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Quicksilver Resources (NYSE:KWK)

Q2 2011 Earnings Call

August 08, 2011 11:00 am ET

Executives

Philip Cook - Chief Financial Officer and Senior Vice President

John Hinton - Vice President of Finance

Glenn Darden - Chief Executive Officer, President and Director

Analysts

Jeffrey Robertson - Barclays Capital

Brian Singer - Goldman Sachs Group Inc.

David Kistler - Simmons & Company International

Subash Chandra - Jefferies & Company, Inc.

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

Gil Yang - BofA Merrill Lynch

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

Noel Parks - Ladenburg Thalmann & Co. Inc.

Operator

Good morning. My name is Patrick, and I will be your conference operator today. At this time, I would like to welcome everyone to the second quarter 2011 earnings conference call. [Operator Instructions] I would now like to turn the call over to Vice President of Finance, John Hinton, to begin.

John 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 second 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 results might differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences are 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 Darden

Thank you, John. Quicksilver Resources reported this morning net income of $109 million or $0.61 per diluted share for the second quarter of 2011, as compared to net income of $87 million or $0.49 per diluted share in the prior-year period. Financial results were affected by a noncash gain of $19 million related to mark-to-market impact from certain natural gas hedges, a noncash loss of $31 million associated with the company's interest in BreitBurn Energy Partners, first quarter 2011 derivative fair value adjustment and a $122 million gain on the sale of BreitBurn units. Production averaged 417 million cubic feet equivalent per day for the second quarter, a 6% increase from the first quarter and up 20% over the same period last year. Natural gas liquids, and to a lesser extent, oil comprised 20% of the production stream.

Company production is ramping up and currently is in excess of 435 million cubic feet equivalent per day. And Quicksilver maintains its production guidance for the year, a growth rate of over 20% over 2010 volumes. Our team is doing an excellent job of reducing unit costs in a rising service cost environment. Our costs have declined year-over-year across the board. Phil Cook, our Chief Financial Officer, will give you the details on this after my remarks.

Quicksilver's board recently approved a $240 million increase in the company's capital budget for 2011. This added capital will accelerate infrastructure and drilling and completions in our Horn River basin project in Northeast British Colombia, and fund acreage acquisition and drilling in 2 new oil projects we're pursuing. Quicksilver is still firmly committed to living within cash inflows. We have monetized roughly half of our BreitBurn units and anticipate bringing in additional outside dollars through other asset sales and joint ventures to bridge the funding gap.

We have followed the strategy of not selling natural gas properties to buy into oil production at these commodity price levels. Instead, we redeployed proceeds for the BreitBurn sale to a higher growth in Horn River Basin and to new grassroots growth opportunities on the oil side.

By the end of the year to first half of 2012, Quicksilver will have converted its exploratory licenses on 130,000 acres in the Horn River into 10-year development leases. We will have tested a horizontal Exshaw/Bakken oil well in that Horn River play, and we will have drilled and tested wells across over 300,000 acres of highly prospective oil projects. While we would not consider that fully evaluating these new projects, we should have a clear picture of our growth path ahead.

Specifically, on the Horn River project, the company put into operation in May its 20-mile, 20-inch gathering line, which will be the backbone of a midstream system the company will be building out over the next several years. In addition, we executed an agreement with TransCanada to build a 70-mile extension of their Alberta system. Quicksilver is providing certain letters of credit, which will help backstop the building of this line, which will provide a lower-cost option to move and market our natural gas from this project. As we have previously disclosed, we have been in discussions to bring in a partner to help us build not only this system, but an overall midstream business that we project will be significantly larger than the Quicksilver Gas Services business we monetized last year. We anticipate closing a joint venture transaction in the third quarter.

There has been an increase in activity by offset operators in the Alberta Bakken play in Northwest Montana, and we continue to monitor activity and results. We have been approached by companies to possibly joint venture our 150,000-plus Montana acreage position, but at this point, we are evaluating our options. Operationally, we have slowed our drilling activity in the Fort Worth Basin in the Horseshoe Canyon coal projects in Canada. In the Barnett, we've reduced the rig count to 2 drilling rigs and are working down the company's inventory of drilled but uncompleted wells. Even with this reduced activity, Quicksilver will grow daily production over 20% compared to our 2010 numbers.

