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Quicksilver Resources (NYSE:KWK)

Q4 2010 Earnings Call

February 28, 2011 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

Glenn Darden - Chief Executive Officer, President and Director

Richard Buterbaugh - Vice President of Investor Relations & Corporate Planning

Analysts

Jason Horowitz - Muzinich

Scott Hanold - RBC Capital Markets, LLC

David Kistler - Simmons & Company International

Eli Kantor - Jefferies & Company, Inc.

David Tameron - Wells Fargo Securities, LLC

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Michael Bodino - Global Hunter Securities, LLC

Noel Parks - Ladenburg Thalmann & Co. Inc.

Operator

Good morning and welcome to the Quicksilver Fourth Quarter 2010 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to our host, Rick Buterbaugh, Vice President of Investor Relations and Corporate Planning.

Thank you Mr. Buterbaugh, you may begin your conference.

Richard Buterbaugh

Thank you, Rachel and good morning. Joining me once again today is Toby Darden, Chairman of Quicksilver Resources; Glenn Darden, President and Chief Executive Officer; and Phil Cook, Senior Vice President and Chief Financial Officer.

This morning, the company issued a press release detailing Quicksilver's results for the fourth quarter of 2010. If you do not have a copy of the release, you may retrieve a copy 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, which is a non-GAAP financial measure. As required by SEC rules, reconciliations of adjusted net income to the most directly comparable GAAP measures are available on our website under the Investor Relations tab.

Let me once again add at the onset of this call that neither the company nor the Darden family will be commenting on any communications that the Board of Directors has had with any investor group beyond what has already been publicly disclosed. So we will not be taking questions on that subject.

At this time, I'll 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 $318 million or $1.77 per diluted share in the fourth quarter of 2010 as compared to net income of $32.5 million in the prior-year period. This income included proceeds from the sale of the company's Quicksilver Gas Services assets. Fourth quarter adjusted net income was $30 million compared to $47 million in the 2009 period. For all of 2010, Quicksilver reported net income of $435 million. Adjusted net income was $119.9 million or $0.70 per diluted share.

Quicksilver had another good year increasing production volumes to 355 million cubic feet equivalent per day, up 9% year-over-year, increasing reserves 20% to 2.9 trillion cubic feet equivalent, of which 68% of proved developed and proving additional Horn River Basin potential. The company replaced 475% of its production with the reserve adds at an all end finding development and acquisition cost of $1.29 per Mcf equivalent. Once again, Quicksilver continues to be among the lowest-cost companies in the industry and our reserve bookings are only 32% proved undeveloped.

Also once again, we self-funded all capital expenditures within cash inflows. With the sale of the Quicksilver Gas Services assets, Quicksilver reduced its debt by approximately $537 million, ending the year with a debt balance of approximately $1.9 billion. Today, we have over $800 million available on our $1 billion credit facility.

The company previously announced a capital budget of $455 million for 2011. We intend to stay within cash inflows and to remain disciplined with our spending.

The company projects production growth of approximately 20% for 2011.

On the operational side, the company drilled 20 operated wells in the Barnett and connected 38 total wells in the Barnett in the fourth quarter. For the year, Quicksilver drilled 96 wells and connected 116. We had an inventory of approximately 121 wells drilled but not completed at year end.

The company drilled 14 wells in the Horseshoe Canyon coal play in Alberta and connected 38 operated wells. We shifted a portion of the Canadian budget to acquiring additional acreage production in reserves in the Horseshoe Canyon on properties we already operate. This $22 million purchase added approximately 23 Bcf of gas in the proved developed column of reserves and approximately 5 million cubic feet of gas production on a daily basis.

In the Horn River Basin, Quicksilver has now drilled six horizontal wells into the Muskwa and Klua shales. Four of these wells have been completed with initial production rates per well topping 15 million cubic feet a day. We are currently expanding our gathering system to bring all of these wells in this gas to market. We expect to finish drilling two additional Muskwa wells before the seasonal spring breakup begins in late March. Only three more wells will be required over the next year to convert the company's 130,000 net acre exploratory license block into 10-year leases. Quicksilver also has drilled its first horizontal well into the shallow Exshaw formation in the search for oil production in the Horn River.

