Quicksilver Resources Management Discusses Q4 2013 Results - Earnings Call Transcript

Mar.14.14 | About: Quicksilver Resources (KWK)

Quicksilver Resources (NYSE:KWK)

Q4 2013 Earnings Call

March 14, 2014 11:00 am ET

Executives

David Erdman

Glenn M. Darden - Chief Executive Officer, President, Director and Member of Equity Awards Committee

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

Analysts

Brian M. Corales - Howard Weil Incorporated, Research Division

Kathryn O'Connor - Deutsche Bank AG, Research Division

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

David Epstein - CRT Capital Group LLC, Research Division

Joseph Patrick Magner - Macquarie Research

Operator

Good morning, and welcome to the Quicksilver Resources Fourth Quarter and Full Year 2013 Earnings Call. My name is Mary Kate, and I will be your operator today. [Operator Instructions]

I would now like to turn the call over to David Erdman, Director of Investor Relations. Please go ahead.

David Erdman

Thank you, Mary Kate. Good morning. I'm joined by: Glenn Darden, President, 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 and full year 2013. A copy of the release is available on the press releases link of our Investor Relations webpage. 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 those projected in these forward-looking statements. Additional information concerning risk factors, which could cause such differences, are presented in length in the press release we issued this morning as well as in the company’s filings with the SEC.

This call will also include information regarding adjusted net income, which is a non-GAAP financial measure. A reconciliation of adjusted net income to the most directly comparable GAAP measure is available with the press release we issued this morning.

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

Glenn M. Darden

Thank you, David. Good morning. Today, Quicksilver reported earnings for the fourth quarter and for the full year 2013. For the fourth quarter of '13, we had an adjusted net loss of $5 million. The full year reported earnings were positively impacted by the sale of the Barnett properties to Tokyo Gas. And John Regan, our Chief Financial Officer, will give you the financial detail following my remarks.

Quicksilver's concentration has been on improving the company's balance sheet and liquidity, and as a result, 2013 was more of a defensive year. On the financial front, we lowered net company debt approximately $300 million to the end of the year. We also refinanced $1.1 billion of company bond debt, which reduced interest expense and extended debt maturities by 2.5 years. We have relied on asset sales to lower debt.

We began last April with the Tokyo Gas sale. We followed with the sale of our Montana assets, and most recently, we announced the divestiture of our Colorado interest. Quicksilver also announced last November the formation of a joint venture with Eni in West Texas. Eni and Quicksilver have been partners in the Barnett for the last 5 years, and this JV is an attractive expansion of that working relationship. John will discuss our reserve picture in 2014 capital budget but directionally, that budget and spending is focused in '14 on drilling and completion projects, targeting building company cash flows.

Now I'd like to talk a little more about the Colorado sale. The clock started with Shell, our JV partner's announcement, to exit this investment and several other North American oil shale basins. Once they decided to begin a sales process for their 50% interest in the JV, we needed to evaluate our options. Not long after we received -- not long after that, we received an inquiry from Southwestern to purchase a portion of our interest.

From a near-term perspective, Quicksilver had additional cost to renew acreage in this large lease block, and another consideration was the uncertainty of the size of the upcoming capital expenditures proposed by a potential new partner. We evaluated this side-by-side with our other grassroots oil project in West Texas, and with that JV with Eni, our drilling and completion costs in as many as 5 horizontal tests are covered with a 50% carried interest in the 52,000-acre block. In addition, we are carried for a smaller interest in a test well on 7,500 acres on the northwest side of this core acreage.

Based on our analysis, we believe we can reach a development decision point more expeditiously and at a significantly lower cost in the West Texas project. In the end, we decided to monetize our Colorado position and entered into a 3-way party agreement with Quicksilver and Shell committing to sell 100% of our JV interest to Southwestern for $180 million.

With this sale, our focus will be sharpened to 3 core areas: The Barnett, Canada, with Horseshoe Canyon and Horn River, and West Texas. In the Barnett, we expect to drill 30 gross wells this year, continue with our successful work-over program, and look for new opportunities to leverage the company's operational efficiencies across a bigger footprint. Our team continues to lower costs in those segments of our operation, and we expect to arrest the decline in the Barnett from reduced spending over the last 2 years. Barnett volumes should be approximately flat to up slightly for the year relative to 2013, on a pro forma -- for the TG sale basis.

On the Canadian side, we're working to complete a transaction on the Horn River Basin project. We haven't reached the finish line, but we're on a good track and it's the same track, and we believe we're dealing with the right players at the right levels to make this project a success. Our strategy has been to join with strong companies with a mandate to lower their supply costs, and our goal is to secure a long-term value creating solution for all involved. That strategy is playing out and we'll give an update when we execute agreements.

Quicksilver has acquired an excellent site for potential LNG export, we've lowered gathering charges and pushed out capital commitments with our midstream partner, KKR, and we've trimmed transportation costs as well. Each of these elements has improved the overall Horn River project.

Our Canadian team is also busy drilling new wells in the Horseshoe Canyon development, and we expect to have up to an additional 100 gross wells online by year end. So far in 2014, AECO, the Canadian pricing hub, has rallied and closed the discount gap with Henry Hub, improving our net backs in Canada as well.

We clearly understand our mission. The Quicksilver team is operating more efficiently, is continuing to cut costs and is knocking down strategic transactions. We have significantly improved the Horn River Basin project with the goal of securing the right partners to create value for all involved. We look forward to reporting additional progress as we execute on the plan.

