Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Quicksilver Resources (NYSE:KWK)

Q4 2011 Earnings Call

February 27, 2012 11:00 am ET

Executives

John E. Hinton - Vice President of Finance

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

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

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

Analysts

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

Anne Cameron - BNP Paribas, Research Division

Jason Gilbert - Goldman Sachs Group Inc., Research Division

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

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

Gil Yang - BofA Merrill Lynch, Research Division

David Snow

Dan McSpirit - BMO Capital Markets U.S.

John C. Nelson - Macquarie Research

Maryana Kushnir

Subash Chandra - Jefferies & Company, Inc., Research Division

Alex Heidbreder

Steven Karpel

Eli Kantor - Jefferies & Company, Inc., Research Division

Kathryn O'Connor

Operator

Good morning. My name is Lacey, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter 2011 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to Mr. John Hinton, Vice President of Finance and Investor Relations. Please go ahead, sir.

John E. Hinton

Thank you, Lacey, and good morning. Joining me today are Toby Darden, Chairman; Glenn Darden, President and Chief Executive Officer; and Phil Cook, Executive Vice President and Chief Financial Officer. This morning, the company issued a press release detailing Quicksilver's results for the fourth 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 may differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed in the company's filings with the SEC.

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

I will now turn the call over to Glenn Darden to review our financial and operating activities in detail.

Glenn M. Darden

Thanks, John. Good morning. Quicksilver Resources earned $49 million or $0.28 per diluted share in the fourth quarter of 2011. Full year 2011 net income was $115 million or $0.67 per diluted share. This compares to $1.82 and $2.52 per diluted share for the respective periods in 2011. Each year was impacted by special items: in 2011, the sale of the BreitBurn units; and in 2010, the sale of our interest in Quicksilver Gas Services. Phil Cook, our CFO, will break this out in detail in his remarks.

Quicksilver grew production 16% in 2011 versus 2010 volumes and replaced 165% of production. As drilling slowed down due to lower gas prices, we allocated capital to 2 grassroots oil projects: adding acreage to our Colorado position, which I'll talk about in a moment; and building new acreage bases in the Permian and Delaware Basins. These areas look very prospective for long-term growth.

In Colorado, where we have assembled 210,000 acres in what we now have established the oil window of the Niobrara, our initial drilling results have looked better with additional production run time. We have drilled and completed 6 wells testing the Niobrara, the last of which is a horizontal well. All of these wells are producing oil. We completed the first 3 vertical wells with oil fracs and the second 3 wells, 2 vertical and the horizontal, with a different style gas frac.

This technique has shown significantly better results. The horizontal well, which frac-ed only about 1,500 feet of a 4,500-foot lateral, has a 45-day production average of 230 barrels of oil equivalent per day, primarily oil. The 2 vertical wells completed in this manner are steady producers, with the best well averaging 120 barrels of oil equivalent per day, again mostly oil, over the same 45-day period.

Our initial drilling covered an area approximately 30 miles in an east-west direction. We begin the drilling -- we begin drilling again next month with a series of horizontal and vertical wells. This is a bit different than we had announced, but with our vertical success, we will drill a few more vertical wells to test this as well. While we anticipate mostly oil from this project, the company will also begin work on an initial gas gathering system to capture the rich gas and NGL stream.

Based on completed well costs of approximately $3.5 million per vertical well and approximately $6 million for a horizontal completed well, we believe the economics will be compelling, in excess of 40% rates of return, and we have lots of room to run. We also believe these costs will go down as we move into development. Our land team is working on multiple drilling permits currently to be prepared to accelerate this project.

In West Texas, Quicksilver has secured approximately 105,000 net acres in 3 blocks. These areas have lots of activity around them and we will begin drilling next month with a target of having several wells completed by the summer. Quicksilver's objectives are the Bone Springs and Wolfcamp formations, and we will test each of the 3 acreage blocks.

As we previously announced, we have a sales process in place to bring in a partner to accelerate this project and that process is well underway. One of the highlights of 2011 came at the end of the year when Quicksilver closed a midstream joint venture with KKR in the Horn River Basin. This venture will lower our costs to get this large gas supply to market.

This is a long-term project with high-quality reservoir and production characteristics. Our first 2 wells, with relatively short laterals, have produced over 3 Bcf per well in less than 2 years and subsequent wells that we've drilled on our block of 130,000 net acres look considerably better. It is a world-class gas basin and we have begun discussions with potential partners to help us maximize for development. Our team is also working hard on connecting this gas to downstream markets. The company will shortly bring online its first multi-well production pad and this gas is well hedged for the next couple of years.

With Quicksilver's reduced capital budget in 2012, we have downshifted in the Barnett project and we'll run one rig, mostly in the liquids-rich area of the Southern Barnett. In this southern area, at $2.50 per Mcf gas, we net over $7 per Mcf equivalent with the rich liquids. Quicksilver has almost 1 trillion cubic feet of gas in the proved undeveloped and probable reserve categories in this Barnett, so we'll have many years of development in the area as gas prices improve.

Our reserves at 2011 year end stood at approximately 2.8 trillion cubic feet of gas. The drilling slowdown of the last couple of years affected the 5-year time frame required in the SEC to develop existing PUDs. We also lost approximately 55 Bcf for economic reasons. But we have the leases held for the most part and we'll drill those locations as prices improve. Most of our activity in the Barnett in 2011 converted PUDs to proved producing and reduced our drilled but uncompleted well inventory from 120 wells down to 50 wells by year end 2011.

