Cimarex Energy Co. Q4 2009 Earnings Call Transcript

Feb.17.10 | About: Cimarex Energy (XEC)

Cimarex Energy Co. (NYSE:XEC)

Q4 2009 Earnings Call

February 17, 2010 1:00 pm ET

Executives

Mick Merelli - Chairman & Chief Executive Officer

Tom Jorden - Executive Vice President of Exploration

Joe Albi - Executive Vice President of Operations

Paul Korus - Vice President & Chief Financial Officer

Jim Shonsey - Vice President & Controller

Mark Burford - Director of Capital Markets

Analysts

Bill [Metner] – Macquarie Capital

Nicholas Pope – Dahlman Rose

Eric Hagen - Lazard Capital

Andrew Coleman - UBS

Mitch Wurschmidt – Keybanc Capital Markets

Greg Brody - JP Morgan

Ray Deacon - Pritchard Capital

Operator

Welcome everyone to the Cimarex fourth quarter 2009 financial results conference call. (Operator Instructions) I would now like to turn the conference over to Mr. Mark Burford, Director of Investor Relations. Please go ahead, Sir.

Mark Burford

Thank you and thank you everyone for joining us today on our fourth quarter results conference call. We did issue our press release this morning, a copy of which can be found on our website and we also posted to our website a presentation that has some statistics and we will also be referring to from time to time on today’s call. That can be found on the same path also on the same link for the webcast on our website at the Investor Relations tab.

This conference call will include forward-looking statements. The risks associated with these forward-looking statements have been outlined in our earnings release and in Cimarex’s SEC filings and we incorporate those to reference during this call.

On the call here today in Denver we have Mick Merelli, our Chairman and CEO; Tom Jorden, Executive Vice President of Exploration; Joe Albi, EVP of Operations; Paul Korus, VP and CFO; and Jim Shonsey, our Controller.

With that we will go ahead and just jump in and I will turn the call over to Mick for some opening remarks.

Mick Merelli

Thank you all for joining us today I am just going to make a few brief statements and then turn the call over to the boys to explain the details.

2009 was a very, very interesting year for Cimarex. We started the year in a tremendous slowdown of activity. Actually after we got a quarter or so into the year we were probably at the lowest level of activity we have ever had at Cimarex in terms of number of drilling rigs operating. Then as we headed into the year we started to pick up momentum and by the time we got to the end of the year 2009 has wound up being probably one of the best, if not the best year, Cimarex has had.

In terms of accomplishments we invested $524 million in our exploration and development drilling. We added 312 Bcfe improved reserves from the drilling which is 185% of our production. So we have more than replaced our production with drilling reserves. Our year-end exit rate for the company was 486 MMcfe/d and that included 150 MMcfe/d of production that was attributable to our 2009 drilling program.

We had really good results from all of our areas. Again, we continue on with the same old story for us. We are rate of return driven. We are growth through drill bit driven. We have a nice blend in our portfolio of drilling opportunities. Our mid-continent counter resource play we have 94,000 net acres in that play. This has been a year of definition for us. It is continuing. So we have drilled more wells. We have learned more about the play. As Tom will explain a little bit later the play looks better. The longer we are involved in it the better it looks so it is continuing to improve.

Our Permian Basin horizontal oil project group is driven by 380,000 net acres of lease position. We have a nice mix of opportunities. We got down to zero rigs for awhile in that play. We started picking up activity towards the end of the year and Tom I am sure will talk a little bit about that.

Of course our Gulf Coast exploration has always been a good, profitable drilling program for us. But 2009 was really an outstanding year.

So as we look into 2010 we are entering 2010 with a large inventory of drilling projects that have good economics. They are actually resistant to some pretty low commodity price levels. I don’t know if Tom is going to even mention it or not but we run everything on a downside case of $3.50 gas and $45 oil flat.

We have a nice group of things to drill in all of our areas heading into 2010. Right now we are thinking that is going to be somewhere between $700-900 million we are going to spend on our drilling program in 2010. That is just an estimate. So anyway, we head into the year with lots of opportunities, low debt and high production so we are really excited about what is coming up in 2010 and we are very proud of our results in 2009.

With that I will let Tom go ahead. Tom Jorden.

