Quicksilver Resources' CEO Discusses Q2 2012 Results - Earnings Transcript

Aug. 8.12 | About: Quicksilver Resources (KWK)

Quicksilver Resources (NYSE:KWK)

Q2 2012 Earnings Call

August 08, 2012 11:00 a.m. ET

Executives

David Erdman – Investor Contact

Glenn Darden – President, Chief Executive Officer

John Regan – Chief Financial Officer

Tobey Darden – Chairman

Analysts

Noel Parks – Ladenburg Thalmann

Brian Corales – Howard Weil

Brian Singer – Goldman Sachs

Steven Karpel – Credit Suisse

Scott Hanold – RBC Capital Markets

James Spicer – Wells Fargo

David Epstein – Wedbush Securities

Louis Nardi – Buckman & Reid

RJ Cruz – US Fixed Income

Maryana Kushnir – Nomura Securities

Operator

Good afternoon. My name is Erica and I will be your conference operator today. At this time, I would like to welcome everyone to the Second Quarter 2012 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you.

I would now like to turn the call over to Mr. David Erdman. Mr. Erdman, you may begin your conference.

David Erdman

Thank you, Erica, and good morning, everyone. I’m joined by Toby Darden, Chairman, Glenn Darden, President and Chief Executive Officer, and John Regan, Chief Financial Officer. This morning the company issued a press release detailing our results for the second quarter of 2012. If you don’t have a copy of the release, it’s available on the Investor Relations page of our website, at www.qrinc.com under the News and Updates tab.

During this morning’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 will be 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, a reconciliation of adjusted net income to the most directly comparable GAAP measures are available with the press release we issued this morning.

So with that, I’ll turn the call over to Glenn Darden.

Glenn Darden

Thank you, David. Good morning. Quicksilver Resources today announced preliminary 2012 second question results. The adjusted net loss for the second quarter, a non-GAAP financial measure, was $21 million or $0.13 per diluted share compared to adjusted net income of $11 million or $0.06 per diluted share in the 2011 period. Including the impact of one-time items, the net loss was $673 million or $3.96 per diluted share.

Second quarter 2012 results were impacted by a $992 million non-cash impairment of oil and gas properties due to lower average natural gas and NGL prices compared to the 12 months ended March 31, 2012 and a non-cash gain of $8 million related to the change in hedge ineffectiveness. John Regan, our Chief Financial Officer, will provide the details with his discussion.

Quicksilver is aggressively attacking costs and cutting capital expenditures with these low gas prices. In addition, we have amended our credit facility, which gives the company more flexibility to execute our plan. We have pushed out capital commitments in all areas of operations and we will walk through those changes on this call.

We’re seeing production improvements in the field in our newer areas and progress with securing outside capital for our projects. Quicksilver has slowed spending in the core dry gas areas of both the Barnett and Horseshoe Canyon areas due to the low gas prices. Even though we realize roughly $6 per Mcf equivalent on the wet gas marketed at Mont Belvieu in our wet area of the Barnett, we have slowed to keep capital inside of cash inflows. We do not have lease expiration issues in either of these areas, so we will accelerate the developments again with better pricing.

The Barnett MLP has received the green light from the SEC, but we are currently on hold awaiting better marketing conditions. We remain committed to monetizing a portion of the Barnett this year in order to reduce company debt and whether that comes in the form of the MLP or perhaps an asset sale will depend on value.

Moving to Canada, the Horn River Basin is looking very, very good. It appears that we are in an excellent area of the Basin geologically with well-developed sections of both the Muskwa and Klua formations in the Devonian section which exceed 520 feet of combined thickness. Our first multi-well drilling pad alternated Muskwa and Klua wells so that no completed section was closer than 1,200 feet to the next comparable well. From previous results, we have recognized the tremendous potential of the Muskwa, and with this new pad coming on line, we see the capability of the lower Klua section to be as strong or stronger.

Shortly after the end of the second quarter, Quicksilver finalized completion operations on this eight well pad. Production has been curtailed due to flow limitations of the test equipment, but individual wells have tested at rates between 20 million and 30 million cubic feet of gas a day. These wells were drilled with 6,000 to 8,500 foot laterals, depending on the lease boundaries. At this point, these eight wells have an estimated production capacity in excess of 150 million cubic feet of gas per day. To put that in perspective, this one pad which comprises less than 1% of our acreage position in the Horn River Basin can bring on gas volumes equal to 40% of our current total company production.

We will continue to flow the wells into completion clean up and then curtail this production to levels required to meet pipeline and processing commitments over the next year. We project the prolific nature of this production will allow us to drill fewer wells to meet these obligations going forward. We have pushed out some of these commitments and John will give you more details in his remarks.

Currently, we have 60 million cubic feet of gas a day hedged in Canada for this year at $5.82 per Mcf. As we have previously discussed, our team has been working hard on the downstream part of this project and we are making good progress on connecting this large supply of gas with end users. There’s significant interest in Western Canadian Gas underscored by recent M&A activity. We believe that the HRB is well positioned for the export market. We will update you on this side of the project as it develops.

Quicksilver’s Niobrara project in Northwest Colorado is steadily improving. We are convinced that we have captured an area with several hundred million barrels of oil recovery potential and are beginning to see a consistency of results. Our operations team is lowering drilling and completion costs and improving production results. These vertical wells are coming in at roughly 100 barrels of oil equivalent per day, mostly high gravity oil and rich liquids, at a development cost of close to $3.2 million. The decline curves are relatively shallow and early results are similar to our analogue composite decline curve made up of 80 historical wells that have produced in the area. With 1,200 feet thick section of Niobrara under our acreage, it appears this play may be drilled vertically.

Quicksilver is moving to the completion stage in two wells in our West Texas project, one in the Third Bone Springs in Pecos County has been fracked and one in Wolfcamp formation in Upton County which will be completed shortly. We have been encouraged with excellent shows while drilling and are seeing oil in the early stages of flow-back in the Pecos County well. We should have both of these wells on production in the fall and look forward to reporting those results.

