even the new projects are at various early stages of maturity and as a result will each require different levels of funding going forward.

Quicksilver will be finalizing its 2012 capital budget shortly. And similar to the previous 2 years, if capital expenditures exceed cash flow, we will bring in outside dollars to fund individual projects. We foresee proceeds from the MLP paying down bond debt.

We will begin the discussion this morning with the Horn River Basin and the significance of our recently closed joint venture with KKR followed by a discussion on 2 exciting oil projects that we're gaining momentum on.

For color on these projects, I'll turn the call over to my brother, Toby.

Thomas F. Darden

Good morning. As Glenn has discussed, Quicksilver has projects in various stages of development, and I plan to give you a more detailed look at those today.

First, I'd like to bring you up to speed on our Horn River Basin midstream joint venture with KKR. This is a very important piece of the development process in Horn River. As a little background, we have a world-class resource play in the Horn River, and on Page 7 of the presentation, we have 130,000 net acres in the play of core acreage with under 20 licenses with 100% working interest. We expect to have those exploration licenses converted to 10-year leases in 2012. We have largely derisked a net resource potential to Quicksilver shareholders of greater than 10 trillion cubic feet of natural gas, and Quicksilver and the industry have essentially derisked this basin.

On Page 8, you can see a picture of both rigs on a pad drilling an 8-well program this winter to establish commerciality and lower development costs to get into our system program of development.

On Page 9, you'll see the type curve developed from largely industry but also our own production results. On short laterals -- relatively short laterals relative to what we plan to develop under, we have recovered between our first 2 wells were about 10 Bcf wells and our third and fourth wells were between 15 and 20 Bcf. Based on fairly lengthy results from those -- production results from those wells, we've established a type curve on a 7,600-foot lateral. The earlier wells were under 5,000-foot lateral, so we expect this to be potentially somewhat conservative. But we'll have initial rates from those wells of about 14.5 million a day, with EURs of 16 Bcf per well. And we've tested across the block and our competitors have tested around us to a degree that we feel very confident in these results. We now have enough time under our testing program to give us confidence.

But the challenge for Horn River is the remote nature of the acreage. It's on -- in the northeast corner of British Columbia, and from the outset, we knew we would have to establish a midstream solution and a transportation solution for the gas produced from this basin.

As you can see on Slide 10, we think we have done that in 2 steps, basically. We contracted with TransCanada to build an extension of their mainline system all the way up to our acreage. It's a 70-mile extension, and it gives us access to AECO at the lowest possible price. Combining that with our joint venture with KKR, which is a large business opportunity unto itself, we have -- we will have the lowest-cost delivery of gas out of the Horn River Basin to the liquid market of AECO and, ultimately, to the West Coast, where there are going to be export opportunities, we believe.

Our KKR joint venture is a critical piece of that. It's a 50-50 joint venture. On Page 11, you will see Quicksilver contributes our 20-inch pipeline and existing compression facilities, for which KKR paid Quicksilver $125 million.

This partnership, which has a scope much larger than the initial phases, but in its initial phase we'll build 150 million a day CO2 treating facility at a cost of about $120 million. And Quicksilver has the option to be carried for its 50% of capital in exchange for preferential payout to KKR, which greatly assists us during the early development phase of this project.

Some additional features of the joint venture on Page 12 are we have created a 30 million-acre area of mutual interest covering 3 basins. We believe this is a very significant basin unto itself, but there are a couple of areas around us that we think could be additive, and we would like to have KKR as our partner as we explore those basins in the future.

There are going to be -- the 30 million-acre area of mutual interest is for midstream assets -- development of midstream assets. We've dedicated our 130,000 acres and over 10 Tcf of potential reserves to this system to anchor the investment. We have significant opportunities also along the extension of the mainline of TransCanada for third-party gathering and treating, and we will deliver our first gas into the treating facilities at a rate of 100 million a day in 2014.

On Page 13, in addition to being a very large business opportunity unto itself as a midstream business, Quicksilver shareholders will realize a real benefit from this on the upstream side as well. As you can see, the current option for third parties to AECO on Page 13 is currently about $1.56 per Mcf. Under our plan and development through the KKR facilities and into TransCanada to AECO, the price will be $0.76, which is a savings of $0.80 per Mcf to the upstream development, which in this price environment can't help but be noticed is of significant savings.

On Page 14, you'll see our compressor site and, ultimately, the CO2 plant site in development currently, and that will be building through 2014.