We are focused on building inventory for the future, and our new ventures team has an excellent track record of early entry into new growth areas. We strongly feel we are on track to bring on the next wave of growth for the company following the company's low-cost template.

Quicksilver is in good financial shape. We have approximately $800 million of liquidity in our $1 billion credit facility. And as I said earlier, we anticipate bringing in additional dollars to cover the shortfall between cash flow and CapEx later this year.

We have built and continued to manage this company with a long-term perspective. Quicksilver's Barnett franchise continues to produce good margins. The Horn River Basin is a huge new growth area for the company, and we have a large inventory of acreage to test on the oil side. Today, Quicksilver has the most opportunities in company history. We look forward to reporting the positive results of our efforts.

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

Philip Cook

Thank you, Glenn, and good morning. As Glenn said, production volumes were 417 million cubic feet of natural gas equivalent per day in the second quarter of 2011, up 6% from 392 million a day in the first quarter of the year.

For the current quarter and first half of 2011, total production grew by 20% and 21%, respectively, when comparing to the same periods a year ago. Our realized natural gas price for the quarter was $5.06 per Mcf, flat with the first quarter of the year. NGL realized prices were $39.38 a barrel in the second quarter, up slightly from $37.84 a barrel in the first quarter.

Realized oil prices were $96.28 a barrel in the current quarter compared to $87.05 per barrel in the first quarter. For the remainder of the year, we have 190,000 million cubic feet per day of natural gas hedged with a weighted average floor of $5.95, and 10,500 barrels per day of NGLs, with a weighted average floor of $38.84. Based on current gas and NGL prices, we would expect our realized gas prices for the year to be approximately $5, and our realized NGL prices to be around $40. Our realized gas price includes the impact of our hedging activities and is based on a NYMEX price for the rest of the year of $4.18.

Total production revenue increased from $190.3 million in the first quarter of the year to $207.7 million in the current quarter. Of this $17.4 million increase, $12.5 million is attributable to higher production and the remaining increase is due to higher realized prices. Lease operating expense on a unit basis was $0.64 per Mcf for the second quarter compared to $0.61 in the first quarter of the year. The increase is due to field compression repair expenses in Canada and some small losses on sales of inventory. These amounts exclude gathering, processing and transportation expense, which is presented separately on the face of our income statement. The gathering and processing expense, which is the cost to gather and process our gas from the well head to the tailgated facilities, was $0.86 per Mcfe for the second quarter compared to $0.89 reported for the first quarter. This decrease is primarily attributable to production mix. As production increases in the northern part of our Barnett asset, gathering and processing on a unit basis decreases as the gas in the northern Barnett is dry, and therefore, does not require liquids extraction.

Transportation expense, which is the cost to get our gas from the tailgated facilities to market, was $0.37 per Mcfe for the second quarter compared to $0.36 for the first quarter. This increase is also due in large part to production mix between the southern part of the Barnett asset and the northern part. Our transportation rates for our northern asset are higher than the south, so as production increases in the north as -- on a percentage basis, the transportation portion of our cost increases. But as I've just discussed, this increase is more than offset by the decrease in gathering and processing component of our cost structure.

Production taxes and ad valorem taxes were $0.22 per Mcfe for the current quarter compared to $0.21 per Mcfe for the first quarter of the year, virtually flat quarter to quarter. DD&A for the current quarter was $1.44 per Mcf compared to $1.49 for the first quarter, a decrease that's due to recalculation of our depletion rate related to our Canadian oil and gas properties.

G&A for the second quarter of the year was $0.42 per Mcfe compared to $0.52 in the prior quarter, approximately $0.12 and $0.14, respectively, of this expense is related to noncash stock-based competition. The decrease is primarily due to lower professional and labor fees and lower payroll taxes when compared to the first quarter.

