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Quicksilver Resources (NYSE:KWK)

Q1 2012 Earnings Call

May 08, 2012 11:00 am ET

Executives

John E. Hinton - Vice President of Finance

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

John C. Regan - Chief Financial Officer, Chief Accounting Officer, Senior Vice President and Controller

Analysts

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

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

Vivek Pal

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

Stephen P. Shepherd - Simmons & Company International, Research Division

Brian T. Horey - Aurelian Management LLC

Brad Carpenter - Wells Fargo Securities, LLC, Research Division

Kathryn O'Connor

Steven Karpel - Crédit Suisse AG, Research Division

Unknown Analyst

Operator

Good morning, and welcome to the Quicksilver First Quarter 2012 Earnings Conference Call. My name is Terrence, and I will be your conference operator. [Operator Instructions] I would now like to turn the call over to our host, John Hinton, Vice President of Finance and Investor Relations. Thank you. Mr. Hinton, you may begin your conference.

John E. Hinton

Thank you, Terrence, and good morning. Joining me today are Glenn Darden, President and Chief Executive Officer; John Regan, Senior Vice President and Chief Financial Officer; Chris Cirone, Executive Vice President and General Counsel. Toby Darden, our Chairman, is traveling today on business.

This morning, the company issued a press release detailing Quicksilver's results for the first quarter of 2012. 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 which could cause such differences is detailed in the company's filing with the SEC.

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

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

Glenn M. Darden

Thank you, John, and good morning. Quicksilver Resources reported a net loss of $60 million or $0.35 per diluted share for the first quarter of 2012. First quarter results were negatively impacted by a $63 million noncash impairment of oil and gas properties due to lower average natural gas prices compared to December 31, 2011. There were also noncash charges of $37 million related to the restructure of the hedge platform and an unrealized loss on new 10-year hedges. Earnings were improved by a $41 million earn-out payment from Crestwood Midstream Partners LP. Excluding these items, the first quarter 2012 adjusted net loss was $15 million or $0.09 per diluted share compared to adjusted net income of $3 million or $0.02 per diluted share for the 2011 period. John Regan, our Chief Financial Officer, will provide more details on the financials in his discussion.

As we projected, due to reduced activity in the Barnett area, company production volumes came in at 377 million cubic feet equivalent per day for the quarter, which is roughly 9% below fourth quarter 2011 volumes. Volumes will build back in the second half of the year, and our forecast is for total annual volumes to be approximately within 5% of 2011 volumes. With the reduction of gas prices, Quicksilver has taken steps to minimize spending in dry gas areas, as well as to target the cost side.

This quarter shows higher costs on the lease operating side, which is primarily attributable to gas lift costs in certain projects. We are aggressively attacking these costs and have shut in certain production pads. These shut-ins will positively affect company EBITDA, but will have a minimal effect on company production volumes.

Additionally, in the Barnett, the company is on track to launch our master limited partnership when it receives final approval from the SEC, which we expect relatively shortly.

Quicksilver has certain development commitments in the Horn River Basin project in Northeast British Columbia. These commitments tie to contracts for pipeline transportation. Quicksilver's volume commitment is 75 million cubic feet per day for the rest of 2012, building to 100 million per day in May of 2013. There may be certain delays on the Spectra side on the pipeline -- and processing side, which could allow us to delay some of that ramp-up to 75 million a day. But we'll keep you abreast of that as that develops.

The commitments to KKR in our midstream joint venture are contained within these volumes and are not in addition to them. We will be bringing on our first multi-well development pad in the next 30 days in order to satisfy these obligations. In anticipation of this activity and new production, Quicksilver has the majority of Canadian gas hedged. It also is important to note that Quicksilver has 2/3 of total company production hedged for the remainder of the year at an average price of $6.02 per Mcf equivalent.

In addition to meeting pipeline commitments, we believe that these new Horn River wells will showcase the quality of the reservoir and production for our potential partners. We anticipate securing an upstream partner for this project later this year. Quicksilver's land team has been busy finalizing drilling permits and clearing title in both Colorado and West Texas. We have begun drilling a 6-well program in West Texas and we're roughly at total depth on our first well today, and we'll commence our second round of drilling up to another half a dozen wells or so in Colorado by the end of the month.

Our strategy is to build oil volumes following the grassroots approach this company has utilized from the beginning. We believe we have captured a lot of value in both of these areas and are putting the pieces in place for significant long-term developments. The company is in the later stages of the process to secure a partner for the West Texas project and bids are due at the end of this month. We anticipate a closing transaction later this summer.

This is a transitional time for Quicksilver. Not only are we working to build liquids volumes, we are looking to put in place development structures that can maximize the value of a large asset base we've captured and that we feel aren't being valued today in our stock price. The joint ventures, the MLP and the new drilling will all contribute to a stronger Quicksilver by year end.

In the interim, we have no near-term maturities with our bond debt, ample capacity in our credit facility, and the company's production volumes are well hedged this year and next. Our focus is spending within cash inflows, and we've done that the previous 2 years and we're going to do that this year, and reduce debt through joint ventures and the MLP. We strongly believe these newer ventures will put Quicksilver on a new growth path and be much stronger, as I say, by year end.