Completion operations for recent Muskwa wells and the Exshaw well are anticipated to begin this summer. The company has been building its acreage positions in two potential oil plays to roughly 150,000 acres in the Greater Green River Basin, Niobrara project. As we have discussed previously, Quicksilver has approximately 175,000 acres in the Southern Alberta Bakken play, most of that held by shallow oil production in the Cut Bank area in Western Montana.

We will be drilling our first test wells in the Niobrara project this summer, and we'll continue to monitor offset drilling operations by other operators in the Cut Bank area before drilling there.

Overall, this company is in very good shape. We have lowered our debt to a $0.65 per proved Mcf. We have a low overall cost structure relative to our industry peers, and we have few drilling requirements to maintain our large leasehold positions. And we have a significant portion of our gas production hedged at close to $6 per Mcf for the year.

As I said earlier, Quicksilver will continue to be very disciplined with our capital. And we will continue to look for opportunities to add value to this company.

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

Philip Cook

Thank you, Glenn, and good morning. Production volumes were 389 million cubic feet of natural gas equivalent a day in the fourth quarter of 2010, up 7.5% from the sequential quarter and 20% from the year-ago quarter. For the full year 2010, total production volumes were 355 million cubic feet of equivalent per day, which grew 9% compared to 2009. This growth was driven primarily from our activities in the Barnett Shale in the Horn River, where we brought online additional two wells during the fourth quarter.

Our realized natural gas price for the quarter was $6.38 per Mcf compared to $6.83 in the third quarter of 2010. You will recall that we had hedged 200 million cubic feet a day with a weighted average floor of $7.40 throughout all of 2010. NGL realized prices were $32.46 per barrel in the fourth quarter compared to $30.91 per barrel in the third quarter. Realized oil prices were $77.16 a barrel in the current quarter compared to $69.32 a barrel in the third quarter.

As we move into 2011, we have 190 million cubic feet a day of natural gas hedged with a weighted average floor of $5.95 and 10,500 barrels a day of NGLs with a weighted average floor of $38.84 per barrel. Based on current gas prices and NGL prices, we would expect our realized price for the year to be about $5 per gas and our realized NGL price to be about $40. Our realized gas price of $5 includes the impact of our hedging activities and is based on an NYMEX price for the rest of the year of $4.13.

Sequentially, total production revenues increased from $218.2 million in the third quarter of the year to $224.9 million in the current quarter, a 3% increase. Of the $6.7 million increase in revenue, $9.1 million is attributable to higher production, which is offset by lower realized gas prices.

For the current quarter and full year of 2010, total production revenues grew by 4% and 7.5%, respectively when comparing the same periods in 2009. With the closing of the Crestwood transaction starting in the fourth quarter of 2010, we no longer consolidate Quicksilver Gas Services. However, the fact that they provide midstream service to us constitutes a continuation of services under U.S. accounting rules. Therefore, we have not presented their historical results as discontinued operations. As a reminder, our third quarter 10-Q included pro-forma income statements showing the effects of the Crestwood transaction on our historical results had the Crestwood transaction been effective on January 1 of 2010. All the following unit costs for the fourth quarter do not include the effects of consolidation of Quicksilver Gas Services. The third quarter numbers, on the other hand, do include the effect of KGS being consolidated for those periods.

Lease operating expense on a unit basis was $0.62 per Mcf for the fourth quarter compared to $0.60 for the third quarter. About $0.02 of this expense for both periods is non-cash and is related to stock compensation for operational employees. These amounts exclude gathering, processing and transportation expense, which we now present separately on the face of our income statement.

