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

Quicksilver Resources Inc. (NYSE:KWK)

Q4 2008 Earnings Call

February 25, 2009 11:00 a.m. ET

Executives

Richard Buterbaugh – Vice President, Investor Relations and Corporate Planning

Glenn Darden – President and Chief Executive Officer

Phil Cook – Senior Vice President and Chief Financial Officer

Toby Darden – Chairman

Analysts

Michael Jacobs – Tudor Pickering & Holt

David Kistler – Simmons & Company

Brian Singer – Goldman Sachs

Scott Hanold – RBC Capital Markets

Gil Yang – Citigroup

David Snow – Energy Equities, Inc.

David Cameron – Wachovia Securities

Noel Parks – Ladenburg Thalman

Wei Romualdo – Stone Harbor

[John Heely – Forrest]

[Vevich Pale – Knight]

Joe Allman – JP Morgan

Mayo Shattuck – KKR

Kali Ramachandran – State Street Global Advisors

Steven Beck – Jefferies

Adam Light – RBC Capital Markets

Operator

Good morning, my name is Kashina (ph) and I will be your conference operator today. At this time, I would like to welcome everyone to the Quicksilver Resources fourth quarter, 2008 earnings call. (Operator’s Instructions) I would now like to turn the conference over to Rick Buterbaugh. Rick, you may begin your conference.

Richard Buterbaugh

Thank you Kashina and good morning; joining me today are Glen Darden, President and Chief Executive Officer of Quicksilver Resources; Toby Darden, Chairman; and Phil Cook, Senior Vice President and Chief Financial Officer.

This morning, the company issued a press release detailing Quicksilver Resource’s results for the fourth quarter full year of 2008. If you do not have a copy of this release, you may retrieve a copy of it through the company’s website at www.qrinc.com under the News and Updates tab.

During today’s call the company will be making forward-looking statements, which are subject to risk and uncertainties. Actual results may differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed in the company’s filings with the SEC.

Today's presentation will include information regarding net cash from operating activities before changes in working capital, which are non-GAAP financial measures. As required by SEC rules, reconciliation of net cash from operating activities before changes working capital to their most directly comparable GAAP measures are available on our website under the Investor Relations tab.

At this time I will turn the call over to Glenn Darden to review our operating results in detail.

Glenn Darden

Good morning. This has been another very good quarter for Quicksilver Resources on the operation front, and 2008 produced many highlights. Adjusted net income for the fourth quarter of 2008 was $40.4 million, or $.23 per diluted share. Adjusted net income for all of 2008 was over $221 million, up 83% year-over-year.

Quicksilver replaced 474% of production with the drill bit, with a total replacement of 785%. Company grew reserves 42% from year-end 2007 and reduced unit production costs 20% year-over-year. The company also took two non-cash impairment charges which affected net income. The first was a $411.8 million ceiling test write-down of the company’s oil and gas properties. The second was a $208 million impairment charge for the company’s ownership in BreitBurn Energy partners. Phil Cook, our Chief Financial Officer will discuss these in detail, following my prepared remarks.

On the operational side, our team continues to improve efficiency in the field, and that is reflected in the numbers. As I said earlier, we have reduced our unit production cost 20% year-over-year. Quicksilver’s organic finding in development cost for 2008 was $2.14 for MCF equivalent. We anticipate our 2009 FND costs to back under $2.00 more in line with our three-year average of $1.45 for MCF equivalent. Quicksilver will continue to be a low-cost finder and producer.

There’s been a lot of discussion regarding basis differentials in the Fort Worth Basin. As a reminder, Quicksilver markets 100 million cubic feet of gas per day at Henry Hub, which is the Henry Hub Basin, and has ability to market up to an additional 260 million cubic feet a day at the Katy or Carthage hubs, which receive Houston ship channel pricing. This results in a differential of approximately $.35 often max priced at Henry.

We are seeing significant opportunities to further reduce cost both on the capital side and operationally. A lot of the operational efficiencies are there by design. Quicksilver’s integrated system of drilling, gathering, and processing gas volumes coupled with firm transportation contracts with the pipeline companies result in very attractive margins for our gas volumes. The biggest opportunities for cost improvements are the service and pipe side. As the industry has slowed, we are seeing significant savings in both of these areas. But truly, we’re seeing savings across the board.

As we have talked about before, Quicksilver has hedged almost 80% of its projected volumes of natural gas for 2009, and floors of roughly $8.60 for MCF. The projected volume number equates to a 20% year-over-year growth number. This would be flat with our 2008 fourth quarter production volumes.

We have built in a lot of flexibility in the 2009 capital budget of $600 million, which will allow us to reduce spending, should conditions warrant. And current commodity prices, it may be prudent to reduce capital further allowing for additional debt repayment. Should this occur, obviously our hedge percentage would increase.

Our 2008 production growth was outstanding, excluding the divested volumes from the previously owned Northeast operations in November of 2007. Production grew 67% year-over-year. The increase was driven by higher volumes in the Fort Worth Basin where successful drilling and our alliance purchase last August of 40 million cubic feet a day, increased the volume from the basin 96% versus the 2007 level.

Canadian volumes increased over 10% year-over-year on a reduced capital budget. In addition, our early infill drilling program is working in the Orchard Canyon coals. This program can add an additional 200-plus BCF of gas to our Canadian coal reserve base. The infill program will probably be delayed until gas prices recover and would reduce 2009 budget and spending.

In the Horn River Basin, an area looking more and more like a world-class shale gas basin, we are currently drilling two wells to test the (inaudible) shale. We have reached depth in the first well confirming over 500 feet net shale section. Both wells will be drilled horizontally in the shales, completed, and tied into sales lines later this year. This is a long-term project for Quicksilver with a minimum drilling requirement of only nine wells over four years to validate our exploratory licenses covering 127,000 net contiguous acres. We will then have 10 to 12 years to earn the entire lease block. Currently there are 15 rigs drilling in the area, so it quite active.