So that brings you up to speed on our KKR JV. I'd like to give you a little news on our Niobrara project in Colorado. On Page 16, you can see that we've accumulated over 210,000 net acres, with an average net revenue interest of 81%. That falls back on our strategy of getting in early. We have low cost in this acreage and we have a very consolidated position. Very proud of our group for putting this together. It covers 936 square miles.

To give you a recap on where we are and why we took this play. The Niobrara Lower Mancos has oil production in the area, significant oil production, actually, that has been primarily drilled as verticals with little to no stimulation. Our subsurface studies have defined a large fairway, and we've taken acreage, as I mentioned, over 930 square miles. It has a thick Niobrara section with a large oil reserve target. That is about 1,200 feet thick, and from our vertical testing across the block, we have determined that the entire section is oil charged. We think there's an oil reserve target to Quicksilver's acreage of around 500 million barrels of oil if we're able to exploit it effectively.

The estimated drill depths, and that's another attractive part of this play, are shallow. They're between 4,500 feet to 9,000 feet vertical depth. The crude is sweet. It's 40 gravity with low GOR at 2,000:1 or less. And what we are seeing and what we believed going into the play is that modern frac technology and horizontals could open a trend to areas of poor natural fracture development. The encouraging part of that is we've now drilled wells across our acreage and our first horizontal well in kind of the middle of that is showing 5x the vertical results at rates of over 500 barrels a day.

Yes, It should be noted that that's a 3,000-foot lateral. And ultimately, as you've seen in other plays, we expect the lateral length to grow quite a bit, probably double.

On Page 18, you'll see a cross-section across the acreage of 35 miles east-west that shows the average thickness of the Mancos Niobrara section with the carbonate benches within it. As I mentioned, our tests have shown that the section from top to bottom is oil charged.

On Page 19, the red outline shows basically where we have taken acreage, and within that outline, old vertical wells have recovered over 12 million barrels of oil and 5 Bcf of gas to date from wells mostly vintaged between 1960 and 1980.

You can see on the next advance that we have production decline curves with long production histories across that entire play and very significant recoveries, even though it was a low-tech style of development. We have wells that have made over 0.5 million barrels to date, and some are still producing.

From the 80 vintage wells we can access good production data on, on Page 20, we developed a composite type curve of those wells. The interesting thing of those -- the interesting feature of these and the reason we think they're inadequately stimulated is they have very, very flat declines, like 2% to 3% tail declines and ultimate recoveries of nearly 200,000 barrels per well across an 80-well sample, which is representative of the acreage block. That's what gave us confidence in the beginning to take this acreage, and it's being borne out in our vertical tests and, currently, our new horizontal tests.

On the next page, you'll see a map of our acreage and the geologic setting from a measured depth standpoint. And the green arrows show the test wells we have drilled across our block, and you can see it's pretty representative sample across the block of vertical wells. And then the western 1/3 of that, we've drilled a horizontal that, as I mentioned, is now producing over 500 barrels a day. This horizontal well had good oil shows throughout, and we had to wait up because it kept flowing oil on us while drilling.

The next topic I'll go through is our Wolfpack prospect in West Texas. We have taken acreage -- an acreage position in 4 core areas totaling 155,000 net acres on Page 24. We're surrounded by active leasing and drilling programs. This is probably the hottest -- certainly one of the hottest plays in North America and one of the 2 hottest plays in Texas. We have encouraging well results by adjacent operators. We took the acreage on good geology and actually good shows in and around our acreage. We estimate that ultimately, we'll develop over 1,000 wells on acreage we currently hold. We have plenty of term on this acreage, and we have reserve potential greater than 300 million barrels of oil equivalent.

On Page 25, it gives you a little better picture of where we are in proximity to our competitors and some of the people in the news lately. We are currently in this area of the play, the 6th largest acreage holder in the play, and we have taken 3 blocks in close proximity to BHP, Exxon Mobil, XTO, ConocoPhillips, Concho, EOG, Approach. So you can see we're in the neighborhood.

And the next 3 slides, on 26, 27 and 28, you'll see the individual acreage blocks with a little more detail on who's there. Obviously, some of the names of our friends have changed. Petrohawk is now BHP, et cetera. But you can see that it's well-located acreage, and we're pretty excited about the opportunity here. The Santa Rita is in Crockett and Upton County on Page 26.

Our Leon Valley area, which is the thickest part of the pay and play is on Page 27. The red block that shows Lone Star, I believe, is currently Concho.

On Page 28, our Balmorhea area is adjacent to BHP in the orange and Clayton Williams to the north of us.