As a brief recap, our cash expenses for LOE gathering and processing transportation, production and ad valorem taxes and recurring G&A in the second quarter were $2.38, as compared to $2.44 in the first quarter, a $0.06 or 2.5% decrease. As previously discussed, with oil and gas prices for the quarter at these cash costs, our operating cash margin is $3.09 on an unlevered basis. Our recurring cash interest expense is $1.16, it's on a levered basis. Our cash margin for the quarter is $1.93 or 35% on revenue.

In the second quarter, we recognized gains of $122 million related to the sale of 7 million BreitBurn units. In July, underwriters exercised our option to purchase 600,000 additional units. We now own approximately 13.5% of the outstanding BreitBurn common units, or roughly 8 million units.

Adjusted net income for the quarter was $11 million or $0.07 a diluted share, as compared to adjusted net income of $2.7 million or $0.02 a diluted share in the first quarter of the year. Adjustments to net income primarily relate to our equity method investment in BreitBurn and gains on BreitBurn units that were sold. The second quarter of 2011 also excludes a noncash gain of $19 million related to the mark-to-market impact of long-term derivatives. This increase in adjusted net income is primarily attributable to higher production volumes.

For the second quarter of the year, capital expenditures were approximately $199 million. Through the second quarter, our capital expenditures are $360 million. As discussed in the press release, the Board of Directors has approved an increase in the company's 2011 capital program, which are approximately $696 million. This increase is primarily associated with additional acreage and drilling in Colorado, additional acreage in West Texas and incremental drilling in midstream expenditures in Canada. Our incremental drilling in Canada is necessary to fulfill our commitments with regard to transportation on the TCPL line, which we committed to earlier this year. That line and related treatment facilities will be complete in 2014. Our acreage acquisition activity in Colorado and West Texas potentially established 2 additional oil exploration plays to our portfolio of opportunities.

We expect cash from operations for the year to be in the range of approximately $320 million to $340 million. And as I mentioned previously, we have generated additional cash of approximately $145 million so far this year from the sale of BreitBurn units and still own approximately 8 million shares. We expect to generate an additional $100 million to $150 million of cash outside of operating cash flow to supplement our capital program this year. I would also remind everyone that we are still in an earn-out period with regard to the sale of our KGS asset, and our anticipated earn-out from that agreement will be $50 million, which will be received in the first quarter of 2012.

Total debt at June 30, 2011, was approximately $2 billion, including the convertible debentures. Of this amount, our revolving credit facility has approximately $117 million drawn on a borrowing base of $1 billion. This leaves the company with significant liquidity even after consideration of outstanding letters of credit of -- and we have liquidity of $800 million on that facility.

As a reminder, the holders of our $150 million convertible debentures can put those debentures to us on November 1, 2011. As a result of this, these debentures are classified as current liabilities on our June 30 balance sheet. In addition, to the holders' ability to put these debentures to us, we also have the right to call them on November 8, thus far.

Now, I turn the call back to John for guidance and the question portion of the call.

John Hinton

Thank you, Phil. Third quarter 2011 production volume is expected to average in the range of 425 million to 430 million cubic feet equivalent per day. Average unit expenses on an Mcfe basis are expected as follows: We saw boarding expense between $0.60 and $0.64; gathering, processing and transportation between $1.24 and $1.26 per unit; production taxes between $0.21 and $0.23; general and administrative between $0.42 and $0.45; and DD&A between $1.45 and $1.47.

We'll now take any questions that there are.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from David Heikkinen from Tudor, Pickering.

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

Walk through your cash from ops on the sale of BreitBurn and kind of the capital budget. Can you give us a better breakdown though, line item-wise, of how much more capital is going into Canada, what's going into Colorado leasing and what's going into your Delaware Basin leasing and drilling?

Philip Cook

Sure, Dave, this is Phil. In Canada, we increased capital expenditures there by about $70 million, and we'll drilling additional 8 wells there this year, and build out some midstream infrastructure. In Colorado, total expenditures for the year, we have about $140 million, $50 million of that is drilling. And as we said in the press release, we'll drill between 8 and 14 wells there. And then West Texas, we'll spend about $30 million.

