Concho Resources, Inc. Q3 2008 Earnings Call Transcript

Nov.12.08 | About: Concho Resources (CXO)

Concho Resources, Inc. (NYSE:CXO)

Q3 2008 Earnings Call

November 12, 2008 10:00 am ET

Executives

Jack F. Harper - Vice President - Business Development and Capital Markets

Timothy A. Leach - Chairman of the Board of Directors, Chief Executive Officer

Steven L. Beal - President, Chief Operating Officer, Director

Analysts

Joseph Allman - J.P. Morgan

Michael Jacobs - Tudor Pickering Holt & Company

Mark Lear - Sidoti & Company

Michael Scialla – Thomas Weisel Partners

Houston Netherland – Natixis Bleichroeder

Jeffrey Robertson – Barclays Capital

Operator

Welcome to the third quarter 2008 Concho Resources, Inc. conference call. My name is Dan and I’ll be your coordinator for today. At this time all participants are in a listen-only mode. We will conduct a question and answer session towards the end of this conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the call over to your host for today’s call, Mr. Jack Harper.

Jack F. Harper

The following conference call contains forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933 and Section 21(e) of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this conference call that address activities, events or developments that the company expects, believes or anticipates will or may occur in the future are forward-looking statements.

These statements are based on certain assumptions made by the company and are subject to a number of assumptions, risks and uncertainties many of which are beyond the control of the company which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Additional information concerning the factors that could cause actual results to materially differ from those in the forward-looking statements is contained in the company’s annual report on Form 10K and quarterly reports on Form 10Q under the heading Cautionary Statement regarding forward-looking statements as filed with the Securities and Exchange Commission.

Any forward-looking statements speak only as of the date on which such statement is made and the company undertakes no obligation to correct or update any forward-looking statement except as required by applicable law.

I’ll now turn the call over to Tim Leach, our Chairman and CEO.

Timothy A. Leach

Thanks for your interest in Concho. I’ve got the Concho management team here with me. You’ll be hearing from me and Steve Beal. We have some comments and review that we’re going to make and then we’ll turn it back over and look forward to answering your questions.

As all of you have experienced, the third quarter of 2008 was one of the most challenging in our industry’s history. Oil prices declined 29% during the quarter and have continued to show weakness. The Concho team has experienced in this type of volatility in the past and will continue to execute the same strategy that’s been successful for us over the last 20 years, specifically staying within cash flow.

During the third quarter Concho produced 1.9 million Boe which was a 58% increase over the third quarter of 2007. If you exclude the Henry acquisition, organic production increased 33% over 2007. We also experienced increases in cash flow due to the increased price in production. EBITDAX of $122 million is up 130% over the same period of 2007.

Operationally we added 48 net drill wells and 49 recompletions during the quarter at a cost of $110 million. Additionally for 2008 we will marginally under-spend our cash flow due to two major factors: The reduced number of net wells drilled in our core New Mexico asset and also the postponement of certain projects outside our core areas.

On November 6 Concho’s Board approved the 2009 capital budget which will fund projects from cash flow up to a total amount of $500 million. This amount is a continuation of our current level of billing activity and includes six rigs in the New Mexico Yeso play, eight rigs in the Wolfberry play of West Texas, one rig in the Lower Abo Blinebry play and participation as a non-operator in a two-rig program in the North Dakota Bakken shale play.

Approximately 90% of this budget can be funded with internally generated after-tax cash flow assuming NYMEX pricing that average $65 oil and $6 gas and production at the upper end of our new guidance. This does not assume any reduction of our drilling and completion costs from their current levels although constructed discussions are underway with several of our largest vendors. We will monitor the direction both of commodity prices and drilling costs and will adjust the capital budget and estimated production as warranted.

The 2009 capital plan is very similar to 2008. 92% of it’s in our core area, 88% is operated and 61% of the cap ex will be drilling wells which will be moving reserves out of the [2P and 3P] category.

Additionally while we’re pleased with the third quarter results, there were a few noncash items that we should mention.