Gathering and processing expense, which is the cost to gather and process our gas from the wellhead to the tailgate of our facilities, was $0.18 per Mcfe for the fourth quarter compared to $0.15 reported for the third quarter. This increase is attributable so the effects of the Crestwood transaction or in other words, the sale of KGS. Previous to the sale, we recorded KGS activity net on our income statement. Therefore, even though Quicksilver paid KGS the $0.80 per Mcf, the net cost of operations was only $0.15, which is what was recorded in our consolidated income statement.

Transportation expense, which is the cost to get our gas from the tailgate of our facilities to market, was $0.40 per Mcf for the fourth quarter compared to $0.43 for the third quarter. The decrease is due in large part to lower prevailing natural gas prices.

Production taxes and ad valorem taxes were $0.21 per Mcfe for the current quarter, compared to $0.28 reported for the third quarter. The decrease is primarily due to the absence of fourth quarter of taxes on KGS assets and a bit to lower natural gas process.

DD&A for the current quarter was $1.47 per Mcf compared to $1.58 for the third quarter. The decrease is due to the absence of the fourth quarter depreciation on KGS assets, offset by an annual depletion rate adjustment for our E&P operations that reflects an increase in our future development cost of our proved undeveloped reserves.

G&A for the fourth quarter of 2010 was $0.51 per Mcfe compared to $0.72 in the prior quarter. Approximately $0.20 and $0.15, respectively, is related to non-cash stock-based compensation, the increase of which relates to $3.6 million of accelerated vesting of equity compensation associated with the Crestwood transaction. The decrease in other G&A is primarily due to the resolution of the legal matter during the third quarter and costs associated with the Crestwood transaction incurred during the third quarter. The remaining decrease is due to the absence of G&A costs for KGS employees.

As a brief recap, our cash expenses for lease operating expense, gathering, processing and transportation and production ad valorem taxes and recurring G&A in the fourth quarter 2010 were $2.32 as compared to $1.86 in the third quarter. This increase again is due to the Crestwood transaction effects on gathering and processing expense offset by lower G&A, taxes and transportation expense.

In the fourth quarter, we recognized gains of $7.7 million related to the sale of 650,000 Breitburn units. Also, BreitBurn recently sold the units in a public offering. Considering the sale by BreitBurn and our sale of units, we now own approximately 27% of the outstanding BreitBurn Company units or roughly 15.6 million common units.

Adjusted net income, a reconciliation of which is available on our website and in our press release, for the quarter was $30 million or $0.18 of diluted share as compared to adjusted net income of $28.7 million or $0.17 of diluted share in the third quarter of the year. Adjustments in both quarters primarily relate to our equity method investment in BreitBurn, gains on BreitBurn units that were sold or conveyed and the unrealized effects of mark-to-market adjustments on the gas purchase commitment to Eni, which expired on December 31, 2010. Also excluded for the fourth quarter of 2010 is the gain on the sale of KGS and a non-cash full cost ceiling test impairment charge related to our Canadian oil and gas properties.

In 2010, the company generated approximately $440 million of cash flow from operations, monetization of BreitBurn units and sales of other property and equipment. We used a portion of the $700 million in proceeds from the Crestwood transaction to completely repay the outstanding borrowings under our credit facility. The remaining cash from closing in excess of the outstanding credit facility was used to fund the estimated tax payment of $85 million associated with the gain from this transaction.

Total debt at December 31 was approximately $1.9 billion, down over $500 million from total debt of $2.4 billion at December 31, 2009. Also debt net of the market value of BreitBurn units and cash to proved reserves, improved dramatically down to $0.52 per Mcfe in December 31 compared to $0.98 of prior year-end on the same basis.

Some other reminders regarding our debt. The maturities on our public debt do not begin until 2015, giving Quicksilver significant flexibility regarding cash management over the next few years. During the fourth quarter of 2010, our bank group extended the maturity date of our revolving credit facility by one year to February 9, 2013. And the holders of our $150 million convertible debentures can put those debentures to us on November 1, 2011. As a result of this, these debentures are classified as current liabilities on our December 31, 2010, balance sheet.

In addition to the holders' ability to put these debentures to us, we also have the right to call them on November 8, 2011, at par plus accrued interest.

