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Quicksilver Resources (NYSE:KWK)

Q4 2012 Earnings Call

February 25, 2013 11:00 am ET

Executives

David Erdman

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

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

Analysts

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

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

James Spicer - Wells Fargo Securities, LLC, Research Division

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Steven Karpel - Crédit Suisse AG, Research Division

Maryana Kushnir

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Louis V. Nardi - BMO Capital Markets U.S.

Operator

Good morning. My name is Tanya, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter and Full Year 2012 Earnings Call. [Operator Instructions] I would now like to turn the call over to David Erdman. Please go ahead.

David Erdman

Thank you, Tanya, and good morning, everyone. I'm joined by Glenn Darden, President and Chief Executive Officer; and John Regan, Chief Financial Officer. This morning, the company issued a press release detailing our preliminary results for the fourth quarter of 2012. A copy of the release is available on the Investors Relations page of our website at www.qrinc.com under the News and Updates tab. First, let's cover Safe Harbor provisions.

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 these projected in the forward-looking statements. Additional information concerning risk factors, which could cause such differences, are detailed in the press release we issued this morning, as well as in the company's filings with the SEC.

The SEC permits oil and gas companies to disclose in their filings proved reserves, probable reserves and possible reserves. Referencing this call to 3 key reserves include estimates from each category of reserves and are forward-looking statements. Today's presentation will also 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 measure is available with the press release issued this morning.

So I'll now turn the call over to Glenn Darden.

Glenn M. Darden

Thank you, David. Good morning. Quicksilver had an adjusted net loss for the fourth quarter of 2012 of $2 million or $0.01 per diluted share, compared to breakeven adjusted net income in the 2011 period. This quarter includes a large noncash impairment charge of approximately $1.2 billion, primarily attributable to a change in accounting treatment for hedges and also to the reclassification of existing proved undeveloped reserves, which are now not expected to be developed within 5 years, as we reduced drilling activity in response to lower natural gas and natural gas liquids prices. These impairments are prescribed by the SEC rules, and in the case of the reserve reduction, are based on an SEC mandated gas price of $2.76 per Mcf.

John Regan, our Chief Financial Officer, will give you more details with his remarks.

In actuality, our gas hedges had a value of over $200 million at year end, and our reserves based on strip prices earlier this month were over 2 Tcf of gas equivalent. On the production side, we have established oil production in both Colorado and West Texas. In the case of Colorado, at the end of 2012, we closed a previously announced deal with Shell to combine our 2 acreage positions in the Sand Wash Basin. Quicksilver now owns a 50% working interest in approximately 320,000 net acres within an 850,000-acre area of mutual interest. And this project looks very promising.

We have steadily increased the productivity of Quicksilver's vertical wells with our most recent well coming in at over 400 barrels per day. Combined, our operational plans this year include drilling 8 wells and preparing the land, unitization and title work, for a more robust drilling program in future years.

Quicksilver has drilled initial wells on 2 sizable acreage blocks in West Texas. In Pecos County, we have successfully tested the third Bone Springs with a short lateral and are now bringing on our first Wolfcamp well in Upton County. This short lateral Wolfcamp well recovered -- has recovered a little over 30% of its frac load back and is -- we're seeing currently about 45 barrels a day of production with the volumes -- oil volumes increasing.

Due to continued low natural gas prices and a drop in NGL prices this year, we began slowing our capital program roughly midyear in 2012. As a result, the company's net annual production was down approximately 5% over 2011. In the fourth quarter, we averaged 342 million cubic feet equivalent per day.

In the Horn River basin, we had anticipated ramping up production in the third quarter of 2012 to meet new third-party treating commitments. But that facility is yet to be commissioned. So in mid-December after acquiring discounted treating capacity in an existing plant, we began ramping up our volumes in the Horn River to 100 million a day of raw gas. Most of this production is coming from 7 wells on a new 8-well pad. Currently, surface facilities are restricting maximum flow from these wells. The remaining well on that pad is currently shut-in and will be brought on in the future to keep our production at approximately 100 million a day. I'll talk more on the Horn River in a moment.

Quicksilver's full year 2012 production averaged 360 million cubic feet equivalent per day. Production for the first 45 days of 2013 averaged 366 million cubic feet equivalent per day.

We have slowed the drilling and completion phase in the Barnett, but our team has done a good job in the field of minimizing the decline. In fact, in the last 2 months, our production has been roughly flat. In the Barnett, we have a large asset base of approximately 2.5 trillion cubic feet equivalent of 3P reserves, based on recent strip prices. But the lease is mostly held by production, with significant opportunity still to develop.

As you know, we have looked at several options to monetize a portion of our Barnett assets in order to reduce company debt. Initially, we plan to create an MLP to drop down roughly 20% of the assets.

On a parallel track, we have also evaluated offers for selling minority interest across the board. We are focused on the latter path and are currently moving toward getting this deal closed.

In Canada, particularly in the Horn River Basin, our strategy has been to set up initial infrastructure, drill exploratory wells to convert the licenses to leases, and to showcase the world-class gas reservoir we have captured. We have been in discussions with potential partners over a number of months. Our game plan, led by Quicksilver's Canadian team, is to create an integrated solution to maximize the value of the multiple Tcfs we have found. Three events, over the last couple of months, has stimulated these discussions with multiple parties and has led to negotiations. First, was the outstanding well performance of our first multi-well pad. These wells tested at rates from 23 million cubic feet to 34 million cubic feet a day per well.

The second event was the announcement of the Chevron, Apache, Kitimat transaction, which valued the Kitimat project in the Horn River Basin acreage, at an approximately $1.5 billion. We believe the confirmation by a major of this basin and resource was a significant validation of what we are working towards.