First, we reported a gain of $176 million as a result of the mark-to-market of our commodity hedges. This compares to the mark-to-market loss of $90 million we experienced in the second quarter.

Secondly, we took a $14 million noncash charge, the majority of which was to impair a portion of our acreage in the Delaware Basin Shale play of Culberson County and the Fayetteville Shale play of Central Arkansas. While this acreage still has remaining turn under the current conditions, it no longer fits into our near-term drilling plans.

In summary, the things we control seem to be going well. Drilling’s going according to plan, the wells are performing as we expect if not better, the Henry transition’s been accomplished, and we continue to add new reserves. Historically times like these have provided the best opportunities for value creation and I think that Concho is well positioned.

The third quarter had a lot of moving parts in it. I’m going to turn it over to Steve Beal to describe in more detail some of those moving parts.

Steven L. Beal

I’d like to briefly touch on some of the operational and financial matters affecting the quarter before we turn it to Q&A.

Our third quarter production of 1.9 million Boe is net of the storm related impact we experienced in the quarter which was approximately 115,000 barrels equivalent. As a result of the interruptions we’ve experienced this year including the carry-over effect in the fourth quarter of the storms on the Gulf Coast, we currently expect full-year 2008 production of 7 million barrels of oil equivalent which is still within the guidance range we published after the closing of the Henry acquisition on July 31.

We’re currently operating 17 rigs, all of which are in the Permian and includes eight rigs on the Southeast New Mexico shelf, six of which are drilling to Yeso and two of which are drilling in our Lower Abo horizontal play, and eight rigs in the Wolfberry West Texas.

At September 30 we had 43 wells that had been drilled, completed and were producing from the Blinebry interval of the Yeso that had not yet been completed in the Paddock interval. These wells have been completed in the Blinebry utilizing the larger frac which is a program we expect to continue into 2009.

Although we are continuing to gather data on the impact of the redesigned fracs, it does appear to us now that we’re capturing incremental reserves above our engineering model. We’re currently in the process of reviewing this data with our third party engineer and would expect to have some recognition of the positive impact of these fracs in our year-end 2008 engineering report.

We continue to see positive drilling results from the Abo horizontal play and are currently running two rigs there. As a reminder, this play sits one township to the north of our core Southeast New Mexico shelf Yeso play and it appears to us now as though the prospective area of the play is expanding.

As Tim alluded to, we now anticipate that our total 2008 capital expenditures will be approximately $355 million as compared to the $389 million we anticipated. This reduction is attributable to a couple of factors.

First, we’ll drill seven fewer net wells and perform fewer refracs and deepenings on the shelf than planned resulting in reduced cap ex of approximately $20 million. That’s partially the result of the way we’re completing the wells in the Blinebry now and the fact that some of the recompletes into the Paddock won’t happen until after year end as we continue to gather data on the results of the Blinebry frac program.

Our exploration activity outside the shelf in the Wolfberry will be approximately $10 million less than we originally thought and we’ll have about $4 million less of outside operating activity as a result of the decrease in the number of well proposals we’re receiving.

We’ll enter 2009 with a capital program, as Tim mentioned, concentrated in our core areas. Approximately 2/3 of the capital will be devoted to the Southeast New Mexico Shelf, 1/4 of the capital will be devoted to the Wolfberry, and the remainder will be devoted to the North Dakota Bakken on our joint venture in the Westburg area of McKenzie County with [Newfield].

As you guys are all aware, the situation in our industry is very dynamic as commodity prices and costs continue to fluctuate. We’ll aggressively monitor this and make appropriate changes as necessary to honor our long-standing philosophy of spending within cash flow.

If we end 2009 having invested the monies we currently anticipate, our production growth in 2009 compared to pro forma 2008 production of approximately 8 barrels of equivalent assuming the Henry acquisition had closed on January 1 of this year will be somewhere in the range of 21% to 33%.

At September 30 our net debt was approximately $581 million resulting in debt-to-total capital of about 33%. We currently have $330 million of availability under our $960 million senior revolving credit facility after having completed our semi-annual borrowing base redetermination in October.