We’ve also made good progress on the JV front and are in advanced stages of negotiations on two joint venture transactions. Our objective is to cover the company’s development cost exposure on all of our new venture projects. Because we have executed non-disclosure agreements as part of these negotiations, we will not be giving any additional information on this call. Our target is to complete these transactions in 2012.

The Quicksilver team has been very busy on multiple fronts. By working with our bank group, we have made certain there are no near-term liquidity issues. The company’s bond debt has longer dated maturities, the first of which is August in 2015. Quicksilver’s hedge position remains a key asset and our 2013 hedges cover almost 50% of projected production at $5.30 per Mcf.

In the marketplace, we are finding players who are taking a longer-term view of the natural gas commodity, and with the quality of our asset base this matches up well. In fact, despite today’s spot price, we are seeing more interest from multiple parties seeking long-term gas reserves.

Quicksilver’s grassroots oil projects are gaining traction and we are building asset value there as well. This is a pivotal year for the company and there’s a lot more value in the assets than is reflected in the stock price. We look forward to reporting on the progress in the coming months and unlocking this value.

And now I’ll turn the call over to John Regan to discuss the financial details. John?

John Regan

Thank you, Glenn. Before I dive into this traditional discussion on the financial results, I’d first like to talk about what we’ve done to improve Quicksilver’s flexibility, much of which Glenn highlighted in his remarks. We worked with our bank group to amend the interest coverage covenant in our credit facility. We have said previously that we believe we would comply with our covenants for this year and that continues to be the case, but with the deterioration in NGL prices that started a few months ago, our projections indicated that compliance would become more difficult.

Our banks overwhelmingly supported our request for a reduction in the interest coverage ratio, and along with that request we also accelerated the fall redetermination. So I’d like to cover the key elements and provisions of the amendment and the redetermination, which we closed yesterday. First, the borrowing base was reset at $850 million, with no change in the global LC capacity, which is $200 million. Most notably, our interest coverage requirement was amended downward from 2.5 times to 1.5 times, where it remains through March 2014 before stepping up to 2 times in June 2014 and back to the original 2.5 times in September 2014. The lenders also added a senior secured leverage covenant of 2.5 times, which will begin in September 2012.

Another key component of the amendment is that the lenders now limit our ability to pay down bond debt to the extent utilization of the credit facility exceeds 25% on a pro forma basis. This provision, however, does not completely restrict our ability to reduce bond debt as we could and likely would seek approval from our vendors to direct some or all asset monetizations towards bond repayment. Other changes to the facility include an upward adjustment to the pricing grid by 50 basis points and a limitation on the incurrence of certain new debt and restricted payments.

I would like to highlight that certain of these limitations fall away the later of June 2013 or when our total debt to EBITDA is equal to or less than 4 times. The facility will continue to be redetermined on a semi-annual basis, with the next scheduled review in April 2013. The amended agreement is included with our 10-Q which we expect to file in the next day or so.

The reduction in the interest coverage ratio affords Quicksilver tremendous flexibility to manage the balance sheet and additional time to execute on our plans to complete JVs, develop our emerging assets and benefit from the projected commodity price increases suggested by the forward natural gas curve. Despite the reduction in the borrowing base, we don’t foresee any liquidity issues given our reduced capital program for the remainder of 2012, as well as the expected reduced near-term LC commitments in Canada and the potential for asset sale proceeds.

With respect to the incurrence test governing our bonds, which is an interest coverage ratio of 2.25 times, our internal projections show we will continue to meet this test this year. I do want to point out that if we were to not meet the test, our business plans and our liquidity position would not be materially affected. The consequence of falling below the 2.25 threshold is that we would be precluded from incurring debt outside of our credit facility until our coverage ratio exceeds that threshold. However, there is no acceleration of scheduled repayment. We’ve discussed in the past that we intend to reduce debt through asset sales to address our leverage, and those efforts are ongoing.

To update you on our proposed IPO of Quicksilver Production Partners, as Glenn mentioned, we have received a No Further Comments letter from the SEC, but current market conditions particularly on the NGL pricing front, are not ideal to launch the IPO today. However, we are encouraged by the recent trends in natural gas and NGL prices. While we can’t point to an exact time when we would begin a marketing effort, we continue to believe an MLP is an attractive way to monetize the mature Barnett assets regularly over time.

We’ll obviously remain flexible with how we approach our asset monetizations, but our resolve to reduce debt is unchanged. As Glenn also mentioned, negotiations for joint ventures have gained ground and we’re confident that we can raise the cash necessary to fund our emerging plays in 2013 and beyond.

Shifting over to the earnings discussion, for the second quarter our net loss was $673 million or $3.96 per diluted share. This compares with net income of $109 million, or $0.61 per diluted share, in the 2011 quarter. Our adjusted net loss or clean earnings for the second quarter of 2012, which I remind you is a non-GAAP measure, was $21 million or $0.13 per diluted share versus net income of $11 million or $0.06 per diluted share in the 2011 quarter.

Our adjustments to arrive at adjusted net income are outlined in our earnings release. They include, non-cash impairment of oil and gas properties which resulted from rolling in second quarter commodity prices that were substantially lower than the second quarter of 2011, non-cash gains related to hedge ineffectiveness and non-recurring audit fees for our registered independent accounting firm.

We computed the second quarter U.S. ceiling test using a trailing 12 month gas price of $3.15 and an NGL price of $35.61, which is 15% lower than the average gas price used in Q1 and 28% lower than the average Q1 NGL price. In Canada, we used an AECO price of $2.72, which is 25% lower than the Q1 price. The hedge ineffectiveness item arose primarily because the correlation between AECO and NYMEX for the outer years of our long data hedges converged during the second quarter.

From a production standpoint, production was 359 million cubic feet of natural gas equivalent per day in the second quarter, down approximately 5% from the first quarter and 14% from the 2011 quarter. These declines were largely caused by our scaled-back completion program in the Barnett. Early in the second quarter, we shut-in several production pads in the Barnett that had negative economics at then prevailing prices, though these shut-ins impacted production by less 10 million a day. We also shut-in some adjacent wells to accommodate the alliance completion program that we entered into with Eni.