The third event was the National Energy Board's decision on the Komie North pipeline application. This proposed pipeline is intended to connect Horn River Basin production to TransCanada's overall Alberta system and provide an alternative route to market gas out of the basin. In our view, the NEB will require more producer support in order to build the 36-inch pipeline. This pipeline, as originally proposed, was initially backstopped only by Quicksilver. It appears that TransCanada will now work with other producers in the basin, in addition to Quicksilver, to get that support, and we'll refile the application. The importance for Quicksilver is that this will defer and reduce our financial commitments over the next several years. We can keep our current production volumes flat over the next several years, without requirements to increase volumes, and can advance the downstream marketing plan. This deferred spending better fits into the timeline of our potential partners and matches up with their downstream marketing plans as well.

We are working hard to control cost in every sector of the company. We reduced cost in the field and in the back office. The company has set a capital budget of approximately $120 million for 2013, which is roughly 70% below our 2012 budget. This budget is in line with Quicksilver's projected operating cash flow for the year. We project a small decline of approximately 5% in overall company production volumes, which I believe speaks well to the quality of our current asset base. This budget does not include the positive impact of strategic divestitures, proceeds from which would be used to primarily delever the company.

As I said earlier, we have deferred capital projects out for every years, particularly in the Horn River Basin. We have had preliminary meetings with our bank group and will be out -- determining our borrowing base in the next month or so. And we believe we will have adequate availability in this facility. Quicksilver has several bond maturities in 2015 and 2016, of which the earliest is August of 2015, and we are evaluating our options to manage that maturity schedule.

The company's hedge position continues to be a valuable asset, with approximately 200 million of gas production volumes per day hedged at $5.10 for 2013, and 170 million per day of gas volumes locked in at $5.08 in 2014.

Our game plan is clear. Quicksilver expects to keep capital expenditures within operational cash flows and manage our current asset base to have single-digit production decline. At the same time, we will work to finish our asset sale and strategic transaction process, and we will push our new oil projects forward. Currently, there are opportunities in the capital markets to refinance a portion of our bonds at attractive rates, and we will work towards the best solution to give Quicksilver financial flexibility. We will also continue to pursue better downstream markets, both in Canada and the U.S., which can enhance long-term value for our products and our shareholders.

And now, I will turn the call over to John Regan, our CFO, who will walk you through the financials and give more detail on several of the topics I had covered. John?

John C. Regan

Thank you, Glenn. Good morning, everyone. In the fourth quarter, we recorded a noncash impairment of $1.2 billion, of which 63% is attributable to a change in hedge accounting and 37% is related to the reserve revisions. We've impaired a total of $2.8 billion in 2012, though we do not expect these impairments to continue, given today's forward strip.

Let me address the fourth quarter impairment and its 2 main components. First, at year end, we made the decision to discontinue hedge accounting, chiefly due to the challenge and complexity of the associated documentation of measurement requirements. With that change, we can no longer include the value of the hedges as part of our full cost ceiling. This single change led to $734 million of pretax effect within our reported impairment, which I had as higher than the book value of hedges, because of the difference in the underlying price used to value the hedges for these 2 purposes. To explain, we used SEC reserve pricing held constant to value the hedges for ceiling test purposes, which was $2.76 per Mcf for the year end 2012 test, but we used the forward strip on 12/31 to value the hedge's book value for balance sheet purposes. The book value of the hedge portfolio was over $200 million at year end 2012, using the 12/31 forward strip, and that continues to be an important source of our cash flow.

The second major component of the fourth quarter impairment relates to reserve revisions. The vast majority of which are related to the reclassification of certain 2011 Barnett PUDs, to the probable category, as a result of slow development plans. This resulted in certain PUDs not scheduled to be developed within 5 years of their initial recognition. The derecognition of PUDs and price reductions make up greater than 80% of the 2012 reserve revisions, which aggregate to cost $410 million of the fourth quarter full cost impairment.

In addition to that, we also recognized a $326 million noncash deferred tax valuation allowance in the fourth quarter, which was primarily driven by the generation of net operating losses, themselves stemming from the ceiling test impairment. The valuation allowance has the impact of causing there to be no benefit recorded on our pretax book loss, generated in the U.S. during the fourth quarter. As a reminder from my comments in the third quarter call, the recognition of the valuation allowance in no way impacts our ability to use the NOLs in the future to reduce cash payments for regular taxes if we generate taxable income in the U.S., for example, if we have a taxable gain resulting from our ongoing U.S. joint venture process.

These noncash impairments say little about the long-term value of our assets. We don't believe the 2012 SEC price is predictive of future pricing, as evidenced by the forward curves today. We believe this causes a significant underestimation of the true value of our assets.

Our adjusted net loss for the fourth quarter, excluding these and other items, which I point out as a non-GAAP measure, was $2 million, or $0.01 per diluted share versus breakeven in the 2011 quarter. Full year 2012 adjusted net loss was $46 million or $0.27 per diluted share versus adjusted net income of $20 million or $0.12 per diluted share, for full year 2011. Our adjustments derived at adjusted net income are outlined in the table of this morning's release.

Our reported year end 2012 proved reserves are 1.5 Tcf equivalent, which includes a 44% revision, based on lower prices, to the tune of 33% for natural gas and 28% for NGLs when compared to 2011. The change in hedge accounting had no impact on the volume or PV10 of reported reserves. In this morning's release, we provided reserve sensitivity from year end SEC pricing, based on a $0.50 change in the benchmark natural gas price and a $5 change in the benchmark oil price. With a $0.50 increase in the gas price and a $5 increase in the oil price, our proved reserves would increase by 21% to 1.8 Tcfe. Conversely, if prices fell by the same amount for the SEC prices, our proved reserves will decrease 13% to 1.3 Tcf equivalent. Using a $4.88 natural gas price and an $88 oil price, which roughly to launch this average of the 10-year strips earlier this month, our proved reserves would increase 41% to 2.1 Tcf equivalent.