On the expense side of the income statement we did as Tim mentioned recognize a third quarter mark-to-market gain on our open commodity derivative position of about $176 million. In addition we paid cash settlements on our derivatives totaling about $25 million for the quarter. We have provided for you in our press release a summary of our outstanding open contracts as of September 30.

As I’m sure most of you are aware, beginning in October we’ve seen a widening of gas differentials in the Permian that are well outside their historical range. Our fourth quarter revenues associated with residue gas will be negatively impacted by that as a result. As you know the Permian has historically enjoyed a relatively stable relationship to NYMEX. The futures market for 2009 would suggest that a return to that kind of stability is expected and we’re evaluating the propriety of entering into additional basis hedges for 2009 associated with our expected gas production.

Our total oil and gas production costs of $27 million in the third quarter included $12.5 million of leased level operating expenses with the balance being production related taxes. The increase in LOE per unit that we experienced in the quarter is largely attributable to increased electricity costs in Texas, increased saltwater disposal costs associated with the Henry properties because the disposal system in the Wolfberry’s not as integrated in the asset base as is the case on the Shelf specifically in Texas we’re trucking more barrels of water and higher labor costs.

The last item that I wanted to mention to you before we got into Q&A is the G&A charge associated with the employees that we were fortunate enough to add from the Henry acquisition. Our purchase agreement with Henry included a provision whereby our initial purchase price was reduced in exchange for our commitment to pay certain bonuses to certain persons we added over the course of the next two years.

From an accounting perspective we’re required to recognize that obligation over the period of service rather than recording it as an assumed liability at the date of purchase. Although this obviously doesn’t change the cash impact of the payment on the company during this period, it will result in this obligation being reflected on the income statement as a part of general and administrative expense until the obligation is completely satisfied in July of 2010. The aggregate amount that will be ratably charged to expense over this period is approximately $22 million.

With that we’ll now be happy to open the floor up and take any questions that you might have.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from Joseph Allman - J.P. Morgan.

Joseph Allman - J.P. Morgan

Steve, could you give us a breakdown of production by area if you have that available for the most recent data?

Steven L. Beal

I apologize. I don’t have that right in front of me right now. If Jack could follow up with you off line on that, but I can tell you just sort of painting with a broad brush we’ve got about 60% or so of our production that comes off the Southeast New Mexico Shelf, we’ve got about 4% or 5% or so that comes from the Southeast New Mexico Basin, and the balance or about 35% or so comes from West Texas which is dominated by the production out of the Wolfberry.

Joseph Allman - J.P. Morgan

The cap ex reduction for ’08. I know you gave the items. What’s the reason for seven fewer wells and fewer recompletions?

Steven L. Beal

The biggest reason is that we picked up some acreage and our partner had historically not joined us on those wells. They’ve elected to join for the balance of the wells that are going to be drilled this year so obviously where we thought we were going to be drilling higher interest wells, they’re now going to take their interest and we’ll be drilling lower interest wells.

Joseph Allman - J.P. Morgan

So it’s actually the same amount of activity, just less interest for you folks.

Steven L. Beal

That’s right. It’s reduced net well count.

Joseph Allman - J.P. Morgan

You went over those impairments fairly quick. The Fayetteville Shale, you’re just not going to drill it up so you had to impair it or what?

Timothy A. Leach

We still own that acreage. It still has term. As you remember it’s kind of on the southern edge of the fairway. We were planning some drilling activity up there but under the current circumstances it just doesn’t fit into our drilling plans. So we thought now would be a good time to impair it.

Joseph Allman - J.P. Morgan

Any plans on selling that or trying to sell it?

Timothy A. Leach

We have conversations going on. In fact we’re drilling a well or in the process of completing a well on our acreage up there with Chesapeake to that hale zone that’s below the Shale.

Joseph Allman - J.P. Morgan

There’s the Barnett/Woodford Shale. Does the impairment you took in the third quarter pretty much write everything off there?

