Quicksilver Resources Q1 2010 Earnings Call Transcript

May.10.10 | About: Quicksilver Resources (KWK)

Quicksilver Resources (NYSE:KWK)

Q1 2010 Earnings Call

May 10, 2010 11:00 am ET

Executives

Philip Cook - Chief Financial Officer and Senior Vice President

Thomas Darden - Chairman of the Board, Chairman of the Board of MSR, Chief Executive Officer of MSR and President of MSR

Richard Buterbaugh - Vice President of Investor Relations & Corporate Planning

Glenn Darden - Chief Executive Officer, President and Director

Analysts

David Snow - Energy Equities

Philip Dodge - Stanford Group Company

Noel Parks - Ladenburg Thalmann

Michael Scialla - Thomas Weisel Partners Equity Research

Wei Romualdo - Stone Harbor

Brian Corales - Coker & Palmer

Kim Pacanovsky - McNicoll, Lewis and Vlak

David Kistler - Simmons & Company

David Heikkinen - Tudor, Pickering, Holt

Operator

Good morning. My name is Debbie and I will be your conference operator today. At this time, I would like to welcome everyone to the Quicksilver Resources First Quarter 2010 Earnings Call. [Operator Instructions] Thank you. Mr. Rick Buterbaugh, you may begin your call.

Richard Buterbaugh

Thank you, Debbie, and good morning. Joining me today are Glenn 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's results for the first quarter of 2010. If you do not have a copy of the release, you can retrieve a copy of it on the company's website at www.qrinc.com under the News and Updates tab.

During today's call, the company will be making forward-looking statements, which are subject to risks and uncertainties. Actual results might 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 adjusted net income and net cash from operating activities before changes in working capital, which are non-GAAP financial measures. As required by SEC rules, reconciliations of adjusted net income and net cash from operating activities before changes in working capital to the most directly comparable GAAP measure 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 financial and operating activities in more detail.

Glenn Darden

Thank you, Rick. Good morning. Quicksilver Resources reported net income of $8.2 million or $0.05 per diluted share for the first quarter of 2010. First quarter 2010 adjusted net income was $33.8 million or $0.20 per diluted share.

For the first quarter, average production was approximately 318 million cubic feet equivalent per day. This compares to 332 million per day for the same period last year, which included approximately 17 million cubic feet per day of gas production in the Alliance Project, which was sold to Eni in June 2009.

As we have discussed before and given guidance on, gas volumes will ramp up as this year progresses. What has changed is our decision to reduce the 2010 capital program, and we intend to reduce our drilling and completion activities in the Fort Worth Basin. This decision was made to conserve our resources in light of current natural gas prices. Despite our significant hedge position, which covers roughly 70% of our gas volumes with minimum prices of $7.40 per Mcf, we feel it is not prudent to significantly grow volumes in this price environment. As a result, the company will increase volumes approximately 11% to 14% over 2009 daily volumes versus the 20% growth number we previously guided to. And while we will reduce overall spending, the company has shifted some dollars to add key leasehold acreage in both the Barnett and Horn River Basin areas. This will add to the inventory for future development. We believe these moves will help us capture more value for our shareholders in the future.

We are seeing more opportunities to add to our position to where Quicksilver has operational efficiencies, and we'll make those moves when it makes financial sense. On the operational front, we're currently running three drilling rigs in the Barnett. The company drilled 28 gross wells or 22 net, and connected 21 gross wells or 17 net wells to sales in the first quarter. Quicksilver now expects to drill approximately 75 net wells in the Fort Worth Basin in 2010. We do plan to complete approximately 30 additional net wells from the existing inventory of drilled but uncompleted wells and should exit the year with approximately 120 wells in the drilled but not completed inventory.

In Canada, we have slowed activity as well at particularly in the Horseshoe Canyon coals project and completed five wells in the first quarter. Currently, all operations are suspended due to the spring/fall breakup season. More of our capital has been directed to the Northeast British Columbia project where we have drilled to more wells in the Muskwa formation in the Horn River Basin. Completion activity on the first of these wells is expected in late summer, and the second well will be completed in the winter season.