Tom Jorden

Thank you Mick. This is Tom Jorden. For those of you that are following on our slides on our website I am going to be on slide eight. Slide eight shows our core operating areas. As Mick said we have our mid-continent project, our Permian basin predominately horizontal oil and then our on-shore Gulf Coast.

Our 2009 end of year reserves were 1.53 TCFE of which 47% of those were mid-continent, 32% were Permian on an equivalent basis. Then 7% were Gulf Coast and 14% kind of western and other. This slide also shows our fourth quarter 2009 projection of 486 MMcfe/d and how that splits up. As you can see from the slide for those of you that are following along, 44% of it was mid-continent and 31% Permian. So mid-continent and Permian is our core modern risk drilling areas account for 75% of our production. Gulf Coast in the fourth quarter accounted for 25% of our production.

So although the Gulf Coast is only 7% of our reserves, in the fourth quarter it accounted for 25% of our production. That is a testament to the success we have had on-shore in southeast Texas with our geophysically based plays. I will give a little more detail on that in a minute. It also is a testament to rate of return and how high a rate of return those projects are even though they are a small part of our production base, huge, huge production and cash flow properties.

Moving onto slide 9, this shows our capital investment broken down by region and as a comparison between our 2009 and 2010 planned programs. As Mick said in 2009 exploration development capital we invested $524 million. 48% of that was in the mid-continent. 30% of that was in the Permian and 20% was in the Gulf Coast. In terms of activity level in aggregate in 2009 we drilled 110 gross and 67 net wells; 51 gross net wells in mid-continent, 22 net; 49 gross wells in the Permian basin, 36 net; 9 gross wells in the Gulf Coast, 8 net.

In 2010 we are planning an exploration development capital of between $700-900 million. That is a fairly broad range. We are going kind of steady as she goes. We are watching our cash flow. We are watching the available opportunity set. We are watching product prices and watching costs. We certainly have the ability to accelerate or decelerate that number based on the conditions.

Of that $700-900 million in 2010 we expect 52% of that to be in mid-continent and the bulk of that is our Cana play. 31% would be Permian basin and that is horizontal oil and then 16% of that capital will be Gulf Coast and that is the high risk, high potential geophysically driven program that is a continuity of 2009.

If you look at the midpoint of that capital range we are estimating about 110 gross wells; 45 net wells in mid-continent; 85 gross wells or 60 net wells in the Permian and about 15 gross wells, 12 net in the Gulf Coast. Total activity we are projecting for 2010 is 210 gross wells or 117 net wells. When you compare that activity to 2009 you see that is almost twice the activity and obviously it is not twice the capital. A big portion of that is costs have come down a lot in 2009.

Certainly if you look at the first quarter we had a lot of carry-over capital from 2008 where drilling completion costs were at historical highs and that certainly impacted us in 2009. As we have talked in subsequent calls and Joe may get into this we certainly have seen costs moderate and we are just flat out getting more value for our adjusted dollar today than we were in 2008 and first half 2009.

Moving onto slide 10 this is a summary of our mid-continent region. It is a summary of our reserves and our capital. It compares our 2008 end of year reserves with 2009 end of year reserves for oil and gas. As you can see in 2009 our oil reserves in mid-continent were up 40% from end of year 2008. Our gas reserves were up 18% from end of year 2008 and on an equivalent basis and this is 6:1 equivalent. Our aggregate reserves for mid-continent we ended 2009 with 730 Bcfe as compared to 609 Bcfe in 2008. That is a 20% increase in reserves out of our mid-continent.

The present value on a 10% discount is less than 2009 and that is a function of the prevailing price at the end of the period. Our production in the mid-continent was for oil we were down 9% in 2009 compared to 2008. For gas we were down 1% 2009 compared to 2008 and on an equivalent basis 2009 in the mid-continent we produced 218 Bcfe and in 2008 we produced 223 Bcfe so we were down 2%. That is by and large a function of our rig count. As a company we went from 43 rigs in the third quarter of 2008 to 3 rigs in February of 2009.

So we have talked about that in prior calls and as we have picked up the activity we have certainly seen that production curve change slope on the rest of that decline. We have a great position in the mid-continent. As the slide shows we have a 1,077,000 gross, or 690,000 net acres. That is up 7% on a net acreage basis from 2008. I will give a little detail on the Cana play. We certainly continue to acquire interest there and we are very pleased with our position.