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

John C. Regan

Thank you, Glenn. Good morning, everyone. Earlier today, we reported fourth quarter adjusted net loss of $5 million or $0.03 per diluted share, resulting in full year 2013 adjusted net loss of $32 million or $0.18 per diluted share. This decline in adjusted earnings compared to prior year is largely attributable to lower volumes and lower realized prices. We had 18% lower production volumes in 2013, which reflects our after sales and minimal capital activity. We had 28% lower realized NGL prices resulting from a decline in market prices and the roll off of several premium price swaps and the lower realized prices on natural gas, primarily again related to the expiration of several premium price hedges at the end of 2012.

Before continuing, I'll remind everyone that adjusted earnings is a non-GAAP financial measure, and as such, we have provided a reconciliation to reported net income in the table of our earnings release.

We also reported this morning 2013 proved reserves of 1.3 trillion cubic feet equivalent, calculated under SEC conditions, which is a 19% increase over our 2012 proved reserves pro forma for the TG and Synergy transactions. Our standardized measure of $820 million is a 71% increase over 2012 pro forma reserves.

Our proved reserves and our standardized value reflect the improvement in natural gas price, that our TGE to total proved ratio was 88%, which is comparable to 2012 for us. If you recall, our 2012 SEC reserves were based on the benchmark natural gas price of $2.76, which was around $2 below the average 10-year natural gas forward curve in February of 2013.

Although the 2013 SEC benchmark natural gas price is $0.91 higher than the 2012 SEC price, it's still about $0.73 below the recent 10-year natural gas forward curve, and thus isn't necessarily reflective of what we believe current market values would be.

At year-end 2013, we had 32 PUD locations in the Horseshoe Canyon, compared with 0 PUDs there in 2012. We had a total of 55 Barnett undeveloped locations in 2013, or 5 fewer than we had in 2012. Again, our PUD to prove ratio remains historically low, and is one of the lowest in our peer group.

Similar to 2012, we estimate our total reserve percent potential at nearly 14 trillion cubic feet equivalent, the vast majority of which is attributable to the potential of our Horn River asset. Our proved reserves in the Niobrara were 70,000 barrels at year end 2013.

Turning to production, we averaged 266 million cubic feet of natural gas equivalent in the fourth quarter, which is at the midpoint of company provided guidance. However, we experienced inclement weather on our service areas in north Texas and in British Columbia that caused a slight disruption in value -- in volumes during the quarter. Specifically, heavy icing disrupted production in the Barnett by approximately 25 million a day, for 5 days or an average of about 1.2 million for the quarter, and below normal temperatures in the Horn River Basin caused freeze offs, resulting in a loss of about $7 million a day for 15 days or an average of $1.2 million per day for the fourth quarter.

Excluding the impact of these factors, production would have been at the top of the guidance, resulting instead in a 2% decline for third quarter volumes compared with a 3% decline based on actual figures. In any case, fourth quarter production is down due to the absence of any new production coming online as our capital production in the third and fourth quarters was deployed towards the drilling of 7 Barnett wells, which are currently being completed, or are in flow back, and for which we expect first production within the next 30 days.

On the cost side, excluding nonoperational and nonrecurring items as outlined in our press release, total cost for the fourth quarter, which include: LOE, GPT, production taxes, G&A and DD&A, were $3.11 per unit in the aggregate, which is $0.19 under guidance. This is mainly attributable to lower-than-expected G&A, which I'll cover in a few moments.

LOE per unit was at the midpoint of guidance, as our cost containment efforts offset the negative impacts of weather I described earlier.

With respect to our announced sale of the Niobrara asset, we expect a $2 million reduction in LOE for the remainder of 2014. Operating expenses created [ph] in Colorado are disproportionately higher than average unit expenses in our core areas, as is typical of an oil play, particularly in the exploration phase. We were not previously forecasting significant production or operating income from Colorado in 2014.

On GPT, we continue to see upward pressure on unit cost, as Horn River volumes are declining, particularly in light of the fixed volume commitments that we have there. But since year end, we have begun partially fulfilling our unused midstream capacity via an uninterruptible assignment to a third-party producers, which will help suppress the effects of future production decreases in the basin.

G&A is $0.19 below guidance, primarily due to lower-than-expected costs for the quarter for outside professional fees and for costs associated with our strategic ventures that are excluded for purposes of presenting adjusted earnings. Excluding strategic transaction costs and other nonrecurring items, G&A at 2013 is down 22% year-over-year, as we implemented efficiencies and adjusted structural costs in response to the weakness in commodity prices during 2012 and 2013. We do expect some upward trending on G&A this year, as we're planning to fill some key positions and as we adjust our annual incentive compensation.

Production in ad valorem taxes are $0.11 below guidance, due mainly to lower-than-expected appraisal value on many of the Barnett assets, which resulted in a reduction to the ABT process for payment in the fourth quarter. All of our prospective costs per unit reflect a decreased production in Q1, which was the driver behind our providing guidance on both a unit and an absolute dollar basis for Q1 of '14.

Turning to capital spending, we incurred $26 million of capital in the fourth quarter, much of which was directed towards drilling in the Barnett. We drilled 6 wells in our Alliance field, but these wells won't contribute meaningfully to production until the second quarter of 2014.

Our full year CapEx incurred was $99 million, which is $21 million lower than our original capital budget, as we deferred spending in West Texas pursuant to our joint venture efforts, and we capitalized West overhead as a result of lower capital-related activity and staffing reductions we experienced in 2013.

Next, I'd like to outline the amendment we made to the Fortune Creek partnership, where we secured 2 key changes to the agreement. First and foremost, in consideration of a $28 million cash contribution, Fortune Creek will reduce the gathering rate assessed on Horn River volumes by $0.13 per unit until at least 2016, and by an average of $0.07 every year thereafter for the remaining term of the gathering agreement. Our minimum volume commitments at Fortune Creek, however, do remain the same.