Production was also lower in the quarter compared to previous guidance due to the delay in the completion of the Horn River eight-well pad. We deferred bringing the wells online due to the delayed start of third party treating facilities, which also delayed a step-up from our commitment of 30 million a day. You heard earlier from Glenn about the exceptional results from the Horn River pad. Despite this pad’s strong productive capability, we intend to restrict its production in the near term to optimize midstream commitments now and in the future. We believe this pad will allow us to meet a substantial portion of these commitments well into 2013.

We had an average realized price of $3.98 per Mcf in the second quarter, which is down $0.36 from Q1 and $1.08 from the 2011 quarter. Average NGL realized prices were $39 a barrel compared to over $43 in Q1. On an equivalent basis, we averaged $4.61 per Mcfe for the second quarter. On an unhedged basis, realized prices on an equivalent basis were down over 40% from the 2011 quarter. Despite the weakness in NGL prices and without the benefit of hedges, we are still able to realize over $6 per Mcfe at the wellhead from the liquids-rich portion of Barnett production and we maintain firm transportation to Mont Belvieu.

Production revenue was $151 million for the quarter, which is down $21 million from the first quarter and $57 million from the 2011 quarter. The decline compared to both periods is due to production declines, lower prices and indirectly by our capital spending pattern. Compared to the first quarter, lower commodity prices accounted for $17 million of the $21 million decline. Compared to the prior-year quarter, lower commodity prices accounted for $43 million of the $57 million decline. Other revenue for the 2012 quarter is almost entirely comprised of the hedge ineffectiveness item I mentioned earlier.

Now on to expenses. LOE was $0.66 on an equivalent unit basis for Q2 compared to $0.84 for Q1. We accomplished the sizable decrease through our Barnett shut-in program in the second quarter, which reduced LOE by approximately $1.5 million or $0.05 per unit. The remaining reduction in LOE is related to lower saltwater disposal volumes and lower gas lift volumes. LOE in the Horseshoe Canyon dropped $0.25 per unit due to lower well and compressor repair and maintenance costs. We believe the third quarter blended LOE rate will remain in the low $0.60 range as certain Barnett production pads remains shut-in and we get the benefit of a lower gas lift rate in Lake Arlington, which was a negotiated reduction that became effective July 1.

Also, our increased volume in the third quarter from the Horn River will be spread across that asset’s fixed cost base. Gathering, processing and transportation increased $0.05 over the Q1 rate, mainly due to a fixed transportation charge to deliver a portion of our Horn River gas.

Unit cash expenses for LOE, GPT, production and ad-valorem taxes and recurring G&A in the second quarter were $2.54 compared with $2.66 in the first quarter. At our average realized prices for the quarter, our cash margin was $2.07 on an unlevered basis. On a levered basis, recurring cash interest expense is $1.32 per Mcfe, so cash margin was $0.75 or 16% on revenue.

We expect to see further improvement in our unit cash expenses going forward due to the factors I identified earlier. We maintain a strong hedging position for the remainder of 2012 with a total of 230 million cubic feet per day of gas hedged at a weighted average floor price of $5.75 and we also have 7,000 barrels per day of NGL hedged at $45.

For 2013, we have a total of 160 million cubic feet of gas per day hedged at a weighted average price of $5.30. Our Canadian portfolio includes 60 million cubic feet per day for the remainder of 2012 at a weighted average price of $5.82 and 40 million cubic feet per day for 2013 at a weighted average price of $5.62. In the aggregate, the fair value of our hedged portfolio was nearly $350 million at quarter end.

As a reminder, our GAAP revenue continues to be impacted by the hedge restructuring program from earlier this year. The value of the hedges that were restructured will be amortized into revenue over their original 10-year term even though we received the cash on a more accelerated basis. Thus, there is a disconnect between the cash benefit of the hedges and their income statement impact.

Generally, the cash receipt proceeds the income statement recognition, so any model that assumes cash equal to revenue would be inaccurate and have the effect of overstating revenue compared with actual results. However, our operating cash flow does reflect the collection of proceeds under the restructured hedges. We will be looking for near-term opportunities to layer on 2013 NGL hedges should the market for liquids improve and to opportunistically bolster our natural gas hedging levels.

Turning to capital spending, we incurred $156 million of capital in the second quarter or $291 million for the first half of the year. Nearly 70% of our capital budget was weighted to the first half of the year as we drilled to satisfy commitments in Horn River and we utilized the second drilling rig in the Barnett for a portion of the first quarter. As disclosed in our press release, we are reducing capital spending for the remainder of 2012 and expect to do the same into 2013 unless gas prices improve significantly.

To detail what we’re doing, we’ve reduced 2012 capital spending by $50 million from budgeted levels to address weakness in gas prices and NGL prices. Our new full-year projection for capital expenditures is $360 million versus an original budget of $410 million, which means we’ll spend about $70 million in the second half of this year across all of our asset bases.

Since we have a lot going on with the Horn River asset, let’s deal with that one first. The good news here, as Glenn and I eluded to earlier, is that we believe the eight-well pad we just completed in the Horn River has the capability to meet takeaway commitments well into 2013, so we don’t anticipate having to drill to fill commitments in the Horn River until 2013. Also, we’ve extended the in-service state of the NOVA Komie North pipeline extension to the summer of 2015 from our original scheduled date of April 2014.

This election effectively defers into 2014 capital spending – I’m sorry, this election defers into 2014 capital spending originally planned for 2013 and will immediately reduce LC commitments to NOVA by approximately $45 million. We expect we’ll have about $20 million in LCs in place for this project from August 2012 through at least December 2013, which is a significant reduction from the amounts we reported in our 10-K.

We’ve eliminated Horn River drilling capital for the remainder of 2012 since we are deferring the 2012 winter drilling for the reasons I outlined. The well performance and midstream deferral may have a more pronounced downward impact on our 2013 capital budget.

I want to point out that our current plan will optimize our commitments to third parties in the Horn River, including the capital spending obligations of the Fortune Creek partnership. To clarify that capital spending obligation, we must invest $100 million of capital per year for three years or an aggregate of $300 million over three years.

We can, however, carry over amounts spent in excess of the per year minimum. Our capital spending in the Horn River for the full year 2012 meets roughly 60% of the $300 million three-year investment target. And we have already met 90% to 95% of our minimum 2013 spending commitment with the carryover from the 2012 capital program.