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

And then process or any data rooms open for joint ventures on the Alberta Bakken, Colorado or Delaware Basin?

Philip Cook

We don't have a formal process. We have, what I would call, more of a soft process. So while we don't have a data room open, we're showing a lot of data on an individual basis.

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

Okay. And then, I know I'm kind of thinking about run rate with these plays, moving parts around joint ventures, trying to answer some questions around your 2012 capital budget. Can you talk at all about how the conceptual thoughts around where you'll be in fourth quarter and then what that implies heading into 2012?

Glenn Darden

Dave, this is Glenn. It's a little bit early to talk about that. We'll probably talk about that at the next call.

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

Okay. I just expect CapEx to be up. Is there a reason to think that it wouldn't be up?

Philip Cook

It may be up, but I guess the other expectation you have is that we will continue to not outspend cash inflows. That will be our goal for 2012 as well.

Operator

Our next question comes from Dave Kistler from Simmons & Company.

David Kistler - Simmons & Company International

Looking at the 2011 production guidance that you guys put out just tail end of last year and then looking towards your result this quarter and your 3Q guidance, it implies a very significant ramp in the fourth quarter to achieve your guidance. Can you kind of walk us through that path?

Glenn Darden

Sure, and our Barnett, it's-- the growth is primarily driven by the Barnett. Our Horseshoe Canyon is about flat, and the Horn River is growing a little bit, but that's much back-end loaded at the end or into 2012. But this is just climb the ladder in the Barnett, and we've always anticipated this. We reaffirmed guidance today. It was a little light on, in the second quarter, but we're catching up very quickly in the third quarter, and fourth quarter's still on pace. And it's just timing of completions and crew availability, and when we can get in, et cetera. But we have reaffirmed guidance.

David Kistler - Simmons & Company International

Can you talk a little bit towards maybe the production mix that will be driving that guidance? And then just if we assume kind of a 3% production growth to the midpoint for Q3 guidance, then we need to be looking at kind of north of the 7% for Q4 to get to kind of low-end of the guidance. I'm just trying to understand if that could be gassy, oily, and is my math off?

Philip Cook

You're math is not off, and it's gassy and it's Barnett.

David Kistler - Simmons & Company International

Okay, perfect. And then switching over to your acreage acquisitions in the Delaware Basin, is that primarily bolt-on or is that for an area within the Delaware Basin?

Glenn Darden

Part of it is bolt-on and part of it is into other prospective areas not too far from the bolt-on acquisitions.

David Kistler - Simmons & Company International

And targeting the same kind of intervals that you were looking to target with the Delaware Basin, more of the original acreage?

Glenn Darden

No, we took that original acreage from Barnett and Woodford. And fortunately, we've had a play roll over the top of us, which is prospective for Wolfcamp and Bone Springs. And so that's what we're focused on primarily.

David Kistler - Simmons & Company International

Okay, great. And then with respect to Canada, the drilling that's going be taking place to fulfill your commitment on your 2014 transmission, do we assume that, that production is going to be drilled, not completed, drilled behind pipe? How do we think about that going forward? Maybe Phil can...

Philip Cook

We're beginning to ramp up the production side of things. So that will -- we're following it stepwise fashion. But we started with the build-out of this backbone of the midstream, our 20-inch gathering line, and we'll be building more midstream here. We've alluded to the fact that we'd want to be building a business of considerable size there. And we're starting to build volumes to fill the line.

Glenn Darden

Yes. So I think the way you should think about it, Dave, is that we will continue to drill and complete and produce wells in Canada. And the wells that we are drilling are along the areas where we have infrastructure. We have commitments to deliver volume on Spectra of 100 million a day by the time we get to 2014, and there'll be another 100 million a day coming down to TCPL. And the other thing that you should think about is that there is excess capacity currently on Spectra, so we'll probably produce more than 100 million a day through the Spectra system for a period until we get the TCPL facilities hooked up.