Quicksilver now has only six more wells to drill over the next three years to validate all exploratory licenses that cover our 130,000 net acre block. We also plan to test the Exshaw formation at approximately 4,000 feet, where we have encountered oil shales in each of the four wells drilled to date. This will occur in early 2011.

Quicksilver has been in joint venture discussions with several parties on the upstream and midstream/downstream parts of our Horn River project. There's been quite a lot of interest and we may choose that path as the way to secure financing for that long-term project. In Northwest Montana, where we have a significant acreage position held by production, we will continue to monitor drilling and completion activity around as companies test the Alberta Bakken at relatively shallow depths. Our intent is to begin testing our acreage block in 2011.

This company is fortunate that we do not have significant drilling deadlines and commitments. It is a tribute to our land team in the way we assembled our land positions in the various plays and it gives us flexibility in times like these to ease off the accelerator on the drilling site. This, in no way, means we are slowing down the hunt for additional opportunities that will add value for our shareholders. We do believe that these are the times when those opportunities will arise.

And now, I'll turn the call over to Phil Cook, our Chief Financial Officer, to walk us through the financials. Phil?

Philip Cook

Thank you, Glenn and good morning. Production volumes in the first quarter of 2010 were 318.4 million cubic feet of natural gas equivalent per day at the upper end of our guidance range for the quarter. Volumes decreased slightly from the fourth quarter of 2009 as anticipated, due to taking producing wells off-line to conduct frac-ing on new wells. As Rick will go over in a moment, you will see that volume guidance for the second quarter will have growth of over 10% sequentially due to capital activity during the first quarter. Much of the connection activity was completed at the end of the first quarter or early in the second quarter, which supports are expected production ramp up for the rest of year.

On the pricing front, our realized natural gas price for the quarter was $7.44 per Mcf after hedging, compared to $7.46 in the fourth quarter of 2009. You will recall that we hedged 200 million cubic feet a day with a weighted average floor of $7.40. NGL realized prices were $31.19 a barrel in the first quarter compared to $36.60 a barrel in the fourth quarter, down 15%. Realized oil prices were $71.36 a barrel in the first quarter, up from $68.79 a barrel in the fourth quarter, 4% increase.

Sequentially, total production revenues decreased from $215.5 million in the fourth quarter of 2009 to $201.5 million in the current quarter. Of the $14 million decrease in revenue, $7 million is attributable to lower production and $7 million is due to lower realized pricing. Lease operating expense, on a unit basis, was $0.62 per Mcf for the first quarter, equal to the $0.62 for the fourth quarter. Keep in mind that approximately $0.02 of this is non-cash and is related to stock compensation for our operational employees. These amounts exclude processing, transportation and production tax expense.

Processing expense, which is the cost to gather and process or gas from the wellhead to the tailgate of our facilities, was $0.20 per Mcfe for the first quarter compared to $0.17 for the fourth quarter of 2009. This increase reflects compression overhaul expenses as well as compressor rentals, which were utilized temporarily at our Alliance project and incurred by KGS during the first quarter. Transportation expense, which is the cost to get our gas from the tailgate of our facilities to market, was $0.44 per Mcfe for the first quarter compared to $0.38 for the fourth quarter of 2009. This increase primarily relates to higher fuel charges resulting from higher prevailing natural gas prices, increased production in the Horn River in Canada, which has a higher transportation cost than our average without the Horn River, and to a lesser extent, a transportation rate increase in Horseshoe Canyon production.

Also keep in mind, we incurred transportation expense on gas, but other products are sold net, so as our natural gas as a percent of total production increases, so does the transportation rate per Mcfe. So just as a recap, unit oil and gas expenses for the first quarter were broken down as follows: LOE was $0.62, processing was $0.20, transportation expense was $0.44, for a total of $1.26.