Second, the amendment provides for a deferral of the required capital spending in Horn River, and allows for the inclusion of acquisition spending for properties whose production can be directed to the partnership's facilities. As amended, the timeline for the remaining $120 million drilling obligation in the Horn River is extended until the earlier of 12 months after the closing of a material Horn River transaction, or June of 2016.

From an accounting perspective, the amendment will synthetically lower the gathering rates paid for Horn River production, but they will appear on our financial statements as a reduction to the Fortune Creek accretion through our consolidation entries. Accordingly, we expect a 20% reduction in accretion expense this year from the 2013 levels.

Lastly, the amendment provides that KKR is released from the required funding of a new treating facility in the Horn River, but they do retain the option to fund the facility or any other facility constructed by Fortune Creek in the basin. In light of this amendment, and based on our objective to preserve liquidity, we expect only minimal capital activity in the Horn River, on both the upstream and midstream side, until we secure a transaction for the asset. The pragmatic significance of the amendment is that we are now able to enhance the near-term cash flows of our Horn River production, and more closely align future drilling activity with the anticipated lead time of capital spending following the completion of a strategic transaction with the asset.

Now turning to the 2014 capital budget. Our board has approved $136 million capital budget, which will be heavily focused on EBITDA-generating projects. Approximately $98 million or 72% of the budget is earmarked for drilling and completion activities in the Barnett and Horseshoe Canyon, where we see opportunities to add production at attractive rates of return. In contrast, we invested only 50% of the 2013 capital budget on drilling and completion dollars across all the assets, and only 20% on drilling and completion in the Barnett Horseshoe Canyon. The drilling and completion portion of the capital budget is expected to maintain flat production from those 2 assets to their respective average fourth quarter 2013 rates, which was approximately 216 million cubic feet of natural gas equivalent per day in total.

Overall production in 2014 is expected to decline approximately 7% compared to 2012 pro forma due to the impact from declining production in Horn River, again, due to our limiting capital deployment there.

Having said all that, we do expect NGL -- the recent NGL price increases and some vendor concessions could afford us an opportunity to accelerate development of some of our southern Barnett inventory, which is outside the capital budget we've described earlier.

As disclosed in our guidance provided in the press release this morning, first quarter production is expected to decline approximately 8%, which is due to 3 significant factors: First, approximately 8.5 million per day on average of Barnett volumes were curtailed during first quarter as we shut in adjacent wells to conduct completion activity on the wells we had drilled in the previous 2 quarters; second, fourth quarter 2013 Barnett volumes were elevated by approximately 14 million per day, due to the recognition of NGLs which had been stockpiled in the second and third quarters last year, related to the outage at a third-party fractionation facility; and third, inclement weather negatively impacted first quarter production by approximately $2.4 million per day, as discussed earlier. These 3 factors are also causing an distortion of unit costs, due to our fixed cost structure.

The 2014 capital budget also includes $15 million for leasehold and $23 million for customary capitalized overhead and interest expense. The capital budget does not include dollars which we may ultimately deploy -- acquisition dollars which we may ultimately deploy during the year. As such, we may amend the capital forecast for potential acquisitions, expanded Southern Barnett spending or upon clarity of the Horn River transaction.

As a reminder, we'll be conducting exploration activities in West Texas this year under a full capital carry by joint ventures, as Glenn described earlier. We expect to spud 2 wells in West Texas by the end of June.

Turning to cash flows, Glenn mentioned some of the specifics about the Colorado sale, but again, it will effectively create cash flow this year of about $120 million in the form of net sales proceeds and for non-capital spending on lease renewals and our portion of drilling costs on proposed 2014 wells. The sale will help maintain liquidity and provide us with the opportunity to invest more extensively in our lower risk core areas.

Operating cash flow in the fourth quarter was $29 million. For full year 2013, excluding the impact of payments we made for tenders, consents and other costs pursuant to the debt refinance effort last summer, operating cash flow was $48 million. We raised $506 million from asset sales in 2013, and spent cash capital of about $101 million, thus spending well [ph] entire cash flow, and driving the reduction to net debt that Glenn described earlier.

At year end, we had over $350 million of combined liquidity in the form of cash, marketable securities and availability under our revolver. We anticipate retaining the $90 million of expected proceeds from the Colorado sale until we have clarity from the redetermination of our global borrowing base, which we expect will occur in April. We do not expect the sale itself will result in a material change to our U.S. borrowing base as the asset was associated with an insignificant amount of proved reserves.

As a reminder, we are currently restricted from deploying the proceeds from the Colorado sale or any other asset sale to retire any portion of the outstanding 2016 sub notes. We expect to meet our remaining investment -- reinvestment requirement arising from the Tokyo Gas transaction, primarily through investments, our 2014 capital program and perhaps with an immaterial paydown of senior debt and through available deferral baskets in our credit agreement.

Despite the recent increases in commodity prices, our portfolio of natural gas swaps are still accretive to today's natural gas strip. Approximately 75% of our expected production in 2014 is covered by fixed price swaps at a weighted average price of $5.08 per Mcfe. To put it in perspective, the natural gas swaps in our core group portfolio are about $0.65 higher than the average of the remaining 2014 strip, based on recent closing prices and are about $1 higher than the average 2015 strip.