Our 10-K, as you know, is due in March 1, 2011. However, the SEC's rules for disclosure of oil and gas reserves require that we provide detailed disclosures of BreitBurn's reserves within our 10-K and also include BreitBurn's publicly available financial statements as exhibits to our 10-K. BreitBurn have indicated that they will not publicly release information that we need prior to March 1. And therefore, we intend to delay our filing until Breitburn does release reserve information in order to comply with the SEC rules. We expect to file our 10-Q on or before March 15, 2011. Now I'll turn the call back to Rick for guidance and the question portion of the call.

Richard Buterbaugh

Rachel, at this time, I'd like to open the lines for any questions that they may have.

Question-and-Answer Session

Operator

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

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

As you think about the Horn River Basin, can you talk about the total resource potential now in the Exshaw, the Muskwa and the Klua separately?

Glenn Darden

Well, we don't have any resource assessment numbers for Exshaw at this point. We haven't tested that, so we'll be completing our first well, as we said, later this summer. As far as the Muskwa and Klua shales, that is right on target. I think our resource number is around 10 Tcf roughly. It's a big gas supply up there and everything we've seen has confirmed that we're in a very good area. In fact, we've gotten a little bit thicker as we move north on our acreage block. So we're very pleased with the results in the Horn River.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Following on that, how are you thinking about the ability to tie that gas into a global LNG market or participate in some of the projects that are moving forward to get a higher realization?

Glenn Darden

Well Toby has really spearheaded our efforts on the downstream side. And Toby, would you like to share?

Thomas Darden

Sure. We have been working on multiple strategies to move gas out of the Horn River. It's obviously the biggest challenge those reserves face. We're working on plans to take the gas east through TransCanada system to potentially the oil sands markets and markets further east on that system. And we are also exploring a couple of opportunities, which have not gelled yet but we are working on them to take gas west should LNG come to fruition on the West Coast. We do look at that with interest and think it will be an important part of the marketing picture for Horn River.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Not to ask a third question, but what do you think about realized pricing then for the basin?

Glenn Darden

We think overall, the AECO hub is going to be relatively solid. And a big portion of that is the demand from the oil sands, so we're projecting roughly the same out to NYMEX that we currently have over time. So the overall Western Canadian sedimentary base is declining at a pretty rapid pace. You have the Montney coming on. You have the Horn River. But the difference in the Horn River, I would say, in that basin and the development of that basin, it will be drilled as markets developed because it doesn't have to be drilled faster. And you're seeing other players pull back on capital commitments there. We're all in pretty much the same situation. We have exploratory licenses that we're validating, and we don't have to drill faster. So if the gas prices isn’t there, we won't. But as markets develop, this is a huge resource to develop. So we see pretty firm prices at the AECO hub long term.

Operator

Your next question is from the line of Scott Hanold of RBC.

Scott Hanold - RBC Capital Markets, LLC

When you all look at sort of your core, I guess, three, not necessarily on the Barnett versus some of the others you're working on like the Horn River and the potential that you may have in the Alberta Bakken and the Niobrara and when you look at sort of your capital expenditures for this year but more importantly going to 2012, how do you think about sort of a shift in strategy of moving away from the Barnett to other plays, because obviously you've got the potential of higher liquids exposure and whatnot?

Glenn Darden

Yes, don't forget, Scott, that we have a high liquids component in our Barnett development. So probably 40% of our economics in the Barnett are coming from liquids today. I haven't confirmed that number with Phil. But that's probably pretty close, and now so we'll continue to develop that. Now having said that, we do have some oil prospects that we hope to gain some traction on this year. But we'll know as the year develops, but our new ventures team is hard at work on that. We like the prospects in the Alberta Bakken, the Southern Alberta Bakken there. And we like the opportunities in the Niobrara. We just haven't drilled test wells yet, so those are at earlier stages. But at our Barnett, the cost structure is very, very low. And we'll develop that at among the lowest cost for gas. So our margins are the highest in the gas industry in this basin. So with our liquids, we still make great returns there.