Production taxes and ad valorem taxes were $0.30 per Mcfe for the first quarter of 2010, compared to $0.18 for the fourth quarter of 2009. This increase is primarily attributable to more assets in the Alliance area, located in Tarrant and Denton counties, which have higher taxes than other counties in the Fort Worth Basin, as well as higher prevailing natural gas prices resulting in more production taxes and the effect of certain tax statements that expired on December 31, 2009, in the Fort Worth Basin. The DD&A run rate for 2010 first quarter was $1.63 per Mcfe compared to $1.55 in the first quarter. G&A for the first quarter was $0.72 per Mcfe compared to $0.60 in the fourth quarter. Approximately $0.17 is related to non-cash stock based compensation expenses. The increase is primarily due to payroll taxes on stock grants that vest in Q1 year, merit pay increases and per Mcfe effect of lower production.

As a brief recap, our cash expenses, oil and gas expenses, production taxes and G&A for the first quarter of 2010 were $2.09. Rick will give you some detail in a moment regarding guidance, but we expect some of these unit costs will be down for the year.

Adjusted net income for the quarter was $33.8 million or $0.20 a diluted share as compared to the adjusted net income of $47.3 million or $0.27 a diluted share in the fourth quarter of 2009. A reconciliation of adjusted net income is available on our website and is attached to the press release that we sent out this morning. As you know, for adjusted net income, we exclude non-cash charges related to BreitBurn for both of the comparable quarters in addition to excluding non-cash charges for Quicksilver. Again, I would direct you to the reconciliation that we provide. On the liquidity front, for the first quarter of 2010, cash capital expenditures were approximately $129 million. We expect to incur approximately $380 million to $390 million additional cash expenditures towards our 2010 capital program.

During the first quarter of this year, Quicksilver paid down approximately $32 million of debt and KGS borrowed approximately $100 million, for net borrowings of approximately $68 million. Total Quicksilver debt at March 31, was $2.3 billion, excluding the $225.8 million of KGS debt, which is nonrecourse to Quicksilver. Of this amount, our revolving credit facility was approximately $443 million drawn on a borrowing base of $1 billion. This leaves the company with approximately $525 million of liquidity in the facility. Our existing vent facility runs through February of 2012, however, we anticipate rolling or putting a new facility in place by the end of this year. Now I'll turn the call back over to Rick for guidance for the second quarter.

Richard Buterbaugh

Thanks, Phil. Production volumes for the second quarter are expected in the range of $350 million to $360 million cubic feet of gas equivalents per day. As a reminder, approximately 70% or 200 million cubic feet per day of our gas volumes has been hedged at a weighted average floor price of $7.40. For the year, we anticipate total volumes to continue to increase and ramp up to average in the range of 360 million to 370 million cubic feet of natural gas equivalents for the day.

Our detailed production cost guidance for the second quarter is listed in our press release, and I won't take the time right now to run through those numbers. But I would like to give you a little more guidance regarding the year in total. For 2010, total operating costs, which include LOE, transportation and gathering and processing costs, are expected in the range of about $1 to $1.10 per million cubic feet of gas equivalent, production taxes in the range of $0.25 to $0.30, with G&A in the range of $0.60 to $0.65. DD&A is expected in the range of $1.50 to $1.60 on average for the year.

Debbie, at this time, we would like to open the call to any questions that may exist. We request that those with questions limit their questions to one question with one follow-up in order to give all participants a chance to ask their questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of David Heikkinen. [Tudor,Pickering,Holt]

David Heikkinen - Tudor, Pickering, Holt

As you think about the new leasing in the Horn River Basin and in the Barnett, can you talk about the areas that you're leasing and compare those to your current acreage that you have on hand?

Glenn Darden

Well, as I said, we've directed certain dollars, about $30 million to leasing. 2/3 of that is Barnett and one particular area is Lake Arlington that we were able to add acreage. So that's an excellent area, in fact, our best area of production. All of the acreage is adjacent to existing facilities, so we look at it as buying reserves essentially. We have good lease terms and not onerous drilling commitments, so this is just adding to the inventory at low prices.