We expect to complete a timely filing of our Form 10-K, either following market close today or on Monday. We expect that a new material weakness will be noted in our filing around the operating effectiveness of our controls, surrounding the recording of significant nonrecurring transactions. We also expect a material weakness reported in our 2012 Form 10-K, related to the reconciliation of deferred income taxes, mainly the temporary difference for fixed assets had not been remediated. Management continues to implement new policies and procedures, and we are working closely with our independent accountants and other service providers to remediate these weaknesses. We are confident that we have the deployed sufficient substantive work around these matters to satisfy ourselves that our financial statements are accurate.

One final note. After filing our 10-K, we expect to file an S-8 to register shares for our annual employee and director compensation programs. We also expect to file an S-4 in the second quarter to register the 2021 notes -- senior notes we issued last summer.

In closing, our goals remain the same, mainly to showcase the value of our Horn River assets via transaction, to build cash flow in our core areas, to sustain liquidity -- sufficient liquidity to continue pursuit of those cash flows to address the 2016 subnotes, to reduce overall leverage, and to continue to attack our cost structure. As I said previously, we aim to accomplish many of these goals on the heels of a capital spend.

And with that, I'll turn the call back over to David to cover first quarter guidance, and begin the Q&A portion of our call.

David Erdman

Thank you, John. Let me quickly cover first quarter guidance. We did outline guidance in the press release we issued this morning.

First quarter 2014 production volume is expected to be 240 million to 245 million cubic feet equivalent per day, and full year volume is expected to be 245 million to 255 million cubic feet equivalent per day. Our cost on a -- both a unit basis and an absolute dollar level are as follows: LOE between $18.5 million and $19.2 million or $0.84 to $0.88; GPT between $31.3 million and $31.8 million or $1.43 to $1.45; production taxes between $3.5 million and $4 million or $0.16 to $0.18; G&A between $12 million and $13 million or $0.55 to $0.59; and finally, DD&A between $13 million and $13.7 million or $0.59 to $0.63.

So that completes our prepared remarks, and we're ready to move to the Q&A portion of our call.

Mary Kate?

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

One, in the past you all have had a pretty big, uncompleted well backlog in the Barnett. Can you just remind us where that stands, kind of drilled on completion?

John C. Regan

Yes. Including the wells that I mentioned that we had drilled in the third and fourth quarter, that number's at about 20. And so again, you're going to see us bring it, 7 or more of those online in 2014. So given where we think the drilling dollars are going to get deployed, I would expect we exit '14 at less than half of that number, even.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay, that's helpful. And then, I know that the Horn River deal has been going on for a while, I mean, can you maybe give us a timeframe over the next months or a couple of quarters that -- what we should be expecting, either from Horn River, or is there other potential asset sales that you all are looking at that can bring in some liquidity?

John C. Regan

Well, what I'd like to say on the Horn River, I think we said in the prepared remarks, we're making progress, we're dealing with the right players, but we're going to announce it when we've got it done. And I think we are dealing at the right levels, we've got the right players in there, and we'll talk about it when it's baked. I'd like to give you more tighter guidance. I'm not -- I haven't been very good on that guidance.

Glenn M. Darden

I think, following up on the latter half of the question, I, there's -- I don't think that you're going to see -- the same, except for the Horn River as I mentioned, I don't think you're going to see much in the way of additional amount, anything in the non-core side of any substance in '14. I mean, I think we've got a couple of assets in the portfolio that are fairly insignificant, that we may help -- we may market in order to help liquidity.

Operator

[indiscernible]

Unknown Analyst

Just a -- been trying to understand the Barnett. And, as I look sequentially, maybe, first, walk us through what the numbers are, in terms of the production and how we should think about, so we can think about, sequentially. You reported a 166 7. Maybe normalize that for all the additions, and then walk us through what the next couple of quarters look like, because I'm a bit confused on the timing of the completions and what that means for production, given your lower production in Q1 but it looks like a ramp up in the latter half of the year in overall production.

David Erdman

Yes. I think you're right. So what you're going to see is, from the fourth quarter rate in the Barnett, you are going to see a dip in production, moving in to first quarter. Again, the wells that we drilled in the third and fourth quarter of '13 are -- were completed in the first quarter, they're either in flow back or in completion right now. And so we expect to bring those on later this month or early in Q2. So in Q2, you'll begin to see, as Glenn said, to arrest the production declines. And so what you'll see is production growth across the remaining 3/4 in the Barnett. And so I don't know if that's the response to your question.

Unknown Analyst

Well, I'm trying to understand the numbers that you had said, there was an 8.5 part of curtailment in the '14, I think, you said of a one-timer. So what was the "real exit rate" of the Barnett for calendar 2013?

David Erdman

That was, Steve [ph], that is -- the real exit rate there when you talk about the 166, that 8.5 that John referred to was, I believe, the curtailment, according to or with the completion activity that we were conducting in the basin in that quarter. And so what happened is, we were dealing with some weather disruptions in the fourth quarter, that then makes the exit rate in the Barnett closer to a 168 handle on an equivalent fee basis.

Unknown Analyst

Right. I mean, maybe flesh this out a little bit more, but I just wanted to see if that's the 168, then you see some decline, but you're going to ramp up. I'm just a little -- I'm just not following all the numbers, but maybe we'll talk about that later. But maybe 2 last ones I'll slip, then. One, explain more what this material weakness is, if there's any cash associated with it. I'm not quite sure I followed what it was, and if it's a big deal or not. And then secondly, what was your -- you gave the standardized measure, what's the PV10?