Our West Texas exploratory project is testing two more previously drilled wells with new tracking techniques. We have not made commercial production to-date in this project and should these two wells be successful, economics would have to measure up to returns in our existing development projects. At this point, the company has not budgeted additional capital in 2009 beyond these two completions. These are difficult times in the industry and in the world, but Quicksilver was built on a foundation of low-cost and as we took on debt, we added hedges. We have been in discussions with outside parties on certain assets, more on the joint venture side, to further reduce debt and establish a strategy to efficiently develop these long-life assets.

A significant portion of our debt is termed out with no maturities before 2013. We have liquidity in our borrowing base facility with our bank group, which gives us flexibility, although we intend to spend within the company’s cash flow or even less. Quicksilver’s a long-term player with a high quality asset base, and at some point that will be recognized in the marketplace.

And now I’ll turn the call over to Phil Cook, our Chief Financial Officer. Phil?

Phil Cook

Thank you Glen, and good morning. Production volumes as Glen said, grew from 277 million cubic feet a day, equivalent in the third quarter of 2008, to 326 million cubic feet a day, equivalent in the current quarter, an 18% sequential increase. For the current quarter, and the full year of 2008, total production volumes grew 67% and 74%, respectively when comparing the same periods a year ago.

Sequentially, volumes in the Fort Worth Basin grew by 23%. Total production revenues decreased from $218 million in the third quarter of 2008, to $206 million in the current quarter, a 5% sequential decrease. Total production revenues grew by 51% and 85%, with respect to the quarter of full year compared to a year ago. In the Fort Worth Basin, excluding impacts of hedging, production revenue grew by 37% and 153% for the quarter in full year, again comparing to same periods a year ago. And then sequentially excluding the effects of hedging, production revenues in the basin decreased by 31% as a result of pricing.

Again, to differentials, one comment about them is that the recent decrease in the basis differentials should have little effect on our 2009 revenues as we locked in most of our Canadian production at ACO, for differentials about $.85 and as Glen said, the Houston ship channel is about $.35 basis differential. Our realized natural gas price for the fourth quarter was $7.49 after hedging, compared to $8.20 in the third quarter, down 9%. Natural gas liquids realized prices were $26.86 a barrel after hedging in the current quarter, compared to $53.82 a barrel in the third quarter, down 50%. Realized oil prices were $64.03 a barrel in the current quarter, down from $84.80 a barrel in the third quarter, a 24% decrease.

Total oil and gas expense for the fourth quarter was about $36 million, an 8% sequential increase when compared to the third quarter expense of about $33.5 million. On a unit basis, lease operating expense for the current quarter was $.69 per MCFE, compared to $.74 in the third quarter. These amounts exclude transportation processing and production tax expense, but as you can see, our sequential reduction at least operating unit costs was 7%.

Transportation expense, which is the cost to get our gas from the tailgate of our facilities to market, was $.36 on an MCFE basis during the current quarter, compared to $.41 in the third quarter of 2008. Most of these decreases are attributable to the field component of transportation expense due to lower prices. As you know, there is no transportation expense in NGL volumes in the southern portion of the basin, as we effectively sell those volumes at the tailgate of our facilities at a net-net price, and therefore is the mix of our production changes and we produce more dry gas, our unit cost on transportation will tend to increase. To state it a different way, as dry gas becomes a greater portion of our production mix, our transportation expense increases on the unit basis, this is due to the cost of NGL transportation being in the price of the product as we began to receive net-net pricing for NGLs.

Processing expense, which is the cost to gather and process our gas from the wellhead to the tailgate of our facilities for the current quarter was $.15 on an MCFE basis, compared to $.16 in the third quarter of 2008. The decrease in these costs on an MCFE basis is 100-percent attributable to lower fuel costs.

So just as a recap, oil and gas expenses were broken down as follows:

LOE was $.69; transportation expense was $.36; processing was $.15, for a total of $1.20, which is an 8% decrease sequentially. As I’ve discussed with you in previous quarters, the trend on LOE is coming down as compared to previous quarters, as we continue to do our Texas production, we expect to further reduce unit costs.

Production taxes for the quarter were $.25 a unit, an increase from the $.17 a unit reported in the third quarter, and higher than previously issued guidance. The increase primarily relates to first-time property tax assessments on a number of our properties, this entire expense was recognized in the fourth quarter, particularly assets in the Alliance area, which as you will recall, we purchased in August.

The DD&A run-rate for the current quarter was $2.08 a unit, an increase from the $2.03 a unit recorded in the third quarter of 2008. And as you know, our DD&A rate continues to change as we place appreciable assets, such as mainstream assets into service and mix of our production changes between the two full cost pulls. We expect the DD&A rate in the first quarter of 2009 will be in the range of $2.00 to $2.05 in MCFE.

With respect to DD&A, total gross expenses were down about $9.8 million, compared to the third quarter of 2008, which is primarily attributable to a legal settlement agreement reached in the third quarter, which resulted in $9.6 million charge. Excluding the settlement on the unit basis, GNA was $.53 for the current quarter, as compared to $.63 in the third quarter of 2008. The unit cost decrease is $.16.

Adjusted net income for the quarter was $40.4 million, or $.23 a diluted share, as compared to the adjusted net income of $70.9 million, or $.41 a diluted share in the third quarter. Fourth quarter 2008 adjusted net income does not include unrealized non-cash after tax income of $114 million related to the third quarter market income that BreitBurn recorded. A non-cash impairment after-tax charge, and also does not include an non-cash impairment after-tax charge of $208 million associated with our investment in BreitBurn which reduced our carrying value of this investment to the 12/31/2008 market value at $7.05 a common unit.

It also does not include an after-tax non-cash impairment charge, $411 million related to our U.S. oil and gas properties, which as all of you know is primarily due to the significant decline in commodity prices at year-end.

Third quarter 2008 adjusted net income does not include an unrealized non-cash after-tax charge of $67 million, related to the second quarter mark-to-market loss that BreitBurn recorded as well as previously discussed a legal settlement, which was also made in the third quarter. And as all of you will recall, we’re on a one-quarter lag, with respect to recording income from BreitBurn.