So we are well located, but more importantly, on Page 29, the reason we think it's important is not just to be close to our friends but the fact that we have 11,000 feet of oil-charged rock through the deepest part of our area -- thickest part of our area. But in all cases, we're 4,000 to 5,000 feet thick. This is a heck of a play. And what's interesting about it is that most of the development that you see now is going horizontal. In the horizontal aspects of the play, as you can see from a very thick section of rock, you have multiple targets within that thick section to go after. So we're really not sure what the ultimate development looks like, but it's going to be many, many wells, stacked, probably. And from the early results from our competitors, it looks like it's going to be high deliveries from the Wolfcamp and Bone Springs section.

Our Leon Valley area, this is just a show map to show what we have in and around our acreage, and I won't go into the detail. But at your leisure, you can study why we think those oil shales are important.

For those of you who are not familiar with the play, this play has developed largely because people didn't realize we can combine zones the way we do today, vertically. And our horizontal technology has improved to such a degree that it makes individual zones much more accessible over a greater area.

The 3 pages, Leon Valley, Santa Rita and -- it will show you those shows that we've seen around us. In Santa Rita, for instance, you see wells that have IP-ed at 350 barrels a day immediately adjacent to our block, and we're pretty excited about the opportunity here.

On Page 32, back to this life cycle slide of Glenn's earlier, I'd like to discuss how we go about each of these plays and how we plan to fund these plays. First of all, Horn River Basin, we've now put the infrastructure plan in place to make it a very attractive upstream opportunity for a joint venture partner. We're going to be judicious about it, but we are going to seek a joint venture partner for that project, and we'll be looking at that over the next little while.

In West Texas, on the other end of the spectrum, we've just taken acreage, we have term on the acreage but we think there are more opportunities to look at out there potentially. And so we're going to bring in a partner early on that project to possibly expand the play and also to help us with the early development from a capital side. We think that will protect the capital budget for continuing to take the Horn River down the path and the Barnett down the path and, more importantly, our new Niobrara down the path and continue to grow West Texas. So we plan -- we have instituted a formal process on West Texas to bring in a partner there.

And that's really the prepared side of my remarks, but I will turn the presentation back to John for any questions you may have.

John E. Hinton

So we'll take a minute to address -- answer any questions that we -- that you may have. I do understand that there were some difficulties accessing the presentation from the webcast, so hopefully that didn't cause you too much problem in keeping up with where we were, but if you have further questions, I'll be happy to address them, either -- we'll be happy to address them either on this call or subsequently.

So with that, I'll turn it back to Debbie to accumulate any questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Anne Cameron with BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

Just thinking about your spending next year in the Barnett, is the current plan to hold production flat, or are you going to try and grow next year?

Glenn M. Darden

We'll be announcing that fairly shortly, as I said in my remarks. But it will grow slightly, but we're going to stay -- we're going to focus on trying to stay within cash flow. At these prices, on the gas side, it may be tough. But if we do spend outside those lines, we will bring in, as Toby talked about, partners for individual projects. On the Barnett side, we calculate keeping that production flat at about $150 million or so, so we may spend a little bit more than that, but we're finalizing that budget currently.

Anne Cameron - BNP Paribas, Research Division

Okay. And your marketing contracts, your NGLs in the Barnett, are most of them indexed to Conway or Mont Belvieu pricing?

Philip W. Cook

They're all indexed to Mont Belvieu.

Operator

Your next question comes from the line of Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Glenn, at the end of the presentation, you talked about joint ventures, and I heard you say that you already started the West Texas joint venture process. The other one you mentioned, was that the Niobrara?

Glenn M. Darden

That was Horn River.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

The Horn River, okay. Okay, so you're pursuing a joint venture for the E&P business, I'm assuming it's the E&P business in West Texas, and also the E&P business in Horn River. And what about the opportunities elsewhere?

Glenn M. Darden

Well, as with any asset we have in the portfolio, Joe, we will certainly look, and we don't have any formal processes going. West Texas is the only one we do. We're moving ahead at moving that direction on Horn River now that we have the midstream in place. But as for our other projects, we're moving them down the track ourselves, but we have had conversations with other players. So we're open if the economics are right.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful. And then in terms of the economics for the Horn River, at what price do you see -- do you think you need to really have an economic play there?

Glenn M. Darden

Well, one of the things that we haven't mentioned yet, we have a significant portion of our gas hedged for 2012 up there. So we have roughly 30 million a day hedged. John, what are those numbers?