David Heikkinen - Tudor, Pickering, Holt

And just kind of thinking about other areas that you'd be adding beyond just the Barnett, can you give us any details there?

Glenn Darden

Primarily, just our existing areas right now. I mean, we have -- Toby and his team and are always on the hunt and adding little pieces, but the majority of the dollars have been spent on existing areas.

Operator

Your next question comes from the line of Dave Kistler. [Simmons & Company]

David Kistler - Simmons & Company

Following up on Dave's question a little bit, in the past, you guys have talked about JVs and you've talked about them on this call as well. But previously, you kind of highlighted that you wanted to have a lot more proved reserves before you went down that path. Given that you've picked up some acreage in the Horn River, how should we be thinking about that? Has that strategy changed? Will you be looking at drilling for quite a while before you consider doing a JV? Just any color you can give us there would be helpful.

Glenn Darden

I think that's the -- there are trade-offs, David. And we've had a lot of interest in our position and we don't have to sell anything at this point. But if the right terms and right partner and structure come along, then we're certainly going to consider it.

Thomas Darden

To add a little more to that, Dave, this is Toby. The Horn River Basin is continuing to evolve into a more proved development. And not just our drilling but all the drilling around our acreage is serving to prove it up and add value to our acreage. So this additional interest that's come in lately has been a little more realistic than the early overtures.

David Kistler - Simmons & Company

And as a follow-up, just in the Horn River, you mentioned an oil play that you're noticing there in the Exshaw oil area, that you encountered in all the wells you've done. Can you give us any additional color there? Is that perspective across all the acreage that you have up there? Is that influencing your thought process for acquiring more acreage up there? Any kind of color that we can work with would be great.

Glenn Darden

Well, we're not exactly sure. But we do know that we've gotten good oil shales in the four wells that we've drilled and that's spaced over 10-plus, probably 12 miles apart of wells, and we need further confirmation. We need production. So we'll test it, we'll re-enter a seismic monitoring well and kind of horizontal window and test this Exshaw. But it looks perspective, so we're excited about it.

Operator

Your next question comes from the line of Mike Scialla. [Thomas Weisel Partners]

Michael Scialla - Thomas Weisel Partners Equity Research

I'm wondering with the BreitBurn settlement behind you now, you're thoughts on that? Do you monetize your interest there or what are the plans there? And just my follow-up is does that acreage include deeper rights to Collingwood and Utica?

Glenn Darden

Well, we'll have to ask BreitBurn on that. I think a lot of our acreage does have deeper rights, or a lot of Breitburn's acreage does. But we don't have that full breakdown here. As far as what Quicksilver does with its BreitBurn units, I hope we've been fairly public about this, we're not looking to just immediately sell those units. The first step, obviously, was to settle our dispute and that is behind us, but we're aligned with BreitBurn. There may be ways to creatively use units to add to our positions in some areas, who knows? But I think that we're not looking to monetize that in one fell swoop, there maybe small monetizations over time. But we are concerned with the unit price. We think that the unit price will go up. And we believe the distributions will go up as well. But over time, long term, it probably doesn't belong in our inventory.

Operator

Your next question comes from the line of Noel Parks. [Ladenburg Thalmann]

Noel Parks - Ladenburg Thalmann

With gas prices where they are and understandably, you're looking at curtailing your drill activity in this environment, do you have any thoughts about assuming that prices do turn around and maybe you can talk about it if say, they're better in six months than maybe versus 12 months. How hard will it be with sort of activity being lower now for a while for you to kind of get back ahead of the every [ph] decline curve in the Barnett?