In the Barnett, we’re scaling back plans for the second half of this year and now expect to drill four wells, complete six wells and connect eight wells to sales. Our expected uncompleted inventory at the end of the year is 24 wells. We’ll have some flexibility for next year, as the contract for the rig we currently have deployed ends at the end of 2012 and we have no material takeaway obligations.

In the Sand Wash Basin, we anticipate drilling one well and completing two wells in the second half of the year. We expect to defer construction of a gas and liquids pipeline, we are planning to renew some leases that are expiring in the back half of 2012 and in 2013. And, finally, in West Texas, we expect to drill and complete two wells for the remainder of 2012.

We’re currently beginning our 2013 capital budgeting process and expect to release that information to you in the fourth quarter. As we think about it today, capital spending levels next year will be less than 2012 as we align the budget with commodity prices and take into account the deferred commitments in the Horn River Basin and the flexibility we have in the Barnett asset. Our ultimate objective, however, will be to spend within cash inflows.

Our operating cash flow in the second quarter was $72 million. Even though we continue to be in an earn-out period for all of 2012 with the respect to the Crestwood sale, we currently don’t anticipate being eligible for a payment in 2013, given the scale-back in the Barnett by us and by other operators.

Total debt at quarter end was approximately $2.1 billion. On a pro forma basis, we have roughly $410 million utilized under our credit facility after the release of the previously-mentioned Canadian LCs.

Now I’ll turn the call back over to David to cover our third quarter guidance.

David Erdman

Thank you, John. Third quarter 2012 production volume is expected to be between 385 million cubic feet per day and 400 million cubic feet per day. Full-year production volume is expected to be 365 million cubic feet per day to 380 million cubic feet per day. Average unit cost on an Mcfe basis are expected as follows, lease operating expense between $0.60 and $0.64, gathering, processing and transportation between $1.16 and a $1.20, production taxes between $0.21 and $0.23, G&A between $0.43 and $0.47, and, finally, DD&A between $1.30 and $1.35.

So with that, Erica, let’s open the line for questions.

Question-and-Answer Session

Operator

(Operator Instructions) You first audio question come from the line of Noel Parks.

Noel Parks – Ladenburg Thalmann

Good morning.

Glenn Darden

Good morning.

David Erdman

Good morning.

Noel Parks – Ladenburg Thalmann

A couple of things. In the Niobrara, can you talk a bit about the distribution of wells you have a across your acreage, basically how much of it you feel like you have a handle on at this point?

Glenn Darden

Yes, Noel. We have drilled wells across the block which, in total, encompasses about a 1,000 square miles of area. And across that block, we have seen kind of average thicknesses of 1,200 feet of Niobrara within that section, which from all of our testing is without water and 100% oil charged across that area.

Noel Parks – Ladenburg Thalmann

Okay.

Glenn Darden

We have been moving through an evolution of treating procedures that have gotten less expensive and more productive, and we’re very encouraged by those results.

Noel Parks – Ladenburg Thalmann

Great. And can you just talk a bit about the EUR figure, the 200,000 barrels that you’re looking at? You’re – can you talk about your sort of oil/gas split assumptions in there? And also sort of what’s the scatter? Do a lot of the wells look like they, from what you have so far, will be right around 200,000 BOEs? Is it a wide range you have to get to that average?

Glenn Darden

Well, there are a number of questions in there, Noel, so I’ll try and address one at a time. Of the reserve number we’ve quoted, about 60% of that is oil and probably another 20% of that is NGLs. And if you could repeat the last half of that?

Noel Parks – Ladenburg Thalmann

Oh, just the 200,000 BOE average you have for an EUR, is that fairly consistent from what you’ve seen so far? Or is there a wide range that just centers at about 200,000 BOEs?

Glenn Darden

Well, where we’ve drilled multiple wells in one area, we’re seeing consistency. We’re seeing some inconsistency across the entire area. But that is largely due to differences in treatment for the wells, I think more so in geology as far as we can tell. So, the section looks very consistent. We have fracturing across a very large area of our acreage and we think ultimately the results based on our later treatments are going to be much – very consistent across that area.

Noel Parks – Ladenburg Thalmann

Okay, great. And, I guess, just the last one for me. If you have any thoughts about sort of where you think – or updated thoughts on what you think spacing would be like across the position ultimately? And just from some remarks you made earlier about having the – with the transactions having the CapEx to develop it, it sounds like you’re thinking in the Niobrara is headed more towards the development mode. So, is that your assumption that you’ve seen enough success that you’re starting the planning to actually develop the entire position or a good portion of it?

Glenn Darden

Well, I’ll put it this way. We have acquired rights of way for mid-stream infrastructure to maximize recovery of NGLs, maximize value for the natural gas. So we believe we’re heading towards the development phase of this project. We will begin in the areas where we started our test drilling because we’ve got more data and more density of wells in those areas, so it will be easier to create economies of scale in those areas. And we’ll gradually bring the to more outlying areas into the development later.

Noel Parks – Ladenburg Thalmann

Great. And the spacing you’re modeling at this point?

Glenn Darden

Yeah, and on spacing, we’re not yet sure. We’ve just drilled one area on about 160s. We think that spacing will definitely come down over time. We have had the benefit of running micro seismic in this area, so we now have some idea on the extension of our fracs. So, we’ll be refining our spacing model as we move along. But this latest round of more densely spaced wells gives us a much better idea of what ultimate spacing will be.

Noel Parks – Ladenburg Thalmann

Great, thanks a lot.

Glenn Darden

Thank you, Noel.

Operator

Your next audio question comes from the line of (inaudible).

Unidentified Analyst

Hey. Good morning, guys. Just a couple of quick ones for us. Can you talk a little bit about I guess the production outlook for 2012 exit and how should we think about that heading into 2013, given today’s gas prices and kind of where everything stands?

Glenn Darden

Well, obviously, a theme of this call is ratcheting back in recognition of these prices. So while we have the capability in the Horn River to ramp up as prices improve, but we’re going to keep that governed to just downstream commitments. But in terms of guidance, we have the capability to ramp up in the Barnett, we have the capability to ramp up in several places. These oil projects will be producing more oil in 2013.