Timothy A. Leach

It impairs most of the acreage in Culberson County. We still have one large block that’s the eastern-most block. All that shale activity that’s going on in Reeves County looks to be pretty successful. This stuff is just much further west and we don’t have any near-term plans to drill anymore wells out there.

Joseph Allman - J.P. Morgan

Lastly on that, Woodford Shale well that you impaired?

Timothy A. Leach

That well was a dry hole. We impaired that wellbore. We still think the acreage has some prospectivity and we’re continuing to work on that.

Operator

Our next question comes from Michael Jacobs - Tudor Pickering Holt & Company.

Michael Jacobs - Tudor Pickering Holt & Company

Thinking about your Blinebry recompletes and just wanted to dig into that a little bit more. You previously started recompleting the Blinebry with larger fracs. Thinking about how you said that some of the recompletes to the Paddock are pushed out. If I’m thinking about it the right way, were you previously recompleting to the Paddock one to three months after completing the Blinebry and now it’s probably six months out as you’re trying to gather more data?

Steven L. Beal

That’s probably a fair generalization.

Michael Jacobs - Tudor Pickering Holt & Company

So thinking about that and comparing the data that you’ve gathered throughout the third quarter, it seems like you’ve got a good idea of three month rates with the larger Blinebry frac versus how you were fraccing it before. Can you give us some indication as to what rates look like in just the first three months if we were to compare apples-to-apples, the larger frac versus the smaller frac?

Steven L. Beal

I think at this point we’d like to defer that till the end of the year. We’ve got a number of wells as I mentioned that we’ve got differing amounts of history on. There’s a few we have six months of history and there’s some that we have last week history.

The distribution of those wells is pretty wide over the acreage position, so I think what we’re going to do is wait until we get to the end of the year and get that data through our third party engineer before we’d be prepared to comment. I think we’ll just leave it with the comment that we made which is that it appears based on the data we have today that we are capturing incremental reserves and it’s not just an acceleration of rates from the modeled EURs.

Michael Jacobs - Tudor Pickering Holt & Company

Moving on and thinking about the ’09 program and your comments Tim earlier that it’s going to be somewhat of an analog to ’08 even though prices are going to be significantly lower, we had previously thought about the acquired Henry assets effectively doubling activity and ultimately getting to 16 rigs.

With ’09 prices about 2/3 of ’08 prices you’re keeping rig activity flat. I just wanted to dig into the Wolfberry economics and perhaps you can give us an idea of price versus cost? For example if oil prices were to go up to $80, would you start adding rigs or how far maybe you can give us an idea of your average rig rate in the Wolfberry and where current spot rates are and how far rates would have to drop for you to start escalating that rig activity?

Timothy A. Leach

That’s a lot of questions Mike. Let me try to remember and answer as many as I can. We did anticipate when we were talking earlier about increasing the number of rigs we were going to run on the Wolfberry assets. In fact when we started the budgeting process, from the current eight rig level we were hoping we would end next year at 12 rigs. At that time oil was somewhere between $80 and $100. If you look at the economics on the Wolfberry wells, we’re already starting to see some in the cost side of it ability to reduce those costs.

But we’re going to put a new presentation on our website tomorrow that we’re going to be appearing at the B of A conference and there’ll be a slide there that will show that down to $50 oil if you reduce those capital costs by 15%, you get about a 20% rate of return.

Out of our total capital budget as Steve mentioned, we’re going to be spending about 25% of our capital budget on that type of activity.

Michael Jacobs - Tudor Pickering Holt & Company

In your current capital budget that you put forward, are you assuming that costs are going to decline?

Timothy A. Leach

No, we did not assume that. We looked at current costs and we thought we could nominally cash flow our capital budget at current activity levels at that $65 and $6 level. The good thing we have about our drilling activity is we can kind of dial it up or dial it down as we watch what the commodity prices and what costs are doing.

Michael Jacobs - Tudor Pickering Holt & Company

Just piggy-backing on Joe’s question on the asset impairments, was that related more to drilling or where differentials were?