David Kistler - Simmons & Company International

Okay. That's helpful to understand that it's going to...

Philip Cook

We'll have to get drilling shut in, if that was your question.

David Kistler - Simmons & Company International

Yes. Now, I just wanted to make sure it was being drilled and going to sales, and you answered that so...

Glenn Darden

And one other point to add, Dave, this is Glenn, that we will have fulfilled all our requirements to convert these exploratory license to leases, as I said. And so most of this new drilling will be on -- more concentrated, closer to our gathering systems, so we can bring that gas online and sell -- and to sell it.

Operator

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

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

Looking to get a little bit more detail on, Phil, you'd mentioned the $100 million to $150 million you expect to bring in outside of cash flow this year. Is that all based on JV done in the Horn River Basin or is there anything else built into that number?

Philip Cook

Well, as Glenn said, we're working on a number of what I'll call projects in addition to having our BreitBurn units that would be available to us to sell should we decide to do that. But we've got a number of conversations with a number of different companies on several of our assets, and that we expect that we'll post at least one of those deals this year. And as I said, Mike, cash flow generation for covering of capital is probably a little along the conservative side. But we'll think we'll get at least one closed.

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

So the range of $100 million to $150 million includes the BreitBurn, the additional 8 million shares of BreitBurn?

Philip Cook

It does not. So BreitBurn would be in addition to that if we chose to sell those units.

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

Okay. And are you -- you're free to sell those now?

Philip Cook

We are. And I don't know where the screen is today, but you bet that number is somewhere between $120 million and $150 million.

Glenn Darden

But again, that's not anticipated in this -- that's not in the [indiscernible]...

Philip Cook

It's only in the shortfall, right.

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

Yes, okay. But -- so I'm trying -- I guess what I'm trying to get at is because the Horn River midstream JV get you to the low end of that $100 million range or do you need something else to get to that number?

Philip Cook

Yes, it could get there.

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

Okay. And then in the -- well, I guess, and kind of to add on David Heikkinen's question on -- I know that you said it's early to look at 2012. If you have the kind of success you're hoping for in the new oil projects, would you look to maybe slow down in the Barnett or would drilling obligations preclude you from doing that?

Glenn Darden

We don't have a lot of drilling obligations, Mike, so we could slow down. And should we have success in these oil plays, that's probably what will happen. More of the budget will rotate in that direction and perhaps a little less growth, but higher, more profitable growth.

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

Okay. And can you talk a little bit more about what's going on in the Sandwash? It looks like there's some pretty good historical production there, but maybe some dry holes as well. Is it -- do you view this as a resource play or more conventional? And if it is more conventional, can you mitigate some of that risk with 3D seismic or how are you -- just how are you viewing this play at this point?

John Hinton

Mike, we look at this as an unconventional play, a resource play. What -- the historical production has come from single intervals with virtually no stimulation by today's standards. And we're dealing with a 1,200-foot big section of resource, with several benches in it that are levers for fracture treatments. So we see the historical production as great confirmation of the continuity of the play across a big area. While they have been single wells, some of those wells have made 1.5 million barrels. So those -- we see this resource play though, attacking the entire section.

Glenn Darden

And we have drilled -- we're drilling on our fourth well, Mike. We will drill at least 4 more wells this year. We're beginning to get the completion crews out there so we'll follow the drilling with the completion operations, and we'll be talking about that as this year progresses. But we've had encouraging signs in the drilling program so far, but we need to see oil production to bear front.

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

Can you talk at all about completed well costs at this point?

Philip Cook

It's a little early on that, but we're roughly $4 million on the deeper end and $2 million-ish on the shallow end.

John Hinton

And, Mike, that's on the one-off well drilling model. Obviously, when we go into development, we'll be able to lower those costs fairly significantly, we think. What we have found in the drilling side though is that we're drilling in about half the time we budgeted. So we're encouraged about that. That certainly will lead to lower development costs as we run down the track.

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

So you're unable though, which is probably unrealistic, but at this point, you're unable to improve on the cost going forward in a, say, inflation precludes you from doing that. What kind of EUR do you need? Or what kind of EUR, I guess, are you targeting at this point?