During the fourth quarter, the company generated approximately $207 million of cash flow from operations before working capital changes, as compared to $127 million in the third quarter, a 25% increase. This is in part due to the classification of the BreitBurn distributions as operating cash flows in periods that BreitBurn records net income, as well as increases in production for the quarter. The bottom line for BreitBurn income is that in periods where BreitBurn does not record income, i.e. they have a loss, the cash distributions that we receive from them are recorded as investing activities in the event that they turn to a profit, those cash flows are included in operating cash flows. So, what we have in the fourth quarter is the entire cash that we receive from BreitBurn being recorded in operating cash flow during the fourth quarter.

Full year 2008 operating cash flow was approximately $457 million, compared to $319 million in the prior year, a 43% increase. Quicksilver received approximately $42.5 million in cash distributions during the year, associated with the ownership of BreitBurn units.

Our revolving credit facility at year-end was approximately $828 million drawn on an oaring base of $1.2 billion. Total Quicksilver debt at year-end was approximately $2.4 billion, which excludes KGS debt, which is non-recourse to Quicksilver. This translates to consoled net debt to capital of approximately 69%. As I discussed in our previous calls, the maturities on our debt don’t begin until 2011, and that first (inaudible) convertible into Quicksilver stock.

The first cash maturity does not occur until 2013, which is the second ling facility. We believe these maturities give the company significant flexibility regarding cash management over the next few years. We continue to closely monitor the credit and financial markets and although we presently expect to generate sufficient cash to achieve our drilling budget, we do have the flexibility should conditions worsen to pay down debt and slow capital further.

Now I’ll make a couple comments about what to expect for the first quarter of 2009. Production volumes for the first quarter should be in the range of 330 to 335 million a day, on a gas equivalent basis. One comment about FA and rejection and how it affects our production; we regularly monitor the economics of selling FA and NGLs or as a part of our natural gas stream. We’re currently selling FA and NGL, although during part of January we were selling it as part of the natural gas stream, when the economics justified it. While we seek to maximize the value of our FA production, we do not believe that FA and rejection decision will have a significant effect on our production mix.

Also as a reminder, approximately 76% of our 2009 natural gas production is hedged, with a weighted average floor of $8.66, and a ceiling of $10.96. On the unit cost side, these remain obviously, as much affected by volumes as the absolute cost, but with the volume expectations that we’ve given, the following run-rates should be expected for the fourth quarter.

LOE should be in the range of $.70 to $.80 on a unit basis; transportation expense, I would expect would be in the range of $.35 to $.40 on a unit basis. Gathering a processing expense should be in a range of $.15 to $.20. Production taxes should be in a range of $.15 to $.17. GNA should be in a range of $.55 to $.60. And DD&A should be in a range of $2.00 to $2.05. So total cash cost should be the range of $1.90 to $2.17, and total unit costs will be in a range of $3.90 to $4.27.

Now I’ll turn the call back over to Rick for questions.

Richard Buterbaugh

Thanks, Phil. Kashina at this time, I would like to open the calls to any questions.

Question-and-Answer Session

Operator

Thank you. (Operator’s Instructions). Your first question comes from the line of Michael Jacobs, Tudor Pickering & Holt.

Michael Jacobs – Tudor Pickering & Holt

Morning everyone. Glen, your hedge position through 2010 speaks for itself, I wanted some help in thinking ahead through the end of the decade, and if we think about 50 to 75 million a day of unhedged production through 2010, how do you think about your rig count and completion schedule at $4.00 gas?

Glenn Darden

Are you referring to 2009 or 2010 or beyond that?

Michael Jacobs – Tudor Pickering & Holt

Kind of the logical progression as you move into 2010 and kind of where you’re comfortable from a percent of production hedged and how would you think about that unhedged production and associated development schedule.

Glenn Darden

You bet. Well, we will have a backlog of uncompleted wells, so we’ll drill in case this year if we spend our full budget, which that’s debatable with current prices. But if we spend our full budget, we’ll drill 180 Barnett wells, and we’ll complete about 100. So, we’ll add 80 wells to an inventory of roughly 90 wells or so. So, moving into 2010, we have probably five rigs contracted at that point, and that slows down in 2010, so those contracts play out, so those aren’t really factors. So we can slow our drilling down significantly, cut it in half or three-quarters, and just complete wells and still keep production flat should we want to, I mean depending on what the gas price is. So I would – based on today’s prices, I would expect to significantly slow down drilling, slow down completions as well, but keep a reasonable – certainly our hedge production volumes for ’09 and 2010 fulfilled.

But we’re significant savings on the frac side and those savings appear to be accelerating. I’ll give you an example of our budget and this is beyond your question here Mike, but I’d like to bring it out now. Our budget for 2009 is $600 million; $150 million of that is mid-stream and of that $150, a little less than a third is covered by Quicksilver Gas Services. So you take that $450 million, all of those costs that $600 million budget was based on 2008 costs, we’re not seeing 2008 costs, we’re seeing easily 20% and probably more than that, maybe closer to 30% savings across the board.

So that’s well over $100 million of savings, but probably just at the drilling level – drilling completion level at $450 million. So, we’re seeing significant savings, we won’t spend those dollars, we’ll just use those dollars to pay down debt, if we kept the same full programs. So you can see if we ratchet back the program, we’re going to have some significant dollars to pay off. But I think back to your question, we’ll stay within our hedge volumes, probably won’t exceed those a lot, if the conditions are the same in 2010.

Michael Jacobs – Tudor Pickering & Holt

Great, appreciate all that color. Just wanted to touch on comments on JV’s reduced capital requirements and kind of address the balance sheet. Given the tone of the acid market, can you give us an idea of timing when you think about those and is JV something we should think about, is it something in the next 12 months, or is that kind of the next decade?

Glenn Darden

I think in the next 12 months is a good timeframe.