John E. Hinton

So we have roughly 30 million a day hedged, a little over 580, and so let's call between 60% and 70% of our production for next year, which even in the $3.50 gas world would give us a weighted average price of something just north of $5.

Glenn M. Darden

So that's making a nice return in the Horn River, so -- but long-term economics, $4.50 gas we make better than, well, low-double-digit returns.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful. And I think, Toby, I think you mentioned about export opportunities for Horn River. Could you just describe that as best you can? And over the next several years, do you envision selling more gas into the North America market, or do you envision selling more gas to the export market? Obviously, the export market would start, at the earliest, the latter part of this decade. But over time, do you see selling more gas to the export market or into North America?

Thomas F. Darden

Joe, that's a very good question. What we analyzed from the beginning was that there are 5 -- up to 5 LNG projects under way or at least in serious stages of development on the West Coast of British Columbia. Ultimately, it is going to be an export market, but that is several years away. And so we focused our early efforts on getting our gas into the most liquid system we could, which was TransCanada, which services really all of North America. It will also service the West Coast when those LNG projects are finalized and developed. We're more working on end use for our products directly in the short run. We do see the Asian market, or the export market, I'll put it that way, as a good long-term part of the portfolio for marketing. We just decided we'd better put a shorter-term plan in place as well, so we're not just waiting on that to occur.

Glenn M. Darden

This is Glenn, Joe. I'll add one more thing. That's one of our motivations on bringing in a partner at this stage in the game in Horn River, is to assist us with the marketing side of things.

Thomas F. Darden

Yes. Joe, to add to that, a number of the long-term players and LNG players are researching Horn River as a potential opportunity for them, as you've seen in some recent announcements.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful. And then just a couple of quick ones. That Niobrara well, that first horizontal, what -- how much did that cost you?

Thomas F. Darden

Well, as usual it's our first well, and it's a test well, and we did a little more than that. But we only frac-ed about 1/2 of the 3,000-foot lateral, due to wildlife stipulations, for the winter. But I think we have around $8 million in that well.

Glenn M. Darden

Yes, we think on the development side, Joe, these will be in -- for slightly longer laterals, these will be $6.5 million-, $7 million-type wells on the development side.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

And Glenn, how long do you think the laterals will ultimately be based on that?

Glenn M. Darden

That is to be determined. But we're very encouraged with the short lateral at the rates we're getting, so -- but we'll see. As all of these plays -- I think Toby mentioned this, as all of these plays evolve, it seems like the lateral length extends. So we shall see.

Thomas F. Darden

But double the lateral length is reasonable to assume, Joe, I think.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, got you. And then lastly, in West Texas, so what's the focus going to be there for 2012? Is it going to be part Wolfcamp horizontal? Or could you just describe what you're really going to focus on?

Thomas F. Darden

What we're going to focus on is bringing in a partner there. We think this is such a big opportunity. As you can see from the thickness of the pay, it's going to require multiple stacked laterals over time to develop, and coupling that with the opportunity to expand the size of the footprint, we think a partner is our first step there.

Operator

Your next question comes from the line of Jason Gilbert with Goldman Sachs.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

I just wanted to ask about the MLP filing. Did the delay there have anything to do with the collapse in that gas strip, or is it something else?

Glenn M. Darden

No, not at all. Just ordinary course of business. The audit's taking a little bit longer than we anticipated, but no issues there. Just perhaps a little more aggressive prediction of a timeline.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay. And you also mentioned that you'd be looking to use external capital to close any potential funding for next year. Is that the JV in West Texas, or would you think about going to the capital markets for something?

Glenn M. Darden

No, more like things on the partner side.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay. And then, I guess, lastly, can you give us any details on your drilling plans for either the Niobrara or for West Texas for next year?

Glenn M. Darden

We'll be talking about that when we release the budget here fairly shortly by -- at the end of the month.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay. And then just one more quick one, if I may. You mentioned you plan to bring in a JV partner in the Horn River. I think we've been down this road before. I'm just wondering what's -- I'm sure you've talked to a lot of the parties, what's changed? Maybe it's the Nexen deal that got done or maybe if you could just give us some clarity there?

Glenn M. Darden

Yes, I would say we've had discussions. We've never had a formal process. And over the last 12 months, we've been pretty clear on saying that we wanted to get the midstream taken care of before we looked at the upstream. And as Toby laid out today, we have that very nicely put to bed with KKR. So this is the logical next step, and we're just following our strategy that we've followed over the last 20 years. So it is the next step. Gas prices are low, but it's a large supply that will come out over many, many years. So I think the more astute players will look at it a little bit longer term than the next 12 months.