This company has grown reserves and production over the last 5 years at 12% and 14% compounded annual growth rates, respectively. And we have done that at an average finding and development and acquisition cost of $1.88 per Mcf equivalent with organic F&D at $1.63 per Mcf equivalent. Most of this has come from the Barnett development. Quicksilver's current reserve base is almost 70% proved developed, with 77% being natural gas, 22% from NGLs and 1% from oil. We are poised to significantly increase our oil production in 2012 and beyond. So we start the year with 23% liquids and we'll add more oil to the mix as we progress.

Our goals are clear for 2012. It's a year of execution in advancing these new projects to development and in paying down debt. As we have previously discussed, we will utilize proceeds from the sale of equity in a subsidiary, the newly created MLP, as a primary tool to do this. We will also work to secure partners for both the Horn River project and West Texas to put both of these projects on sound financial footing. We firmly believe this is a time of tremendous opportunity for Quicksilver and that the company will be in a much stronger position at the end of this year.

And with that, I'll turn the call over to Phil Cook. Phil?

Philip W. Cook

Thank you, Glenn, and good morning. Net income for the quarter was $49 million or $0.28 per diluted share, compared to net income of $332 million or $1.82 per diluted share in the prior year period. For the full year 2011, net income was $115 million or $0.67 per share, compared to net income of $449 million or $2.52 per share in 2010.

Later this week, we'll file a 12b-25 extension with the SEC, which provides for a 2-week extension to file our 10-K. This will allow our auditors additional time to complete their audit work. Because of this filing, our reported numbers for the quarter and the full year are preliminary. While these reported amounts may change due to additional audit procedures, we do not expect that our adjusted net income amounts will change and any change in our reported amounts, we expect, would be in the tax area.

Adjusted net income for the fourth quarter was essentially breakeven compared to adjusted net income of $30 million or $0.17 per diluted share in the third quarter. In addition to the adjustments we routinely make related to equity method income for BreitBurn and for BreitBurn sales, we also had one other adjustment booked in the fourth quarter. We recorded a noncash impairment of $52 million to write down the value of certain midstream assets in Texas that were retained after the sale to Crestwood of the rest of our midstream assets.

Adjusted net income for the third quarter of 2011 excluded a noncash gain of $30 million for the mark-to-market impact of long-term derivatives, also an $11.5 million charge to settle legal claims, as well as costs related to strategic transactions and our normal BreitBurn adjustments.

Adjusted net income for the full year 2011 was $20 million or $0.12 per diluted share, compared to $120 million or $0.69 per diluted share in the prior year. A full schedule of our adjusted net income is included in the attached tables of the press release we issued this morning.

Production volumes were 412 million cubic feet of natural gas equivalent per day in the fourth quarter of this year, down approximately 3% from the third quarter and up 6% from the prior year quarter. Third quarter production was favorably impacted by timing of activity. We completed and connected 44 wells versus 17 in the fourth quarter, so the third quarter captured more of the flush production from new wells. For the full year 2011, total production averaged a record 412 million cubic feet of natural gas equivalent per day, which is 16% higher than 2010. The growth was driven primarily from our activities in the Barnett Shale, as well as the Horn River.

Average realized natural gas price for the quarter was $4.73 per Mcf and $4.95 for the full year, down $0.22 and $1.91 from the third quarter and the prior year, respectively. Average NGL realized prices were $38.50 per barrel in the fourth quarter, which were flat to the previous quarter; and $38.63 for the full year compared to $31.46 per barrel in 2010, a 23% increase in NGL pricing. On an equivalent basis, we averaged $5.12 per Mcfe for the quarter and $5.32 for the year.

To update you on our hedge position for 2012, we're in a strong position this year to deliver solid returns despite low gas prices. As previously announced, we restructured our long-dated swaps to bring the value of the 2016 to 2021 period forward into the 2012 to 2015 time frame. Additionally, we entered into several new long-dated hedges, covering years out to 2021. We now have approximately 65% of our expected remaining 2012 equivalent production hedged at a weighted average price of $6.02 per Mcfe.

Our hedge portfolio is now as follows: We have 230 million cubic feet per day hedged for the remainder of 2012 at a weighted average floor price of $5.75 and 7,000 barrels a day of NGL swaps at a weighted average price of $45.01. Based on current commodity prices, we would expect our first quarter cash average realized gas price to be about $4.55 per Mcf and our average NGL price to be around $43.50. These prices include the cash impact of hedges currently in place. For a full listing of our hedge portfolio, you can visit our Investor Relations page on our website.

Total production revenue was $194 million or $14 million less than the third quarter, primarily caused by lower average realized prices. Total production revenue for the year was $800 million or $56 million less than the prior year, due again to lower realized natural gas prices, partially offset by higher natural gas production and 30% higher NGL realized pricing.

Lease operating expenses on a unit basis were $0.78 per Mcfe for the fourth quarter compared to $0.70 per Mcfe for the third quarter. The increase, compared to the third quarter, is due to higher gas lift expenses, higher salt-water volumes and compression overhaul spending in the fourth quarter. For the full year 2011, lease operating expense was $0.68 per Mcfe compared to $0.65 per Mcfe in the prior year. Costs are higher in 2011 due to increased salt-water volumes and rates, gas lift expenses and higher work-over activity and compression overhauls. These amounts exclude gathering, processing and transportation expense, which is presented separately on the face of our income statement.