Turning to the recent land -- to the recent developments in the Horn River pipeline landscape, the National Energy Board in Canada recently issued a negative recommendation on the proposed 75-mile extension from TransCanada's Albertan system to our Horn River leasehold, citing insufficient commercial support for a 36-inch pipeline. We believe the Energy Board left the opportunity open for resubmission, which will be underpinned by more broad-based commercial arrangements among more producers. TransCanada has 24 months to reapply.

We continue to support the project and the reduced transportation of costs attended to it. However, the Energy Board's negative recommendation enables us to adapt to our capital activity in the Horn River and coincide with the revised timeline's reapplication and subsequent reapproval -- or subsequent approval and construction of that Komie North extension. Until the pipeline is approved, we expect to minimize our capital activity, add new volumes only to economically match our existing minimum treating and transportation commitments.

Further, we expect that in March, the $30 million letter of credit, currently posted to this project, will be reduced to $13 million to cover the right of way and engineering costs incurred to date by TransCanada. Should the project eventually be resubmitted and receive approval, we would also expect a substantial reduction in our total financial assurances, to TransCanada, during the construction phase as we expect other producers will provide financial assurances to cover their proportion of the share. Prior to the Energy Board's decision, we were potentially providing the full financial insurance to TransCanada, which was derived to $300 million by the end of 2014, despite that we had contracted for less than 30% of estimated capacity.

The upshot is that we expect our minimum committed volumes in the Horn River will now we based on 100 million cubic feet per day of gross production, from mid-2013 to mid 2018. This has greatly enhanced the flexibility we have around our development plans, joint venture pursuit and liquidity position. Simply put, the existing production levels need only be maintained over the next several years in order to cover our transportation and treating commitments. We also expect to work with our midstream partners and providers, to address these recent changes in the Horn River landscape, including any implications to capital spending requirements.

Turning to the discussion of fourth quarter results. Our production averaged 342 million cubic feet of natural gas equivalent per day, which is slightly higher than the upper end of the guidance we provided for the quarter. The higher volumes are the results of the ramp-up in the Horn River in mid-December, after we secured alternative treating and transportation capacity. We had not projected these additional volumes in our fourth quarter guidance, as we couldn't reasonably predict the timing of our ability to obtain, the alternative capacity and the consequent wrap-up of production. We expect to target 100 million a day of raw production, using this alternative path until a third-party treating facility at which we have firm capacity is commissioned. At this time, we do not have an estimate of when this will happen. However, there continues to be ample treatment in transportation capacity in the basin, and we expect we can secure all the incremental capacity we need, which is available today at deeply discounted rates.

At current cost, incorporating this alternative capacity, we believe every 10 million cubic feet of gas per day will generate more than $2 million of incremental cash flow per quarter, for volumes in excess of today's 30 million cubic feet per day commitment.

Full year production was 360 million per day, which is down from 412 million per day in 2011. The decline results from the substantial curtailment of Barnett capital activity in 2012. But we expect this decline to slow in 2013, as the production curves of the wells completed in 2011 begin to enter their shallower decline phase. In fact, our Barnett Shale production, year-to-date in 2013, is down approximately 2% from December 2012. The Barnett decline rate in 2012 was mainly attributable to lower completion activity in that year, as we brought on line 83 more Barnett wells in 2011, when compared to 2012.

On the pricing front, we had an average realized gas price of $4.96 per Mcf in the fourth quarter, which included settlements on current hedges, but excluded $16 million of cash collected during Q4 from commodity hedges that were not recognized in production revenue, which equates to an uplift of approximately $0.51 per Mcfe. As a reminder, the value of the hedges that were restructured will be amortized into revenue over their original contract term, even though we received the cash today for the new shorter-term contracts.

We expect that this disconnect between the cash benefit of the hedges and their income statement impact will remain with us until the last of the restructured hedges expire in 2021. The discontinuation of hedge accounting that I previously mentioned will not impact the accounting treatment of future settlements.

The average NGL price in the fourth quarter was $38.50, but on our unhedged basis, was $29.74.

Total cash cost for the quarter on a unit basis were $2.35 per Mcf equivalent, which is within our guidance range. Of this total, LOE was $0.73 on an equivalent unit basis for the fourth quarter, which is $0.07 higher than the previous quarter but flat on an absolute dollar basis. Compared to the 2011 quarter, LOE is down $7 million, which is primarily the result of our continuing cost containment efforts, lower salt water disposal volumes, gas lift and compression expense in the Barnett.

We have just under 50 wells shut-in today for economic reasons, and expect to bring that production of less than 5 million cubic feet a day back online as prices recover.

LOE per unit in the Horn River declined by more than 50% compared to the 2011 quarter, due to economies of scale from the introduction of higher volumes from the new pad. LOE in 2013 is expected to be slightly higher compared to 2012, due to increased maintenance and work-over expenses, almost exclusively undertaken in the Barnett.

Gathering, processing and transportation, or GPT, was $1.25 per unit in the fourth quarter, which is comparable to the third quarter and the 2011 quarter. We expect to see a slight decline in this rate in the first quarter of 2013, as the incremental volumes in Horn River continue to be delivered at discounted rates, which again is a trend we expect to continue until the third-party treating facility is commissioned at a -- as yet undetermined date.

Our G&A expenses included an $8 million write-off of accumulated fees incurred for our proposed Barnett master limited partnership. This write-off results because of the time since our last update to the registration statement, and is only to comply with the accounting treatment prescribed by the SEC. It in no way precludes us from continuing with the offering should we so choose.

We are also addressing our G&A costs to improve margins under continued depressed commodity prices. Earlier this month, we reduced headcount, and we will continue our focus on reducing our overall cost structure throughout the year.

In summary, at average realized prices and including the impact of cash derivatives settlements as disclosed earlier, our fourth quarter recurring cash margin on an Mcfe basis was $3.12 on an unlevered basis and $1.73 on a levered basis.