Glenn Darden

Well, we're ahead of our decline curve. I mean, we'll be growing volumes this year, Noel. But I think that our accelerator here is our drilled but uncompleted well inventory. And I said in my prepared remarks that we'll whittle that down from roughly 152 today to 120 at year end, so we take 30 away from that. But that's still a full year plus of completion activity without drilling any wells. So we'll continue to run a certain level of rigs. But we don't see it as difficult to ramp it back up, but we're not in a hurry to ramp it up back up until prices are much better.

Noel Parks - Ladenburg Thalmann

And just as a follow on, looking at your hedging plans going forward, looking to, say, 2011, 2012, what feels like a satisfactory price for you guys to consider locking in either swaps or collars looking ahead a couple of years now?

Glenn Darden

Well, I'll tell you a different view. Our cost structure is among the very lowest in the industry. And at current gas prices, most players are not making money at today's prices, okay? So we don't think that's a sustainable model, and we understand that their lease obligations, et cetera, but that model will not last long term. So what is -- our cost structure is in the $4 range, so anything we hedge above that, we're making money, but we could hedge in the $5, $5.50 range, maybe. But we'll watch it for a while. We're not in any hurry to lock in at these prices right now.

Noel Parks - Ladenburg Thalmann

Just to clarify that a bit, so would you say it's reasonable for us to expect going forward that come year end, your 2011 hedged position percentage-wise will be about the same as you've intended to do? Or do you think you're more inclined with some oddness [ph] on gas prices to ease up on that a bit?

Glenn Darden

We'll see, and I can't tell you today what we'll do. But we are 25-or-so percent hedged right now at six in a quarter, roughly, so we'll add to that position probably. But we're trying to look for some opportunities that are above today's prices.

Operator

Your next question comes from the line of Kim Pacanovsky - McNicoll, Lewis and Vlak.

Kim Pacanovsky - McNicoll, Lewis and Vlak

I'm just curious, you have two rigs drilling in your dry gas portion and one rig in the wet gas portion. And I'm just curious on why it's not the other way around just considering the Btu differential?

Glenn Darden

Ideally, it would be the other way around, Kim, you're exactly right. We have some development obligations in our deal with Eni that require us to run a certain level of activity in the Alliance area. That, as you know, we have a price protection mechanism for them that they can share certain of our hedges in that through this year. So that changes for next year. So we'll probably be shifting that more toward the liquids window next year, but we'll see.

Kim Pacanovsky - McNicoll, Lewis and Vlak

In Horn River, being that you are looking to joint venture there, why would you not move up the drilling of the horizontal test to the Exshaw?

Glenn Darden

Well, I've certainly hear of what you're saying, and that may not be a part of joint venture discussions.

Operator

Your next question comes from the line of Brian Corales. [Howard Weil]

Brian Corales - Coker & Palmer

Just back to the Barnett with the uncompleted inventory, can you maybe breakdown or rough estimate on what is in the dry gas versus the combo area?

Glenn Darden

I believe that's about 50/50, the stage, Brian.

Brian Corales - Coker & Palmer

And looking at and I know it's looking far out into 2011, I mean, do you have any -- the plans are still with three rigs or could there be cut back in rigs and just an increase in completion activity?

Glenn Darden

We're not looking at cutting back below three. But there could be an increase, that is the accelerator, as I said, on the completion side.

Operator

Your next question comes from the line of Philip Dodge. [Tuohy Brothers]

Philip Dodge - Stanford Group Company

I'm trying to confirm, did you, at the beginning of the year, plan to drill some wells in the Exshaw, may be one, and also in the Southern Alberta Basin? And therefore, this new timetable is somewhat of a postponement in the game plan?

Glenn Darden

We weren't certain of when we would test both the Exshaw and Northeast BC [British Columbia] and the Alberta Bakken. I think one of the things in the Alberta Bakken, there's some activity around us. So we'd like to see some results and perhaps, watch what some of the players are doing in that play, particularly since all of our acreage is held by production there. So there's no, at least, clock ticking. The Exshaw is a little bit different and Toby, you want to talk about that?