John Hinton

We've targeted basically what the vertical wells recovered. And the vertical wells are with old technology. So we're shooting pretty low on our expectation there, and still, looking for significant returns with capital.

Philip Cook

Yes, the data shows 200,000 barrels EUR-type recoveries. So on a vertical well, that produces very, very good economic.

Operator

Next question comes from Noel Parks from Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Just kind of a few things. The last question, set of questions you were answering, those were all related to the Niobrara, I assume, right?

Glenn Darden

Yes.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Okay. I thought the discussion started out with Bone Springs and then it simply transitioned to Niobrara. I wasn't entirely sure of that, so okay, great. And well, on the top of the Niobrara, so now you're looking at 8 to 14 wells compared to the 6 you were originally talking about doing. Is that entirely just a result of the capital decision or is there some other factor sort of encouraging you to step up the pace of this year?

Glenn Darden

Yes, I would say that's a wide range, 8 to 14, but I think that we'll drill probably as many as 10, maybe on the low end, 8. And that is to try to get some tests all across the block. So we're drilling in an east-west span to try to get some answers on this relatively soon.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Okay. And, I mean, are there new challenges or questions that have arisen as a result of your first 3 wells that make you feel like you want to be a little bit more aggressive this year?

Glenn Darden

I wouldn't say challenges, no. I would say that we've had encouragement with what we've seen in the first few wells. But again, we're just beginning completion operations. So -- but we are -- everything we've seen so far has been encouraging.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Great. And far to the east in the play, we have had some news in the industry over the last couple of weeks about a couple of operators making directional changes in the orientation of their laterals and having some pretty dramatically improved results. Do -- for your part of the play since you're considerably west, do you think you could have as much sensitivity to factors like that in your results?

Glenn Darden

This initial program is vertical drilling. And we'll assess that, but we anticipate the drilling testing on the horizontal side, but it depends on the results. If we can make this a vertical play, we may have better economics.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Right. And just one more thing. In Canada, in the Horn River Basin, the Exshaw course that you have taken some time ago, has the data come back from those yet? So what are you seeing?

Glenn Darden

We're in the process of completing that well now, Noel.

Noel Parks - Ladenburg Thalmann & Co. Inc.

I was asking about the course that I thought have been taken some time back in the first well?

John Hinton

Yes, Noel, we took the sidewall course, and I think 4 of the wells we drilled in that area. And have very consistent results with over well saturation, pretty much throughout the section. So we're encouraged by those results. But again, in these plays, we look at the production results more than we do the geologic indicators. However, we've had great geologic indicators in both the Exshaw in the Horn River and the Sandwash in the Niobrara.

Operator

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

Gil Yang - BofA Merrill Lynch

Can you just remind me how many rigs or how many wells you need to put on a year to maintain flat production on a sequential basis in Barnett?

Glenn Darden

John, you want to answer?

John Hinton

So this year, we have the advantage of completing the uncompleted well inventory. So our -- we're able to increase production with 2 rigs. If you're looking at 2012, that's -- and once we've completed that drill bit on complete inventory, that should be closer to 3 or 4.

Glenn Darden

That's on the growth side, but spending roughly $200 million, $250 million keeps production flat. That's kind of maintenance cap for the entire company.

Gil Yang - BofA Merrill Lynch

Okay. But mostly are going into the Barnett numbers?

Glenn Darden

Yes, at this point. But as you've heard on this call, we're ramping up volumes in Horn River, so that would play into the 2012 mix. And we haven't factored any new growth from these oil projects we're testing, so that could shift the capital.

Gil Yang - BofA Merrill Lynch

Right, okay. You typically seem to be pretty opportunity-rich and a little bit more stretched on the balance sheet side when you're talking about some joint ventures. Can you talk about maybe what's different about the conversations you're having this round versus the kind of conversations you were having a couple of years ago?