So we haven’t given guidance. We’ll give year-end guidance, I guess, we’ll get closer to year-end before we talk about 2013. But I guess we’ll watch the commodity price a little bit. We have the ability to ramp it up, if we’d like, if prices are better. And a certain part of this will be dependent on completing these JVs to accelerate some of these new projects.

Unidentified Analyst

Okay. And I guess just a little quick follow-up on the impairments. Should we expect more impairments to come along as the average keeps on coming down, given the past couple weeks here and just the averaging effect for Q3?

John Regan

Yeah, I think there is some risk in that regard. As you know, it’s a trailing 12-month calculation of prices that get incorporated into the calculation. And as we think about what rolled in for July and August of 2012, those prices were lower than we saw in July and August of 2011. So, we’ll need to see where the September price comes out, but I think you’re accurate in suggesting that there is some risk there.

Unidentified Analyst

Okay, thank you very much. That was it for me.

Glenn Darden

Thank you.

Operator

Your next audio question comes from the line of Brian Corales.

Brian Corales – Howard Weil

Good morning, guys.

Glenn Darden

Good morning.

Brian Corales – Howard Weil

A follow-up on the Niobrara. Can you talk – I think you mentioned the costs were little over $3 million. Can you mention maybe where that came down from and where kind of you expect those to be a year from now if you truly are in development mode?

Toby Darden

Sure. Our new fracs are water-based fracs which are much more cost efficient. We have just pumped our first round of those. They’re significantly less expensive than other forms of hydrocarbon fracking, which we were doing prior to that. And we came down from the mid $3 million range to the low $3 million range in our first wave. And we expect those costs, as they do in every one of our plays, to continue to decline for some time here as we get economies of scale to pursue this operation.

Glenn Darden

Yeah, and I would say, Brian, that – remember that a lot of – we’re doing a lot of science out here. So, these early wells are never the development economics. They’re always higher. But, as Toby said, our team is doing a great job of driving those costs down already before we’re moving into full development.

Brian Corales – Howard Weil

And so these eventually could be sub $3 million wells if – over time?

Glenn Darden

We believe that’s right. Yeah.

Toby Darden

We firmly believe they will be less than $3 million.

Brian Corales – Howard Weil

Okay, that’s helpful. And then looking kind of big picture, and I know you can’t talk too much about the JVs. But, I mean, is the Niobrara a candidate for a JV? Is this something you want to keep 100% to yourself? How does that fit in the picture? And then on top of that, have you all done anything additional in the Alberta Bakken? As I know some other companies are increasing activity a little bit.

Glenn Darden

To answer the last question first, we have not done anything additionally on the spending side. We’re obviously monitoring what’s going on around us in the Alberta Bakken.

Brian Corales – Howard Weil

Okay.

Glenn Darden

And as far as the JV side, I would say any of our new projects are open on the JV side, so we are going to put capital structures in place in each of our areas to be able to fund these projects going forward.

Brian Corales – Howard Weil

Okay. And just a follow-up there. If I’m thinking about this right, by the end of 2012 potentially, I know things can change depending on markets, but you could have the MLP as well as two JVs all around by the end of the year or ballpark timing?

Glenn Darden

JV and/or asset sale in Barnett, yes. And a couple of JVs, that’s what we’re looking at.

Brian Corales – Howard Weil

Okay, all right. Well, thanks so much.

Glenn Darden

Thanks.

Operator

Your next audio question comes from the line of Brian Singer.

Brian Singer – Goldman Sachs

Thanks, good morning.

Glenn Darden

Good morning.

Brian Singer – Goldman Sachs

On the Horn River Basin, you’ve referenced export is the potential destination there. Can you just talk to timing of greater clarity on that solution? And does that come as a JV or an asset sale as well?

Toby Darden

Well, Brian, to put it from wellhead downstream, the actions we’ve taken to put our transportation and processing infrastructure together have greatly enhanced our ability to get our gas to multiple markets, including the West Coast of BC. We probably are doing it at a slightly lower cost than our peers in the play. So we’re very happy with the progress our team has made in solidifying our downstream transportation and processing. On timing, export facilities from the West Coast are probably, at the earliest, 2018 and so that’s kind of the timing there.

Brian Singer – Goldman Sachs

Okay. So your plan would be to sell directly to the export facility not to be a part of the export facility itself. And that you would not necessarily sell a stake in anything that you have, you would just be providing the gas on the upstream side.

Glenn Darden

Well, we didn’t make that statement. And we won’t finely parse that, if you will. I think that what we’re working on is an overall solution. And in my comments ahead of this, what I talked about was the strategic nature of the location of this gas. And, obviously, it’s being borne out in transactions on the M&A side, in joint ventures, and I think that this is a lot more strategically a lot better located than perhaps people are giving it credit for. And there’s certainly a lot of momentum going on the downstream side, on the export side. We need a big player alongside of us to play that game, but we’re moving in that direction.

Brian Singer – Goldman Sachs

Okay, thanks. And then lastly, on the Barnett, just to kind of clarify some of the backlog-related numbers. I think you had said, you said in your release your backlog this quarter was 24. I think you may have mentioned you expect 24 at year end as well. It looks like that backlog, just looking at your last release, was 54, but you drilled 7 and tied in 14. Can you just clarify how your backlog has moved and where you expect it to move?

John Regan

Yeah, the big thing that you probably don’t account for in there is that E&I completion program with the 12 wells. So, I think we discussed that in our last call, but those effectively came out of inventory even though they’re not tied into sales from a Quicksilver perspective.

Brian Singer – Goldman Sachs

Okay. And flat at the end of the year. I heard you correctly earlier, 24 now, 24 at the end of the year?

John Regan

Correct.

Brian Singer – Goldman Sachs

Great, thank you very much.

Glenn Darden

Thanks, Brian.

Operator

Your next audio question comes from the line of Steven Karpel.

Steven Karpel – Credit Suisse

Good morning.

Glenn Darden

Morning.