In the mid-continent in 2010 we are projecting $410 million of exploration development investment. That is up from $251 million in 2009 and we invested $648 million in 2008. I have already gone over the planned well statistics. We plan 110 gross or 45 net. So it is a nice asset and it is one we are exploiting aggressively.

Slide 11 shows the hallmark of that asset is our Cana Woodford Shale play here in Canadian County in Western Oklahoma. The insert shows where that sits for those of you who are unfamiliar with it, we are sitting due west of Oklahoma City. In 2009 we drilled 46 gross and 20 net wells. We have 11 gross and 6.3 net wells waiting on completion at year-end. So we talked on previous calls we had a lull in our completions. We put a lot of science behind studying optimum completion techniques. We made tremendous progress on that but we are still working our way through that completion backlog. In 2010 we are expecting to drill 75 gross and 35 net wells in the Cana play. Our year-end 2009 proved reserves totaled 225 BCFE.

On slide 11 there is a table summary of some recent wells we have completed and we have had some very good results but we are still struggling through it. I really want to emphasize to the listener this is still early days in the Cana play. We have a lot of success to report. We have a lot of quandaries to talk about as well. This is still an area we are unsure what the ultimate sweet spot will look like. We are wrestling the science. But the table shows our recent wells the base 225. Our first 30 day average on an equivalent was 3.4 MMcfe/d. Again that is an average rate for its first full month of production.

The Williams 136 averaged 4.67 MMcfe/d. The Bessie 16 averaged 8.55 MMcfe/d for its first 30 days. The Calvert is our southernmost well and was a disappointing well to us although I will talk about that a little more in a minute, it averaged 714,000 cubic feet per day for the first 30 days. The Anderson averaged 5.77 MMcfe/d for its first 30 days. The Draper averaged 8.44 MMcfe/d for its first 30 days of production.

So we have seen a really nice string of recent completions. Very stout pressures. Good 30 day rates. One of the nice things about the Cana play is the liquids. As you can see from our table on slide 11 our yields out here it really is a function of depth and they vary from dry gas at the deepest depths to upwards of 50 barrels of condensate per million cubic feet at some of the shallower depths. So that liquid stream really is significant.

While we are on this map we talked in the past about the Calvert well. Our test in the southernmost part of the play. We hoped to have something conclusive to say. All we can say conclusively is we had some mechanical issues with that well. We lost some portion of the lateral. We didn’t stay in the zone we wanted to. Flat out I have to say we are disappointed in the results of the Calvert but we have a huge asterisk near it and we don’t know what to conclude from that. We are currently in the process of completing a well a few miles to the northwest of it called the Straight Arrow that hopefully will be a second point that will help us make some conclusions about the southern extent of this play.

So Calvert was disappointing to us but there were lots of mechanical issues on that which make us say we are not ready to make any conclusions based on that completion. Nonetheless, we have had very, very good results in the Cana play particularly the most recent wells we have brought on line continue to surprise us. This play is looking better and better to us. Our go-forward type curve is looking very stout.

I want to take a minute and talk about our natural gas liquids in the Cana play. Historically I think we might have confused some of our listeners with the way we handle some of our natural gas liquids. We are not changing our fundamental approach but what we are doing is where we can book those liquids as volumes we are booking those liquids as volumes. Where we can’t we treat them as price. In some of our prior calls we have talked about a receive price and we have run that natural gas liquid stream into our received price.

The way it works is we produce oil at the well site and that falls out as condensate. Then we also have a high BTU gas stream in the Cana play. Much of that gas is 1,200 BTU, and again on slide 12 for those of you who are following along on the slide show. What happens is that gas goes to a processing plant and additional liquids drop out as natural gas liquids. We have typically expressed that in terms of a realized price. Those natural gas liquids can be extremely significant with that high BTU gas stream.

In fact, the liquid stream in total can be as much as a 30% uplift in the overall volume equivalency of the well. So we have looked at our contracts and where we can book those liquids we are booking those liquids now. Where we can’t we will continue to treat it as a price uplift. Nonetheless I think it is important to the listener to note those natural gas liquids in the Cana play are extremely significant to us in terms of play economics and we are not typically a midstream processor but where we can take delivery of those liquids and book them we are booking them.