Steven L. Beal

I think it’s really related to a couple things. One is the good problem that we have is that we have so many projects in inventory that have such high rates of return that as we look at stepping out onto the risk spectrum and spending capital on projects that in a $6 gas price environment in our view don’t have rates of return that compete, we just felt that given our lack of intention to proceed with any activity on those areas right now that now was the time to recognize that.

I do want to reiterate the point that Tim made earlier. It’s not that we’ve seen those leases expire. Those leases do still have term and were conditions to warrant be that prices improve significantly or some of the other parties who are active there crack the code so to speak that doesn’t necessarily mean we wouldn’t participate in that. We just don’t have plans to devote capital to those today.

Operator

Our next question comes from Mark Lear - Sidoti & Company.

Mark Lear - Sidoti & Company

Can you talk about the kind of results you’ve been seeing in the horizontal Wolfcamp play that would entice you guys to commit a rig there for all of ’09?

Steven L. Beal

I’m going to paint with a pretty broad brush here. I think that the kind of results that we saw when we drilled the discovery well in the play, the Reindeer #1, we are continuing to see those kinds of well results. We talked in last quarter’s call about the well we had drilled there once we reinitiated our program and that well was making about 400 barrels of equivalent a day, so that’s the neighborhood that we’ve been encouraged by and therefore expect to continue to drill for.

Mark Lear - Sidoti & Company

So you guys have benefited from seismic finding this to be much more repeatable?

Steven L. Beal

I think it’s not just seismic. Now there’s been a lot of activity in the area so you’ve got far more well control data than you’ve historically had. Our technical team has worked this pretty hard from a variety of different technical perspectives including seismic data, so we do feel far more comfortable today in terms of being able to get a higher degree of predictability around what we’ll find when we drill.

Mark Lear - Sidoti & Company

You mentioned it’s only one township north of that core area. Have you guys done any testing to see if that pay does extend down to those core Southeast New Mexico Shelf properties?

Timothy A. Leach

We’ve got a well underway right now.

Mark Lear - Sidoti & Company

When do you think we would hear some results there?

Timothy A. Leach

It’s probably end of the year.

Mark Lear - Sidoti & Company

Looking at your guidance I wanted to get an idea in terms of what price levels you guys would start looking at maybe laying down some rigs. I guess you’d probably be looking at the Wolfberry before you would the Southeast New Mexico Shelf?

Timothy A. Leach

That’s right.

Mark Lear - Sidoti & Company

What sort of levels would you be looking at though?

Steven L. Beal

If you look at the release, below $65 sustained would not allow us to stay within 10% of estimated cash flow so a sustained price much below that we would start having those discussions.

Steven L. Beal

Unless you saw a materially movement downward in drilling and completion costs.

Timothy A. Leach

It’s pretty simple math to see that 10% savings in drilling costs is $50 million. That’s an adult size number.

Operator

Your next question comes from Michael Scialla – Thomas Weisel Partners.

Michael Scialla – Thomas Weisel Partners

It sounds like you haven’t forecasted a decrease in costs but maybe you’re kind of anticipating one where we’re headed with oil prices. I know there’s a lot of rigs running in the basin, are you seeing any rigs by any of your competitors being laid down at this point or do you expect that to happen?

Timothy A. Leach

Sure, I think Pioneer especially on the Texas side is one of the largest operators have announced their intentions concerning their rigs. You’re seeing a pretty wide spread reduction in capital programs which I think is going to help us quite a bit.

Michael Scialla – Thomas Weisel Partners

Then in terms of the Wolfberry, I know you haven’t had the asset that long but how much variability are you seeing there in terms of depth and cost and EURs as you look across your acreage?

Timothy A. Leach

It’s very consistent.

Steven L. Beal

Mike, we bought those assets with an expectation that you’d see some degree of variability in EURs depending on exactly where you were in the play. I think it’s fair to say that we haven’t seen any more variability than we expected as we drilled in those areas. For example, we have EUR ranges from about 120,000 to 125,000 BOEs to about 165,000 BOEs. When we drilled in places we thought it would be about 125,000 that’s about what it is and where we drilled in places we thought it would be 165,000 that’s about what that is.