And now, I'll turn the call over to our new Chief Financial Officer, John Regan. John is certainly not new to Quicksilver though, having been our Chief Accounting Officer for the last 5 years. But I would like to introduce him on his first earnings call as our Chief Financial Officer. John?

John C. Regan

Thank you, Glenn, and good to be with you. For the first quarter, our net loss was $60 million or $0.35 per diluted share. This compares to the net loss of $71 million or $0.42 per diluted share in the 2011 quarter. Our adjusted net loss or clean earnings for the first quarter of 2012, which I'll remind you is a non-GAAP measure, was $15 million or $0.09 per diluted share versus net income of $3 million or $0.02 per diluted share in Q1 of '11.

Our adjustments to arrive at 2012 net income include the $41 million earn-out payment from Crestwood Midstream Partners; the $63 million noncash impairment of oil and gas properties, which resulted from gas price deterioration in Q1; a noncash loss of $15 million related to the restructuring of our hedged platform; an unrealized loss of $22 million for the day 1 effects of our new 10-year hedges that we entered into in Q1 and a noncash loss of $3 million for hedging effectiveness.

Adding a bit of color to these hedging-related items, we restructured 30 million cubic feet per day of our old 10-year contracts to bring forward the value from the 2016 to '21 period into 2012 through 2015. In doing so, we obtained swap prices that were more than $2 in excess of then prevailing prices. However, the calculated difference between the fair value of the old instruments and the fair value of the new shorter-term instruments triggered the recognition of a $15 million charge.

We also recognized a $22 million charge related to the calculated fair value on day 1 of our new 10-year swaps. For accounting purposes, the swap prices were lower than the forward curve would have indicated that they should've been, which is largely reflective of illiquidity in the outer years of the 10-year. I'd like to note that these contracts, which cover 40 million cubic feet per day, are in an asset position today.

We had average realized gas price of $4.34 per Mcf for the 2012 quarter, which is down $0.39 and $0.73 from the fourth and 2011 quarters, respectively. On an unhedged basis, realized gas prices were 35% lower than the 2011 quarter. Aggregate average NGL prices were $43 a barrel compared to $38 a barrel in Q4. On an equivalent basis, we averaged $5.01 per Mcfe for the 2012 quarter.

As Glenn mentioned, in response to depressed pricing for natural gas, we've been reviewing our production pads to evaluate their economics. To date, we have shut-in 3 pads in the dry area of the Barnett, and we will continue to monitor pad economics and make additional shut-ins where warranted. We believe that this program, despite yielding slightly lower production, will be accretive to our bottom line.

Production in Q1 was down approximately 9% from the fourth quarter and 4% from the 2011 quarter. These declines are caused by our scale-back capital program in the latter half of 2011 and in Q1, particularly, in the dry areas of the Barnett, plus the effects of the continued aging of the basin. We expect our second quarter production to be reduced through our continued review of uneconomic wells and, in alliance, by a completion program that we have entered into with Eni. Under the program, Eni's funding 100% of the completion cost of a pad of 12 wells. After Eni's costs have been recovered through production allocated to them, we will reverse to our 72% working interest. We believe that this arrangement is advantageous to us because it allows us to avoid deploying that capital to the development of dry gas reserves, while retaining an upside interest should natural gas prices revamp.

We do have nearby dry gas wells, some of which will be shut in while this program is ongoing. As a reminder, we believe we are well hedged for the remainder of 2012. We have 230 million cubic feet of gas a day hedged at a weighted average floor of $5.75. We also have 7,000 barrels a day of NGL hedged at $45. In the aggregate, the fair value of our portfolio exceeds $400 million.

Total production revenue was $172 million for the quarter, which is down $22 million from the fourth quarter and $18 million from the 2011 quarter. Other revenue was almost entirely comprised of the hedging-related adjustments that I mentioned earlier.

As for expenses, lease operating expense or LOE was $0.84 on an equivalent unit basis for Q1 compared to $0.78 for Q4 and $0.61 for the 2011 quarter. These increases are due to higher gas lift expenses and higher saltwater disposal costs in the Barnett and the higher surface use cost in Canada, plus the impact of the lower production volumes. The increase in gas lift is caused by the aging of Barnett wells that now require artificial lift to maintain production.

As we've mentioned, we have shut in some of our uneconomic pads which make use of gas lift, and we expect to continue to monitor the economic performance of our operations. We're also working with our vendor base regarding the cost of these and other services, which we believe will also help our cost structure moving forward.

Gathering, processing and transportation or GPT was relatively unchanged from Q4 or the 2011 quarter on a unit basis. Production in ad valorem taxes are $0.20 on a unit basis for Q1 compared to $0.14 in Q4. This increase is caused by elevated ad valorem taxes in the U.S., most notably, for our expanded acreage positions in the Niobrara in West Texas. Our expanded well count in the Barnett and the lower production volumes also contribute to the increase.

G&A for Q1 on a clean earnings basis was $0.53 per Mcfe compared to $0.46 in Q4 and $0.52 in the 2011 quarter. These increases are related to higher professional fees, primarily to our auditors.