So we do receive economic value after processing. We have contracts that give us a percent of proceeds. In our type curve we are going to be showing you a wet gas type curve and a dry gas type curve. That will be on the next slide. Our current product mix if you look at the plan aggregate is about 65% gas and 35% oil and NGL. So this liquids is significant if you look at the play and it is worthy of a discussion and bringing it to your attention.

When we look at slide 13 I would point your attention to a type curve. This is not our go-forward type curve. This type curve is a composite of what we have actually achieved historically. So our go-forward when we drill a new well in the core of the play that is significantly better than this, but this type curve is when we look at the historical drilling in the Cana play and we say what have we actually done, this is the type curve on slide 13.

For those of you who are looking at this in color we have a daily rate which are the two curves that are declining. The light blue curve is a wet liquid stream. So this would be the gas that is actually measured at the well head. The dash curve would be the net equivalent curve after we have stripped the liquids out. So we have talked in the past about a 6.5 Bcfe type curve. When we really account for those liquids that are produced on average in the play that type curve becomes an 8.5 Bcfe. That is volumes we would receive if we had a percent of proceeds contract at the tailgate of a processing plant.

Our 30 day average we have talked about 4.4 MMcfe/d but that is at the well head, wet, high BTU gas. Once we process that gas we look at an equivalent basis of the liquid that gets stripped out we are at a 5.8 MMcfe/d tailgate gas. So the conclusion here is when you look at the Cana play and you say Cimarex, for the wells you have drilled now that you have been in the play for 2.5 years what is your actual average result? Our actual average result if we take all the sins, all the successes, our actual average well on that play is an 8.5 Bcfe well that produces 5.8 MMcfe for its first 30 days.

So the liquids in this play are very, very significant to us. They certainly make a huge difference in the economics. In fact as you compare the Cana play to other resource plays two of the significant differences that are often overlooked are the value of those liquids but also the net revenue interest we achieve in that play. Our net revenue interest in the play is typically 80% or greater. So the economics of this play are tremendous and as our results are improving they just get better.

One slide 14, in summary in the Cana play, certainly for Cimarex it is significant future drilling. We continue to acquire acreage. At year end we had 94,000 net acres. Today we have about 98,000 net acres in the larger Cana play. Our actual results are 6.5-8.5 Bcfe per well. Our average lateral length today is 4,000 feet on 160 acre spacing. If we go 4 wells per section we will have 1,200 gross wells to drill on our acreage position, 400-500 net wells. So for a company our size this is a significant play.

We are underway on an 80 acre pilot project. We are currently drilling and we will be completing and analyzing the utility of going to eight wells per section. Hopefully we will have something meaningful to say about that. Certainly by the middle of the year we anticipate completing those wells in the spring of this year and we should have some data to report on whether we think an 80 acre development is feasible.

At 160 acre spacing our net potential is 2-3 Bcfe. We think that is real. We think that is achievable and we are very, very encouraged by our recent results. As you can see our costs have come down. In 2008 we were at $9.5-10 million per well to drilling complete. Our current estimate is $7.2 million per well and we think we have significant operational upside around that number. So the Cana play has continued to be a very, very successful play for us. We are just delighted to have it.

Moving along to slide 15, when we look at the Permian basin this is a similar summary slide. Year-end 2009 compared to year-end 2008 our oil reserves were up 25%. In the Permian our gas reserves were down 2%. On an equivalent basis our equivalent reserves at year-end 2009 were 487 Bcfe, 2008 they were 442 Bcfe. So we grew those reserves 10%. That is a phenomenal testament to our group in Midland both the exploration and the operations group because if you recall in late winter/early spring our rig count in the Permian was zero. So they really picked up the pace in the latter half of the year and had a very, very nice year.

Again our pre-tax PV10 end of year 2009 is up from 2008 and that is again by and large a function of oil price where we ended 2009 compared to where we ended 2008. Our production in the Permian, our oil production was up 6%. Our gas production was down 11%. On an equivalent basis our production was down 3%. No surprise given the fact that our rig count went to zero during the course of the year. In 2009 we averaged 161 MMcfe/d out of the Permian basin.

We have an outstanding acreage position. We ended 2009 with 554,000 gross and 379,000 net acres. That was up 18% from year-end 2008. Then as I said earlier in 2010 we intend anticipate investing $250 million in the Permian basin. That is up significantly from last year and we will get a lot more activity done. We have some great projects in the Permian.