Thomas Darden

Sure. On the Exshaw, Philip, we have to drill in the winter season. So whether it's at the bare end of the year or end of the first part of next year, that's when it's going to be. So that's not a material postponement, it's just probably. . .

Philip Dodge - Stanford Group Company

So no change in that?

Thomas Darden

No real change in that. And I agree with Glen on the Alberta Bakken, which is located in Montana. The testing going on around us is material to our plans and it's a little premature for us to jump out ahead of some of the already scheduled drilling that's going to around us. It's better to sit and wait. We have no obligations to drill. It's all held by production, and so we're going to be patient on that one.

Philip Dodge - Stanford Group Company

Then the other question on the Barnett, can you increase deliverability with a three-rig program, or instead to grow production, you have to complete some of the inventory?

Glenn Darden

We can increase by drilling and completing with three rigs, yes, we can. So obviously, we'll increase it more by pocketing down some of that inventory. But for a lot of this production and the way the capital is planned is really moving toward the end of the year, and so it kind of front end loads 2011, if you will. But we certainly could grow production from this base right now with three rigs drilling and completing.

Operator

Your next question comes from the line of David Snow. [Energy Equities]

David Snow - Energy Equities

What was your capital budget for '10 at your last guidance?

Philip Cook

$540 million.

David Snow - Energy Equities

And can you give us some color on who and where the activity around you in the Alberta Basin is? Is it Rosetta? Or where is it coming from and how close?

Glenn Darden

Rosetta and Newfield as close as within 2 miles.

David Snow - Energy Equities

Which one is that close? Both of them?

Glenn Darden

Both. That's why we're waiting, David.

David Snow - Energy Equities

It's more than just one zone, I guess, is several zones here that can be productive?

Glenn Darden

It sounds like that, yes, and it appears that way.

David Snow - Energy Equities

So would that make it a vertical play, potentially?

Glenn Darden

We don't know yet, David. The data is not in. Each zone could be a horizontal development. With technology the way it is, it certainly provides a multiplier on the production side. So I don't think the zones are thick enough individually to make a vertical play in any one of them. Whether they could be combined, that's a little unclear at this time.

Operator

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

Wei Romualdo - Stone Harbor

Just an accounting question, could you remind me on your income statement, there is the sale of purchased gas and there's corresponding cost of purchased gas and there's some cash flow impact as well, what was that all about?

Philip Cook

This is Phil Cook. We did a deal with Eni last year, and in that deal we've agreed to buy their gas at the wellhead at a fixed price. That contract, because it goes through the end of this year, we mark-to-market the months that are still yet to expire on the contract. So what you're seeing in our income statement, on the revenue side, is the sale of the natural gas. We have an accrual that any point in time, the difference between the curve from natural gas prices and the guaranteed price to them, which is $8.60. And then the expense that you're seeing in the expense side of the income statement is the cost of buying it, less the accrual plus the mark-to-market for any changes in gas prices.

Wei Romualdo - Stone Harbor

But on the other side, you're hedged on those volumes, right? So is there any actual cost to the company cash...

Philip Cook

No. It's just in a different line item on the income statement. All of our hedging is our natural -- that's at a corporate level hedge and so we might allocated specifically those hedges to that Eni production.

Operator

Your next question comes from the line of Marcus Talbert.

Marcus Talbert - Unidentified

Any type of deleveraging plans this year on the back of your comments of the debt that was just paid down and where you're standing right now?

Glenn Darden

Well, should we do a joint venture in the Horn River, that would obviously be a delevering move for us. There could be some small monetizations of either KGS or BreitBurn units. Those would go straight to debt, as well. But we look to -- still, we're projecting to pay down some debt this year.

Operator

At this time, there are no further questions.

Richard Buterbaugh

Thank you, Debbie. As a reminder, Quicksilver will release our second quarter 2010 earnings on Monday, August 9, 2010, prior to market open. A replay of this call will be available on the company's website for 30 days. I'd like to thank you for your time and interest in Quicksilver this morning. This concludes our call.

Operator

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

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