During 2012, we began recording accretion expense related to Fortune Creek, which is our partnership with KKR. The $125 million investment by KKR is carried as a liability on our financial statements, for which we recognize accretion expense to reflect the return that their contribution generates. In Q1, we recognized $4.7 million of accretion expense related to this partnership. We consolidated Fortune Creek since we manage the day-to-day activities of the facilities and we are the principal customer.

So as a brief recap, unit cash expenses for the aggregate, LOE, GPT, production and ad valorem taxes and recurring G&A in the first quarter were $2.66 compared to $2.46 in Q4. At our average realized prices for the quarter, our cash margin was $2.35 on an unlevered basis. On a levered basis, recurring cash interest expense is $1.12, so cash margin is $1.23 or 25% on revenue.

From a capital spending perspective, we incurred $136 million of capital in Q1. But actual cash spending was $40 million higher due to Q4-related capital for Horn River that we paid for in Q1. This spending relates to our delivery in commitments, which ramp up in Q2 of this year, which Glenn covered earlier.

We continue to believe that our anticipated spending levels for all of 2012 will be as we previously disclosed in our 10-K, which, of course, requires reduced spending in the remaining quarters of the year. Drilling and completion capital for the remainder of the year will be mainly focused in the high Btu area of the Southern Barnett to meet up the commitments in the Horn River and to explore our oil plays in West Texas and in Colorado. Again, we intend to fully fund capital spending this year with cash inflows.

From an operating cash flow perspective, cash flow in the first quarter was $27 million or $48 million excluding the changes in working capital. The $41 million receipt from Crestwood for the 2011 earn-out was recorded as an investing activity. But we consider it to be a source of cash for 2012 capital spending purposes. We continue to be in an earn-out period for all of 2012 with Crestwood with the potential to collect up to an additional $31 million in early 2013.

Total debt at quarter end was approximately $2 billion, and we had 62% of our $1.1 billion credit facility available, meaning we had $680 million available. We expect there will be no material change to our global credit facility borrowing base once the semiannual redetermination is completed later this month. Further, our models show covenant compliance for 2012 even without completion of either the IPO or consummation of a joint venture.

Our plans to improve our capital structure this year remain the same and are moving along as planned. We intend to raise cash to pay down consolidated debt through the IPO, which we cannot discuss in any detail, but which is on pace for a summer launch. Under the proposed transaction, we expect that we will pay off $350 million to $400 million of bond debt. And we'll incur an additional $150 million under a separate nonrecourse credit facility, which likely will feature rates well below the coupon rates of the bond being retired.

We anticipate any future drop-down transactions by Quicksilver will help our continued execution of the debt reduction initiative. We have received interest from multiple parties for potential joint ventures in our West Texas and Horn River upstream operations. Proceeds from these transactions will minimize or eliminate any funding gap on our capital spending, and any excess proceeds will be earmarked to further reduce public debt. A successful joint venture could also favorably impact our net capital spending levels in 2013 and succeeding years.

On April 18, the S&P announced reductions to their price deck as $2 for 2012 and $2.75 for 2013. These reductions place downward pressure on our leverage ratio, and in response, this morning, S&P reduced our credit rating one notch to B flat. However, I point out we have no ratings-related triggers in our financial or operating agreements.

We do expect to file the first quarter 10-Q with the SEC on May 10. And I'd like to applaud the efforts of the financial reporting team that has worked tirelessly to overcome the delays associated with our 2011 Form 10-K and to be in a position to file within the prescribed SEC timeline. Included in that filing, we will report a material weakness related to our internal controls surrounding the recognition of the day 1 loss for the new 10-year hedges. We fully expect this weakness to be remediated when we file our second quarter 10-Q.

I'll now turn the call back over to John Hinton for second quarter guidance and for the question portion of the call.

John E. Hinton

Thank you, John. Second quarter 2012 production volume is expected to be between 375 million and 385 million cubic feet per day. Average unit costs on an Mcfe base are expected as follows: lease operating expense between $0.80 and $0.84; gathering, processing and transportation cost between $1.26 and $1.30; production taxes between $0.20 and $0.22; G&A between $0.52 and $0.55; DD&A between $1.56 and $1.58.

Operator, I'd like to now open the line for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Kim Pacanovsky with PLV (sic) [MLV] & Co.

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

In the Sandwash Basin, can you talk about where you're drilling the first 7 wells? And is it just kind of statistical across your acreage or are there geological reasons for where you're placing the wells?

Glenn M. Darden

Well, Kim, the initial drilling was spread across the acreage, more a statistical approach. We're fine-tuning a little bit. We'll be drilling some wells around our Stoddard well, which is our best vertical well. And what this does is allow us to put in some limited gathering and treating, so we can -- we're making some very rich gas there, so we want to be able to sell that. So some of these wells will be around that Stoddard, but we'll drill across still a range at the acreage.

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

Okay. And in the Permian, can you talk about how you're lined up with services through the year? It seems that services are getting a little tight for some people. And also, it seems like the operating costs are going up a lot. If you could just address that.