Scott Hanold - RBC Capital Markets, LLC

So I guess within the Barnett itself, obviously you've got that part that very high liquids as you mentioned within there, the much dryer gas more-- I guess production-prolific part of the play. Would it be more of within the Barnett, would you continue to look at a mix shift there? And do that sort of partially explain if you actually look at the wells you've drilled versus completed, there is a dramatic difference in the working interest during the fourth quarter?

Richard Buterbaugh

I'm not sure I follow that one.

Scott Hanold - RBC Capital Markets, LLC

If you look at your drilled wells in the fourth quarter, your working interest is nearly 90%. The ones you connected, it was closer to 70%.

Richard Buterbaugh

Yes, the impact of more connections up in the Alliance area where we haven a 72.5% interest in Alliance. In the Southern portion of the basin, our working interest is very close to 100%.

Glenn Darden

For the Eni interest in the Alliance area, Scott.

Scott Hanold - RBC Capital Markets, LLC

So as we go forward, should we expect that the working interest in the wells you connect, I guess when you look at your guidance for 2011, it's pretty clear that fourth quarter looks just marginally higher than where you are on average in the fourth quarter. And now I'm assuming your exit rate in the fourth quarter, coming in the first quarter where is probably on where you guided the first quarter. Can you kindly explain why we didn't see as big of an uptick? Does it have to do with wells that were connected, the percent working interest there?

Richard Buterbaugh

The primary impact on the first quarter, we're still maintaining our guidance for the year for 2011 to be up 20% from average 2010. First quarter production volumes has been impacted to a slight degree by weather activities in the Fort Worth Basin in January and February, where we had lower activity levels during about a two-week period when we had freezing weather, which was not anticipated.

Scott Hanold - RBC Capital Markets, LLC

So if you look at 2011 and the working interest on average for the wells that you'll be connecting and putting on production, would that look more like the 72% or would that look more like the 90%? What is in your guidance?

Glenn Darden

I think you're going to see it in between, Scott. We're completing and getting more wells on in the southern portion of the play during this first quarter. And you'll see that working interest.

Operator

Your next question is from the line of Michael Scialla, Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

I wanted to clarify on the uncompleted well inventory. I think you were targeting 90 at year end. It looks like it stayed up in that 120 range. Is that an apples-to-apples comparison? And if so, any issues that prevented you from completing as many as you'd hoped?

Glenn Darden

It probably is not quite apples-to-apples, Mike. One of the things that we have, of the 122 wells, a number of those are in various stages of completion but aren’t online. So that's really a work in progress and a moving target. But we had to freeze an exact well online number for this press release and the numbers going out for the year. But that number is going to be ratcheted down pretty nicely.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And then in the Alberta Bakken, it looks like you've added some acreage outside of the Cut Bank area, is that correct? And if so, can you just talk about some of the activity you're seeing there and how that relates to your acreage? What you're concentrating on doing there?

Glenn Darden

It's actually including more northern acreage than we already have. We don't have an ongoing leasing operation there. But it's probably a more accurate acreage count of the total acreage we have in the area, not just Cut Bank.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Does more of that look perspective now than they did based on some of the activity of other operators?

Glenn Darden

We think possibly so.

Operator

Your next question is from the line of Noel Parks from Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

In the sort of along lines of what that raised already, for your inventory in the Barnett here drilled but not completed inventory. Looking at your completion cost, going forward, and continuing to try to drill within cash flow, where does your sort of activity level that you need to replace production come in, relative to using current pricing of the amount you'd be able to drill and still stay within cash flow? Are those just about the same, is there a gap between them?

Philip Cook

Noel, this is Phil. So we're going to produce, call it 150 Bcf for the year. And I think your question was how much do you need to spend to replace production? So if you use our five-year finding and development cost to replace that 150 Bcf, it would cost you about $200 million.

Noel Parks - Ladenburg Thalmann & Co. Inc.

So the five-year average, you think, is still a good long-term benchmark?