If I move to slide 16 it kind of summarizes where a number of those are. As I said in 2009 we drilled 49 gross and 36 net wells. We had some new projects come to the fore in the Permian basin in 2009. Our group in Midland was innovative. They developed some new horizontal oil projects that would lower costs in some of our historical plays and really opened up some new territory for us. In 2010 we expect to drill a total of 85 gross or 60 net wells and we have some significant drilling in some horizontal oil plays.

We have talked about our Bone Spring play. We have a Bone Spring play not only in Ward and Winkler County that we talked about repeatedly in the past. We have drilled close to 90 wells in that trend. But in Eddy County, southeast New Mexico, we have opened up a new bone spring, a little shallower bone spring oil play. It is working out very nicely for us.

We have our Abo play. We currently have two rigs running in that Abo play and that continues to show very, very nice results. Then we have some additional development in Wolf Camp and Cherry Canyon. We will have 4-8 rigs running in 2010. We currently have five and we anticipate ramping that up.

Also on slide 16 some example of some wells we have brought on in the fourth quarter. Midway 17 3H was an Abo well that came on. Its first 30 day average was 490 barrels of oil per day. We had 100% working interest. The offset well to that was the Midway 17 2H. It produced 310 barrels of oil per day for its first 30 days. Again 100% working interest. Very nice Abo well. Then these next two wells are in our southeast New Mexico Bone Spring play that is brand new to us in 2009 and 2010. Our Shooter West 31 3H is a well that came online in December. Its first 30 day average was 560 barrels of oil equivalent per day. Very, very nice well. Then the State 14 2H its first 30 day equivalent was 325 barrels of oil per day. So very nice wells. It is a great program in the Permian basin and it is certainly a core part of our diversified approach.

Then finally if I move to slide 17 it shows our Gulf Coast. In 2009 our reserves were up 42% from end of year 2008. That was oil. Gas was up 45%. If you look at our production in 2009 our production averaged 4,300 thousand barrels per day of oil. That was up 2% from 2008. Our gas production was down a little bit over the course of the year. Again that is by and large a function of our rig count. On an equivalent basis we produced 80 rig cubic feet per day over the course of the year 2009 which was down 12% from 2008.

We are in a very nice acreage position on-shore Gulf Coast with 219,000 net acres. That is down a little from 2008 but this is a trend where we use geophysics to identify a particular prospect and their rifle shot. So these big acreage numbers don’t quite mean the same thing in the Gulf Coast as they would in the Permian or the mid-continent. In 2010 we expect to invest $130 million of capital. We will certainly get done everything we can prudently. We are going to roll in the Gulf Coast. 2009 we invested $106 million. So as you can see from a gross and net well count we expect to get about half again as much done in 2010 as we did in 2009.

Onto slide 18. This shows our Yegua-Cook Mountain program. This is certainly our crowned jewel of our Gulf Coast program. We have been operating here actively since 2002. Over the course of the last 8 years we have drilled 94 wells. We have had a 65% success rate and on this trend we have been profitable every year. It is 3D seismic driven. We have over 2,000 square miles of 3D data. As those of you who follow us know we have put a lot of effort into the geophysical analysis here. In 2009 we found ourselves in the best area yet.

Our 2009 discoveries were the Two Sisters 1, our Garth 1 and then our Jefferson Airplane 2 and 3 on the Beaumont Airport property. This set us up for a great year in 2010. 2010 should be just a seamless continuation of our success in 2009.

If you look at slide 19 this is a bit of a zoom in to what we call our River Fork project. That is in and near the city of Beaumont. This shows our 2009 discoveries. You can see our Two Sisters 1 well there we had a higher percent of that. Our Garth 1 well we had a higher percent of that. Our Jefferson Airplane 2 and 3 wells we had 96% working interest. Those wells the average of those four wells they IPd at over 40 MMcfe/d. That is not a typo. That averages 28 MMcfe/d of gas and 2,100 barrels per day of oil. So outstanding economic results. The gas alone is a nice result. If you add that to the oil and you can see why we are so excited about it.

We are currently drilling the Jefferson Airplane 4 and Nine Dragons 1. As slide 19 shows we expect to have a full developed program in 2010. In conclusion we have three core areas that all performed well in 2009. Our Cana play is working very well. We also have our Texas Panhandle asset we haven’t talked about here but we have a rig operating there. We are very optimistic about that. We have our Permian oil and then our on-shore Gulf Coast. 2010 should be a continuation of us having that diversified program, geographically but also product mix.