Michael Scialla – Thomas Weisel Partners

Then, can you elaborate a little bit more on the constraints on the production that you’ve had over the year? I know gas processing was a problem in the first half, can you talk about it a little bit more specific to third quarter?

Steven L. Beal

Yes, we really had kind of had three major things kind of happen to us, the most recent which of course was the effect that we felt out here from the Hurricane that hit the coast. We had a fire in our oil refinery, the refinery to which we send most of our oil in southeast New Mexico so that impacted us on the southeast New Mexico shale.

We also had what was kind of a freak storm that went through that part of the world with straight line 98 mile per hour winds that caused some damage to a natural gas processing facility through which we send a significant amount of our southeast New Mexico shelf gas. So, when you look at all of those things collectively the impact on us this year is around 200,000 barrels of oil equivalent.

Michael Scialla – Thomas Weisel Partners

What’s the timing look like on your debt maturity?

Steven L. Beal

2012.

Michael Scialla – Thomas Weisel Partners

All of it?

Steven L. Beal

2013, it’s a five year facility. The new facility we put in place in July when we closed the Henry acquisition so we don’t’ have any maturities until 2013.

Operator

Your next question comes from Houston Netherland – Natixis Bleichroeder.

Houston Netherland – Natixis Bleichroeder

Just one question here on economics, you gave us an update on Wolfberry economics at $50 oil, can you also give us a similar update on Yeso, what those economics might look like at $50?

Timothy A. Leach

On comparable economics it is about a 55% rate of return on the Yeso facilities.

Houston Netherland – Natixis Bleichroeder

Does that assume your 10% to 15% NYMEX differential?

Timothy A. Leach

Right.

Operator

Your next question comes from Jeffrey Robertson – Barclays Capital.

Jeffrey Robertson – Barclays Capital

Steve or Tim, are you all seeing many opportunities to either expand in the plays that you’re currently involved in or look at new plays just given the capital constraints and the current environment?

Timothy A. Leach

Jeff, the number one focus is expanding in the plays where we already have a core area and yes, there are numerous opportunities probably in the third quarter that’s increased revenues rather than decreased with the price going down. I wish I had a bigger balance sheet.

Jeffrey Robertson – Barclays Capital

You talk about costs but are costs going to fall or is it just a function of the rig count falling before costs start to fall? What kind of discussion are you having with your vendors around 2009?

Timothy A. Leach

Well, I think everybody in the service business knows costs are going to come down. It’s a question of the rate of decline of costs and we haven’t really seen the effect yet of a lot of rigs being laid down although that’s coming.

Operator

Your next question is a follow up from the line of Joseph Allman – J. P. Morgan.

Joseph Allman – J. P. Morgan

I think it was Tim or Steve, just back to that question on the Fayetteville, you said that you’re actually participating well with Chesapeake, could you talk about that and where that is and plans going forward? Will you continue participating in some wells?

Steven L. Beal

Generally, it’s kind of on the southern, I guess sort of south sort of eastern side of our acreage position. I think the well is awaiting completion and the direction that we proceed after that obviously will be determined by what happens when we try to complete this well. So, I think it’s way too early for us to really comment with any definition around what we’d do after that.

Joseph Allman – J. P. Morgan

Then in the lower [Abo], could you talk about how many wells you’ve drilled at this point? And, if I remember correctly the first well was very good, the second well had too much water, the third well I think that’s the one that you described in the press release as holding up pretty well. No, no, I’m sorry I think the third well you drilled further away and then you stopped drilling it, the fourth well was the one that looks good in the press release. Can you just confirm that and talk about what other activity you’ve had?

Steven L. Beal

Let me try to answer it this way, since we reinitiated our program the first well of which was the well we talked about in the second quarter release, we have drilled or participated in about a handful of well, six wells. We have seen certainly far more consistent results from those than we did the first three wells we drilled back in 2007, early 2008.