Gathering and processing expense, which is the cost to gather and process our gas from the wellhead to the tailgate of facilities, was $0.89 per Mcfe for the fourth quarter, which was flat to the third quarter. Transportation expense, which as you know is the cost to get our gas from the tailgate of facilities to the market, was $0.38 per Mcfe in the fourth quarter compared to $0.41 reported for the third quarter of the year. This decrease is due to the mix of production in our Barnett area, as well as lower transportation and fuel cost. Total gathering, processing and transportation expense in 2011 was $1.27 per Mcfe.

Based on guidance provided in our press release today, we anticipate this expense will decline in 2012 as production from Barnett shifts to the high-liquids southern part of the field where gathering, processing and transportation costs are lower compared to other operating areas. As well, higher expected production in the Horn River will drive down unit costs as we bring on newly completed wells.

Production and ad valorem taxes were $0.14 per Mcfe for the current quarter compared to $0.20 per Mcfe for the third quarter of the year. The decline is caused by lower average realized prices in the fourth quarter. For the full year, taxes were $0.19 on a unit basis compared to $0.26 in the prior year. The decline is attributable to reduction of $3.6 million in ad valorem tax assessments related to the sale of our KGS asset and lower assessments as a function of lower commodity prices.

DD&A for the fourth quarter was $1.55 per Mcfe compared to $1.47 for the third quarter. The increase is primarily the U.S. depletion rate due to a 7% decrease in reserves and the impact of our 2011 capital program. For the full year, DD&A was $1.49 per Mcfe compared to $1.56 in the prior year. This reduction is primarily related to the sale of KGS and the reduction in depreciation on those assets.

G&A expense for the fourth quarter was $0.47 per Mcfe compared to $0.70 in the third quarter. Noncash stock compensation is $0.13 of that $0.47 per Mcfe in the fourth quarter and $0.11 in the third quarter. Excluding special items, fourth quarter recurring G&A is $0.46 per Mcfe compared to $0.42 in the third quarter. For the full year, G&A was $0.53 per unit compared to $0.62 in the prior year.

As a brief recap, unit cash expenses for LOE; gathering, processing and transportation; production and ad valorem taxes; and recurring G&A in the first -- in the fourth quarter were $2.46 compared to $2.77 in the third quarter and $2.43 for the full year. At averaged realized oil and gas prices for the quarter, cash margin was $2.66 on an unlevered basis. On a levered basis, recurring cash interest expense is $1.13; therefore, cash margin after interest is $1.53 or 30% on revenue.

In the fourth quarter, we recognized a gain of $85 million on the sale of our remaining 8 million units of BreitBurn. For the full year, we received cash proceeds of $273 million from the sale of these units and recorded an income statement gain of $218 million. Going forward, we do not expect to recognize any amounts attributable to BreitBurn operations in our income statement and also do not expect to receive any further cash distributions from them.

Capital expenditures were $169 million in the fourth quarter and $694 million for the full year, which was substantially funded with internal cash inflows, proceeds from our Horn River midstream partnership and BreitBurn sales. As previously announced, we expect to spend approximately $370 million in 2012 on drilling and completion activities.

Operating cash flow for 2011 was $253 million, or $285 million excluding changes in working capital. The company generated approximately $650 million in cash flow in 2011. And excluding working capital, that number was $682 million through operations, the monetization of our BreitBurn shares and the Fortune Creek transaction. We continue to pursue joint ventures in our West Texas and Horn River upstream operations to minimize or eliminate any gap between capital and cash from operations in 2012. We are still in an earn-out period for all of 2012 with regard to the sale of our KGS asset. Our earn out based on 2011 delivered volumes is $41 million out of a possible $50 million, which was received this month.

Total debt at December 31, 2011, was approximately $1.9 billion. At year end, we have 73% of our $1.1-billion credit facility or $800 million of availability. During the year, we retired approximately $48 million of high-yield public debt and $150 million of convertible bonds, thus lowering our weighted average cost of capital by more than 50 basis points.

We plan to recapitalize books over this year by raising cash to pay down as much as $500 million of public debt. Any cash shortfalls resulting from our development and exploratory capital programs we expect will be funded through joint venture proceeds. We fully expect to fund capital this year with cash inflows and, assuming full execution of our plans, our projected debt-to-capital ratio at year end should be around 50%. I'll now turn the call back to John for first quarter guidance and for the question portion of the call.

John E. Hinton

Thank you, Phil. First quarter 2012 production volumes are expected to be between 375 and 385 MMcfe per day. Average unit expenses on an Mcfe basis are expected as follows: LOE between $0.68 and $0.72; gathering, processing and transportation, $1.24 to $1.28; production taxes, $0.23 to $0.25; G&A, between $0.53 and $0.57; depletion, depreciation and accretion, $1.49 to $1.53.

And with that, operator, we'll open the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Noel Parks with Ladenburg Thalmann.

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

Just a couple of things. In the Niobrara, you gave the updated production figure, 230 a day for the horizontal after 45 days. Can you talk about how well that conformed to sort of to your predrill model and how much variance you see in terms of how different acreage has performed on the vertical wells, given the metrics you were using to determine which acreage you wanted to purchase?