Michael Jacobs – Tudor Pickering & Holt

Apologies if it’s out there and I missed it, but could we get the pretax PB10 number at year-end?

Glenn Darden

After tax, it’s about $1.8 billion. And I’m not sure we – I’m not sure we did pre-taxes. We don’t disclose pretax, but after tax it’s $1.8 billion.

Operator

The next question comes from the line of David Kistler of Simmons & Company.

David Kistler – Simmons & Company

Morning guys. Real quickly on the budget, I believe last you spoke $250 million allows you guys to keep production flat. Is that also consistent with not adjusting for downward move and service costs?

Glenn Darden

You are correct, right that does not factor in any savings.

David Kistler – Simmons & Company International

Okay. And jumping to your credit facility for a second, with a redetermination coming up I believe in May, I’m just kind of curious if we look at the last time they went through it. Do you have a sense for the average price deck that the banks were using, and the reserve base that they were looking at, at that time point versus what they’d be looking at now? Just trying to get a sense for how that might move around.

Phil Cook

Yes, this is Phil Cook. The last time we determined the borrowing base, reserves were about 1.8 TCF and reserves today are 2.2 TCF, so a significant increase from the last time that they looked at it. Pricing obviously is down a bit, maybe by $1, so you know that is going to affect it.

I think, though, because our reserves have increased so much I don’t expect a decrease in our borrowing base. We’re not asking for an increase, but I think it will stay flat. That’s my anticipation. I don’t have any reason to believe that it would get cut.

David Kistler – Simmons & Company International

Okay. Well, I appreciate that.

Phil Cook

The other thing Dave is that obviously we get to include our hedges when that determination occurs.

David Kistler – Simmons & Company International

Sure. That makes sense. And then I guess following up on that obviously if there were ever an issue you could monetize those hedges, but if I’m not mistaken that’s a double-edged sword because they probably give you a little bit better borrowing base based on the security of those hedges.

Phil Cook

We do. We don’t get full credit for the hedges in the borrowing base, so if you did that it’s probably credit enhancing. We certainly like having those hedges out there just from a you know supporting our capital spend over the next couple of years. But the mark-to-market on our hedges is significant, as you would expect.

David Kistler – Simmons & Company International

Yes. And then hopping back to the wells that are being drilled and not completed, or more specifically just the inventory of wells that are being drilled and completed, down more than looks like 50-60% year-over-year versus what you were drilling last year and delivering to sales.

Can you talk a little bit about your ability to drive the production growth rates up from that? And whether that’s high grading the portfolio in terms of going after kind of what would be deemed more core Barnett at higher IP rates, or just basically help me understand how you’re delivering that?

Glenn Darden

Well, I think first of all – this is Glenn – first of all our primary concern is not production growth. I mean, we can ratchet that up. We’ve got the ability to do that. We’ve got the assets to do that, so we’re not concerned with that. Certainly, the market isn’t paying for growth at this point.

So what our concern is to keep an efficient team moving, pay down debt, bridge this gap when commodity prices come back, but we have more flexibility with that, with the Alliance assets, Lake Arlington and our southern Barnett, so we can move rigs across that portfolio with some pretty good flexibility.

So we have more flexibility than we had a year ago in terms of ratcheting up production, but with the savings that we’re seeing on the service side, on the fracking side, on the pipe side, we will factor all of that into our game plan, but at this point our concern is not production growth. Keeping our production flat is not a problem with a lower number than the 250 that we talked about before.

David Kistler – Simmons & Company International

Okay, that’s helpful, but trying to actually get more of a handle on if I think of the Alliance area versus Lake Arlington versus southern Barnett. Can you kind of break out what the IPs or average IPs in production you expect from each one of those areas in terms of if I were to think of hey we moved more rigs to Lake Arlington even though in the past you’ve said you probably wouldn’t do that. But, I’m just trying to think about that as a vehicle for allowing you to manage your cost but also deliver production against your hedges, et cetera, et cetera.

Glenn Darden

Yes. And there’s one other factor. The southern Barnett, as you know, has more NGLs, so when we talk IPs that’s a gas volume, but on equivalent it’s higher. But the southern area where we’ll drill probably one-third of our wells this year – bring one-third of our wells on – that’s in the two, two and a half range to 2-1/2 million per day IPs – two to three let’s say – and they Lake Arlington Alliance are more in the 5 plus million a day range, something like that, but those are dry gas areas.

Operator

Your next question comes from the line of Brian Singer of Goldman Sachs.

Brian Singer – Goldman Sachs

Just following up on a couple of the earlier questions – first on CapEx you’ve mentioned a few times you’re willingness to reign things in a little bit if these commodity prices continue. Can you just talk about a timeline for when you would make such a decision, what gas prices you would want to see and then what you see as the range of where CapEx could be brought down to?

Phil Cook

Brian, this is Phil Cook. We’re making decisions every day, to be quite honest with you. We’re certainly watching our capital on a monthly basis and as Glenn said in his remarks, we will drill inside cash flow this year. We may even slow down a bit more depending on where gas prices go from an all in cash point of view – you know our cash expenses including interest are about $3.30 so obviously we’re still cash flow positive.

We’ve got hedges in place for as Glenn talked about almost 80% of our production. So while bringing on new volumes may not make a whole lot of sense, certainly producing what it’s producing is the right answer for us, but we are looking at capital spend every month and we’ll monitor it very closely as compared to gas prices.

And I’ll add Brian that we do have the flexibility to ratchet back very quickly. So for instance I did mention in my earlier remarks about our in-fill locations in the Horseshoe Canyon. Those are great. Those are leases that are held, and we’ve identified a lot of locations to drill and that’s about probably 40% of our drilling in the Horseshoe Canyon this hear.

Well, we will ratchet that back. How much we will do it? We’ll see, but I think that it’s prudent to look at staying within the hedges right now. Do we go down to that level, we’ll see. That’s a 20% drop, so but we certainly are focused on it as Phil said, on a daily basis.