Glenn M. Darden

Okay. I missed the second question, Steve [ph], but on the material weakness, I think, as you've seen in our quarterly financials, we've been making adjustments to the Tokyo Gas transaction. And so principally, as we went through year end, we had some additional controls that -- or annual controls that were deployed, that identified some of our non-oil and gas assets that were conveyed as part of that transaction. So what you've seen is us make adjustments to the ultimate amount of the Tokyo Gas gain. And so we have concluded that, with respect to the calculation of the gain for the Tokyo Gas transaction, we had a material weakness. So we're confident that we have accurately reflected that in our financial statements now. So I think, in answer to your question, no. The adjustments that are giving rise to the material weakness do not have cash impact.

Unknown Analyst

And just lastly, the PV10, the pretax PV10?

John C. Regan

Well, I can't actually give you that, Stephen, because it would be a non-GAAP measure, because it doesn't include income taxes. So I can give you the standardized measure, which would be a GAAP number, but I can't give you the PV10. We can work with you off-line to make sure you got the information that would help you out in that regard, though. But I mentioned the number in my prepared remarks.

Operator

Our next question is from Kathrynn O'Connor from Deutsche Bank.

Kathryn O'Connor - Deutsche Bank AG, Research Division

I just wanted to ask a question about the Horn River transaction. I know in the past you've sort of spoken about when you made analogies to this transaction versus the Barnett transaction that you have milestones that you hit along the way that are very obvious to you, but are not very obvious to the investment community. I'm just wondering if you can give us a little bit more color on that. Is this the kind of situation where you have an agreement in theory and valuation and were more in the procedural part of it, where we need board approval or internal approval some partners? Or are we still at the phase where we're hammering out? Just give us a little bit on that, maybe.

John C. Regan

It's -- we're in the middle of it, Kathrynn, and we're not going to share details. We like where we're going. That's about as clear as I can give you a signal. We're not going to negotiate this in the public side. But I hope you can appreciate our position there.

Kathryn O'Connor - Deutsche Bank AG, Research Division

Yes, sure. I mean, I guess, based on where we are now, do you think that you could at least get it done sort of in line. I know with before we had talked about getting it done sooner than the Barnett. Can we at least expect it to be somewhat in line with the way the Barnett transaction went and timing-wise?

John C. Regan

Well, again, we're not going to give color. I think that one of the things that we talked about today was the KKR agreement, which kind of factored in an earlier or a transaction possibly occurring inside of the extension timeframe on the capital spend. So we're cranking on it. That's what I can tell you today.

Kathryn O'Connor - Deutsche Bank AG, Research Division

Okay. And then, just -- can you give us a little bit of color on the CapEx guidance that you've given us now for 2014 and how that compares with what you've spoken about in the past as to what you would need to keep production flat at the company?

John C. Regan

Yes. So obviously, this -- the number we had quoted in the past and, I guess, dredging my memory here, but 50-ish, keep Barnett sort of flat and then another -- basically, double that to keep the company flat. So I think you're seeing the dollars being deployed, but we've got about $100 million of drilling completion capital being spent this year and we're expecting relatively flat volumes. It'll be down a little bit. But the majority of the impact of it being down are largely either weather-related that we've already experienced, or the shutting in of adjacent production to bring that new production online. So I think what you're seeing is a capital program this is largely reflective of what we had previously, communicated in terms of what it would take to keep flat production.

Kathryn O'Connor - Deutsche Bank AG, Research Division

And is some element of this timing, I think, to a previous question about having certain wells drilled, but only completed and flowing back and then coming online in Q2, is it sort of a delay in some of the money that you've been spending, too? Maybe which is why we've been seeing a slight decrease in, based on the fact that you would think that you're spending the right level to keep production flat?

John C. Regan

Yes, that's a good point. So as I mentioned, we did close many new [ph] production online in Q1. And so there is -- all we have is production declines and production off in Q1. And so bringing that production back on here in the end of the quarter and then the new production moving into the second quarter is, on a full year basis, helping us maintain.

Kathryn O'Connor - Deutsche Bank AG, Research Division

And then just, you mentioned a couple of times on the call so far of the possibility of M&A and other things. And I'm just wondering, do you have a specific asset in mind that you're looking at, M&A-wise, and you're just waiting on the other Horn River transaction to get the liquidities for that? Or are you just thinking more broadly, once you get some liquidity from the Horn River transaction, that you'll be looking for assets to enhance your Barnett position?

Glenn M. Darden

Yes. I would say the latter is more correct. We're certainly not looking -- we don't have -- we have targets that we always look at. But our focus is liquidity, our focus is building cash flows. But also, as I said in my remarks, expanding our Barnett footprint as you picked up on. So we're looking at opportunities there. But I think we would see a catalyst on the Horn River before we move on anything.

John C. Regan

I think just in the ordinary course, your brethren in the banking business are -- lots of opportunities out there on the buy side.

Glenn M. Darden

But I think a lot of these are smaller bolt-on type.

John C. Regan

Absolutely, yes.

Kathryn O'Connor - Deutsche Bank AG, Research Division

Okay, understood. And then, last one, just a cleanup item. The G&A seems, especially I guess if you take out the strategic transaction cost, looks pretty low. Is that the kind of thing that's sustainable? Or will you eventually have to bring that back up?

John C. Regan

Well, as I mentioned, there are a couple of vacancies that I think we're looking to fill here in '14 that drive G&A. The other thing that you're seeing kind of in the Q4 to Q1 quarter-over-quarter increase is that we did pare back some of the annual incentive awards in the fourth quarter of this year. And so our projections, moving forward, have -- reflect kind of a full payment accrual of moving into the first quarter. So what we would accrue in Q1 won't get paid previously until 2015. But we are targeting building the accrual at a little higher level than we have for this year. Couple that with things like our audit bill, which is a little higher in Q1, because the other spent more time in the first quarter here. So things like that are what's driving the increase and so you have kind of a dip in Q4 and kind of inversions [ph] a little bit in Q1. But I think largely, what I feel like we had adequate resources to discharge what we need to discharge here. So I don't think you're going to see a massive expansion in G&A. But I do think you may see us fill some positions.