A well there takes about 25 to 30 days to drill so generally kind of as a broad characterization you’re drilling about a well a month. We’ve got two rigs up there now so we’ll get a couple to three more wells drilled before the end of this year.

Joseph Allman – J. P. Morgan

Have the wells since you resumed that program, have they been close to the first well?

Steven L. Beal

Some have, some haven’t.

Joseph Allman – J. P. Morgan

Because I think, if I’m not mistaken, and I know it’s confusing here, all the numbers that I’m giving but I think that the third well was a step out, have you resumed drilling that well and other wells around there? Can you talk about that?

Steven L. Beal

We have drilled wells that far away or further.

Joseph Allman – J. P. Morgan

And still the same consistency?

Steven L. Beal

Yes.

Joseph Allman – J. P. Morgan

Then the results of the well that you mentioned in the press release, how does that compare to the first well? Are they both holding up fairly well?

Steven L. Beal

Yes.

Timothy A. Leach

They’re pretty similar results Joe.

Steven L. Beal

I know Jack [inaudible] work on this but just the differentials that you’re seeing for your natural gas, what do you think is driving that and what is going to help that narrow some?

Timothy A. Leach

Well Joe, obviously cooler well will be a big factor and the slowdown in drilling will be affected but as Steve mentioned, the futures curve to ’09, at last as to the [Permian] would indicated that those differentials are going to be back kind of it looked like the normal $0.80 to $1.00 type of differential to the NYMEX out here.

Joseph Allman – J. P. Morgan

Then on the [Blindburry] could you talk about I know you based your spacing locations on 20 acres basing. Could you talk about where your drilling has been so far and have you brought any down to 10s and what those results might look like?

Timothy A. Leach

We have begun to bring some down to 10s and the results look good. The big question that we are continuing to evaluate is the degree to which you can capture some of those 10 acre reserves with that 20 acre larger frac. We believe before we started drilling 10 acre [Blindburry] wells that the [Blindburry] would be productive on 10s just because of the nature of the rock. I think based on what we’ve seen so far we continue to believe that.

Operator

Your next question comes from Michael Jacobs - Tudor Pickering Holt & Company.

Michael Jacobs - Tudor Pickering Holt & Company

I just wanted to follow up, dig in to the economics a little bit, of your eight rigs in the Wolfberry and the eight on the shelf can you give us a breakdown of how many rigs are contracted and how quickly you can benefit from a change in day rates?

Steven L. Beal

Mike, generally all of the rigs are contracted for some period of time, most of which run out at some point during the middle part of 2009. We do have a couple of rigs that go in to 2010. Right now the discussions that we’re having with vendors including rig contractors involve a lot of things including changing rates in order to extend terms or things we can do to mitigate the cost that we’re seeing.

We’ve got a variety of different vendors that we use on the rig side, all those contracts are different to one degree or another, whether they have some sort of early termination penalty that you would pay if you laid down a rig or not, a lot of the ones we have do not. So we think we’ve got pretty reasonable flexibility there to address that.

Michael Jacobs - Tudor Pickering Holt & Company

Can you just give us for scope an idea of your average day rate today versus kind of where rates are actually heading and maybe some order of magnitude.

Steven L. Beal

I guess scoping wise I’m kind of looking at Joe Wright, as you guys know runs operations for us. I think scoping wise the price talk we hear today would have prices going down 10% to 15% from where rig rates are today. For example, in the Wolfberry rates today are between $15,000 and $16,000 a day and the price top today is more in the $13,000 to $14,000 range.

Operator

At this time there no further questions in queue. I would now like to turn the call back over to Mr. Jack Harper for closing remarks.

Timothy A. Leach

I appreciate everybody listening in and as I mentioned in the call we are presenting tomorrow at the [eBay] conference and there will be a new set of informational slides on our website. Thank you once again for your interest in Concho Resources.

Operator

Thank you for your participation in today’s conference. This concludes the presentation you may now disconnect.

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