David Kistler – Simmons & Company International

Got it. And then you also talked about joint ventures and mentioned you’ve got something or potentially something in the next year. Can you just talk about the interest level that you’re seeing now and maybe give us some sense as to whether that’s coming from kind of peer EMPs versus large EMPs versus an international company or majors?

Phil Cook

I would say it’s from larger companies than Quicksilver. It is companies in the industry and it’s for a variety of our assets. So obviously Horn River is an attractive area and a lot of people are not there and would like to be there. So that’s one area that we’re having some discussions.

Operator

Your next question comes from the line of Scott Hanold of RBC Capital Markets

Scott Hanold – RBC Capital Markets

When you’re taking a look at your flexibility to reduce capital, just kind of stay with CapEx at this point in time, what kind of flexibility do you have in the Barnett? Can you talk about right now how many rigs you have running and how that progresses through the year and where really is that flexibility?

Phil Cook

Yes, Scott. We have currently six rigs running, so we had projected that it would have eight rigs running all year and we have six. We’ll move to seven at I think the beginning of March and eight a little bit later this year. But I think where the real flexibility is, is on the completion side, so we have those rigs under contract.

I will say that we’ve looked at – we’re certainly evaluating. Does it make sense to pay a damage fee to get out of contracts, but we haven’t chose that path at this point, but just with the rigs that we have we’ll drill just roughly 180 wells this year.

But probably the real flexibility we have in the Barnett is on the completion side. It’s on expanding, gathering systems at this time so we can reduce that. We probably have $200 million of that $600 million, which is very, very flexible, that we could pull out tomorrow.

Scott Hanold – RBC Capital Markets

And in that $200 million across the board, with infrastructure and drilling, for example on those in-fills in Canada?

Phil Cook

Yes, correct.

Scott Hanold – RBC Capital Markets

Okay so $200 million is your flexibility. And of those eight rigs that you’re going to have at some point in time later this year, are all those under contract for the entire 2009 time frame?

Phil Cook

No, we have a couple of the rigs dropping off I beg your pardon?

Scott Hanold – RBC Capital Markets

No go ahead, you’re answering. Go ahead.

Phil Cook

I was going to say that we have a couple of rigs dropping off in the fall, and several more next year dropping off, so truly we don’t have a long-term exposure there.

Scott Hanold – RBC Capital Markets

Okay. And going to the Horn River, I mean, is that an area you have spend capital on this year? I mean, is there a driving reason why you would want to continue to do be active up in that place?

Phil Cook

Well, we’re drilling our first two exploratory wells and as I said before we have a total of nine wells to drill over four years, so we could say we don’t drill any more wells next year, but truly we want to see what we have there and these two wells will give us a very good indication. We obviously have a lot of drilling around us, so we have some great data points around us and good production volumes as well, but we want to be able to complete a couple of wells, tie them in and get some longer term production data. Toby do you have anything to add there?

Toby Darden

Yes. I think the results around us speak for themselves pretty well, but we want to get some of our own data to evaluate completion practices and well optimization. So there’s be some capital spend there but I think it’s going to be minimal on an annual basis, relative to the rest of the budget, no matter how low the budget goes.

Scott Hanold – RBC Capital Markets

Okay. And one last question, in Canada some of the – I’ll call them the legacy cold bed methane assets – I mean, I know you talked about JVs in various areas. Have you considered an outright sale of those CBMS given the maturity of those assets and is there, I guess, logistical difficulties given that they’re up in Canada too, just to do an outright sale?

Glenn Darden

No, I don’t think they’re logistical issues. I think it’s relate to price, Scott, and it’s just a darn tough time to flat out sell reserves right now. I would be selling them at the low and that doesn’t make a lot of sense to us.

Operator

Your next question comes from the line of Gil Yang of Citigroup

Gil Yang – Citigroup

Regarding the drilling and building up an inventory of uncompleted wells, are you seeing peers doing that or do you think you’re the only guys really doing that in scale this year?

Glenn Darden

I’m not sure, Gil. I would assume that there is some inventory build-up, but I do think that kind of begs a broader answer that what I’ve seen out there in some of the literature. It’s not flipping a light switch to just go complete 100 wells. I mean that’s a long progress. You’ve got to have the frac crews available, et cetera, et cetera.

So just to assume that this backlog just gets turned on in a six-month period of ours or anybody else’s is not really dealing with the realities in the field. So I don’t know truly what other companies are doing but our backlog I would gets is probably a little bit bigger on a percentage basis.

Gil Yang – Citigroup

Okay. And so it sounds like you have to drill 180 wells because you have the rigs obligated unless you choose to do something with that, but it sounds like you’re scheduled for 180. If you’re looking at 2010, how many wells would you have the rig capacity to drill if you used all that capacity?

Glenn Darden

Yes, it would be roughly the same. Now I’m not sure I understood that question.

Gil Yang – Citigroup

Well, I mean it sounds like you have fewer rig obligations in 2010 than this year. And so how many wells could you drill under that obligation.

Glenn Darden

Oh well, yes, probably 100 – cut it almost in half.

Gil Yang – Citigroup

Okay.

Glenn Darden

But we have – I mean, there are lease obligations out there. We’ll probably have obligations to drill maybe 70 wells or so, just to take care of lease obligations. That’s kind of the life of the operator. But overall, whether you complete those, I mean, that’s where we stretched out some dollars.

Gil Yang – Citigroup

Okay. So you could keep your rigs busy by drilling 100 wells is what you’re saying, right?

Glenn Darden

Yes.

Gil Yang – Citigroup

And then if you drill those 100 wells, how many would you need to complete to keep production in 2010 flat with 2009?

Glenn Darden

Well I don’t have that number, Gil, but I mean we could stop drilling today and keep our production flat, okay, by just completing wells in 2010..

Gil Yang – Citigroup

Okay. So the 100 of inventory that you’re going to have, that’s an increase in inventory of 100. How many do you have in inventory today?

Glenn Darden

We might have as many as 180 wells or so in inventory by the end of this year.