Operator

Our next call is from Noel Parks from Ladenburg Thalmann.

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

Just had a couple of things. With the Horseshoe Basin drilling that you started back up, can you just give us an update on what the kind of economics are up there, well cost and so forth?

Glenn M. Darden

Yes. I think overall, Noel, that we're probably 25% to 30% rates of return. These are projects that we have a lot of the infrastructure in. And there, as I said in the remarks, we've seen a nice improvement on net backs. So these are projects that are really bread-and-butter for us and very nice returns.

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

Okay. And what differential assumptions are you modeling for that production sort of on a full year basis?

Glenn M. Darden

On the basis differential?

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

Yes.

Glenn M. Darden

Yes. Based on forward curve, it's probably about a 10%, carry that from NYMEX. And of course, you know we do have some derivatives covering a piece of that.

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

Sure. And I wanted to ask you something about the Niobrara JV with Shell and the sale there. If I remember right, there was an AMI as prior the JV. Going forward, after it changes hands, do you retain any sort of interest override or anything in the area? And is there any prohibition from you doing any other regional activity there in coming years?

Glenn M. Darden

We do have some mineral interests that we'll be leasing to Southwestern as part of the agreement. To my knowledge, we don't have any restrictions of coming back in.

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

Okay. Are those significant mineral interests or just very limited ones?

Glenn M. Darden

There -- it's not significant.

John C. Regan

It's probably less than 5% of the acreage.

Glenn M. Darden

Yes, less than 5% of the acreage or so.

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

Okay, got it. I think that's it.

Operator

Our next question is from David Epstein from CRT Capital.

David Epstein - CRT Capital Group LLC, Research Division

In your Q1 and full year production guidance, I might have missed it, did you give the breakdown of how much you think from the Barnett, how much elsewhere?

Glenn M. Darden

No, Dave. We've not given that breakdown. I think if you wanted to talk after the call, certainly, we'll provide that clarity.

David Epstein - CRT Capital Group LLC, Research Division

Okay. And talking about -- you've talked in the past about the amount of CapEx to keep production flat. That's strictly drilling CapEx like the leasehold and the seismic and the capitalized overhead and interest, that's all extra, above and beyond, sort of the figures you're throwing out?

John C. Regan

Yes, that's right, that's direct capital.

David Epstein - CRT Capital Group LLC, Research Division

Okay. And then, I was looking back to the presentation you did -- you did a couple of presentations in the first half of 2013, obviously, at the big price related reserve revisions in 2012 and then you put out at the strip pricing, what the price-related revisions might be to the upside at those higher prices. It seems like -- so it's good you had some technical revisions in the 2013 reserve report, but it seems that the price for related revisions weren't as high as we might have thought they would have been. What's going on there?

Glenn M. Darden

I don't know how to answer a question that's based on your expectation. But I'd say...

David Epstein - CRT Capital Group LLC, Research Division

Well, let me rephrase, let me rephrase. It seemed a little bit light than what was baked into those earlier presentations that you guys had on sort of a pro forma basis, and obviously, there's some moving parts because some of your slides you had pro formas for the Barnett transaction, some weren't. Obviously, the current price, the SEC price for 2013 isn't exactly what you had in sort of those earlier slide projections, but it's not too far off. It looked like what you added back is less than what you guys indicated would be added back 8, 12 months ago. Am I wrong?

John C. Regan

Well, so one of the impacts was, in the first half of the year, some of the presentations were not reflective of the Barnett sale. So clearly, some of what we did in the 2012 phase wouldn't be projected forward at the new price. Except for that, the other thing that you're seeing is a decrease in the NGL pricing year-over-year. When we talk a lot about gas, nat gases, important just from a pricing perspective, but you saw about a 15% or so retreat on NGL pricing that countervails sort of the benefits we saw on the natural gas side. But you're right, from a technical revisions standpoint, there wasn't a lot there. One thing we did have, some additional 5-year PUDs roll off this year that are also is depressing what otherwise would have been some of the reserve growth. But in my prepared remarks, I gave you the kind of the absolute number of PUD locations year-over-year. So I don't know if that's dispositive of your question, but I think -- Tokyo Gas is a piece of it, as is NGL pricing.

Glenn M. Darden

And with the 5-year roll off, we still have those leases. And it's really based on the last couple of years of capital and expected capital going forward. As things improve, obviously, we can bring those things back on, those locations back on.

David Epstein - CRT Capital Group LLC, Research Division

Right. So that final point might be as much as anything. There was no sort of change as far as views on geology and that sort of issue.

Glenn M. Darden

That's right.

Operator

The next question is from Joe Magner from Macquarie Research.

Joseph Patrick Magner - Macquarie Research

Just curious on some of the material weaknesses you discussed. Did that have something to do with -- it looks like there is a pretty significant change to the deferred tax benefit for the year and then also a cash tax payment that might have been made in the fourth quarter. Is that related?

John C. Regan

No, it's not actually related. So you're right, there is a benefit in the fourth quarter and that's related to an income tax refund that we've actually collected in the first quarter this year. But otherwise, I think the movements -- our deferred taxes are really reflective of the fact that we got a valuation allowance against our deferred tax assets. And so as we get certainty around the temporary differences, you see it driving to the tax line.

Joseph Patrick Magner - Macquarie Research

Okay. And can you all discuss -- it looked like there was a big draw down on the credit facility in the fourth quarter, what the purpose behind that was?