Glenn M. Darden

I would say -- Noel, this is Glenn. I would say that the vertical well has exceeded our initial model. The horizontal well is a bit inconclusive because we've only frac-ed 1/3 of that lateral length. So we think it's doing very well and not far off our model with 1/3 of that lateral frac-ed. So we think both of those wells are performing very nicely.

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

Great. And you gave an idea for the returns you might see. I think you said 40% ROR on the Niobraras. Can you give a sense of what price take you're assuming in that calculation?

Glenn M. Darden

I think that was $85 oil.

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

$85. Okay, great. And also on the Niobrara, you talked about working on a number of permits for upcoming drilling. How's the permitting process been going out there?

Glenn M. Darden

It's not as easy as Barnett, but it's going pretty well. Toby, you want to add?

Thomas F. Darden

Sure. Noel, it's very straightforward, at least in the Western part of our acreage. We are progressing fairly routinely with permits. So we don't see any delays in the areas we want to develop in the short run.

Glenn M. Darden

It's just a big land position, Noel. So -- I mean, we're clearing out -- clearing locations and we've tested across 30 miles east to west. So it's -- we've got a lot of activity on the land side up there now in anticipation of going to development.

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

Okay. And as far as sort of maybe a best-case scenario going forward, do you have a sense of how your oil production might ramp up, assuming you have good results in the Niobrara and are drilling at roughly the pace that would keep you close to cash flow? I mean, I'm assuming 2009, it'd be -- I'm sorry, 2012 will be hard to move the needle. But say, by looking to end of 2013 or something like that, do you think your oil production would be significant enough to really impact revenue at that point?

Glenn M. Darden

We believe so in '13, yes.

Operator

Your next question comes from Anne Cameron with BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

Could we just have an update on the status of where you are with your Delaware basin, Permian Basin sale? Do you have data room open? Or are you just receiving reverse inquiries? And I guess, the same question goes for the Horn River.

Glenn M. Darden

I can give an update of the joint venture discussions. We're fully committed to closing joint ventures on both Horn River and West Texas in 2012. We've engaged advisors with Jefferies in West Texas and Crédit Suisse in Horn River. Data rooms are open on both projects and marketing efforts are underway for both. And we've already received multiple indications of interests on both properties. So this is moving ahead as scheduled and we're going to push them to the finish line this year.

Anne Cameron - BNP Paribas, Research Division

Okay. And, I think, last time you've spoken publicly about it, you sort of guessed at the third quarter as a possible transaction. Is that still on the cards?

Glenn M. Darden

Well, that they will move at different paces but -- and they'll close when they close, but we are -- certainly think that's within reason.

Anne Cameron - BNP Paribas, Research Division

Okay. And then just on your guidance, it looks like productions go down in the first quarter and has kind of uptick in the second and third quarter. What asset is driving? Is that completions in the Horn River?

Glenn M. Darden

Yes, we have large Horn River volumes coming up. We'll have more liquids coming on and drilling in Barnett as the year progresses, but we slowed significantly down toward the end of the year, and in this first quarter, we'll be ramping up again more on the liquids side in the Barnett. So primarily Horn River, we get a nice chunk of production coming in the second quarter and third quarter. So we still project roughly flat volumes with a bit more uptick, we believe, on the oil side.

Anne Cameron - BNP Paribas, Research Division

Okay. And then that Niobrara well, the "500 barrel a day" well, do you have a 30-day rate on that at this point -- the horizontal?

Glenn M. Darden

Yes, we have a 45-day rate, and it's 230 barrels of oil equivalent, primarily oil.

Operator

Your next question comes from Jason Gilbert with Goldman Sachs.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

A couple more credit-y questions. Are you guys facing an April borrowing base redetermination?

Philip W. Cook

This is Phil Cook. We will have a redetermination. We're not expecting to have any issues with regard to that.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Did you have any sense for what kind price deck the banks are using right now?

Philip W. Cook

Yes. They have -- they're using about a $2.50 gas price for 2012 and it ramps up $0.50 increments from there.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay. And then just a follow-up. Can you just remind us quickly what the leverage covenant on the bank facility is? I think you're relatively close on that one.

Philip W. Cook

We're in good shape on bank as well as bond covenants.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay. At what gas price should we start worrying about covenant headroom?

Philip W. Cook

I guess -- I'm not worried about meeting our covenants for 2012. We've projected it out based on the strip and including our hedges for '12, '13 looks fine as well.

Operator

You next question comes from David Heikkinen with Tudor, Pickering, Holt.

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

Just thinking about the Sandwash Basin, can you walk through how much of your acreage or how much of your land would require federal permits versus not federal permits, just around the permitting process, thoughts?

Glenn M. Darden

Yes, David, I think we're roughly 70% fee and the remaining 30% is split between state and federal.

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

Okay. And so then as you go through the year and get kind of primed into 2013, how many permits would you want to have in hand going into 2013?

Glenn M. Darden

It depends on our budget, of course, but we'll want to clear out quite a few.

Thomas F. Darden

And actually, David, we are clearing a fairly significant number of locations as we speak. The wells that Glenn mentioned are only a fraction of what we are clearing for, for future development.

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

Okay. So could you have 2 or 3x the backlog of kind of this -- I'm trying to gauge, obviously, through permitting pace going into '13, because this play could become pretty significant to you all.