Gil Yang – Citigroup

Okay. And then the last question is you have the adjustment or the re-evaluation coming up in April or May and that’s based on year-end reserves. Is the price deck already established or is the price deck yet to be seen based on what happens in March, April, May?

Toby Darden

Yes, JP Morgan has given us a price deck. Its $4.50 and $45 on oil.

Gil Yang – Citigroup

And then you’ll have another re-evaluation ...

Toby Darden

And keep in mind that we get to include our hedges in that.

Gil Yang – Citigroup

And then you’ll have another period back in September, and that’ll be based on June 30 reserves, right?

Toby Darden

Well, that’s at our option.

Gil Yang – Citigroup

You mean you can choose to do it on December 31, 2007?

Toby Darden

We can choose to have a redetermination mid-year.

Gil Yang – Citigroup

Oh, I see.

Toby Darden

So the bank redetermines once a year and we have the option to redetermine mid-year.

Gil Yang – Citigroup

Got you, okay. Is there any reason to redetermine if you don’t want to expand your credit line?

Toby Darden

No. And in the case where we have redetermined mid-year we were increasing the borrowing base.

Gil Yang – Citigroup

Would you be able to use the new SEC booking rules for June 30, or you have to wait until year-end to do that?

Toby Darden

Well we’re not using really the SEC rules for the bank case. The SEC doesn’t allow us to use the hedges. It is a fixed price. SEC pricing is a fixed price forever and it’s the year-end price. The new rules are now going to allow you to use an average price for the previous year but that still is not how we determine the bank-borrowing base.

Gil Yang – Citigroup

I more meant in terms of numbers of offsets you can book.

Toby Darden

I don’t think it’s going to have that big of an impact on us.

Operator

Your next question comes from the line of David Snow of Energy Equities, Inc.

David Snow – Energy Equities, Inc.

Might you consider a joint venture to include the Barnett?

Phil Cook

We’ve been approached about certain assets and I’m not sure. We’d just have to look at the deal.

David Snow – Energy Equities, Inc.

Well would you end up coming off less attractive than when you made the acquisition into Barnett last summer in this market?

Phil Cook

Well that I don’t know.

David Snow – Energy Equities, Inc.

Well which ones are you more inclined to be looking at, and I guess it sounds like the Horn River, but I’m wondering what

Glenn Darden

David, we’re not going to talk about any potential transactions. I mean, obviously, we look at numerous transactions both to buy and sell and look at each of those individually and determine if we believe those are value enhancing for our shareholders or not.

Operator

The next question comes from the line of David Cameron of Wachovia

David Cameron – Wachovia Securities

A couple of questions – so on the guidance you gave was that full year guidance or was that first quarter guidance. It seemed a little different than what was in the press release. Am I reading that right?

Glenn Darden

Yes. It was first quarter. My range is a little bit bigger than Rick’s range was in the press release.

David Cameron – Wachovia Securities

Okay. So

Glenn Darden

The top of the range is the same. The bottom of my range is a little lower.

David Cameron – Wachovia Securities

For production did you say $3.30 to $3.35? That’s what I wrote down.

Glenn Darden

I did, and it looks like I missed that by $10 million a day. It’s $3.25 to $3.30 a day. Sorry about that.

David Cameron – Wachovia Securities

No, that’s fine. I’m just trying to clarify, official is $3.25 to $3.30.

Glenn Darden

Yes, I apologize for that.

David Cameron – Wachovia Securities

No, that’s fine. Next question, again back to liquidity since it’s such a big concern surrounding your stock. The redetermination, you said you have a year and you have $370 million left on the recover, $369 million. Do you have any read on what you believe your new revolver is going to be – what the new borrowing base is going to be?

Phil Cook

I mean, I’ve talked with all of our big banks that are in the credit facility – certainly the top ten and I don’t have any reason to believe it’s going to be cut. Our reserves have grown significantly. We’ve got, as you know, significant hedges in place, which we get credit for the he next two years so I’ve not gotten any indication from anybody that it’s going to be cut. We’re asking for it to remain the same.

David Cameron – Wachovia Securities

Okay. When is that bank date and when do we hear?

Phil Cook

I think the official date is May 1. We will have a bank meeting some time in April. I don’t know the exact date.

David Cameron – Wachovia Securities

And then getting back to I guess Glenn’s comment, the $250 million that you mentioned about keeping production flat with $250 million of CapEx, are you talking ’09 to ’08 or are you talking off current fourth quarter levels or can you give me a little more clarify on what that refers to Glenn.

Glenn Darden

When we talk maintenance capital, we are talking about year over year staying flat, not exit rate staying flat.

David Cameron – Wachovia Securities

Okay so for just to make sure I’m on the right page for 2009 versus 2008 that would be $263 or $265?

Glenn Darden

$267 or whatever it was, yes, exactly.

David Cameron – Wachovia Securities

So the next question would be if I started looking at fall for 2009 and I know what Rick’s response to this is going to be, but it looks to me like you would have declining production quarter-over-quarter throughout the year.

Richard Buterbaugh

We have projected growth into our budget and in our guidance that we’re growing year-over-year by roughly 20% but if you’re comparing exit rate to fourth quarter exit rate there may be decline, yes, if we were going to stay flat. Obviously there’s have to be – just the math.

David Cameron – Wachovia Securities

Yes. I just wanted to make sure I had that because we have you targeted 20% production growth but then given the first quarter guidance that implies a little bit of a decline throughout the year and I just wanted to make sure that we had that modeled correctly.

Richard Buterbaugh

We haven’t changed that David.

David Cameron – Wachovia Securities

And Glenn, six months going back to the JV comment, six months down the road prices recover hypothetically and you’re sitting at $6 or $6.50 gas, the Barnett economics look a lot better. Would you consider selling part of the Barnett as opposed to selling Horn River or JV, I guess?