Glenn M. Darden

On the service side, we have secured frac crews. We've got our own drilling rig that we moved out to West Texas, so that rig will continue to drill -- continuously drill the 6 wells. As far as cost side, we've seen cost creep in several basins. West Texas is probably as hot a basin as there is. But we still should be within our E&P range.

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

Okay. But you have a dedicated crew for the 6 wells?

Glenn M. Darden

It's my understanding we've secured those services, yes.

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

Okay, great. And then I'll just ask one more. On the income statement, you have Fortune Creek accretion. How do we look at that number and look at that going forward? If you could sort of simplify that for me. I know that's related to KKR.

John C. Regan

Yes, that's the portion of the Fortune Creek earnings that are allocable to KKR. So it's the return that they generate on their investment. I think, kind of moving through time, I wouldn't expect to see a lot of variability in that number from quarter to quarter.

Operator

The next question is from the line of Brian Corales of Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Looking at the Sandwash Basin, now that you have more production history from some of those wells, do you have a better idea on kind of what the ultimate recovery is from some of the wells you drilled? And then two, have you all learned anything that you're going to kind of do differently going forward?

Glenn M. Darden

Well, we've certainly learned some things, which we probably won't disclose on this call, Brian, but definitely learned some things in the first round of drilling. As our initial half a dozen wells were drilled, we continuously lowered the cost, so I think these next round will be cheaper to drill and complete. We've learned some things on the frac-ing side. As far as recoveries, on the vertical side, I think those are looking, at this point, at least as good as our analog 80-well model of historical wells thereof in excess of 200,000 barrels recovery on the vertical side. We're still a little uncertain on the horizontal well. The one well that we've completed, we only completed about half of the lateral. So I'm not sure that's exactly apples and apples for an EUR comparison, so -- but we're pleased with the production so far. It's leveled out pretty nicely. We're making some good rich gas with these wells that add to the revenue and reserve. So it's a little bit early overall. We don't have a big sample set. We hope to have a lot more data after this next round of drilling.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then just switching to the Permian, I'm assuming the first few wells you're going to drill vertically. Can you talk about what areas within the Permian or within your acreage that you plan to drill?

Glenn M. Darden

Yes, we're drilling the first few wells just southeast of Fort Stockton in our middle area, the Mancos area. And then we'll move to the Upton County area to drill another 3 wells or so. So that will progress as the summer goes along.

Brian M. Corales - Howard Weil Incorporated, Research Division

And are those vertical?

Glenn M. Darden

Vertical for the most part, but we're prepared to go horizontal on a couple of these wells.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And just one final question. You mentioned you shut in 3 pads in the Barnett. How much gas did you all shut in?

John C. Regan

It's between 6 million and 8 million a day. Pretty small.

Operator

Your next question is from the line of Dan Guffey of Stifel, Nicolaus.

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

Of the 6-well program you're drilling in West Texas, can you talk about, in the different areas, what horizons you guys are going after and how you guys are going to complete the wells, kind of well designs in each area?

Glenn M. Darden

Yes, we can talk about the targets. We're targeting the Bone Springs, third Bone Springs in particular, and Wolfcamp in the Pecos area, more of the Wolfcamp and a little bit of Bone Springs in the eastern area in Upton, Crockett counties. We will complete several of these -- the majority of these wells will be vertical completions and probably combining several of the sections. But as I said in the previous question, you may not have heard this, the answer, but we'll be prepared to go horizontal in a couple of these wells after getting some geologic data on the full vertical section.

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

Okay, great. And then just kind of switching to Horn River, can you guys talk about current takeaway capacity and how that is going to expand over the next, say, 12 to 18 months?

Glenn M. Darden

Yes. John, do you want to take that?

John E. Hinton

So our current capacity on Spectra was -- through April 30 was 30 million a day. It was to step up to 75 million a day on May 1 with the completion -- the intended completion by Spectra of an expansion on their facility, but they are currently running behind on that. And so then contractually, the next step-up we have is May 1 of 2013, when we step up to 100 million a day. So as Glenn alluded to earlier, with the delay in the Spectra completion of their plant, we'll have some flexibility in terms of when we start dialing up the Horn River production. Because at this point, it's a little bit uncertain when they're going to have that completed.

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

Okay, great. And then just one last one in the Sandwash, the Stoddard well. You guys have -- and I know I haven't seen it, maybe I missed it. I don't know if you guys have given performance for the Stoddard well, which it sounds like is your best well in the area. And if you haven't, when do you guys think you may disclose that?

Glenn M. Darden

Yes, we haven't -- we talked a little bit about projected EURs. We haven't fully baked that at this point, but we're going to get more data from a bigger sample set before we give full reserves.

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

Okay. So you guys haven't talked 30-, 60-, 90-day rates or even longer rates for that Stoddard well?

Glenn M. Darden

Well, we probably -- how long have we had that on, John?

John E. Hinton

Yes, I think the last data point that we had was kind of a 45- or 60-day number update that we gave on the first call. We haven't had an update since then.

Glenn M. Darden

Yes, we're making roughly 100 barrels a day there equivalent, mostly oil, probably 80% oil on that well. So it's holding up very nicely.

Operator

The next question comes from the line of Noel Parks of Ladenburg Thalmann.