With that I would like to turn it over to Joe Albi, our Executive Vice President of Operations.

Joe Albi

Thank you Tom. I will briefly summarize our fourth quarter production results, touch on our 2010 guidance as well as our 2009 and 2010 production group focus. Then I will just follow-up with a few comments about where we see service costs.

For those of you following along on our PowerPoint presentation the first slide I will talk about is slide 21. On slide 21 it summarizes Q4 and our full-year 2009 production. As we discussed in our last call with our increase in activity and the success of our south Texas program the fourth quarter was likely to be a turnaround quarter for us from a production standpoint. You may recall we stated the success of the quarter really relied on the timing and drilling and completion of the wells in Q4 and that they could play a big role for us with fourth quarter volumes.

Well things definitely went our way. We ended the quarter with reported average net daily equivalent production of 467.6 MMcfe/d. That is 26.1 million per day or 6% from Q3 where we reported an average of 441.5 MMcfe/d. It also was well above our guidance for the quarter of 440-455 MMcfe/d. So we had a good quarter. With that strong quarter our full year production took a little bit of a bump from where we thought it would be at the beginning of the year. We averaged 462.9 MMcfe/d, down as expected from 2008 but it did beat our beginning year 2009 guidance of 440-460 MMcfe/d.

If we adjust for property sales our average 2009 production was down 3.6% from 2008. Hidden in all this is the good news that I will discuss here shortly. Our property sale adjusted 2009 exit rate surpassed that of 2008.

On slide 22 we have gone ahead and put together a listing of our production by region comparing Q3 2009 to Q4 2009. A couple of things I will just point out with the chart, as compared to Q3 we saw increases in both oil and gas production during Q4. With our total company net oil production averaging 22,900 barrels per day, up 2% or 500 barrels per day from our Q3 average of 22,400 barrels per day. Our total company net gas production was also up, averaging 330 MMcfe/d, up 8% or 23 MMcfe/d from our Q3 2009 average of 307 MMcfe/d.

If you look at the table our south Texas program was really the primary catalyst in both oil and gas production in the quarter. Our Q4 Gulf Coast oil production averaged 6,400 barrels per day. That is up 46% of 2,000 barrels per day from Q3. While our fourth quarter Gulf Coast gas production averaged 77.7 MMcfe/d up 50% or 25.9 MMcfe/d from Q3. On a net equivalent basis our Gulf Coast production averaged 116.2 MMcfe/d during Q4, up 49% from Q3 and represented about 25% of our total company production during the quarter. So you can really see the impact of our south Texas success with the wells we had online by the end of the year and our regional breakdown in the Gulf Coast.

On slide 23, we went ahead and broke down our production by region for oil and for gas. Tom hit on our equivalent breakdown. I will just talk here real quickly on oil and gas. You can see on the oil side that the Permian still makes up the lion’s share of our fourth quarter production representing 52% of our Q4 oil volumes followed by the Gulf Coast at 28% and mid-continent at 20%.

On the gas side the mid-continent dominates. That again is driven primarily by our Cana play. Mid-continent represented 54% of our fourth quarter total gas production followed by the Gulf Coast at 24% and the Permian at 22%. Cana continued to play an important role during Q4 on an equivalent basis adding 33 MMcfe/d to the bottom line on a [permanent] basis.

If we jump to slide 24 I will touch a little bit on our 2009 exit rate like I mentioned earlier. As you might be expecting our production growth occurred month to month during the quarter and resulted in a December exit rate of 485.7 MMcfe/d. Two drivers in this figure were our four new south Texas wells which comprised 94 MMcfe/d of this amount and Cana which comprised 37 MMcfe/d of that amount. On December 31 in Cana however our production was showing more growth. We are approximating Cana delivering 46 MMcfe/d on December 31 and over 50 MMcfe/d here in the first month of the year in January.

The good news about our exit rate is that we have made up the lost ground we lost in 2009 after significantly cutting back our operated rig count. In fact, adding back in 9.3 MMcfe/d of estimated December production that did not show up on our books would bring our December 2009 exit rate to 495 MMcfe/d which is 6 MMcfe/d higher than our December 2008 volume of 489 MMcfe/d. So with the cut back rig count and a budget 1/3 of what we had in 2008 we end the year in 2009 with a sale adjusted exit rate greater than that of 2008.