Glenn M. Darden

Yes, we think so. I mean, we're clearing a lot of locations. We've got work on 70 or so permits right now, David. That hasn't -- we're going to be drilling 70 wells in 2013 but we want to be prepared...

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

No, not capital limited, but just given your level of your excitement. And then as you think about trough-ing production in the first quarter, you kind of talked about essentially flat. Putting that in numerical terms, is that kind of plus or minus 5% or plus or minus 2%? Just trying to bread box essentially flat as far as 2012 volumes.

Glenn M. Darden

Plus or minus 5%. But I would say, we are -- our target is to be flat or a little above.

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

Okay. And then on just fourth quarter to first quarter, this is detailed on the G&A expenses, just the dollar per Mcfe range, I mean, kind of thinking about that, the range went up. Is that just because volumes went down? So just think about it as kind of a steady dollar spend rate through the year on G&A, more so than a volume?

Philip W. Cook

Yes. Yes, volumes down and costs up slightly just for cost of living increases for people.

Operator

Your next question comes from Dan Morrison with Global Hunter Securities.

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

Couple of quick questions on the JVs. It sounded like from your prepared comments you mentioned starting, moving a rig in the Permian next month. Is that March or April?

Glenn M. Darden

Yes, March.

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

Okay. Where -- I'd actually -- as it stupid as that sounds, I didn't even know what the calendar looks like. But the -- we're at the end of the month. Where will that -- where will you put that rig initially?

Glenn M. Darden

We'll be testing all 3 blocks basically. We'll be drilling with an average of one rig. We'll actually use multiple rigs to cover the territory, but it'll average one-rig utilization.

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

Okay. And any idea on what your initial targets are horizontal, vertical in the 3 different blocks?

Thomas F. Darden

Well, as we do in most of our plays, we look at the vertical section first and then select our horizontal intervals for development. Each of the test wells will be configured in such a way to allow us to go horizontal should we choose to do so after testing the vertical section.

Glenn M. Darden

I will add to that, Dan -- this is Glenn -- that offset operations can affect the way we do this. So this activity is moving close to our lease positions in all of these areas. So we may get some outside help with the engineering.

Thomas F. Darden

Yes. In fact, we are getting some outside help with offset production.

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

Great. And in the marketing of the JVs, in particular for the Permian, do you have a structured kind of -- a target structure defined? Or are you just sort of putting the assets out there and seeing what comes in?

Glenn M. Darden

We have kind of a baseline assessment for each JV. In the West Texas, it'll be more of a rolling process with opportunity to take an offer if we like what we see. And in Horn River, it's more of a structured process but still has that option.

Philip W. Cook

But cash up front, carry in drilling and what our target is to secure good financial footing for both of these projects for the longer term and still have a meaningful position.

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

You have a -- I'm sure you do, but would you share the dollar figure you have in mind for either or both?

Philip W. Cook

We haven't stated that in the data room either.

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

Okay. And final question. The Permian, since it's kind of in 3 distinct play areas, is that available to be split up to go 3 ways? Or trying to just get it en masse with one partner?

Glenn M. Darden

We prefer one partner, but we certainly are looking at all of our options on that.

Operator

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

Gil Yang - BofA Merrill Lynch, Research Division

I think, Phil, you mentioned the flush production. Would you just review what you said there, it came online from a bunch of wells in the fourth quarter.

Philip W. Cook

Yes. So I was comparing third to fourth quarter and we brought on more wells in the third quarter than in the fourth quarter. So we had flusher production from new wells and there were more wells in the third quarter than the fourth.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And that -- and is that flush production coming down the reason that the first quarter's down again from fourth quarter?

Philip W. Cook

Yes, I mean, all of these wells, once they go on production, decline.

Glenn M. Darden

And we drilled fewer in the fourth quarter. And that certainly laps over into the first quarter, because most of those production impacts are felt in the quarter after they are drilled.

Gil Yang - BofA Merrill Lynch, Research Division

Okay, got you. And the wells that came online, flush production were -- what part of the Barnett were they in?

Philip W. Cook

They were primarily in the northern dry gas section, whereas most of our drilling this year will be in the southern portion, as we said.

Gil Yang - BofA Merrill Lynch, Research Division

Right, right. Okay. Your unusual work-over activity, was that confined to any particular region?

Philip W. Cook

No, it was all over the Barnett. And as you know, as these wells get older, they need additional maintenance.

Gil Yang - BofA Merrill Lynch, Research Division

Right. Is there any particular reason the work-over activity was in the fourth quarter? It was just a good time to get done?

Glenn M. Darden

I think it was a backlog. It just happened to fall in the fourth quarter.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And can you comment on the work-over -- how much does the work-over activity sort of add to your rate? Is that a meaningful number? Or...

Glenn M. Darden

It varies from area to area and we don't have a metric on that. That's on track. We look at each work-over as a standalone economic project, so the additional rates have to justify the work-over.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And you say you have 50 wells that are not yet hooked up in the Barnett. Where are those -- or 55. Where are those 55 right now?

Glenn M. Darden

They're spread across north and south, Gil, so -- roughly even.

Gil Yang - BofA Merrill Lynch, Research Division

Right. And what will be the backlog exiting the year?

Glenn M. Darden

A little less than 40.

Gil Yang - BofA Merrill Lynch, Research Division

All right. So -- and that backlog will be worked down more in the south than in the north presumably?