Turning to derivatives. We believe our natural gas production is well hedged for the next several years. For 2013, we have a total of 200 million per day of gas production hedged at a weighted average price of $5.10. We have 170 million per day of gas hedged at $5.08 for 2014, and 150 million a day hedged at $5.23 for 2015. These derivatives cover a majority of our expected gas production for the years covered.

Our Canadian derivatives, included in the foregoing, are 50 million a day for 2013 at a weighted average price of $5.31 and 40 million a day for 2014 and '15 at $5.38. All of our NGL derivatives expired at the end of 2012. Given our transportation agreements and capacity at Mont Belvieu, we continue to produce ethane at the premium to natural gas prices. Despite the near-term pricing constraints, we do see opportunity on the upside for the NGL price curve.

With the discontinuation of hedge accounting, the net deferred hedge gains that are included in a cumulative -- accumulated other comprehensive income, or AOCI, as of December 31, 2012, will be recognized as production revenue during the periods in which the hedge transaction occurs, which is similar treatment to the restricted hedges that I've discussed earlier. Beginning with the first quarter of 2013, unrealized derivative gains and losses generated during that period will be included in earnings, but will be excluded from adjusted net income.

From a capital spending perspective, we incurred $31 million of capital in the fourth quarter, bringing our 2012 spending to $390 million, in line with what we've said last quarter. As disclosed in this morning's release, our 2013 capital budget is expected to be $120 million, again in line with 2013 operating cash flow. This budget excludes any effects from our asset sales or our proposed strategic transactions. The proceeds of which will be mainly directed towards debt reduction.

We're planning a modest 2013 drilling program in the Barnett, which will produce an estimated 9% decline compared to the fourth quarter production rate. Because of the results of our 2012 Horn River capital plan and the flexibility afforded by the delay of the Komie North pipeline, we believe we have sufficient existing capacity to keep Horn River production at 100 million per day for the majority of 2013. Our capital plan includes costs in the second half of the year to prepare for drilling at 4 to 6 well pad in early 2014.

To recap our midstream commitments in the Horn River Basin, our treating and transportation commitment steps up to 100 million per day perhaps as soon as May 1, 2013, and stays flat until 2018. Looking beyond 2013, we expect to reduce or defer drilling in the basin from our prior plan, in light of the Komie North delay.

In Colorado, we plan to fund our 50% to participate and up to 8 wells with Shell, and we intend to renew leases set to expire during 2013. We expect our West Texas asset to provide the opportunity for healthy returns, but we also expect to measure a development program in 2013 to accelerate the programs should we secure a joint venture partner this year. We don't currently have a projected timeline to accomplish this, but we expect to make doing so a priority, once our efforts in the Barnett and the Horn River are completed. With only 30% of the capital budget directed towards drilling and completion, we expect 2013 average company production to decline approximately 5% compared to the 2012 production, and to be roughly flat with the fourth quarter production rate.

Operating cash flow in the fourth quarter was $81 million. Borrowings decreased $100 million, due mainly to the reduced capital run rate and the cash proceeds received from the Niobrara transaction, which we utilized to reduce borrowings under the credit facility.

Total debt outstanding at December 31 was approximately $2.1 billion, which includes approximately $100 -- $450 million utilized under our credit facility. Utilization includes $60 million of letters of credit outstanding, which I would expect to decline to about $45 million after the letter of credit to TransCanada is reduced to $13 million, as I previously discussed.

The semiannual redetermination of the credit facility is scheduled for April, and we expect an as yet to be determined reduction due to the borrowing base. In any event, we don't foresee liquidity issues given our reduced capital program for 2013, as well as expected reduced and deferred letters of credit commitment in Canada, cost-reduction initiatives and the potential for asset sale proceeds.

At year end 2012, we did not meet the incurrence test within our bonds, which has an interest coverage ratio of 2.25x. With that, we are limited in our ability to incur additional debt outside of our credit facility until we do meet the tests. I want to emphasize that there is no acceleration of any debt as a result of our not meeting this test, and we still have the ability to issue additional debt to refinance existing borrowings. Further, we have the ability -- we continue to have the ability to access the full amount of our existing borrowing base under the credit facility.

We are currently considering a number of near-term refinancing options to enhance liquidity and to begin to extend the maturity date of our 2015 and 2016 bonds. In this regard, we have been in regular conversations with our banks regarding the potential for a second lien or unsecured debt offering. Since the beginning of 2013, there have been a number of new issuances, the caps-weighted names, similar credit ratings to ours that have been executed in rates and terms that we would consider attractive. We could execute the launch and funding of any such refinanced offering, potentially as early as the second quarter.

Today, we have provided unaudited financial statements via our release. The audit of our financial statements is ongoing, and may not be completed by March 1, primarily as we continue to analyze our deferred income taxes and our derivatives.

We expect to complete the audit and file our 10-K by the extended deadline of March 18.

Now I'll turn the call back over to David to cover full year and first quarter guidance.

Glenn M. Darden

As outlined in our press release issued this morning, the first quarter 2013 production volume is expected to be 360 million to 365 million cubic feet equivalent per day. Full year volumes are expected to be 335 million to 345 million cubic feet equivalent per day. First quarter 2013 average unit cost, on an Mcfe basis, are expected as follows: LOE between $0.80 and $0.82; gathering, processing and transportation between $1.20 and $1.22; production taxes between $0.14 and $0.16; G&A between $0.55 to $0.57; and finally DD&A between $0.52 and $0.54.

So we'll move to the Q&A portion of the call, but I first would like to mention that management will not be making additional comments or providing additional detail about our ongoing JV processes until we have executed agreements.

And so with that, Tanya, let's open the line for questions.

Question-and-Answer Session

Operator

[Operator Instructions] The first question is from the line of Dave Kistler.