Philip Cook

Yes, I mean the five-year was about $1.30 and the year was $1.29, so we were right then and there. We're up right there on the number.

Noel Parks - Ladenburg Thalmann & Co. Inc.

And just to clarify, as far as how that would come in against your cash flow budget or your cash flow production for the year?

Philip Cook

Our original budget was that we would spend $455 million, and that we'd do that inside of cash inflows. I talked a little bit of what our realized gas price are going to be. And clearly, gas prices have come down since we did our original budget. But we all think our realized natural gas price to be about $5. And including interest, our cash costs are about $3.60, so they were for the fourth quarter. I expect those to continue to come down.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Can you just talk a little bit about lateral length in the Horn River Basin? And maybe if you have any updated thoughts on completion going forward?

Glenn Darden

Noel, the lateral lengths are continuing to increase a little bit. We pushed the limit as have our competitors in length. It's logical to assume those will approach a mile in length. But that's kind of a long-term development plan. And of course our completion intervals within those laterals stay fairly consistent. I think we're 200 to 250 feet, maybe max 900 feet between stages. So you parse out the lateral into that many stages depending on the length.

Noel Parks - Ladenburg Thalmann & Co. Inc.

And the completions as far as techniques?

Glenn Darden

As far as what?

Noel Parks - Ladenburg Thalmann & Co. Inc.

The techniques being used for completion?

Glenn Darden

Well, I think everyone's pushing more sand and trying to find more sand closer.

Operator

Your next question is from the line of David Kistler with Simmons & Co.

David Kistler - Simmons & Company International

Diving into the drilled uncompleted wells just a tad bit more, can you break them out in terms of the mix of liquids-rich versus non-liquids-rich? And then if you think about just in terms of what you're targeting for year-end '11 exit rate on that inventory?

Glenn Darden

It's roughly 50% in the South, 50% in the North. And we have a fairly balanced program, maybe a little bit more weighted toward the North. But we're bringing on a lot of Southern production as we said earlier.

David Kistler - Simmons & Company International

And do we have a target though for year-end inventory?

Philip Cook

That target right now really the completions of that uncompleted well inventories, what we use to help us balance within our cash flow. So that is a constant moving target. The overall objective of the company is that we will self-fund all of our capital. If we need to reduce that to some extent, we'll probably do less completions. So I don't want to give you a specific number at this time.

David Kistler - Simmons & Company International

And just to understand that, if the capital allocation issue, wouldn't it be more prudent to just not drill a well and complete a well? You'd actually have a similar production level yet less capital outlay.

Glenn Darden

In a perfect world, you're right, but as you know, we have rig contracts.

Philip Cook

And we still have some lease requirements so. We have fewer than most, but we still have some.

David Kistler - Simmons & Company International

Can you update us on the status of those rig contracts?

Glenn Darden

We have three rigs under contract currently

Philip Cook

And they remain under contract throughout this year. The explorations will begin spring of next year.

Glenn Darden

One thing that we'll add to that. We have some optionality, and we can trade rigs in basins. So we may be able to deploy a rig. For instance, drilling Niobrara and take away from an obligation in the Barnett in the For Worth basin.

Operator

Your next question is from the line of Subash Chandra with Jefferies & Co.

Eli Kantor - Jefferies & Company, Inc.

This is Eli Kantor on the line for Subash. Just a quick follow-up question on the Alberta Basin Bakken. What county is this incremental acreage located in, as the 130,000 net acres that you have drilled to earn option? Has that changed? I realize a part of that is included in the incremental roughly 55,000 net acres. And then just lastly what are the plans for 2011?

Glenn Darden

Well, first of all, the acreage count is just our acreage. It doesn't include the wells agreement acreage where we have oil rights to drill. So that would add potentially another 120,000 or so acres if we were to drill. And all of the acreage is in Glacier and Toole counties.

Eli Kantor - Jefferies & Company, Inc.

What are the plans for 2011?

Glenn Darden

We're going to continue to monitor the offset operations that other players are conducting. And with good results, obviously there are a couple of the players are pretty far along in their testing programs. So we hope to perhaps piggyback on what they've learned and start spending dollars on our own.