Steven Karpel – Credit Suisse

I just want to understand kind of two-fold on the MLP front. I know you can’t comment too much, but you said you’re waiting for better conditions in the market. And I guess I’m trying to understand what those better conditions are? I think about the gas market has improved, the equity markets seem pretty good and the yield markets, credit markets seem pretty strong. And then, secondly, I don’t know that I’ve heard you say it in such a clear way of considering something other than an MLP for those assets. Is that a change or is that just maybe I’m paying more attention now?

Glenn Darden

Well, what I would say and I’ll pass it off to Toby, but we have a lot of assets in the Barnett and a small subset is devoted to the MLP. And what I was trying to say there, Steven, is that the MLP is there but we may do something in combination with the MLP or we may do bigger a asset sale. Toby, you want to add to that?

Toby Darden

Sure. Well, let there be no mistake, the management of Quicksilver is firmly committed to de-levering this company. We see our Barnett franchise, which is among the top four in the play, as the primary driver in this de-levering effort. We’re currently in discussions with several parties regarding a variety of structures to maximize the value of this asset for our shareholders and achieve our delevering goals.

The structures could include utilizing the MLP or asset monetization, development JVs or some combination of those to bring down debt levels for Quicksilver. So that’s the way we’re looking at the MLP particularly. It’s a vehicle that is approved and ready to go and it may be a part of our delevering structure.

Steven Karpel – Credit Suisse

Understood. And if you could comment, maybe this is more for John, about the borrowing base. Can you talk about what the borrowing base was and if there’s anything between the Canadian borrowing basin and U.S. borrowing base that’s different? And then upon the MLP, what would happen to the borrowing base?

John Regan

Okay, so the borrowing base prior to the redetermination was $1.075 billion. And, the reason for the reduction of the borrowing base was largely driven by different price deck utilized by the banks as well as kind of the rolling off of some of the hedges that are expected to roll off over the course of the next eight months or nine months until the next redetermination. In the event of the MLP launch, there is a $200 million reduction to the overall borrowing base. And I would say that also as part of the redetermination there’s not a significant change in the allocation of the Canadian base to the U.S. base.

Steven Karpel – Credit Suisse

And what do you currently contemplating then will be the MLP borrowing base, meaning the $200 million that you would – that would get a reduction? Would that be offset by a MLP borrowing base?

John Regan

We do expect there will be an MLP borrowing base, although the banks haven’t sharpened their pencils on that number yet. But that’s what we’re working with them now on.

Steven Karpel – Credit Suisse

And then finally, this is kind of a bigger picture question that I know you’ve answered a few times over the years as people have asked you, your maintenance capital. If maybe, Glenn, if you think about how you look at the maintenance capital today, and I think in the past you’ve done it on a number of wells, so given the reduction in capital and what you’ve seen and given maybe some of the reduction we’ve seen in production certainly on a sequential basis, can you talk about how you view “maintenance” or what it takes to keep production flat at this type of context? And maybe we’ll use the Q3 numbers because those are better numbers than the Q2.

Glenn Darden

Yeah, I think just on paper, if we were drilling purely Barnett, we could keep production flat for $100 million to $125 million, something like that. That’s not the way it plays out in practice. Obviously, we’ve got better results in Horn River. We can – we’ve spent dollars there, we can ramp that up as the markets improve. But we’re not as concerned with keeping the production flat as kind of solving our longer-term issues of funding our multiple projects and reducing debt.

And so we may see production – you will see production come down a little bit, as we’ve talked about in this call, for 2012, but we have plenty of capability of ramping that up significantly as prices improve. And fortunately, we don’t have a lot of commitments on the leasing side, on the downstream side that require us to spend dollars in bad commodity price environments. So the way we’re looking at it is we’re going to knock down debt, we’re going to get these projects funded and you’re going to see this company on a pretty steep growth path, following the accomplishment of those things.

Steven Karpel – Credit Suisse

Thank you very much, gentlemen.

Glenn Darden

Thank you, Steve.

Operator

Your next audio question comes from the line of Scott Hanold.

Scott Hanold – RBC Capital Markets

Good morning, gentlemen. Congratulations on a solid quarter, especially on the cost control side.

Glenn Darden

Thank you.

Scott Hanold – RBC Capital Markets

My first question, with regards to the West Texas net acreage amounts, would you be able to break that out for me in terms of how much is in each of those four areas?

Toby Darden

Yes, the primary areas we’re focusing are on our Pecos County and in Crockett and Upton County. And we have about 35,000 acres in Crockett and Upton and we have about 45,000 to 50,000 acres, and I say that with some encouragement, in the Pecos area. So, those are the two areas of focus. We have additional acreage to the west of that but we are focusing our capital on the eastern two blocks.

Scott Hanold – RBC Capital Markets

Okay. And then I guess there’s 50,000 in the Presidio area and then the remainder would be in the Jeff Davis area.

Toby Darden

That’s correct, Scott.

Scott Hanold – RBC Capital Markets

Okay. Any initial thoughts about horizontal potential here?

Toby Darden

Yes, we have – we are completing our first horizontal in the Pecos County area. We’ve seen excellent shows throughout the drilling and through the flowback of our first stage of frac, really just beginning the complete flowback now.

And we are planning to drill a horizontal out of vertical wellbore in Crockett and Upton to maximize that opportunity as well. So, we do see horizontals as an important part this play. With such a thick vertical section to deal with there, you want to make sure you’re not leaving things behind. So we drilled a number of verticals to evaluate the section and are now drilling horizontals in what we believe are the earliest most prospective parts of the vertical play.

Scott Hanold – RBC Capital Markets

Okay. And then I know that you’re limited as what you can say with regards to the potential JVs. But I guess are you looking to get just JV the Eastern areas or is it going to be all across your Permian acreage? What are your thoughts on that?

Toby Darden

Well, as we said earlier in the call, we’re pursuing pursue JVs on several properties and we’ve made significant progress in the efforts on these JVs. We see the JVs on assets outside the Barnett as major drivers for the growth of Quicksilver. And we’ve assembled a great position in several very significant plays which are going to enhance the value for our shareholders. We’re now under an NDA, or under NDA and in detailed negotiations on a couple of JVs. And due to the delicate nature of the negotiation in terms of our agreements, we can’t provide any further information on discussion.