Glenn Darden

Yes, we look at every one of these things David and if it is value enhancing we’ll do it. I think that both areas have such long life production that if you’re doing a joint venture you’re certainly looking at who your partner is and what they can bring to the table aside from dollars. You’ve got a long-term relationship there. But Horn River, obviously, is in a different stage of development than the Barnett, but I guess if things change we’ll certainly look at different options, but it’s hard to forecast.

David Cameron – Wachovia Securities

Anything else besides the JV or outright sale that you guys would do to free up additional liquidity?

Glenn Darden

Slow spending.

David Cameron – Wachovia Securities

I guess that’s the easiest of the three, probably.

Glenn Darden

Yes. We talked a little bit about that today.

Operator

Your next question comes from the line of Noel Parks of Ladenburg Thalman.

Noel Parks – Ladenburg Thalman

I just wanted to go back to Horn River Basin for a bit. Now that you’ve got your couple of wells down – two things. Could you talk a little bit about just how the drilling progressed as you expected or easier or more difficult than you expected. And second, could you just talk a little bit or maybe update us a bit on the characteristics of the shale, just as far as you know them so far.

I know that you did mention that you saw 500 feet of net thickness, which I didn’t realize the 500 foot number you had given before was net. You confirmed that, but just in terms of I know you were talking about the silica content and the total (inaudible) carbon and so forth. Are you seeing essentially what you expected or better or worse, et cetera?

Toby Darden

No. We’ve actually been pleased with the data we’ve received so far. The silica contents are high. I think that’s what’s making the wells that have been completed all the way around our block so good. They’ve had very high IPs with very little optimization of completion procedures.

Our variety of competitors around our block have all shown high IPs. We found the thicknesses we were expecting at least as thick as we were expecting, maybe more, and it’s definitely gas-bearing rock. That’s all we’ve done prior to completion. We’re very pleased with what we’ve seen so far. There were no appreciable drilling problems to answer your first question, but we think it’s going to be a very large gas play.

Glenn Darden

And remember, Noel that these initial wells are more science wells. We’re going to complete these but we’re doing a lot of science on these, coring and rock analysis, so all of that is being conducted right now, but as Toby says, (inaudible) to look is the thickness is a little bit better than we thought, but it ties to our mapping pretty well.

Noel Parks – Ladenburg Thalman

And can you just refresh my memory on the play as a whole, sort of the variability of the formation as you go across the basin there. Is it a fairly uniform play or does it depend a lot on what you see from area to area?

Glenn Darden

It appears to be a fairly uniform deposition across the base and so far the production results are fairly uniform across a pretty big area as well, so we’ll see on our block if we’re in between those good production tests. So, we’ll see.

Toby Darden

And Noel, we geologically selected the acreage to try and stay in the thickest portion of the shale and that’s borne out by our first two test wells.

Noel Parks – Ladenburg Thalman

Okay, thanks. And just one last thing. This might be for Phil, could you just repeat your comment about transportation expense. I think if I understood you right, you said that if your dry gas total increases to the amount of total production that we would see transportation expense increase on a unit basis and just because that expense for the liquids would get covered by lower volumes. Do I have that generally right?

Phil Cook

No. It’s so as we have more dry gas in the mix on an MCFE basis because NGL’s don’t have transportation costs attached to the, we sell NGL’s at the tailgate of the plant and so any transportation cost that is inherently incurred on NGL volumes is really in the price of the NGL’s that we get. So just incurring a transportation expense on the dry gas. So as dry gas is a greater percentage on a unit basis for the total, it’s going up. It’s just a mix issue.

Noel Parks – Ladenburg Thalman

Okay so transportation expense on a unit basis is going up.

Phil Cook

On an MCFE basis, not on a dry gas per unit basis.

Glenn Darden

As a reminder, just to make sure that everybody can get their questions asked, let’s please limit your questions to one at a time.

Operator

Your next question comes from the line of Wei Romualdo, Stone Harbor.

Wei Romualdo -- Stone Harbor

Just to clarify, you don’t have any NGL hedgings in ’09, right?

Glenn Darden

That’s correct.

Wei Romualdo -- Stone Harbor

Okay. The current CapEx budget of $600 million and you’re saying that you will live within cash flow. What price deck assumption are you using because it seems to me at the current $4.50 and $45, that CapEx is more than your cash flow.

Glenn Darden

But we have roughly 80% of our natural gas hedged at $8.60.

Wei Romualdo -- Stone Harbor

Right. Maybe I’m not doing my math right, but I’ll check. What price deck are you using to come up with the conclusion that the CapEx is within the cash flow? Are you using the $4.50 and $45?

Glenn Darden

We did not use $4.50 and $45. No, when we did our budget I think we used about a $6 or $6.50 natural gas price and we included our hedges and we were using NGL per barrel prices of $25-ish, in the range of $25.

Wei Romualdo -- Stone Harbor

Okay so you’re using a net realized price of $50 and $25 and with that you believe the cash flow it will be around $600?

Glenn Darden

And we include our $8.60 hedges on 80% of our natural gas.

Toby Darden

Keep in mind we as well, within our cash flow, we’re assuming that expected distributions that we receive from BreitBurn Energy Partners as well as an anticipated tax refund of approximately $45 million.

Glenn Darden

So there’s about $100 million roughly of cash coming in – $90 to $100 million of cash coming in that’s not a result of just cash flow generation. It’s a distribution as well as a tax refund that we expect to receive later in the year.

Wei Romualdo -- Stone Harbor

Okay, got it. And the $450, out of

Phil Cook

But I would also say that we’re looking at capital every month and as gas prices fall your idea is correct that on that portion that is not hedged obviously the cash flow related to those volumes is going down and that’s why we continue to look at capital every month and as Glenn has said in his previous remarks, we have a tremendous amount of flexibility with our capital program to continue to ratchet it down if need be.

Wei Romualdo -- Stone Harbor

And the $450 out of the $600

Toby Darden

I’m sorry. Can we move onto the next question, please. I’d be happy to follow up with you after the call.

Wei Romualdo -- Stone Harbor

No problem.