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

Sorry, I got on a little bit late. I just want to ask you about at the -- in the Niobrara. You mentioned in the press release that the Niobrara was your -- was one target, but you also were looking at the Mancos. Could you just talk more about that and just differences between it and the Niobrara, and a little bit about what your expectations are there?

Glenn M. Darden

Yes, I would say our primary target is Niobrara, Noel. And certainly, with what we've seen so far, we've completed -- one well didn't penetrate the Niobrara, it was completed in the Mancos. And that performance was poorer than our Niobrara completions. So I would say target #1 is Niobrara. We believe this is a Niobrara project.

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

Okay. And let's see, just to back up a second here, you -- in the JVs discussions that you're having, in the -- particularly in the Permian, as far as the folks who are coming to the table, what's sort of the main selling point or the main thing that has attracted interest from them? Is it other players who have experience in the plays that you'll be targeting? People who are more brand-new entrants? And I wonder if you could characterize them as being extremely price-sensitive as far as what they'd pay to enter the venture or being a little bit more big picture about the longer-term opportunities?

Glenn M. Darden

Well, Noel, as you know, it's a very hot area and we've got -- we've captured some nice acreage positions in a couple of the hottest areas. These plays are moving south, as you also are aware of. I would say that we kind of run the gamut on the type of player. We certainly have talked with and had data room visits from players that are in the basin that are very savvy West Texas players, as well as savvy operators that are not there that want a position in these various areas. So I can't speak to, "Are they price-sensitive?" But it's a hot area and leases there are going for some pretty high numbers. So we'll see how the bids come in.

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

Okay. Great. And then just the last thing I have is, in the Barnett where you've started shutting in some selected areas, how difficult or costly do you anticipate it would be to return those productions if the time came?

Glenn M. Darden

Not costly at all. No, I think it's just that we've been monitoring this for a while and made the decision a couple of weeks ago to shut in some wells. This was related more to costs. As John said, it's not a big material event on the production side, but we will raise our EBITDA by shutting these in. And so it is more profitable to do that.

Operator

Your next question comes from the line of Vivek Pal of Knight Capital.

Vivek Pal

I know you mentioned it, but I didn't catch all of it, so I apologize. You talked about the initial debt reduction would be paydown of a note as opposed to bank debt. Did I hear that right?

John C. Regan

Yes, it's probably debt. And I would say that the first takedown of debt was when we took out the converts last year of $150 million last year. But for this year, it will be most likely probably debt.

Vivek Pal

And you have a senior subordinated note that is currently callable, and then you have senior note that's coming due in August, which I believe is the timing. Have you -- do you have any preference on that? Or is it going to be like a waterfall kind of a paydown? Or you just wanted to improve your near term -- clear out the near-term maturities? Or what -- how should we think about it?

John C. Regan

So the company hasn't formally announced what its intention is. And as we get closer and closer to having the cash in hand from the IPO, we will begin to more thoroughly formulate our plan. But at this point, we really don't have a firm plan in place that we've communicated externally.

Vivek Pal

Okay. And one more, if I could, please. Would the asset sales reduce your borrowing base?

John C. Regan

I guess when you think about it, it will reduce the borrowing base at the parent level. However, we believe that the borrowing base in the aggregate on the consolidation will be actually elevated a little bit.

John E. Hinton

I guess one thing to keep in mind, there's not -- we don't really have many reserves booked in West Texas or in Horn River. So joining a joint venture is not going to move the needle much on those 2 projects.

Vivek Pal

Right, right, right. But when you do the MLP, would it be like a dollar-for-dollar reduction in borrowing base or probably less? And how much of the hedged -- hedges that you have in place that you have to put in an MLP in order to have more like a stable kind of a cash flow? And would that have any implications on your borrowing base? Because I'm assuming you're getting some credit for the above market hedges that you have.

John C. Regan

Yes, I guess what I would say is, we can't really talk about the MLP and what's in the MLP. But we believe that it will be less than a dollar for dollar reduction. So whatever the borrowing base is going to be potentially at the MLP, that there will be less than that in the reduction to the parent. So I guess what I would put, that we're still forecasting ample capacity at the parent even post effective of an IPO.

Operator

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

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

Just a couple of questions. On LOE, you talked about making some steps to get LOE down by shutting in some pads and other things. What would you -- would you anticipate LOE per unit to go down between 2Q and 3Q? Could you give us some color on your expectations of LOE per unit, back half of the year?

John C. Regan

Yes, I think you're going to see a couple of things. As we mentioned, production in the latter half of the year will be significantly impacted by bringing the Horn River wells online. So we expect kind of a burst in production there. And I think on a unit basis, you will probably see that wane through, not only the flush production from the Horn River, but to a lesser extent, the cost reductions here in the U.S.

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

Okay. And then when -- do you know the exact timing of when those wells will be coming online in the Horn River or the month?

Glenn M. Darden

We'll begin to bring those online, Marshall, here at the end of this month, beginning of June.

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

And they should all be online by the end of June? Or will it stretch into the third quarter?

Glenn M. Darden

The initial pad will be online by the end of June.

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

Okay. And then one last question on the horizontal well in Colorado. You talked about making about 100 barrels a day, is that ...