Scott Hanold – RBC Capital Markets

Okay, fair enough. And just one last one question. Can you just give us a sense of where your coverage and leverage ratios stand currently?

John Regan

Yeah. That’s – that’s probably detail we don’t want to get into on this call. So, are you talking about where the covenant is or where we actually stand?

Scott Hanold – RBC Capital Markets

Where you actually stand, because you updated the covenants? So I was wondering where you are relative to those terms.

John Regan

Yeah, I guess my response would be that we are in compliance.

Scott Hanold – RBC Capital Markets

Okay, fair enough. Thank you so much.

John Regan

Thank you.

Operator

Your next audio question comes from the line of James Spicer.

James Spicer – Wells Fargo

Yeah, hi. Good morning, guys. I’ve got a couple of questions, really just more clarifications. The first one is that you mentioned that under your amended credit facility there were limitations in your ability to pay down bond debt. But then you also said that potentially using asset monetizations you could do that. And I just was unclear on exactly what – if you could or you couldn’t and what will be governing that.

John Regan

Yeah, so the repayment of bonds, we are limited in being able to do that until the borrowing base is less that 25% drawn. However, in the models that we’ve shared with our lenders, it is clear that to the extent that we had cash at our disposal that it is far better for our leverage position to retire bonds than it is to take out credit facility debt, which you know features a much lower interest rate.

So in the event we were to have cash in hand, we would likely approach our banks and ask them for permission to direct some of those proceeds towards bond repayment. So it is not a – we are not precluded from doing it, and we expect that the banks would listen to us and likely allow us to retire some portion of bonds.

James Spicer – Wells Fargo

Okay, that’s helpful. And then, secondly, on the CapEx budget, if I look over the past two quarters, it looks like you’ve talked about your CapEx budget being $370 million for the year, and now it’s down to $360 million. But you had also said that previously it was $410 million. So, I’m just wondering whether I missed something or where that $410 million number came from originally?

John Regan

The $370 million was kind of the direct capital spend. As you know, for accounting purposes we have things like capitalized G&A and capitalized interest that are also required to be recognized. So the $370 being the direct plus, call it, a roughly $40 million of indirect capital, got us to a total capital program of $410 million. On an apples-to-apples basis, including those indirect expenses, the $360 million does include those. So, on an apples-to-apples basis, it is a $50 million reduction.

James Spicer – Wells Fargo

Okay, understand. Next, I just wanted to be clear, it sounds like if you were to pursue a Barnett or just some sort of an asset sale on the Barnett outside of the MLP, that would not preclude you from doing in MLP, is that correct?

John Regan

That is correct.

James Spicer – Wells Fargo

Okay. And then, lastly, you may have already answered this. But the JVs that you’re working on right now, have you’ve been specific about which assets they’re related to?

Glenn Darden

No, we have not.

James Spicer – Wells Fargo

Okay, thank you.

Operator

Your next audio question comes from the line of David Epstein.

David Epstein – Wedbush Securities

Hi, folks. So I think you said something on the order of $20 million is probably what you would be required to spend in 2013 to sort of meet that cumulative $300 million figure for CapEx spend. Separate from that, there’s also sort of an indirect commitment of the volume commitments to Fortune Creek, right? And would the $20 million allow you to meet those volume commitments?

John Regan

So, it all depends on how long we want to meet the commitment under that. As we said in our earnings release, the pad itself is capable of production in excess of 150 million a day. So, the current commitment to Fortune Creek is at 75 million a day. So, while the wells may not meet it for all of 2013, certainly for a good portion of 2013, they would allow us to meet it. And the additional capital then that we would spend would really be more towards – with a mind towards 2014 production.

David Epstein – Wedbush Securities

Okay. So, you don’t think you’d have to spend much more than that $20 million to meet it on the volume side for all of 2013?

John Regan

Yeah, that’s – well, so to largely meet it for 2013. And I don’t know the $20 million because I think the number is probably closer to $5 million.

David Epstein – Wedbush Securities

Okay, I thought before you said something like you – I thought something like, you spent like $180 million, give or take, in the Horn River, which would obviously cover – the $100 million for 2012 and I was thinking $80 million for 2013. Did I get that wrong?

John Regan

Yeah, so the qualifying capital, if you will, is projected at about $175 million. And the agreement with Fortune Creek allows us to not only carry over costs, but we’re also able to reduce capital in any year by 20% provided we make it up in the succeeding year.

So, as you think about $100 million commitment in 2013, effectively we can unilaterally declare that to be an $80 million target. And we’ve spent – we have roughly $75 million of carryover. So, as we think about it, it’s kind of at the minimum end, $5 million. That’s not to say that’s what we would spend, but as we think about what we’re contractually obligated to do, that’s kind of the floor.

David Epstein – Wedbush Securities

Okay. And then there are a lot of moving parts in the production declines you’ve been experiencing, have any of them – has there been anything geologic in nature, things not performing according to the curves you expected?

John Regan

No. They’re actually looking better than our forecast. So we’re very pleased with the way that’s going.

Toby Darden

And this latest pad has increased our optimism on recoveries from this play.

David Epstein – Wedbush Securities

Oh, yeah. Right, right. And I’m sorry. But then even looking at the Barnett and stuff because we’ve had some performance declines there.

John Regan

Well, I wouldn’t say performance declines. We’ve had production declines, lack of activity. But, no, the performance is right on our projections.

David Epstein – Wedbush Securities

Thank you. That’s what I meant. Thank you very much.

John Regan

Thank you.

Operator

Your next audio question comes from the line of Lou Nardi.

Lou Nardi – Buckman & Reid

Hi. I was wondering if I can get a little more clarification on the bank agreement. The formula that applies to using MLP proceeds to buy back loans, does that same formula apply to outright asset sales?

John Regan

I don’t know what you mean by the formula. So, are you asking...

Lou Nardi – Buckman & Reid

If you – can you buy back loans from asset sales if you’re only 25% drawn on the borrowing base?

John Regan

If I am less than 25% drawn on the borrowing base?

Lou Nardi – Buckman & Reid

Right.