Eli Kantor - Jefferies & Company, Inc.

As a follow-up on the Green River Basin, how big is the oil reservoir that you guys are planning on targeting? What kind of completion? How do you plan on completing your test wells for this year? And do you have any preliminary IP EUR or completed well cost expectations for those wells?

Glenn Darden

We are in the very early stages of that development. We have a leasehold capture. We'll be drilling some test wells. And we'll release information as we go along, but it's early stages on that.

Operator

Your next question is from the line of Michael Bodino of Global Hunter Sec.

Michael Bodino - Global Hunter Securities, LLC

Number one, you gave us some color on production in the first quarter. Could you give us a color on expenses and thoughts on that beyond the first quarter? I know we had volumes down a little bit versus our previous expectation. Do you expect costs to stay in line with the guidance you out in the first quarter?

Philip Cook

We have not given specific guidance yet for the full year 2011 from a cost standpoint. I would expect them to trend down on a unit basis from what we disclosed in the press release this morning for the first quarter.

Michael Bodino - Global Hunter Securities, LLC

Relative to your Niobrara program this year, could you give us a little more color what your thoughts on what you plan on drilling whether vertical, horizontal or where you expect to spud these wells?

Glenn Darden

To give it a little more color, we'll be drilling around half a dozen vertical tests to gain resource information on the play. As we do in most of our plays, we will try and quantify the resource before determining how we go about the completion or development program.

Operator

Your next question comes from the line of Jason Horowitz with Muzinich.

Jason Horowitz - Muzinich

The prospectus for the 2019 notes that you issued says that your restricted payments basket was $549 million as of August 2009. Can you give us an update on this?

Glenn Darden

The restricted payment basket is $650 million.

Operator

[Operator Instructions] Your next question is from the line of Mike Scialla with Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Phil, I think you said you expect your realized NGL price to be $40 per barrel this year. What WTI price is that based on?

Philip Cook

Actually not based on WTI price. It's based on where we have hedged and where we think liquids prices are going to be. We don't hedge based on WTI, and we sell the actual stream of liquids at Mont Belvieu.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Can you tell me what unhedged NGL price do you expect for the year, what you're forecasting?

Philip Cook

I think it's about $42.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

It looks like you added a little bit of acreage from, at least in my last count, in the Niobrara play or Green River Basin. Is that all still in Colorado or are you looking elsewhere?

Glenn Darden

It's Wyoming and Colorado, the acreage is primarily in Colorado.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Is it basically one block that straddles the state line?

Glenn Darden

No, we're not commenting on the location of it, Mike, it is following the same. It's surrounding the other acreage of that we've taken.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

The Alberta Bakken, is there anything you see there that would indicate your acreage looks anything geologically different in any way than what's being drilled right now in the play?

Glenn Darden

We don't think so, no.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Toby, you alluded to issues with sand. How big a potential problem is that with getting the wells completed this year?

Thomas Darden

This year and for many years to come, I don't think it's a major issue. It's just going to be a long-term cost issue and we're looking at ways to keep the costs down. But sand supply is not an issue.

Operator

And your last question is from the line of David Tameron with Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

Range is obviously selling their package in the Barnett, the deal should be sometime soon. How should the market think about their acreage in relation to yours? Can you talk about similarities or obviously there will be a reprove one way or another once that deal is announced can you just talk about it?

Glenn Darden

As I understand it, it's primarily dry gas, so that will be one difference where a big chunk of our acreage has liquids. But probably fairly similar acreage position they have some good quality acreage in the northern fairway as we do, but we have that southern area and perhaps our acreage is a bit more blocked up, more consolidated.

Operator

At this time, there are no more questions. Mr. Buterbaugh, would you like to make any closing remarks?

Richard Buterbaugh

Yes. Thank you, Rachel. Just as a reminder, a replay of the call will be available on the company’s web site beginning later this afternoon and will be outstanding for 30 days. Thank you.

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