Glenn Darden

Well, I would say that it's all about value, Gil, and about following our strategy. What we've done in the Horn River is we've advanced the ball down the field on the midstream side, and that will become more apparent as we talk about our future plans on that build-out. But we've moved these things along. I think that having that infrastructure in place makes more sense to talk about upstream joint venture after that infrastructure's in place. And so, we've been approached by several parties on the upstream side of Horn River. I would say that those talks are certainly behind the progress of the midstream. And then in these other areas, we've had a lot of inbound overtures. So we're kind of evaluating on a case-by-case standpoint, how is it different.

John Hinton

Gil, I can give you a little color on that. How it's different is that we've been talking to parties now for about 2 years on Horn River, and as the Niobrara and West Texas have evolved for about a year. And what's interesting, the parties we were talking to, 2 years ago have returned and we're having a second round of discussions on a more serious note. I would say several parties. On the midstream JV, that's moving on along, we think, very well. And as Glenn mentioned, that JV will set the foundation under Horn River for significant ramp-up on the upstream side, which makes it a better JV for an upstream partner. But as important is the size of the midstream opportunity there, which is a multiple of what we did with KGS, which, as you probably follow, is pretty successful financial to, for Quicksilver.

Philip Cook

Yes, and I'd just add one thing that I think that the opportunities for third parties today seem more real. We've always seen them as being very real and very touchable, but I think today, particularly in the Horn River, the bid in the ask is much closer than it was 2 years ago.

Gil Yang - BofA Merrill Lynch

And presumably they moved up closer to your number?

Philip Cook

Yes.

Operator

Our next question comes from Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

I'm wondering if you could just add a little more color on the well performance that you're currently seeing from the 4 Horn River Basin wells now on line.

John Hinton

From the most recent 2, they are significantly better than our first 2. We are -- our tight curve, which was, we've been using now for 4 or 5 years has moved up, which is encouraging. The economics look good in a relatively low gas price environment, and we're trying to improve those economics through lower-cost transportation out of the basin, which this midstream JV would help us achieve and the build-out of infrastructure by others in the basin is going to help us achieve. So -- but the wells themselves are getting better with time. We've completed 4 wells, but there have been well over 100, probably closer to 200 wells drilled in the basin now. And the statistical repeatability of results is pretty comforting. You see our wells performing as well as the best wells in [indiscernible], so we're pretty encouraged about the overall results.

Philip Cook

These numbers are between 10 and 15 Bcf per well, what we're looking at. Our early wells are right in the kind of 10 Bcf range, our later wells are higher. And it's as we've drilled north, our section has gotten thicker, which has been encouraging. So we're very charged about the Horn River Basin.

Brian Singer - Goldman Sachs Group Inc.

And what first year decline rate do you have that's built-in? And is that kind of what you're seeing as well?

Glenn Darden

Brian, we started with a tight curve that emulated the Barnett tight curve. And we're seeing flatter, earlier flattening of the curve. So we're encouraged by the results. In fact, some of the earlier projected declines from the initial decline rates flattened more quickly and indicated we're going to get higher, recoverable reserves.

Brian Singer - Goldman Sachs Group Inc.

Right. Okay, great. And then can you give a little more insight into your playbook in West Texas, what you expect to gain from the recompletions and then, how and when you see next steps?

Philip Cook

Our recompletions, those are wells that we drilled for the deeper Barnett and Woodford sections, and the Wolfcamp and Bone Springs are above them in the section, and therefore, up the hole and well force. So it gave us a couple of inexpensive tries at the play. It probably won't be the last of our testing. We'll drill probably several wells over the next year to further validate the play. But the early results are pretty encouraging from our competitors, and we're very excited about the lanyette [ph] that's occurred over kind of the dormant West Texas asset.

Glenn Darden

And I would add that we have increased our acreage position closer to the actual Wolfcamp, Bone Springs play as well. So this -- the whole play is moving our direction in the Delaware Basin, and we've not only added some acreage around the legacy positions, but added new acreage much closer to the existing new production.

Brian Singer - Goldman Sachs Group Inc.

Got it. I'm assuming that you like what you see from the results from addition on the recompletions. When would you think, time-wise, you would consider spudding new wells?