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

Real quickly, just circling back to the Shell JV, when you guys initially gave us information, you contributed a disproportionate amount of acreage into that and indicated that there was some remuneration from Shell. Can you give us the -- kind of maybe some more details or more specifics around that, in terms of the capital that came in, so we have a sense of how to think about valuing the acreage?

Glenn M. Darden

Well, David, we have a confidentiality clause in our agreement with Shell that we can't disclose exact details. I think you can get, directionally, the numbers from our public filings just on debt reduction done, and yes, specifically if you look at our invested cash flows, I think you'll see some direction there.

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

Okay, great. I appreciate that, guys. And then on the CapEx that you outlined, you kind of indicated about 30% to 40%, if it would be drilled at specific, can you break that down by area?

Glenn M. Darden

It's primarily Barnett and Colorado, a little bit in West Texas.

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

And then lastly, looking at sort of the, I guess, deferral or the decision by the NED or recommendation to push out the pipeline, how does that impact your ability to work around the JV in the Horn River? I would imagine that could put some pressure as far as delaying the timeline on that.

Glenn M. Darden

Well, it actually has been the reverse, David. We've -- it stimulated the talks and actually pushed to negotiations. And the reason it has, one of the hurdles we've had is having to develop on faster timelines than our potential partners wanted to move. They're looking at downstream solutions that are kind of 2018 and beyond timeframe. So bringing on earlier higher volumes was a negative in those negotiations and kind of a stumbling block in those. And now, with this reduced capital expenditure, until the 2018 timeframe, that really enhances the picture. I think this better aligns our capital activity to what the proposed partners were wanting to see in terms of capital development.

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

Okay. And then just one last one and I'll hop off. You're looking at selling non-up in the Barnett, so that leaves a pretty significant portion there. You mentioned that, at least in the near term, the MLP might be deferred or not followed for a bit. Are there other avenues you're looking at in the Barnett from monetization of those assets?

Glenn M. Darden

Well, we looked at several avenues, David, and I appreciate the question. Obviously, the first path we announced was the MLP, and that market has deteriorated to a bit. I think more than that, putting in a significant portion of our liquids into that entity initially was not as good a value our selling minority interest across the whole asset base. And so while we we're going down the path of the MLP, we also had an alternative path that we were -- we undertook on selling a minority position and that has gotten a lot more traction. It's better value proposition for the company and that's the path we had chosen. I think what John was saying in his remarks was that we still have the option at a future date to do something on the MLP side but we are taking that accounting charge.

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

Okay. But one clarification then on the minority interest or non-op piece you're selling, how much production and reserves are associated with that?

Glenn M. Darden

We haven't disclosed that and we hope to shortly but what's important to us is keeping the cost structure and the overall asset base together. We think that's the most efficient for a working interest partner and it's certainly the most efficient from us as operator. So that's what we focused on. It's a meaningful piece, that's what it's targeted to do to pay down significant debt. So it's not a tiny working interest and I'm sorry to be vague but we'll give you the clarity here shortly.

Operator

Your next question is from the line of Noel Parks.

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

Just a couple of things. In particular, I was interested in the new JV with Shell. It's been, I guess, a couple of months now since you closed. And have you gotten very far really as far as comparing notes on sort of your expected results? I know they have been a little cagey in the past year or so about exactly what they were seeing? And just wondering what you know and what the results have been like so far?

Glenn M. Darden

Well, without disclosing confidential information, Noel, what we have done is sit down, our technical teams combining the knowledge that Shell has gained over the last couple of years in their test drilling, they've taken a different approach, I'll put it that way, we've concentrated more on testing the various types of stimulation. And so we've drilled more vertical wells, we've stimulated those with different frac-ing materials and techniques. And we've advanced the ball, we believe, significantly with those changing, evolving techniques. So what we set down with Shell on is share technical information and we've also formulated a game plan for 2013 in terms of unitizing acreage, what wells we're going to drill. And as we stated, it's a small drilling program to start with but geared toward accelerating beyond 2013.

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

And sure. For the 8 wells that you have planned, is it geared more towards, I don't know, filling in gaps where you haven't drilled so far or are you at the point already where you can already start to sort of concentrate maybe high grade a little bit in terms of really trying to spread out across your acreage?

Glenn M. Darden

The wells are spread across the acreage block, so it's not a high grade as much as there's some lease commitment wells, but also more valuable data gathering and bringing on production.

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

Okay. And with the well that you reported, the one vertical that's 400 barrels a day, now that you've been working the play a couple of years now, can you kind of give some perspective on sort of maybe what people have gotten wrong in other areas, the Niobrara, maybe outside, say, Wattenberg for instance? You're trying to start from scratch in some of these areas. I know a lot of folks have found oil in plays in their initial testing, but then they get down, I guess, they haven't found the thermal maturity they needed or -- can you just kind of give us some perspective on kind of what you got right and maybe other people missed in picking your area?

Glenn M. Darden

Well, I'd rather not speak to other companies' efforts. What we have been very focused on is trying to get our story right and it started slowly. What we were very concerned with was affecting the plays in the reservoir with our stimulation treatment. And so we started with various types of fracs, oil-based, gas-based type fracs and have evolved to more of a conventional water-based frac and it doesn't seem to hurt the reservoir. So I really can't speak to other operators in other basins in -- attacking the Niobrara, but we've seen steady improvement on our side. And Shell, I believe, has seen obviously encouraging signs on their side as they were encouraged to join our acreage positions.

Operator

Next question is from the line of James Spicer.

James Spicer - Wells Fargo Securities, LLC, Research Division

I guess, just to start with, the $120 million CapEx budget, you mentioned that 30% of it is for drilling and completion. Can you provide a little bit more granularity as to the remaining 70%?

Glenn M. Darden

Sure. Yes, as a reminder, we have about $25 million of what I'll call back office cost in the form of G&A and interest cost that we have to capitalize under the accounting rules. So that's a majority of it. And additionally, we've got leasehold that we need to renew, particularly in Colorado, we have some 2013 expiries that we'll be spending towards. And then you've covered the drilling and completion side of it.