Glenn M. Darden

That was the vertical well.

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

Oh, that's the vertical well. Okay.

Glenn M. Darden

But the horizontal is roughly the same on an equivalent basis, just making a little bit more gas. Again, that gas is pretty rich.

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

Okay. And how long have those been on production at this point?

Glenn M. Darden

120 days, something like that.

Operator

Your next question comes from the line of Stephen Shepherd with Simmons & Company.

Stephen P. Shepherd - Simmons & Company International, Research Division

So it sounds like you're making good progress on the consummation of either the Barnett MLP or, I guess, the -- in the West Texas JV transactions. I was just wondering, in the event that one or both of those don't come to fruition or the timing is extended relative to, I think it was summer, which was the timeframe you offered earlier on the call, what does the contingency plan look like there? Is that something that you all have thought about? And then just as a follow-up to that is, have you all publicly gone out with what your targeted proceeds are from those transactions?

Glenn M. Darden

Well, I will add that we're making progress on the Horn River joint venture as well. So those are -- there are 3 items that we're targeting. And yes, we have contingency plans. We're not going to lay those out today. We have laid out our target proceeds on the MLP, and that's in the S-1 filing, and that was $400 million of proceeds, a combination of equity and debt that we would apply to a bond debt. And -- but we haven't put any public targets on the 2 joint ventures.

John C. Regan

Yes, I would point out that although -- Glenn said $400 million, as I covered in my comments, it could be in the range of $350 million to $400 million. One of the things that the transaction potentially triggers for Quicksilver is some taxation. So we'll pay the federal government some money. That may be a use of cash there.

Operator

Your next question comes from the line of Brian Horey with Aurelian.

Brian T. Horey - Aurelian Management LLC

On the 3 pads that were shut in, in the Barnett, what kind of EBITDA savings do you think you're going to have from that?

John C. Regan

It's probably in the $400,000 to $500,000 a quarter.

Brian T. Horey - Aurelian Management LLC

Okay. And the 12-pad well that you're drilling with Eni, when do you expect that will come online?

Glenn M. Darden

The completion with Eni?

Brian T. Horey - Aurelian Management LLC

Yes.

Glenn M. Darden

Yes, those -- they're completing those wells as we speak. So we've had some shut-in production surrounding that and -- over the next 45 days or so.

John C. Regan

But again, with that arrangement, all the volumes will go to Eni.

Brian T. Horey - Aurelian Management LLC

Until they get back their other capital?

John C. Regan

That's correct.

Brian T. Horey - Aurelian Management LLC

Okay. And does that exhaust their drilling carry? Is that where the source of that funds is?

Glenn M. Darden

That drilling carry ends -- there's no drilling carry at this stage of the game.

Brian T. Horey - Aurelian Management LLC

Okay, okay. And what kind of shut-in are you going to have while you're completing those wells? Can you give us a sense of order of magnitude on that?

John C. Regan

Yes, across the quarter, that's about $11 million of that, $10 million to $11 million.

Brian T. Horey - Aurelian Management LLC

Okay, great. And then the first pad in the Horn River that you're bringing on, is that going to be enough to kind of fulfill that volume commitment that you've signed up for up there or do you need other pads to do that?

Glenn M. Darden

No, it will easily cover that.

Brian T. Horey - Aurelian Management LLC

Okay. And it sounds like, I guess, maybe you'll be constrained somewhat until the expansion gets done by Spectra?

John E. Hinton

No, there's actually -- with the slowdown in drilling in Canada with the current prices, there's plenty of unutilized capacity in the current Fort Nelson plant, so there's no issues about getting that gas to market when it comes -- when we bring it on irrespective of the fact that their plant expansion's been delayed.

Glenn M. Darden

Yes, John's earlier answer was just specific to our commitments. But there's plenty of capacity to move gas.

Operator

Your next question comes from the line of Brad Carpenter with Wells Fargo.

Brad Carpenter - Wells Fargo Securities, LLC, Research Division

I just had a real quick question regarding your full year capital spend guidance. Looking at 1Q with the $136 million, the run rate looks a little bit high. And I think my question has largely been answered just through piecing together other answers you've given throughout the call, but I was hoping you could kind of help me reconcile first quarter numbers going throughout the rest of the year, and how you remain at $370 million. Are we going to see capital expenditures dramatically curtailed in the latter half of the year? And is this just going to be through working with your vendors to reduce costs across the board?

John C. Regan

Yes, I think you're seeing a couple of things. First of all, Q1 had kind of a disproportionate spend related to the midstream in Canada. It also had a disproportionate spend on acreage acquisitions. And then the drilling and completion activity -- or the drilling activity in Horn River is really weighted towards the winter months. So kind of as we move into Q2 and Q3, we'll see some curtailing of costs there.

Brad Carpenter - Wells Fargo Securities, LLC, Research Division

Okay, great. And then should we assume no further acreage purchases throughout the year? Is it still kind of something that's on the table for the $8 million or so that you put up in the first quarter?

John C. Regan

Well, I think what I'd say is we are committed to the plan to live within cash inflows, but we will certainly be opportunistic if some attractive acreage in the areas where we have operations and other acreage comes [indiscernible].