Operator

Your next question comes from the line of David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Question. On the capital front, Glenn or whomever, how many wells do you plan on drilling in the Niobrara for 2012? What's the development pace look like out there?

Glenn M. Darden

Yes, we haven't announced that yet, David. We're finalizing our budget with our board now, and that will be here in the next several weeks. We'll be able to talk a little bit more about that.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. Let me ask one more along the same lines. So if I'm thinking about 2012 capital budget, you said given gas prices, you may outspend a little bit. What would be the flex area, if you will, or the marginal area where that may or may not get the last capital dollar covering [ph] these?

Glenn M. Darden

Well, let me back up for a second, David. What I would say is we're not going to full development in the Niobrara in 2012. And what we tried to outline here this morning is we're following our game plan that we follow in every basin we go to, that the next step is truly the validation-type wells. So yes, we're having good early results. We want to confirm this over a wider area on the horizontal side. So we'll drill more horizontal wells, but it's not a full development schedule. So back to your question #2, what doesn't get cash, obviously, we talked about West Texas and that project with term on leases, and we're focused on bringing in a partner first. I would say that gets limited cash. Barnett gets less cash, probably, but still grows. So that's kind of the way we're looking at that. Horn River gets cash as we're building those volumes. Horseshoe Canyon does not get cash. So that kind of stays flat, starts declining a little bit, but that's our most mature asset.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

All right. Okay, that makes sense. And then finally, have you just considered an outright sale of one of these properties rather than -- or what's the advantage of doing a JV versus just an outright sale? And can you just talk about how you think about that process?

Glenn M. Darden

Well, we're not afraid to sell, as we talked about. It's all about value, David. So if someone were to come in on one of the new projects and say, "We want to take it off your hands, and here's what we'll pay," we'll analyze that. But right now, we're at an early stage on certainly the Niobrara, and having good success, we want to see a little bit more before we would monetize that. But we think it's a great long-term project that can increase our liquids component beyond 20% right now for the company.

Operator

Your next question comes from the line of Dan Morrison with Global Hunter.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Most of my questions have been answered, but to get a little more color on your West Texas position, you said it's all term leasing. What's are you -- what's kind of your primary term look like on the bulk of the acreage there?

Glenn M. Darden

Primarily 5-year terms, Dan.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Five years?

Glenn M. Darden

5-year leases, yes.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Okay. And the horizontal versus vertical development for the Niobrara, is there potential for part of your play to just be a vertical development? Or are you really targeting areas that just lack sufficient natural fracturing?

Thomas F. Darden

Well, we originally looked at it as testing it vertically to give us resource information on the play. Vertical wells are within our economic projections, but we've been a little bit surprised early by the results in our horizontals. So it's a little early to tell how it will all be developed. I'm sure there'll be some of both. But I think well results will dictate that over time.

Glenn M. Darden

And one thing I'll add, Dan, is if we can get 5x on the vertical volumes with the horizontal well, it'll be pretty clear that we'll be developing this horizontally.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Right. And what are your vertical costs for the vertical drilling?

Thomas F. Darden

On a vertical well, it's about $3 million currently with the number of stages we have envisioned, so -- but that's an early statement. One of the things I should add that -- to Glenn's comments about 2012, as with every other basin we've been involved in, we are now in the infrastructure-planning phase of this project. Infrastructure is very important as we want to consolidate our oil and not spend so much on trucking, maximize our liquids recovery, et cetera. So a big part of 2012 will be spent planning and budgeting what we want to do going forward on the midstream side so that we maximize the net back to this development. So you'll see us doing that this year.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Is there -- what's the production composition there, gas versus oil, then?

Thomas F. Darden

It's low GOR. It is almost all oil. So there is a gas component, but it's minor and -- but what gas there is, is very rich. So you can look at the Bakken development and kind of see the same situation, except we'd like to address the gas gathering early so that we get the benefit of that as we develop the resource.

Glenn M. Darden

And the gravity of the oil is we've seen range from 38- to 40-degree gravity. So very high gravity, good, sweet crude.

Operator

Your next question comes from the line of Andrew Gazso with Enbridge.

Andrew Gazso

Just wondering if you could expand upon Quicksilver's key drivers for choosing KKR as your JV partner in the Horn River versus perhaps another midstream player in the Alberta, B.C. region?

Thomas F. Darden

Well, we went down the path with a few players, and KKR seemed to align best with our long-term plans up there. And so that's why we went that way, and we think they'll be a good partner for us over the long haul. We do see Enbridge up there as well.