John C. Regan

As I recall, it seems to me that our availability in the credit facility was fairly constant across the last quarter of the year. So I don't remember a big draw down.

Joseph Patrick Magner - Macquarie Research

Okay. I thought there was a couple of hundred million available at the end of the third quarter and that dropped to under $100 million at the end of the fourth quarter, just make sure I saw that.

John C. Regan

Yes. I think you may be confusing overall liquidity with availability. So I would say that liquidity at the third quarter was about $300 million, and that was roughly 2/3 cash and securities on hand and about 1/3 of availability under the credit facility. And so there's projecting that forward to the 12/31 numbers. You had about $350 million in liquidity, which is about $250 million of cash and securities and about $100 million of credit facility. So I guess, with those 2 snapshots, the availability on the credit facility was fairly, fairly at parity.

Joseph Patrick Magner - Macquarie Research

Okay. Maybe I'll follow up afterwards. In terms of the renegotiation of the spending requirements in the Horn River, what did that -- where does that show up in terms of the liability? I imagine that was a current liability and probably got pushed into another bucket. Just curious what the net impact was on the balance sheet.

John C. Regan

So the spending requirement was actually -- was it not a recorded liability. It was disclosed in our commitments and contingencies. And so really, the payment itself is an off-balance sheet effect, except that it does reduce the partnership liability that we have on the balance sheet on a dollar-for-dollar basis. Well, on our balance sheet we have a liability for the partnership. But the capital spending is separate, apart from that. So the capital spending itself is nowhere on the balance sheet, disclosure only. The payment we made will defray the liability on the balance sheet.

Joseph Patrick Magner - Macquarie Research

Okay. And is it possible to quantify KKR foregoing the spending on the processing facility, what that spend would've been and what might need to be financed in the future?

Glenn M. Darden

Well, that spending requirement was based on the pipeline, the Komie North pipeline, getting approved and built. And as you may remember, that was -- that permit was denied at this stage of the game by the NEB. So that really obviated the need for building that plant. So there's no obligation, unless we have building of significant volumes and the building of that Komie North pipeline.

John C. Regan

So again, today, as I think we've said on a number of occasions, there's ample capacity both on the gatherings, the transportation and the treating side in the basin. The midstream's probably been over developed vis-à-vis where the upstream is. So there's ample capacity today. I think as the basin gets clarity about what the ultimate home for the gas is, that you'll see additional capacity get filled and there would be in kind of, in the next decade, clarity as to what the treating needs will be on ours and others' acreage.

Joseph Patrick Magner - Macquarie Research

Okay. And just one last one. Appreciate that you don't want to discuss too many details about the JV process, but in terms of the acquisition of the LNG site, if I remember correctly, the value proposition for Quick in the past was primarily tied to the upstream side by acquiring a site. Has that changed the project plan or the need to present more of an integrated solution to potential buyers or partners? I'm just curious how that fits in or what that change looks like relative to prior plans or discussions.

Glenn M. Darden

Sure, Joe. We are an upstream plate and that's our expertise and that's where we bring value to the table. What we've done is put together a game plan, including a site that appeals to and is directionally toward an integrated model. So that is where we've been headed in all of our discussions/negotiations. And that's what is appealing, I think, to the players at the table. So we're not bringing downstream expertise. We have the expertise on the upstream and moving gas around where we need to. But the players involved are the experts at the downstream and exporting gas.

Joseph Patrick Magner - Macquarie Research

Okay. And is there any sort of a pipeline piece that's involved?

Glenn M. Darden

Yes, there is. But it's not building as much pipeline as some of the other projects that have been announced.

Operator

Our next question is from Gil Nathan [ph].

Unknown Analyst

I had a question for you on -- if you could walk us through a little bit on decline rates. Could you walk us through, in Horseshoe Canyon and Barnett, specifically, without the capital spend to keep production flat, what normal declines look like? And then with new production coming on, what decline rates would look like going forward?

Glenn M. Darden

Yes. I think – Gil [ph], this is Glenn, the base production line -- decline line is probably 7% in the Horseshoe Canyon and it's maybe 15%, 17% or so in the Barnett. That may be a little aggressive, a little high on the Barnett side, probably on the base side, it's closer to 12-ish.

Unknown Analyst

And actually, what this the -- sorry, go ahead.

Glenn M. Darden

No, after you, Gil [ph].

Unknown Analyst

I was going to say also, if you don't mind, HRB, since you're not going to be turning the capital there, what we should think of in terms of decline?

Glenn M. Darden

It's on the order of 20.

John C. Regan

Yes, it's roughly 20, at this stage.

Unknown Analyst

I know you guys are working on HRB and doing a transaction there. Is there any thought with the $90 million coming in from the sale on Niobrara to just increasing the drilling program, especially in the Barnett, right now? Because you seem to have ample liquidity. I know you got 2016 maturity, but there are good rate of return wells.

Glenn M. Darden

Yes, if you think about the things that are coming to a confluence here in the next 60 days or so, that I'll be closing on the Colorado transaction, I'll be getting clarity as to my borrowing base. And so I think with that clarity, I think -- and again, as I mentioned in my prepared remarks, some of the buoyancy in the recent NGL pricing and what we expect that may come to us in the form of better concessions, that southern Barnett development could become pretty compelling. So I think we've got a couple of dominoes to knock down and some clarity to gather and then you may see us do that. That's why I'm trying to signal that in my prepared remarks that, that we're not far from fairly compelling economics for additional southern development.

Unknown Analyst

And where is NGL pricing right now, give or take?