Glenn M. Darden

Yes, that'll be the focus.

Operator

Your next question comes from David Snow with Energy Equities Inc.

David Snow

I was thinking the Sandridge [ph] was in further east, Sandwash Basin, and like is this all one basin? Or am I wrong about that?

Glenn M. Darden

It's all -- David, it's all part of the Greater Green River Basin and this is the Sandwash Basin. We're in a shallower area in northwest part of Colorado, primarily due west of Steamboat Springs and up to the Colorado-Wyoming line.

David Snow

Okay. Who else is out there with you? Do you have it pretty much by yourself?

Glenn M. Darden

Our largest competitor is Shell. We have a few others in the area. Continental Resources, Amamex [ph] from here and Fort Worth, a few others. But the largest competitor with possibly a little less, but a roughly equivalent acreage position to us, is Shell.

David Snow

Are you getting any help by any of the others in nearby activity? Or are you away from them?

Glenn M. Darden

We're beginning to. We're starting to see some results from the others and that's helping.

Operator

Your next question comes from Dan McSpirit with BMO Capital.

Dan McSpirit - BMO Capital Markets U.S.

What were the estimated future development costs associated with 2011 reserve bookings? Can you share that with us?

Philip W. Cook

Actually, Dan, I don't have that number in front of me, but if you want to follow up with John Hinton, we'll get it for you.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And then can you share with us the early rates, the initial rates on the other Niobrara wells drilled in the Sandwash?

Glenn M. Darden

Yes, the IPs were roughly in line with what we expected. But we frac-ed them with a different material, and we don't think we've seen the performance out of them. We haven't published rates, but we will eventually.

Dan McSpirit - BMO Capital Markets U.S.

Okay. And what do you think the timing will be of those published rates? I ask because I'm not having any luck with the Colorado Oil and Gas Commission website.

Glenn M. Darden

We'll do it in the next few months. We're going to be able to publish more of a type curve. It's really early in the development as you can imagine, but traditionally, we've been among the earliest to publish type curves in each of the basins we go into. So you'll see kind of that grassroots approach to developing economics as we develop them.

Dan McSpirit - BMO Capital Markets U.S.

Got it, okay. And one last one for me. In your pursuit to reduce public debt by $0.5 billion this year or by the end of this year, I just want to confirm that part of the cash inflows include sources of proceeds from the sale of units in Quicksilver Production Partners. Is that correct?

Glenn M. Darden

Yes.

Dan McSpirit - BMO Capital Markets U.S.

Okay. And can you just comment, give us some texture on where that stands today? Is that still on track given -- I ask that just given the price of the underlying commodity here.

Philip W. Cook

Our plans haven't changed since we've announced this in November. It is with the SEC so we can't really comment on that, and we hope to be launching the IPO shortly after we get the clearance and approval from the SEC.

Operator

Your next question comes from John Nelson with Macquarie.

John C. Nelson - Macquarie Research

I think you guys gave cash flow for the year, and I just missed that. I was wondering if you could repeat what those numbers were.

Philip W. Cook

Yes. I'm not sure that I fully gave cash flow for the year, but discretionary cash flow was about $285 million and that was actually operating cash flow without working capital changes, and then that was for the year. And for -- I'm sorry, for 2011 operating cash flow was $285 million, yes, and we generated $650 million in 2011, which included cash flow from operations, the monetization of BreitBurn shares and the Fortune Creek transaction, which is the KKR deal in Canada.

John C. Nelson - Macquarie Research

Okay. And then I know you guys mentioned fewer Barnett wells in the quarter and some work-over activity. But 4Q numbers came down 4% below your guidance. I think, sequentially, you're down another 8%. Is there anything else that's sort of affecting your production? Are you having to shut in wells while frac activity is going on at a higher rate than usual? Or can you just give any more color on that?

Philip W. Cook

I think more than anything, we just basically slowed down as the -- going into the end of the year and first quarter. As Toby said, we didn't bring on as many wells on the completion side, didn't drill as many wells in the fourth quarter, so that's going to affect the first quarter. But overall, in the year, we expect the volumes to be flat year-over-year, roughly flat, maybe a touch higher year-over-year. As we bring production on in second and third, you're going to see the volumes ramp up pretty significantly in second and third quarter.

John C. Nelson - Macquarie Research

Okay. Just one more if I could. What would you guys expect Horn River to average for the year?

Philip W. Cook

$45 million to $50 million a day.

Operator

Your next question comes from Maryana Kushnir with Nomura Asset Management.

Maryana Kushnir

I just wanted to clarify one thing in the press release. You said that organic reserve additions were 248 and then there were 55 removed for economic reasons and another 55 were classified as probables. And then in the summary of the reserves, you show aggregate extension, discoveries and revisions of 39. So just like those numbers do not add up, if you could clarify if I'm missing something.

Philip W. Cook

Yes. The difference is technical revisions.

Maryana Kushnir

What would those be? Or could you...

Philip W. Cook

Due to a number of things, including curves being shortened for when we re-estimated reserves.

Maryana Kushnir

And is that primarily in the Barnett?

Philip W. Cook

Yes.

Operator

Your next question comes from Subash Chandra with Jefferies & Company.

Subash Chandra - Jefferies & Company, Inc., Research Division

Yes, question on Niobrara. I don't know if I heard this right. Toby, did you say there were 70 wells you plan on drilling in 2013?