John Hinton

I think independent of that, we will consider spudding new wells probably early in 2012.

Glenn Darden

We'll be into 2012, right.

Operator

The next question is from Eli Kantor from Jefferies & Company.

Subash Chandra - Jefferies & Company, Inc.

It's Subash Chandra. Think, looking ahead in 2012, it's really not as far you think. But I'm thinking aloud here. If you could sort of edit my thoughts on the growth from the Barnett probably slows. I think you've suggested that as the backlog has worked off this year and you commit to its program. But then in 2012, I guess, you talked about more liquids growth. So does that mean that we have to have proof of concept in these liquids plays within the next 6 months and that working itself into a development program for 2012? Or is there going to be some sort of significant Horn River contribution in 2012?

Glenn Darden

There will be more of a Horn River contribution, and we're going to evaluate these projects but we're not in a hurry to do that. I mean, we're going to do it efficiently as we can. But a couple of these areas may be developed. Maybe we anticipate being part of that 2012 program. But it's just a little bit early to give you our 2012 budget when we have so much out there on the testing side right now.

Subash Chandra - Jefferies & Company, Inc.

Right, okay. Yes, I thought I heard you say that you'd have a lower growth but more liquids, so better revenues.

Glenn Darden

That could be a path we take based on success in these -- in those areas.

Subash Chandra - Jefferies & Company, Inc.

Okay. And as far as -- in a JV process, would you expect some sort of upfront cash or do you see more of an avoided CapEx deal?

Glenn Darden

A combination of both.

Operator

Your next question comes from Jeff Robertson from Barclays Capital.

Jeffrey Robertson - Barclays Capital

Glenn, can you talk at all at this point about any further plans for the Exshaw beyond testing the current well?

Glenn Darden

I think that's where we are right now, Jeff. We're looking at that. We've got a completion rig on there right now, and we'd like to see what we have in the first one. But does that mean that we're not going to test other ones? No. At this point, we just -- we're concentrated on this one well to start with.

Jeffrey Robertson - Barclays Capital

Would you expect or could you drill another well this winter given the timeline you have from information from this first well or would you wait until the following drilling season?

John Hinton

Jeff, I think we'd wait for production data regardless of how good it looks in the beginning. We'd like to see the way it produces overtime. So that's not atypical of all of our plays. As Glenn mentioned, we're going to be methodical about the way we test these plays, just as we have been throughout our history. And even in the oil plays in Niobrara, we are going -- we've only drilled several wells. We're going to complete those wells kind of in echelon. And then we're going to watch them a little bit before we rush out and hurry the development. The other component of that is in the Niobrara particularly, there is a midstream opportunity there. And we'll probably -- if we have the fortune, we have the opportunity to build up that infrastructure so that we're developing into infrastructure rather than rushing the development without infrastructure.

Jeffrey Robertson - Barclays Capital

And then lastly, I can't remember if you had mentioned this before, but with the 45 wells in the Barnett that would be waiting on completion at the end of the year, can you talk about how those are distributed across your 3 core areas?

Philip Cook

Yes. They're fairly, evenly distributed, probably, certainly, North and South, Jeff. But on a liquid side, I think we'd have, over time, we'll have more locations in the south with the liquids to drill and complete. But that inventory of uncompleted wells is spread fairly, evenly across.

Operator

[Operator Instructions] Your next question is a follow-up from David Heikkinen from Tudor, Pickering.

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

Get one more question in myself. When I kind of think about give or take, private transaction or discussion, given the share price today, is there any chance that management or the board may reengage in a take private discussion?

Glenn Darden

I don't think so, David.

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

Okay. And so as you think about the path of the next 6 months, then really, the biggest transaction probably is the Horn River midstream deal. And then there's a possibility before year-end that you do another joint venture?

Philip Cook

Yes, there is.

Operator

At this time, there are no further questions in the queue. I will now like to turn it back over to management for any closing remarks.

John Hinton

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

Operator

This concludes today's conference call. You may disconnect at this time.

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