Operator

Your next question comes from the line of John Heely of Forrest (ph).

[John Heely – Forrest]

My question has been answered. Thank you.

Operator

Next question comes from the line of Vevich Pale of Knight (ph).

[Vevich Pale – Knight]

A lot of your peers issued debt when the market opened up a few weeks back and Quicksilver did not. I mean, any reason? Do you feel you should have done it, I mean, because of given how the liquidity is, because my understanding was that your absolutely debt level – you’re comfortable with the absolute debt level. So any reason why it was not turned out any little bit to free cash flow potentially. Would you pay down bank debt or would you pay down the second lien, if you were to get any free cash flow this year?

Phil Cook

We’ll pay down the second lien. With regard to having not been in the bond market, as you know we’ve been right on the top of earnings release financial statements have in all practicality had gone stale, so we’ll file our 10-K within the next week or so which will freshen our financial statements.

If you go back a couple of months, issuing debt in the bond markets was fairly expensive, probably in the high teens to 20% sort of yield for us. So that’s the primary reason we haven’t entered the markets and we didn’t see the need to necessarily.

Our credit facility while it’s a revolver, the interest rate on that credit facility is, you know, 4% at this point. So to issue at 20% and pay down 4% didn’t make a whole lot of sense. Having said that, that’s not to say that we will not be in the bond market during the year.

[Vevich Pale – Knight]

So if you were to get any proceeds did you say bank or pay down the revolver or pay down the second lien?

Phil Cook

From an asset sale point of view we have to pay down the second lien.

[Vevich Pale – Knight]

Got it, but from proceeds you’ll do the revolver to get flexibility?

Phil Cook

I think technically we need to pay down the second lien first. We’ve have to get permission from the first lienholders, which is our credit facility, but to the extent that we got that permission would pay down the second lien.

[Vevich Pale – Knight]

From the assets sales or the new issue? I’m sorry.

Toby Darden

From both.

[Vevich Pale – Knight]

Got it. Thank you.

Operator

Your next question comes from the line of Joe Allman of JP Morgan.

Joe Allman – JP Morgan

Hey Glenn on the JV, is it important for Quicksilver to be the operator in whatever agreement you make?

Glenn Darden

Yes, it is.

Joe Allman – JP Morgan

And then earlier you mentioned 20% to 30% drop in cost you’ve seen already. Now that’s a drop from the peak that we saw in 2008, right? That’s not an average

Glenn Darden

Well, that’s from our average numbers, which were probably close to the peak in 2008. So we’re using those numbers.

Joe Allman – JP Morgan

Okay. And then just real quick you mentioned, Phil you mentioned the bank deck $4.50 and $45. There’s a step up after that, right, could you give that step up?

Phil Cook

Yes. It goes $4.50 to $5 to $5.50 and I think finishes out at $6 and stays flat.

Joe Allman – JP Morgan

Okay. And how about on the oil side?

Phil Cook

And I think it goes from $45 to $55 on oil.

Joe Allman – JP Morgan

And then just lastly, EV10, you didn’t give the pre-tax but on the after tax, could you give us a PUD PV10, or you know a (inaudible) PV10 there after tax.

Phil Cook

I don’t have that sitting in front of me but we certainly will follow up with you.

Operator

Your next question comes from the line of Mayo Shattuck of KKR

Mayo Shattuck – KKR

I was wondering if you could talk a little about the liquidity you’ve seen in the natural gas hedging market and whether you’re finding it any more difficult at all to layer on additional hedges, and then I guess secondly what price you’d find it attractive to actually layer on more hedges.

Glenn Darden

Well, we haven’t been in that market in several months, so we’re probably not the best parties to give you a perspective, but at these levels we’re not interested in hedging today.

Operator

Your next question comes from the line of Kali Ramachandran of State Street Global.

Kali Ramachandran – State Street Global Advisors

Your second lien facility has a minimum PV10 to secure debt and total debt covenant. What were those levels at the end of this year?

Glenn Darden

At the end of the year for convenient purposes the PV10 was almost $4 billion, $3.99 million and change and you’re right we have coverage tests and we passed those coverage tests.

Kali Ramachandran – State Street Global Advisors

Are those tested quarterly?

Glenn Darden

Those are tested quarterly, yes.

Kali Ramachandran – State Street Global Advisors

And the next re-eval and your next time to re-valuate it if you so choose would be what the June time frame?

Kali Ramachandran – State Street Global Advisors

Yes.

Operator

Your next question comes from the line of Steven Beck of Jefferies.

Steven Beck – Jefferies

Could you talk a little bit about the value of your derivatives? I’m thinking about current, you know within the next 12 months and then beyond.

Glenn Darden

You mean what’s the mark-to-market? Is that the question?

Steven Beck – Jefferies

Yes, that is.

Glenn Darden

It’s somewhere – you know it changes every day, but it’s somewhere between $350 and $375 million.

Operator

Your next question comes from the line of Adam Light of RBC Capital Markets.

Adam Light – RBC Capital Markets

Hi, I’m mostly taken care of, but just to clarify on if you pay down second lien with new debt that doesn’t free up any borrowing base capacity until the liens are off the formerly unsecured debt is that correct?

Glenn Darden

That is correct, Adam.

Operator

Ladies and gentlemen, we have reached the allotted time for questions. Presenters, will there be any closing remarks?

Toby Darden

Yes, Kashina, thank you. Just as a reminder a replay of this call will be available for 30 days on the company’s Web site. The company does anticipate releasing first quarter 2009 earnings on Wednesday, May 6, 2009 before the market opens. I’d like to thank you for your time and interest in Quicksilver this morning. If you have additional follow up questions, I’d be happy to take then in my office this afternoon. At this time this concludes our call.

Operator

Thank you ladies and gentlemen. That does conclude today’s Quicksilver Resources Fourth Quarter 2008 Earnings Call.

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

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

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

Source: Quicksilver Resources Inc. Q4 2008 Earnings Call Transcript
This Transcript
All Transcripts