Thomas F. Darden

No, we said we were permitting. I think that was around the permitting discussion, how many are we permitting. And we have 70 underway now and we may even add a few. But that doesn't mean we're going to drill that many wells in 2013. In fact, we'll drill as we have planned this year to stay within cash inflow. So you can pretty much count on that.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. Is that -- is the horizontal well, is that on pump?

Thomas F. Darden

It is now, yes -- no, it is not. The vertical well is, I'm sorry.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. So it's still producing naturally?

Thomas F. Darden

Yes, it's still flowing.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay, okay. And out here, is it primarily a carbonate member you're targeting? Or is it something a bit more conventional?

Glenn M. Darden

Well, it's a bit more, I guess, you'd call it today unconventional. While everybody's unconventional, maybe it's conventional. But it's a 1,200 foot big section that we are targeting and we're looking at several carbonate benches within that section at this time. Our vertical well is completed throughout the section. Our horizontal well targeted one of the carbonate benches, so there's a lot of additional testing to be done, but it's a huge resource. And so we're very excited about the early results and being able to earn while we learn.

Subash Chandra - Jefferies & Company, Inc., Research Division

And what do you think was the reason why you couldn't get the entire lateral stimulated?

Glenn M. Darden

Well, we had a time frame on wildlife stips that caused us to truncate the second half of the lateral early, or keep from frac-ing the second half of the lateral. And so that's really what the primary cause of not getting it fully completed was.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. And maybe for my notes, I'm forgetting, but what other wildlife stips are we talking about, partial-year development?

Glenn M. Darden

Well, in partial-year development, we're talking about 1 quarter or so, which is really no different than any of our other winter operations.

Thomas F. Darden

That we lose.

Glenn M. Darden

That we lose.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay, Got you, okay. And the -- in the HRB, how many wells per pad are you bringing on, I think you said second or third quarter? Are these sort of 6- to 8-well type pads you're bringing on?

Glenn M. Darden

Yes. 8 wells plus.

Subash Chandra - Jefferies & Company, Inc., Research Division

Got it, okay. And you mentioned, I think, 2 pads.

Glenn M. Darden

More than that [ph] year actually, but over the year, yes.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay, got it. And finally, for me, did anything come out of that SEC review of it? They asked a whole bunch of companies to talk about EURs and shales and so on.

Philip W. Cook

There has not been anything coming out of it, Subash. They sent out the original request for information and have backed off significantly, realizing that they were going to get a lot of information from a bunch of producers. So we're still in conversations with them, but there's been nothing else to report.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. So it's not -- that's not a question that they hold over the industry when you file for the upstream MLP.

Philip W. Cook

No.

Operator

Your next question comes from Alex Heidbreder with Millennium.

Alex Heidbreder

A couple of questions. First of all, in the Barnett, you guys talk about having 50 gross wells yet to be completed, and it looks like you're only catching up on about 11 of them. Why not work on the inventory further?

Glenn M. Darden

Well, we are working off other inventory. We're drilling new wells, so we're completing those. So we're basically taking the overall inventory down 10 wells or so. So we'll be completing more wells, but just with activity level, we'll always have a certain amount of uncompleted wells in the inventory with pad a drilling, et cetera.

Alex Heidbreder

Okay. And then what are your total non-booked, not in P1 [ph] or PUDs, non-booked Barnett locations? And how much of those are in the liquids-rich south versus everywhere else?

Glenn M. Darden

Well, we have probably north of 0.5 trillion cubic feet of probable at this stage of the game, and a large chunk is in the south.

Alex Heidbreder

Any idea on like number of locations?

Philip W. Cook

Not number of locations, but, obviously, it depends on gas price, and it could be anywhere from 0.5 Tcf to 1.5 Tcf of unbooked reserves in the 2 [ph] and 3P [ph] category.

Alex Heidbreder

Okay. And then on the -- in the hedge book, I guess, can you give a hedge book update? What was the pre-hedge revenue for Q4? And were there any out-of-period hedge settlements in Q4?

Philip W. Cook

There was no out-of-period hedge settlement. I don't have pre-hedge revenue in front of me. Our hedge book is about $350 million in the money right now.

Alex Heidbreder

Got it. So on the end of your balance sheet, it will show up like a $350-million current long-term asset.

Philip W. Cook

Yes. Part of that is current, and part of that is long term.

Alex Heidbreder

Yes. Okay. And then in the Horn River, what is the Btu of the gas? And/or is there any liquids credit whatsoever?

Glenn M. Darden

No. There's -- it's dry gas. It's about 1,000 Btu.

Alex Heidbreder

And what do you -- I mean, given -- I know we're still early stage, but what do you think the 10% kind of break-even AECO price is?

Glenn M. Darden

$4 NYMEX.

Alex Heidbreder

So that's something like $3.50s at AECO.

Philip W. Cook

Yes. And today, we have about $60 million a day hedged in Canada at $5.75. So those wells that we're drilling in Horn River are economic with our hedges in place.

Operator

The next question comes from Steven Karpel with Crédit Suisse.

Steven Karpel

I know, Phil -- I wanted to follow the last question on hedging. Maybe what I'm trying to get to is an EBITDA number adjusted for the hedge realizations.

Philip W. Cook

You mean including the hedge realizations?

Steven Karpel

Exactly. Including the cash flow impact as well as the income statement impact.