Andrew Gazso

Yes, we are involved in the area. I'm just wondering what -- is there anything else that they brought to the table that perhaps another midstream partner couldn't not have brought?

Thomas F. Darden

Yes, I think it was, overall, a decision on economics.

Andrew Gazso

Fair enough. And can you tell me, you believe that Horn River to be a long-term play, and it appears to me that you've only got 10-year contracts. Is there a strategic move behind that?

Glenn M. Darden

10-year contracts on the midstream, you say?

Andrew Gazso

Yes.

Glenn M. Darden

No. Nothing strategic. 10 years was just a good, round number and solved the economic issues, and so we set the contracts to 10 years.

Operator

Your next question comes from the line of Mark Aydin with MLV & Co.

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

It's Kim Pacanovsky. You said that for the treatment facility, the "150 million a day" facility, that you can be carried by KKR in exchange for preferential payout to them. How would that change your $0.76 midstream cost to get the gas to AECO?

Thomas F. Darden

The economics and the partnership are independent of the rates charged by the partnership to the upstream. So it has no affect on the upstream whatsoever, that preferential payout. It just occurs within the partnership sharing.

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

Okay. And could you just let us know what the total capital you spent on the -- the extension to -- the TCPL extension?

Philip W. Cook

Yes. We spent about $100 million, Kim. This is Phil. And to address another piece of the first question you asked, to the extent that we were not carrying, we would then get 50% of the cash distributions that are coming out of that joint venture back to us. So effectively, it would lower our cash cost. The cost that you're seeing is the fully burdened cost with them getting preferential cash distributions, because our assumption is they will carry us in this first facility.

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

Okay, all right. And then I know that you've discussed this before, so I apologize for the question. But can you just remind us why the C-29-D well that was the 20-Bcf EUR well, what are your thoughts on why that well was so much better than the other wells? It looks like the lateral length was about the same.

Thomas F. Darden

Well, there's some variability in it, but our last 2 wells have been 15 to 20, Kim. So they're both very good wells. What we do see is that we're improving our frac techniques as we work through it, but we may have a little better section of rock in that particular wellbore. But what's interesting is across the entire basin, the results are fairly consistent, and all the operators were credible operators who drill well. So we're seeing consistent results. Ours are certainly in keeping with the best results from our competitors.

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

Okay, great. And finally, you said that the Niobrara wells, only about 1/2 of the 3,000 feet was frac-ed because of wildlife restrictions. Can you just go over what your drilling season is like up there?

Thomas F. Darden

Yes, we have access to frac basically for half the year on federal acreage. So that's what the wildlife stipulations refer to. But basically, we can operate year round and produce year round.

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

Okay. So you just ran out of time with this well?

Thomas F. Darden

Yes, and I should say most of our leases are fee leases.

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

I'm sorry, can you repeat?

Thomas F. Darden

Most of our leases are fee leases, not federal [ph] subject to that.

Operator

Your next question comes from the line of Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch, Research Division

I got in little late. Could you just repeat -- I apologize for asking, but can you just repeat what the well results well were in the Niobrara in terms of rates and whether or not they were spot 24-hour rates or longer-term rates?

Thomas F. Darden

Sure, Gil. We've had the horizontal well on production for a couple of weeks and have been gradually opening it up a little bit, and the rates have gone up. But this is over the last little while. So we're pretty comfortable that we're going to see rates of that for some period of time.

Glenn M. Darden

Gil, this is Glenn. The horizontal well has been online for a couple of weeks. As Toby said, we've gradually increased the choke size, and it's improved without any pressure declines, or very minimal pressure declines. So now it's producing at a little over 500 barrels a day, and this is 2 weeks after we brought it on. So it's not a spot rate.

Thomas F. Darden

And that's on a 20 -- 60-40 choke, so we're still choked down fairly well and showing better than 900 psi.

Gil Yang - BofA Merrill Lynch, Research Division

Can you tell at what flow rate it would be needed to be put on pump yet?

Thomas F. Darden

No. We're really early in our results, and we'll see over time how the production behaves. This is our first horizontal, and it really will develop our process going forward for how we produce these wells.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. What's the -- you talked a little bit about the GOR, et cetera. What are the realizations you expect to see in the area, net of transportation?

Philip W. Cook

Well, depending on what oil price, I would say it's probably $7, $8 under whatever NYMEX price -- oil price you're assuming.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And how should we think about the geology in terms of is this a very consistent resource play like the Barnett would be? Or is it more somewhat structural or trend-like? So how broad will the sweet spot, do you think, be based on your understanding of the geology?