Glenn M. Darden

But overall, we'll stay within the budget.

Operator

Your last question comes from the line of Kathryn O'Connor with Deutsche Bank.

Kathryn O'Connor

Just a follow-up maybe on that CapEx question we just had. The amount of money that you rolled over from Q4, are we -- what is the adjusted cash CapEx number that you're guiding to given that you had that number? Are we just supposed to add $40 million to the $370 million?

John C. Regan

Yes, I think the challenge is going to be, again, the Horn River will be heavily weighted to Q4. So as I think about what the year-over-year changes in working capital will be, I'm not sure that, that year-over-year change is going to be the $40 million that we saw in Q1. So it may be slightly north of the $370 million, but I would not say substantially north of it. I don't think it's $410 million to be more direct.

Kathryn O'Connor

Okay, that's what I was asking you. Okay. And then the other comments you made about the Permian and that you'll mostly be drilling vertical wells, but you're prepared to go horizontal. Is that accounted for in your CapEx?

Glenn M. Darden

Yes, it is.

Kathryn O'Connor

Okay. And then if you do get the JV done in West Texas, will you then adjust your CapEx based on the proceeds that you receive?

John C. Regan

I think it's going to depend largely on what the nature of the transaction is. And I think we're prepared to move forward with our execution of the plan this year. And really, I can't answer that because I don't know what the terms of that deal are going to look like.

Glenn M. Darden

But Quicksilver is not intending to spend more dollars. Quicksilver won't expand its own budget.

John C. Regan

On a net basis.

Glenn M. Darden

On a net basis.

Kathryn O'Connor

Yes, I guess I was just wondering if you guys end up with some sort of drilling carry in the way that it's set up with that, would you just use the drilling carry? Or would you be open to using above and beyond whatever carry you've got from your partner in CapEx, I guess? That's more directly what I was trying to ask.

John C. Regan

That would help fill the gap between cash flow and CapEx.

Kathryn O'Connor

Okay. And then for that -- for the completion arrangement you have with Eni, what quarter do you think that they're going to end up getting paid back?

John C. Regan

Well, I think it's largely a function of price, but it's going to be outside of 2012 most likely.

Kathryn O'Connor

Okay. So -- but sometime in like early 2013 just depending on price?

John C. Regan

Yes. Well, I think we need to see how the wells come on, but I would think, again, outside of 2012, but anything beyond that would be speculation on my part.

Kathryn O'Connor

Okay. And then maybe I missed it during the course of the call, but I was trying to understand, on a sequential basis, production costs going -- I mean, we kept production kind of flat or we're keeping it sort of flat on a guidance basis from Q1 to Q2. And sort of given what you said about increased production coming on from the Horn River Basin in this Q2, why production costs per unit would then be going up sequentially versus possibly going down?

John E. Hinton

Well, they were kind of -- so quarter-over-quarter, we were in the low 80s for Q1. We're going to be in the same kind of ballpark for Q2 with production being roughly the same.

Kathryn O'Connor

Okay. But I guess if you have more production coming on, you think that, that should help costs. Does that mean that there's some upside to the cost guidance that you gave?

John E. Hinton

Well, the production guidance for 2Q is basically the same as we gave for 1Q, so that Horn River production is going to be coming on, but it's going to be in the latter part of the quarter.

John C. Regan

Yes, I think the earlier question concerned second half versus first half of what the cost structure looked like. So I think you'll see some downward pressure in second half.

Kathryn O'Connor

Okay. So I guess we're not going to see as much of an effect from the Horn River basin. I realize that production's flat sequentially, but I guess we're going to see the Horn River Basin really come in, and that production help your cost when we get to the second half, but there won't be enough of an effect to help, really, the second quarter.

Glenn M. Darden

It may help. You'll see a bigger effect in the second half.

John C. Regan

That's right.

Operator

You actually have a follow-up question from the line of Vivek Pal of Knight Capital.

Vivek Pal

Who are your counterparties for the hedges?

John E. Hinton

They're participants in our bank facility.

Vivek Pal

Okay. And in terms of your acreage in Horn River, how would you compare that to what Nexen recently sold to the Japanese in the JV? Is it -- how would -- is this fair to assume that you'll get similar kind of price per acre or the market deteriorated too much?

Glenn M. Darden

Well, I would say -- the reservoir quality, our well performance is as good or better than anyone in the Horn River Basin. So we'll see what the market's clearing price is, but this is the long-term project for the company, and the players that are looking at it with us are looking at it in the very same way.

Vivek Pal

It's predominantly for LNG, right? Is that a fair statement?

Glenn M. Darden

I would they're looking at it from a number of angles.

Vivek Pal

All right. And lastly, your target for debt reduction of about $900 million, a lot of people have called it very aggressive. But every time you make a presentation, you reiterate how confident you are that you'll get this debt at the end of the year...

Glenn M. Darden

Let's be clear, we have not backed off on that. What we said was the $900 million is over the next several years. We have targeted $500 million of debt paydown this year, and we're still looking at that and targeting that. So our goals have not changed.

Operator

And our final question comes from the line of Steven Karpel with Credit Suisse.