Philip W. Cook

Yes. So EBITDA was about $400 million for the year and about $95 million for the quarter.

Steven Karpel

And adjusted for -- what does that compare to for last year? Did you adjust that number, get adjusted at all?

Philip W. Cook

No.

Steven Karpel

And I think you gave the hedge asset number. Is that the current -- is it currently $350 million?

Philip W. Cook

That's the -- the year end, it's $350 million, but I suspect that it's still $350 million today.

Steven Karpel

And any plans to monetize any portion of that? And the question, I think, went back to the borrowing base, that you don't expect much movement at the borrowing base. Is that as a result of the hedging? But do you get the full -- are you getting full credit? Or is there any reason that you would monetize a portion of that to help with the borrowing base?

Philip W. Cook

We have no plans to monetize it. I don't think we'd need to, to help the borrowing base. And of course, each bank does it differently and you get some amount of credit for hedges. I think in no case do you get 100%, but also in no case do you get 0%. So, as you know, JPMorgan is our lead bank and we've been in conversations with them. We don't think we have an issue for '12 and I don't think we'll have an issue for '13 either.

Operator

We have a follow-up question from David Snow with Energy Equities Inc.

David Snow

Just trying to get an idea of what the oil production growth might look like this year -- the liquids production growth, I mean.

Glenn M. Darden

We haven't projected the actual growth but percentage wise, I guess, we've talked about 62% oil growth. We have a -- 1% of our total reserve base is oil, so we're going to be drilling that. I think where you're going to see -- you're going to see directionally the growth and you're going to see more volumes come on as we move later in the year and into '13.

Thomas F. Darden

But we're also going to see liquids volumes ramp-up in the south part of our Barnett, so you're going to see that mix evolve much more to liquids and oil during 2012, but it will strengthen in 2013.

Operator

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

Eli Kantor - Jefferies & Company, Inc., Research Division

This is Eli Kantor. I'm on for Subash. Similar question, just, I guess, asked a different way. For 2012 production, can you give a percentage split between oil, gas and NGL volumes?

Philip W. Cook

I mean, it's going to be very similar to what 2011 was. I would say we're going to be 20% liquids and 78% gas and 2% oil. Maybe [ph] higher on the liquids.

Eli Kantor - Jefferies & Company, Inc., Research Division

I'm sorry?

Philip W. Cook

Maybe a touch higher on the liquids, but roughly the same. But you'll see the oil coming up. The liquids from the south will be coming up and we'll be bringing on dry gas in Horn River as well, so...

Eli Kantor - Jefferies & Company, Inc., Research Division

Got it. That's helpful. And then in the Sandwash Basin, how much do you plan on spending on gas gathering this year? And is that a good annual run rate to expect going forward?

Glenn M. Darden

On the midstream side?

Eli Kantor - Jefferies & Company, Inc., Research Division

Yes.

Glenn M. Darden

We budgeted $15 million and that will largely be gathering, some liquids extraction and some downstream delivery into more liquid market points. So we're starting the backbone of midstream structure for Colorado and that's good news.

Eli Kantor - Jefferies & Company, Inc., Research Division

Is that $15 million number a good annualized run rate to use, kind of '13 and beyond? Or is it going to be a little more lumpy?

Thomas F. Darden

I think you're going to see it being somewhat proportional to the development pace. We're certainly going to have to build for the volumes that actually come on. And so after 2012, we'll have a better handle on that.

Operator

Your next question comes from Kathryn O'Connor with Deutsche Bank.

Kathryn O'Connor

I know you guys did some debt repurchases in Q3 and it didn't look like you did any in Q4. But did you do any after December 31, at the beginning of this year? Have you done any repurchases in the open market of your debt?

Philip W. Cook

No, we have not.

Operator

Your next question is a follow-up question from Alex Heidbreder with Millennium.

Alex Heidbreder

Sorry if this is repetitive. I just -- I didn't see it -- or I didn't hear it earlier. What is the actual 2012 CapEx budget? And what's the pretax PV10?

Philip W. Cook

The CapEx budget is $370 million for drilling and completion activities and another about $40 million for other capital requirements, and I do not have the pretax PV10. It'll, obviously, be in our -- it will be in our 10-K when we get filed.

Operator

Your next question comes from Anne Cameron with BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

Just a quick question about your hedges. You have like $20 million a day that's designated as hedged Canada gas. I figure that has something to do with some agreements you've signed up there. Is that eligible to draw -- are those hedges eligible to be dropped into the MLP?

Philip W. Cook

Well, we have $60 million a day, I believe, in hedges in Canada and we've designated them to Canada. We have other hedges that we're dropping into the MLP. So those are for Canada.

Anne Cameron - BNP Paribas, Research Division

So that means you cannot drop them into the MLP?

Philip W. Cook

Well, we can do -- can, but we're not going to.

Glenn M. Darden

Yes, they're just designated for hedge accounting.

Anne Cameron - BNP Paribas, Research Division

You don't have any hedges up there that are -- you've gone into because of agreements with your midstream providers.

Philip W. Cook

No, we have not.

Operator

At this time, there are no further questions. I will now turn the call back over to Mr. Hinton for any closing remarks.

John E. Hinton

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

Operator

Thank you for your participation in today's conference call. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Quicksilver Resources' CEO Discusses Q4 2011 Results - Earnings Call Transcript
This Transcript
All Transcripts