Thomas F. Darden

Well, the rock is very similar across the acreage position we've taken. We have thickness that varies maybe a couple hundred feet, but in the range of 1,200 feet, probably the thinnest is 800 and the thickest, maybe a little thicker than 1,200. So we have 3 carbonates benches across the entire block. They're trackable across it. We have shot 1 3D survey that we are just beginning to evaluate, so we really haven't fully looked at that yet. But we'll get a better idea of that over time. But the consistency of the rock composition seems very similar across that entire area.

Glenn M. Darden

Gil, that our testing program tested wells at various structural positions, in lows and highs, just across the block to test that very thing that you're asking, can this be a resource play? So that was something that, while we can't definitively say absolutely yes today, we sure like the way it looks, because we've had very several results across a pretty wide band, as Toby talked about. So more work to do we here, but we're very encouraged early on.

Gil Yang - BofA Merrill Lynch, Research Division

Are there any commonalities other than the thickness in terms of are there particular fault structures or faulted zones that seem to be more productive than others, or is that not an issue?

Thomas F. Darden

The reason we like it, there's a lot of activity structurally, and so that tends to accentuate fracturing. But as I say, from a development standpoint, we're not sure what's going to make the best wells yet. We're just encouraged by good early results.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And your -- I wouldn't say lack of interest, but your willingness to wait before you monetize the Niobrara, does that suggest that with the test result you've seen so far, the risk-reward balances towards waiting, derisking yourself and capturing more value? Whereas in the Wolfcamp, it's a little bit more -- it's a little riskier, more capital-intensive with that greater risk, and so it's better to do that with other people's money if you can? Is that a fair comment?

Glenn M. Darden

I would say, Gil, we have more projects than we can afford. So we're farther along on the Niobrara. We're certainly making well, good commercial wells, and we're starting to make good oil. So we have some more work to do there. We may bring in a partner at some point. We're not against that. But we're farther along there, and we're a company that's reserve-oriented. So on West Texas, we're not discouraged there. It's just a project that we believe is very attractive to bring in a partner on, and we had to choose.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Just one last quick question. What's the cash flow of the Barnett at based on a $4 gas?

Glenn M. Darden

It's about $250 million.

Gil Yang - BofA Merrill Lynch, Research Division

At $4?

Glenn M. Darden

Yes.

Operator

Your next question comes from the line of David Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly, a couple of housekeeping items. With respect to the MLP, given the collapse that we've seen in gas prices since you first announced it, is there a possibility now that you'd move gas hedges from a corporate level over to the MLP? Or can you discuss that at all?

Glenn M. Darden

We really can't discuss it. But the MLP will be filed here in the next few weeks, so you'll be able to see what assets we are moving into it.

David W. Kistler - Simmons & Company International, Research Division

Okay. And with the filing of the MLP and your upcoming decisions on CapEx, as you move forward in that direction, should we be looking at any changes to kind of rig count thoughts that you initially had in the Barnett? If I recall correctly, you're kind of down to about 2 rigs there, and I think that previously you'd indicated you're going to keep that flattish for this next year?

Glenn M. Darden

No, I think that's a good assumption. And I really -- even though we are creating this MLP, Quicksilver on a consolidated basis will look very similar just because of the fact that we'll own a significant portion of this business.

David W. Kistler - Simmons & Company International, Research Division

Okay, that's helpful. And then one last housekeeping question. You spoke about $4.50 natural gas delivering kind of low-double-digit returns in the Horn River. Is that a S4.50 set off of Henry Hub or AECO? And if it's Henry Hub, what are your kind of your expectations for AECO differentials going forward?

Philip W. Cook

I'd say that result is based on the NYMEX price, and the AECO differential right now is running just about $0.40 and up to about $0.45 if you're looking out to kind of for about 5 to 6 years.

David W. Kistler - Simmons & Company International, Research Division

Okay. And you feel pretty comfortable with that $0.45 just, I guess, irrespective of kind of the activity that's taking place there and obviously the success you and others are having in the Horn River?

Philip W. Cook

I would say that's actually come in a little bit from where it has been. Historically, it's run about $0.50 or $0.60, so I think there's plenty of exploit capacity, and so I wouldn't expect that we're going to run much risk of a basis flow out there.