John Regan

Yeah, so I would still have to – by the agreement itself, I would have to direct a portion of the proceeds to the bank, but I would also have an ability to direct on a dollar-for-dollar basis repayment of bonds at the 25% and below level, until zero.

Lou Nardi – Buckman & Reid

Okay. And then do you have a pre-hedge gas price for the quarter, average gas price?

John Regan

Yeah, I covered that in my comments. Yeah, sorry, so let me find that in my comments and we’ll come back to it before we conclude the call.

Operator

Your next audio question comes from the line of (inaudible).

Unidentified Analyst

Hi. Good morning, guys.

Glenn Darden

Good morning.

Unidentified Analyst

On the bank agreement, just to follow up on James’ question, do the covenants differentiate between your ability to repay senior debt and sub debt? For instance, would you still be able to redeem the 7 1/8% sub notes or is that...

John Regan

Yeah, the same restriction effectively applies to the senior subs as it does to the senior bonds.

Unidentified Analyst

Okay, perfect. And then you guys have talked about several cost reduction initiatives. Could you help us quantify what the potential savings could be? Or could you perhaps lay out just more specifically about what you guys are doing? I mean, you’ve obviously talked about some of the stuff you’re doing in Niobrara. But just perhaps a little bit broader view in that sense?

John Regan

Yeah, just to be clear, are you asking from a capital perspective or from an expense perspective?

Unidentified Analyst

On the OpEx side.

John Regan

Yeah, so on the OpEx side, as we covered, we’ve been working with vendors such as our mid-stream provider to have a lower gas lift rate, which has an accretive effect to our returns. We have scaled back some of our workover activity and we have also scaled back some of the kind of service equipment repair programs that we had in place. On top of that, I think from a back office perspective, s G&A perspective, we had projected some head count growth that we probably won’t follow through with. And I think just kind of broad-based fiscal discipline, all working in concert to attain those results.

Unidentified Analyst

That’s helpful. Do you guys have any sort of dollar figure you’re thinking about in that sense?

John Regan

Lower.

Unidentified Analyst

All right.

Glenn Darden

Yeah, I would say that we do have internal targets, yes. But I’m not sure we’re prepared to communicate those. They’re embedded in our guidance forecasts.

Unidentified Analyst

Okay, fair enough. And then just lastly on the CapEx side for next year. I think you said CapEx should be lower than 2012. How should we think about that more specifically, for instance is the sort of second half a good run rate to think about as a baseline?

John Regan

Yeah, as I mentioned in my comments, we’re just really getting started in earnest on that 2013 capital plan, so I would ask you to give me a little bit of time to bake it and we’ll come back to that for you in the fourth quarter.

Unidentified Analyst

Okay. And then I guess just to be clear, you guys are expecting to spend within cash inflows. Would that cash inflow number include asset sales? Or is that just sort of an operating cash flow number?

John Regan

Yeah, we consider it to include proceeds from asset sales.

Unidentified Analyst

Okay, great. Thank you very much.

John Regan

Thank you.

Operator

Your next audio question comes from the line of RJ Cruz.

RJ Cruz – TCW

Yes, can you be more specific in how the proceeds from the JVs are going to be deployed?

Glenn Darden

Primarily to fund these new projects.

RJ Cruz – TCW

Okay. And you have no plans to pay down debt? I’m sorry.

Glenn Darden

Except proceeds to pay down debt, yes.

RJ Cruz – TCW

I’m sorry, I didn’t catch that. You said for CapEx first and then the rest for paying down debt?

John Regan

Paying down debt, yes.

RJ Cruz – TCW

Okay. Any specific – any split on how – on what goes to the debt pay down?

John Regan

So, the way we think about it, as you know, our capital program is currently in excess of our operating cash flow for the year. So I think what we mean is we intend to reduce overall debt year-over-year, so indirectly you use asset proceeds to bridge the gap to zero and then use the excess to retire the debt. It’s pretty mechanical.

RJ Cruz – TCW

Okay. So, given the new borrowing base that you have, are there any gating factors on the 25% limits? Or in other words, my question is can you actually pay down bonds given what you have outstanding on your revolver?

John Regan

Again, I think we need – once I have the cash in hand, then we approach the banks and formulate a strategy at that time.

RJ Cruz – TCW

Okay, all right. Then maybe just one clarification on your NGLs. How much of your NGLs are ethane?

John Regan

That’s roughly 55%.

RJ Cruz – TCW

Okay, that’s it from me. Thank you.

John Regan

Thank you.

Operator

Your next audio question comes from the line of Maryana Kushnir.

Maryana Kushnir – Nomura Securities

Hi. I wanted to clarify the item that relates to the restructured hedges. So it seems like you’re suggesting there is basically non-cash revenue that’s included in the revenue line?

John Regan

It’s actually the opposite of that, there is cash that doesn’t become revenue.

Maryana Kushnir – Nomura Securities

Okay. So, if we – I guess, if we want to calculate some sort of adjusted EBITDA that approximates cash flow before interest and tax payment, then do we – how much do we add back to the revenue reported?

John Regan

Yeah, so it’s clear we’ve gotten a lot of questions on this topic. So, if you’ll give me a day or two, I think we intend to do some things from an investor relations perspective that will provide some additional clarity on that.

Maryana Kushnir – Nomura Securities

Yeah, it would help us if you could perhaps disclose in your press release adjusted EBITDA the way most of the investment analysts I believe in the high-yield bond community and equity community look at it.

John Regan

We’ll take a look at that.

Maryana Kushnir – Nomura Securities

Thank you.

John Regan

It is a highly complex concept, however.

Maryana Kushnir – Nomura Securities

All right, thanks.

John Regan

Thank you.

Operator

Ladies and gentlemen, we have reached the allotted time for Q&A. I would like to turn the call back over to Mr. David Erdman for closing remarks.

David Erdman

I’d like to thank everyone for joining us this morning. If we didn’t get a chance to address your question, I invite you to give me a call. My information is posted on our website. Otherwise, we appreciate your interest in Quicksilver Resources. And this now concludes the call.

Operator

This concludes today’s conference call. You may now disconnect.

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