John C. Regan

Preparation costs in Horn River.

Glenn M. Darden

Yes. And then as I covered in my script, there's some -- we plan on 2014 pads in the Horn River and so you've got some advanced prep costs for those in the latter half of this year.

James Spicer - Wells Fargo Securities, LLC, Research Division

Would you characterize that $120 million then is pretty much minimum maintenance type level, is there much flexibility in going below that if you felt like you have to?

Glenn M. Darden

I mean, I certainly think we could. We could lower that number if we needed to.

James Spicer - Wells Fargo Securities, LLC, Research Division

Okay. And then the next question I had was just on the potential refinancings that you mentioned. You talked about potentially you could launch something as early as the second quarter. I guess, I'm wondering how independent is that process of the Barnett minority interest sale process and how important is it for the execution of a refinancing process that you get at Barnett deal announced?

John C. Regan

Yes, I certainly think it would be beneficial to have the Barnett deal just to provide clarity to the transactions that we project. But I do think that there's some independent opportunity to move forward with a refinancing even without Barnett. But I think certainly it creases the schedule a little bit if you do have the Barnett deal on hand.

James Spicer - Wells Fargo Securities, LLC, Research Division

Okay. And then in terms of the potential refinancing, what's the priority for you in terms of the balance sheet? Is it more sort of absolute debt reduction or is it more looking at specific maturities?

Glenn M. Darden

Well, for us, it's the constant battle of liquidity and maturity schedule. So obviously, it won't be a deleveraging event if I'm layering on new debt to replace old debt. But we are mindful of both our liquidity needs for 2013 and beyond and what the maturity schedule looks like beginning in '15.

Operator

Your next question is from Mike Scialla.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

I think you may have answered this one, but maybe you want to flush it out a little bit more. If you do get a JV down in the Horn River or Barnett minority shale done, I guess, first, use the proceeds going to be to pay down debt. Would you look to increase that budget at all for 2013 if gas price environment stays where it is right now?

Glenn M. Darden

No, I don't think we would, Mike. I think we'd be focused on delevering the company.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Got it. Okay. And you'd mentioned that the PUD reclassification accounted for about 80% of the production of your proved reserves, if I heard you right. Can you say how many PUDs you lost out of that proved reserve category?

Glenn M. Darden

I don't have that data in front of me, in terms of number of individual PUDs.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then I was curious on you mentioned ethane prices, you're still seeing a gas-plus price. Assuming current gas prices, where is that breakeven? Can you say what ethane price would cost you to project?

Glenn M. Darden

Well, although we are accretive to it, we are close. But it's probably in the $0.20 range for ethane.

Operator

Your next question is from Steven Karpel.

Steven Karpel - Crédit Suisse AG, Research Division

You somewhat might addressed this but I'm trying to understand about the Barnett and terms of what you are talking about the decline. I think it was a 6% decline in the quarter. So I'm trying to understand how, get to the 9% decline for the year and to understand what the drilling is there and then really more specifically about the completion the number of completions, number of completions and how the 2 numbers kind of tie together?

Glenn M. Darden

Sure. So I think what we were trying to say and maybe I did it inelegantly, that we did see about a 9% decrease in the Barnett, which was largely reflective of the fact that in 2012, we brought online 83 fewer wells than we had in 2011. And then we were trying to point out that the steep part of the production curve decline really occurs in year 1. So we have kind of borne the brunt of the steepness of the production decline in the later half of 2011 and into 2012. And so we expect that those production declines will begin to shallow as we enter 2013. So we don't expect the production declines that you've seen in 2012 to repeat in 2013.

Steven Karpel - Crédit Suisse AG, Research Division

Let me ask you this way, how many Barnett wells will you bring on in 2013?

Glenn M. Darden

Depending on the number of factors including availability of adjacent pipe. That's probably in the 10-ish or less range.

Steven Karpel - Crédit Suisse AG, Research Division

Then so if my numbers then fit, what would be the number of wells to make that 9% decline 0, so flat?

Glenn M. Darden

I mean, I need to do that math but we can come back to you with that figure.

Steven Karpel - Crédit Suisse AG, Research Division

And then an accounting one for John and I tried to understand this but I confess I didn't, so maybe I need the accounting lesson to understand where the $16 million for the hedging gains, how that will go through, one, your cash flow statement, and two, ultimately, when will that be recognized as that moves from AOCI?

John C. Regan

Sure. So this is on the restructured. You're talking about the hedges that we restructured in the first half of the year, for 2012. So in essence, we froze the OCI, so we had an asset on our balance sheet roughly equivalent to the tax affected amount that was in AOCI. So that credit that sits in AOCI will be amortized over the initial or the original contract terms, so in the case, it was 10% -- I'm sorry, 10 years. AOCI will be relieved through revenue over 10 years. So your debits to AOCI are your credits to revenue over 10 years. In the meantime, you are collecting the cash against the asset side of the balance sheet on a more accelerated basis than that.

Steven Karpel - Crédit Suisse AG, Research Division

And how will the cash flow through, I might want to make sure I follow that?

John C. Regan

Most of the cash flows through based on the shorter-term contracts. And that's what really gives rise to the amounts that I was referencing in my comments.

Steven Karpel - Crédit Suisse AG, Research Division

All right. I might follow-up with you on that one. And I think there was a previous question on the refinancing. You've made a point that you haven't met the debt incurrence covenants, but you specifically talked about the credit facility. So then how big is that credit facility allotment or incurrence today that you could do in terms of refinancing, in essence, you also referred to a second lien potential. How big can that be under your current bond debentures?

John C. Regan

So the bonds have a lien limitation of $1.2 billion, which would be the combined amount of the second lien in the credit facility.