Steven Karpel - Crédit Suisse AG, Research Division

First up, how much of the -- I mean, it's going back a little ways -- but of the Alliance acreage has been developed now at this point?

John C. Regan

You're talking about from the Alliance acquisition in '08?

Steven Karpel - Crédit Suisse AG, Research Division

Exactly. I guess, has all of the acreage been drilled upon, I guess, is the way to say it?

Glenn M. Darden

No, it's probably 80%, Steve.

Steven Karpel - Crédit Suisse AG, Research Division

80% of the acreage or 80% of the locations?

Glenn M. Darden

80% of the acreage. But we have -- of course, we have continued to expand that acreage position since that time.

Steven Karpel - Crédit Suisse AG, Research Division

And maybe the way to ask is then, do you have any drilling requirements then on that acreage still, too?

Glenn M. Darden

Very few.

Steven Karpel - Crédit Suisse AG, Research Division

And maybe across the Barnett and the non-liquids area, what are your drilling requirements over the next 24 months?

Glenn M. Darden

Yes, very few drilling commitments there...

Steven Karpel - Crédit Suisse AG, Research Division

So will you quantify that for us?

Glenn M. Darden

I beg your pardon?

Steven Karpel - Crédit Suisse AG, Research Division

I was just saying if you could quantify across the Barnett, your -- I mean, I know it's a tough specific question, but the drilling requirements in gas or dry gas areas over the next couple of years?

John E. Hinton

I would say, I mean, Glenn said "very few", but we don't have any continuing drilling commitments. We don't have a lot of -- most of our acreage is already held by our production, so I would say it's very few.

Steven Karpel - Crédit Suisse AG, Research Division

Okay. And John, when -- and I didn't quite follow this on the borrowing base renewal. You had said you're okay on the covenants. Did you get any covenant relief or any changes to the credit agreement upon the redetermination? And if not, any reason you didn't? And I know in the past that you haven't had trouble getting the amendments, so why not give yourself even more room and get the market speculation out of there?

John C. Regan

Well, we're still moving to that redetermination point right now. But we have not gone after any covenant changes at this point.

Glenn M. Darden

Yes, we haven't requested any, Steve.

Steven Karpel - Crédit Suisse AG, Research Division

Right, I understand. And then the final one is just maybe a big picture, and I know you -- if you could kind of summarize this for us if -- how do you -- if you want to go 3, 4 years down the line, how do you look at the company? What's the targets? I mean, what is -- what do you tell the board that, I don't know, is it oil/gas percentage, if it's production size, if it's earnings size, if it's what the balance sheet looks like, different areas of plays or -- you've talked a lot about transforming in 2012, but what does the company look like in 3 years, 4 years?

Glenn M. Darden

It looks significantly stronger. And we can't share with you what we talk about with the board, but we're certainly moving toward the oil side with the 2 big projects there. We see a development in the Horn River that kind of drills to fill markets, and that's what we're discussing with potential partners there. We think we'll have a couple of different partners or at least one different partner in West Texas, and we hope we're developing there. So we think our liquids volumes will come up, but we also see an improvement in gas prices. This industry is slamming on the brakes. And it -- the skid marks are long and it takes a while for it to show, but I think we're starting to see it in the supply numbers. And we'll certainly see it in this earnings season, that players with natural gas are being hurt by this low price. So we can hunker down with other gas players and perhaps have a better land position to do that than most players. We have a good debt structure, and I wouldn't be surprised to see some LNG develop on the West Coast of British Columbia. So that's a very long-dated option we have for natural gas in the Horn River and we're going to take advantage of it.

Steven Karpel - Crédit Suisse AG, Research Division

What is your -- what's the Quicksilver 2013 gas price for your models?

Glenn M. Darden

I'm not going to say. I think it will be improved, Steven. I think it will be better. It's certainly not going to be back to the glory days, but I think it will be improved.

Operator

And you have a follow-up question from the line of Kathryn O'Connor with Deutsche Bank.

Kathryn O'Connor

Sorry, just a really quick one. You said in the press release that you expect to close the MLP and the West Texas sale or JV in the summer. Could you just clarify, to you, what that means, summer. Like which month?

Glenn M. Darden

Well, I would say that, that's just as clear as we're going to say. Obviously, we have the SEC to clear on the MLP, and as John said, we can't talk a lot about that. We have bids due at the end of May on West Texas, and we'll close both of those, we hope, fairly shortly after that. But these things take a little time, and I can't pinpoint the day that both will close.

Kathryn O'Connor

Okay. But it's sort of like a June, July, August. I mean to me, that's summer. I just wanted to double check.

Glenn M. Darden

Yes, yes.

Operator

You have a question from the line of Shawn Schniven [ph] of Oppenheimer.

Unknown Analyst

Most of my questions have been answered, but I just wanted to clarify, the $500 million of debt paydown that you're targeting for this year, is that a net number? Meaning, is that net of any incremental debt you add on at the MLP level?

John C. Regan

Yes. That's the consolidated number, consolidated debt.

Operator

At this time, there are no more questions. Mr. Hinton, would you like to make any closing remarks?

John E. Hinton

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

Operator

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

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