David W. Kistler - Simmons & Company International, Research Division

Okay, great. And then just one last question. This is a little bit more service-oriented. With the Niobrara and the Wolfcamp and those potentially factoring into -- well, definitely factoring into your 2012 CapEx and outlook, have you guys already gone through the process of securing rigs and some completion equipment? And if not, what's that environment looking like in both of those areas? Could that potentially lead to a period of time where services are hard to get? How are you thinking about that?

Thomas F. Darden

We've had no problems in the service area getting equipment, and so we don't see any issues there going forward.

Operator

Your next question comes from the line of Luke Gittemeier with Nokomis.

Luke Gittemeier

Most of my questions have been answered. I was a little curious, you guys talked about the Niobrara being a generally water-sensitive formation and trying a couple of different mediums on it on the vertical wells. How did you all finish the horizontal one, and kind of how's that going?

Glenn M. Darden

Well, we didn't talk about that today, and we're not going to talk about our treatments. But I do think that -- well, I will say that we have experimented a bit.

Operator

Your next question comes from the line of John Nelson with Macquarie.

John C. Nelson - Macquarie Research

Just wanted to clarify something earlier. The Niobrara well used in development could be $6.5 million to $7 million. Was that on the 3,000-foot or 6,000-foot lateral, that assumption?

Thomas F. Darden

That's probably in between that. It's about a 5,000, 4,500, I think.

Operator

Your next question comes from the line of Marshall Carver with Capital One.

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

Yes, just a couple of questions on the -- did -- were you able to test the -- you gave the rate on the horizontal well. Were you able to test the vertical wells or your own [ph] production in the Niobrara? And what did you learn from the vertical wells?

Thomas F. Darden

I think we announced in the last call that we were seeing results between 50 and 100, and I think we're in that range pretty comfortably now.

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

Okay. So no new vertical wells since then?

Thomas F. Darden

Probably a little higher in the range.

Glenn M. Darden

Yes, we've had a couple of new vertical wells, and they've actually been a little better, Marshall, in that "100 barrel a day type" range. And again, this is drilling new wells, learning a little more and experimenting with the fracture treatments, just kind of getting into the play.

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

Okay. And one other question. In terms of the timing, when do you expect to be able to announce a JV for the West Texas? Would that be in -- do you a have time frame in mind, like would that be February or March, or should we expect that in conjunction with the 2012 budget?

Glenn M. Darden

No. It won't be -- the budget is going to be announced here in the next several weeks. We have a formal process, as Toby said, under way. And is that a first half of the year? Perhaps. That's what we would envision.

Operator

Your next question comes from the line of Drew Venker with Lazard Capital.

Andrew Venker - Lazard Capital Markets LLC, Research Division

I was hoping you could talk a little bit more about your vertical Niobrara wells. And just wondering how those rates are holding up. Are they within that initial 25% decline you guys talked about?

Thomas F. Darden

We're still gathering data over time. We'll publish that at the appropriate time. It's a little bit in data-gathering mode right now. So we're comfortable that it's well within our projections for production based on those early constructive type curves.

Operator

Our last question is from the line of Anne Cameron with BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

Just one more question on the Niobrara, and I apologize if you answered this when you went through the slides. But the 80 vintage wells that you're using for the composite vertical type curve, where exactly are those wells? Are they on your acreage currently? Are they next to it? Are they concentrated in one area?

Thomas F. Darden

No, if you look at the slide presentation, Page 19, you'll see that the sample wells are across the entire block. So the reason we took the acreage where we did, we had confirmatory well data in all of the areas we took acreage. But you can see the recoveries of sample wells across that block on Page 19, and we took 80 wells across that entire area outlined in red to construct this type curve. And those are old vintage wells, I'd say '60s to '80s. That's when they were drilled and IP-ed. In fact, some of the older wells don't have the prior production history to see what their IPs were. So they were largely open-hole or, in most cases, completed 1 zone out of the 1,200 feet, maybe one of the carbonate zones out of the 1,200 feet. No one was really looking at sales back then. So we're encouraged by that.

Glenn M. Darden

So maybe just directly to your question, some of these wells are on our acreage blocks, some are -- most are offsetting or are near our acreage.

Thomas F. Darden

So the active wells, obviously, are not on our acreage block.

Anne Cameron - BNP Paribas, Research Division

And on Slide 19, is all your acreage in the red outline as well? Or is your acreage like the light brown?

Glenn M. Darden

Our acreage is inside that red outline, yes.

Operator

There are no further questions.

John E. Hinton

A replay of this call will be available on the company's website for 30 days. Thank you for your time and interest in Quicksilver this morning. This concludes our call.

Operator

Thank you. This concludes today's conference. You may now disconnect.

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