Steven Karpel - Crédit Suisse AG, Research Division

And do all of your bonds, the 15, 16s and all those plus the 19s all have the same number aggregate, they reach a different way, but do they come all from $1.2 billion?

John C. Regan

That's correct. They all are at $1.2 billion.

Steven Karpel - Crédit Suisse AG, Research Division

All right. And have you begun discussions with your bank for permission? I believe you already got permission from the banks, and correct me if I'm wrong, to utilize this second lien?

John C. Regan

We would need permission from the banks and we have begun that discussion.

Operator

Your next question comes from the line of Greg Walker.

Unknown Analyst

I just have a follow-up to that last question. The $1.2 billion, where are you now on that?

John C. Regan

Well, today, I have an $850 million credit facility and no second lien.

Unknown Analyst

Okay. So it would allow you to go up another $400 million.

John C. Regan

Yes. $350 million.

Operator

Your next question comes from the line of RJ Cruz.

Unknown Analyst

Going back to the second lien question, maybe I read this wrong, in your credit agreement, but I thought that the limitation to second lien was $65 million.

John C. Regan

Well, that's not accurate.

Unknown Analyst

Okay. So regarding the discussions that you're having with the banks, so effectively, they would permit you to refile the 2015s and 2016s without meeting the 25% utilization requirement under the revolver?

John C. Regan

Can you repeat or rephrase that question or repeat that question?

Unknown Analyst

Right. So I think Steve already asked this question, but I just wanted to make sure. So currently, you're saying that you're negotiating with the banks, because my understanding is that your utilization needs to be -- under the revolver, it needs to be 25% or below before you could pay down any of your unsecured bonds?

John C. Regan

Right. So I think I understand the question now. So as we cover with in earlier questions, we would need permission from the banks in order to take the second lien. Attendant to that, we would also cover with them the intent to use proceeds, such that if the banks are amenable to it, we would like to direct maybe more than we would otherwise be allowed to towards the debt maturities.

Unknown Analyst

Okay. This discussions you're having with the banks, would that require any kind of consent fee payments?

John C. Regan

We're still on that negotiation phase.

Unknown Analyst

Okay. And going back to the SWEPI transaction, would Shell be required to disclose or provide details in their 10-K about the transaction and the financial implications specific to them?

Glenn M. Darden

That's a Shell question. We don't know that.

Unknown Analyst

Okay. But what is it exactly in the confidentiality agreement that prevents you from disclosing any more details about SWEPI?

Glenn M. Darden

There's a confidentiality clause that prohibits us from discussing any financial metrics of the transaction.

Operator

Your next question is from the line of Maryana Kushnir.

Maryana Kushnir

I have a few questions. First of all, when you give guidance of $120 million CapEx for 2013, is that basically what's going to be on the cash flow statement? The reason why I'm asking because you had some carryovers from last year in 2012, and then being cash amount -- total cash amount of $480 million versus $390 million of CapEx incurred in 2012. So I just want to understand what the actual cash number will be in 2012, and whether you'll have to deal with similar issues in 2013?

John C. Regan

So if you think about at 2011, we had ongoing drilling in the Horn River basin on that pad. So really, what you saw in 2012 was the actual payment of substantial portion of that, much of which has been accrued in 2011. So I would say that the 2011 effect in 2012 was more disproportionate than what you will see in 2012 moving into 2013. So I think from a cash flow perspective, you will see a number that is substantially more in line with the $120 million on our cash flow for '13.

Maryana Kushnir

Okay. So you're basically saying might be a little higher, right?

John C. Regan

Well, we need -- it all depends on the -- it's really a function of the change in the accruals that we have between yearend '12 and yearend '13 that will drive that number. As we've laid out, we clearly know what we were doing at the end of 2012. But as we were making our projections at what we'll be doing at the end of 2013, we see those as roughly comparable exercises such that the effect of the change in accruals will be minimal, and thus the cash flow number will be $120 million.

Maryana Kushnir

Okay. Also I might have misread something in the press release or actually it's not mistaken, but as I was looking through the financial statement, it appears to me that you might have bought some bonds back in the open market in Q4. Am I correct or I'm misreading it?

John C. Regan

Yes, we did not do that.

Maryana Kushnir

Did not. Okay. Then Fortune Creek JV, there was a line item which shows Fortune Creek distribution is about $14 million, $15 million in 2012. What should we be expecting for that line item in 2013? And what drives the distributions?

John C. Regan

Yes, I would expect roughly that same amount in 2013. And really, that's driven on the gathering fee that's generated in that partnership and its payment out to our joint venture partner.

Maryana Kushnir

Does it -- is that because of you consolidate it and then you pay out to the minority?

John C. Regan

That's exactly right.

Operator

Your next question comes from the line of Curtis Trimble.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Well, I was hoping to get a little bit of clarity on the reserve booking and kind of production trends out of the Horn River basin. Looking at your reserve statement, obviously, you didn't book any undeveloped locations out there but in the context of developing a 4 to 6 well pad into this year and next year, thought it might be interesting to talk about a little bit of reserve upside.

Glenn M. Darden

Well, maybe I didn't understand what you're asking specifically. You're asking what our total reserves are in the basin or...

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

No, just getting a little bit of idea on your booking strategy, given that you got a 4 to 6 well pad on the docket there but no undeveloped reserves booked for the Horn River basin.

Glenn M. Darden

Yes. I would say, first of all, we converted these -- most of these reserves were on the books in 2012, and we converted PUDs and PDNPs into proved develop producing. So what we're seeing on performance, we had some performance upgrades in 2012 reserves based on the productivity of these wells, particularly in the Klua formation.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Got you. And that's 105 Bcf number that you see there. Production trends on the wells that you've had on, how have pressures held up? And what's your EUR on an average basis there and...