David Erdman

Yes. It's -- what we've been seeing is on a gross basis, recent indications of about $38 on a blended. The forward strip, obviously, is far different looking but today we're getting realizations at that level.

Unknown Analyst

Okay. And historically, or at least, the last couple of quarters, it's trending closer to $29?

John C. Regan

Yes, the high 20s to low 30s.

Glenn M. Darden

I'm just going to remind you, we do have NGL hedges on the books today, which I believe are 4,000 barrels a day through September at close to $30.00 and maybe $0.50 on that.

Unknown Analyst

Okay. And with the recent spikes on the AECO side, has there been better -- you said there's better net back. Is it on a daily realization? Are you just talking across the curve going forward?

John C. Regan

We've taken it -- we have taken advantage of some daily spikes as well.

Operator

Our last question comes from John Raleigh [ph].

Unknown Analyst

Just thinking nothing about the terms, but just the general structure of a theoretical deal. We've seen some comments that say, give you just a straight sale of a piece the Horn River and then you have actual deals out there, think, your oil Total deal, we have completion payments, interim resource payments, file decision payments, first shipment payments. What in general do you think will be simplistic, one piece of the transaction deal or something more similar to what we've seen in the real world the last year?

Glenn M. Darden

Well, I'm not sure that there's been a variety of deals, but again, we're not going to negotiate this in the public eye or spotlight. So I think what we're working on is -- will be pretty simple, pretty straightforward and very explainable to The Street.

Unknown Analyst

That's great. Can you just give us a feeling for -- once you announce a deal, what is the expected post-deal timing for a ramp in Horn River drilling ? Is it you announce the deal and drilling starts to ramp in early '15, '16 or immediately? What -- give us just a general sense.

John C. Regan

Well, that will be decided by the partners. But you will see increased activity.

Unknown Analyst

Okay. And can you remind us, given what's out there today, how large the Fortune Creek system is contemplated to be?

Glenn M. Darden

Well, of course, it depends on demand. And as John said, that -- right now, there is ample capacity and equipment to handle a lot more gas on the gathering side and transportation side. So it really depends on moving forward, their -- KKR would have the option, but not the obligation, to build certain facilities and it depends on dollars invested, certainly, in rate of return, in that regard on their rights. But one of the things that I wanted to go back to your last question, we have seasonality issues with drilling. So let's just say, we announce plans to drill several more wells, we're going to have to move pretty quickly to get drilling in -- a significant amount of drilling in 2014.

Unknown Analyst

I think, I'm not asking my question right, but in terms of Fortune Creek, you guys do have approval for how much capacity there, in terms of maximum capacity you could build and what the planned stages are? Is it 100 million cubic feet a day, is it 600?

Glenn M. Darden

Yes. The permit on the Fortune Creek facility is significantly larger. It's 5x production today, or more.

Unknown Analyst

Right, okay.

John C. Regan

So as you think about the treaties, I assume your question is specific to the treating side of things?

Unknown Analyst

Yes.

Glenn M. Darden

Or is it on the gathering as well.

Unknown Analyst

Yes, it's on the treating.

John C. Regan

So on the treating side, we felt like with one train, we could get some -- we would have the volumes to which we have committed to in the gathering agreement. So I think you saw alignment between what we expect for the treating to be to the gathering side. As the basin has evolved and since we signed the agreement, certainly, nobody -- there's been a lot of drilling activity up there. So at this stage, it's just more economical for us in lieu of constructing a new facility just to take advantage of what the existing facilities there are. And I think that -- you'll see that would be our strategy, utilizing what's already there really until we have clarity regarding development.

Glenn M. Darden

And one more point, the reasons -- I was going to add one more point, that the reason for building that facility was taken away when the permit for building the clean pipeline, TransCanada pipeline, the Komie North, the permit was denied. That may be rekindled and then the reason -- then it would step to the fore.

Unknown Analyst

So this system ties into Spectra? And was contemplated to tie into TransCanada system to take the gas south?

Glenn M. Darden

That's correct, yes. The Komie North line would have been a TransCanada system -- tied into the TransCanada system. Our current production is tied into Spectra.

Unknown Analyst

When we brought up the point earlier, this issue, it highlights the fact that the National Energy Board, the Canadian board, has, I guess, so far approved over 15 billion cubic feet a day in LNG export licenses, for over, I guess -- and then, the prospective number of license applications seems to be growing. You read a new player every day discuss this. Is there any concern that you guys haven't filed or you would file too late, and there could be an arbitrary cutoff or some sort of limit put out by the NEB that would just hurt your prospects of getting the project done? And if you don't feel that way, why?

John C. Regan

Well, I would say we're working on the permit as we speak, on the preliminary, on the license side. But I also think, straight to the project that factors into the decision process as well. And so our objective is to put a stronger project together as we can. And we're not doing this in a vacuum. We've had ongoing dialogue with officials.

Unknown Analyst

Okay. That's very helpful. And last, simple question. Just on your unhedged gating gas anchor. Year-to-date in 2014, what are you guys realizing roughly?

Glenn M. Darden

John, I'll have you owe you that, but it is -- certainly, our net backs have been higher than any -- well, most any point in 2013. We've seen AECO performing very well thus far this year, which we believe is primarily weather-related, of course. And so, I would tell you net backs are higher. And if you wouldn't mind just contacting me after the call and I can make that clarity for you.

Operator

Mr. Erdmann, would you like to make any closing remarks?

David Erdman

Yes, thank you. Thank you, everyone, for joining us this morning. We appreciate your interest in Quicksilver Resources. This now concludes the call.

Operator

Thank you to all of our callers and thank you in the audience for joining us today. The call has concluded. You may now disconnect.

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