Glenn M. Darden

Yes, I don't know that we released -- I'm not sure we've released our EURs, and I know we haven't released our curves but we're very pleased with the results so far. It's been a little bit of an inconsistent production pad because of surface restrictions. And so what we've done, the gas that we could bring on was in excess of what our requirements were, so we slowly, step-by-step, cleaned up each well on the pad and now have the production kind of governored to meet this $100 million. Now we have a little production from some of our earlier wells but the bulk of our production is from this pad. So as the year progresses, we'll be releasing curves. And but there's no -- we certainly believe that our HRB position has an excess of 10 to 12 Tcf of gas there. Nothing has discouraged us in that regard. In fact, it's more to the upside are our thinking.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Sure. In terms of timing for the refile of the application with the Komie North, any idea on maybe what the maximum period for that would be, given past experience?

John C. Regan

Well, I don't know that there is much experience on this application process being resubmitted. What -- we continue to work with TransCanada, they continue to have a desire to see the pipe constructed. And at this point, we don't really know what that timeline looks like. We do know that it could be as long as 24 months.

Glenn M. Darden

But I would say directionally, as far as our exposure, it's apparent that the NEB wants more producer support. And as John mentioned in his comments, we committed to fully backstop the building of that line even though we were only locking in about 30% of the capacity of that line. So I think if we keep that firm capacity commitment or renew that firm capacity commitment, I would think our percentage would be in the 30% range or less in terms of financial backstops.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Sure. And therefore, that's the related pull down in your letter of credit?

Glenn M. Darden

That's correct. And those, of course, go away upon the completion of that but again, that application needs to be resubmitted with a bit more broad-based support, we believe.

Operator

Your next question is from the line of Vitak Wong [ph].

Unknown Analyst

I was just wondering if there is a PV10 number that you could provide us?

John C. Regan

You're saying on a reserved basis?

Unknown Analyst

Yes, on your reserves, yearend 2012 reserves.

John C. Regan

Yes, we expect we're going to include that or we certainly will include that on our 10-K, in which you should see the next couple of weeks.

Unknown Analyst

Okay. Fair enough. And in terms of your revolver borrowings, where do you stand right now?

Glenn M. Darden

Right now, we're -- are you talking about utilization or including letters of credit or pure outstandings?

Unknown Analyst

Can you give me both, outstanding and utilization?

John C. Regan

Well, we are about $425 million drawn and then we have about 60 of LCs outstanding which, of course, includes the full value of the $30 million that we expect to be reduced in the near term.

Unknown Analyst

Okay. In terms of the upcoming redetermination of the borrowing base. I guess, is the borrowing base mainly on the proved developed reserves? So I'm just trying to gauge if the write-off the PUDs is going to have like this thing is going to impact on that $850 million borrowing base?

John C. Regan

Well, I would say that the borrowing base calculation is sophisticated and it has different advance rates for different reserve categories. I would point out that the PUDs going away is more a function of a 5-year rule, not an abandonment of the technical ability of those PUDs. So from a reserve perspective, those continue to be something that we're working with the banks on as these 5-year PUDs has fallen away, what if any advance rate do we get on them in the borrowing base.

Unknown Analyst

Okay. And in terms of the 10 wells that you'll be bringing on in the Barnett, is that all from your, I guess, 25-well backlog, so no new wells drilled, Is that correct?

Glenn M. Darden

It could be a combination of those.

Unknown Analyst

Okay. Where does that drilling and completion cost stand right now on the Barnett? And if you could break it down to 2 pieces?

Glenn M. Darden

Well, again, a lot of that is going to probably depend on lateral length. But you're probably talking about something in the neighborhood of $4 million to $6 million a well and -- I'm sorry, for the longer laterals. And you're probably looking at 1/3 on the drill side, 1/3 or less on the drill side and then 2/3 or so on the completion side.

Unknown Analyst

And is there a thought to, I guess, keep Barnett production somewhere around where you have somewhere close to your hedge volumes since you do get very good pricing on your hedges?

Glenn M. Darden

Well, I think the way we manage our gas production and our hedges are on a portfolio basis. So I think we look at the value of the hedges. Clearly, if you go back to my remarks, we have higher production in Canada today than we have hedged, so I have some opportunity to move my hedges to be Canadian hedges. And certainly, the discontinuation of hedge accounting gives me more maneuverability and I want to look at those things. But I think, again, we'll manage the production and the hedges on a portfolio basis. And I don't see a need to maintain Barnett production just from a hedging perspective.

Operator

We have time for one last question and that is from Lou Nardi.

Louis V. Nardi - BMO Capital Markets U.S.

I'm just curious if you had any PUDs anywhere other than Barnett that got eliminated this year?

John C. Regan

No. All of our PUDs last year were Barnett, all our PUDs this year are Barnett.

Louis V. Nardi - BMO Capital Markets U.S.

Okay. Yes, for some reason, I thought there were some on West Texas, right?

John C. Regan

I guess as we point out, there were -- have we had -- we had some PUDs associated with an 8-well pad that we brought on the Horn River. But all of those, as Glenn mentioned earlier, were converted to PDP.

Louis V. Nardi - BMO Capital Markets U.S.

Converted. Got you. Okay. And I think I missed something, but I'm not sure, when you were talking about the refi, some of the bond maturities, you mentioned the second lien with the banks. Did you mention another alternative in addition to that, that you're looking at?

John C. Regan

Well, I think in terms of the capital markets and what's available to us, it could be more unsecured debt, it could be second lien, it could be a number of other things.

Louis V. Nardi - BMO Capital Markets U.S.

And the discussions are on the second lien with the current back lenders?

John C. Regan

Including those that are in the credit facility and some that would potentially be our partner on new issuance.

Operator

Mr. Erdman, do you have any closing remarks?

David Erdman

Thank you, Tanya. That's all. Thank you, everyone, for joining us this morning. We appreciate your interest in Quicksilver Resources. This now concludes the call.

Operator

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

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