On slide 25, you will see a tabulation showing our production guidance for the year. I will touch on a few things with regard to this. I am guessing our revised production today may have been a surprise to some of you. With our increase in activity and continued success in both South Texas and Cana we anticipated and are seeing positive production growth for 2010. The acceleration in the completion of two of our wells in the Beaumont area; that being the Amazon Queen and the Jefferson Airplane 1, and our pickup of simulation completion activity in Cana, those two have helped really drive our revision to our guidance here for Q1.

We have upped it to 560-575 MMcfe/d. That is a projected 20-23% increase from Q4 2009 and likely a new record for the company. Now you might ask what happened in a matter of 10 days. Paul in the hall told me well maybe it was just a good couple of weeks. But it maybe was a combination of that but a couple of things happened over the last 9 days. First, we closed the books in January and we had a real good take of what February looked like. The biggest impact was our Jefferson Airplane 1 well that after revising our drawing plans on that well we moved the projected start date up.

We got her online earlier this week. We originally forecasted that well to come on in late March and April. Now at 26 MMcfe/d and 1,300 barrels of condensate a day you can see that can have a positive impact on our core. Our other Jefferson Airplane wells are in a competitive reservoir. We are now at three wells producing from that feature. We are maximizing production where we can.

So south Texas represents a good reason for it, but in addition to that in Cana a simulation completion program has resulted in three very nice wells we haven’t touched on in the slides for Q4 that are producing upwards of about 8 MMcfe/d. As such, with the acceleration in Cana and the better well performance that we appear to be seeing at least on these three wells we have taken a little bit of risk out of our Cana wedge and front-end loaded the production. So as you can tell you can see it bump into Q1.

As you might gather from our revision to Q1 guidance, the timing and results of the south Texas wells can significant influence our production. Our current modeling for the full-year anticipates production declines of our existing wells while trying to best estimate the success and timing of our new completions. With the bump in Q1 we are also increasing our full-year guidance to 540-570 MMcfe/d and that would reflect the 17-23 [inaudible] increase over 2009 and again likely a new record for the company.

As most all of you know, Q1 is a tough quarter to try and project full-year guidance. As we move further into the year we will continue to refine our estimates for new well production declines and the production adds from our new wells. The projected timing and success of new wells will play a key role in our full-year guidance especially when accounting for some of these high rate south Texas producers like we have been so fortunate to hit.

From a product mix standpoint for 2010 with the help of increased Permian activity and continued increasing associated Cana oil and NGL production our 2010 product mix is projected to skew a little more slightly towards oil with a projected range being 31-33% on an equivalent basis, up slightly from our Q4 average of 29%.

I will jump to slide 26 and kind of shift gears to our production operations group. As we mentioned in previous calls, 2009 was a year of focus for us on our base properties. Our production group did an excellent job tending to just that; optimizing production for exploitation activities while significantly cutting LOE. In addition something I am very proud of from a safety standpoint we finished the year with no lost time or OSHA reportable accidents in the field and that is a feat that all of us are proud of.

Over the course of the year the group deployed $58 million of capital, performing over 375 projects the majority of which being lift related projects directed towards optimizing gas and oil production primarily in the Permian and mid-continent areas. In addition, working from a high graded inventory we performed a number of recompletion projects, again mostly in the Permian and mid-continent.

Our look back economics indicate we spent our capital wisely. We met our expectations for production gains and all the while working with a significantly reduced budget. We spent $134 million in 2008 on exploitation activities as compared to the $58 million we spent in 2009.

By far the biggest impact we had on our base properties was our reduction in LOE. Reductions in well servicing, saltwater disposal, power and fuel, maintenance and compression we reduced our production cost on an absolute basis 18% from $55 million a quarter in 2008 to $45 million a quarter in 2009. These reductions carried over to our lifting costs with our 2009 average lifting cost of $1.05 down 15% from $1.23 average in 2008.

On slide 27 you can see an illustration that shows our lifting cost reduction by quarter. It happened slowly but over the course of the year these reductions started to hit the books. We dropped our lifting costs in Q1 $1.15 per MCFE down to $0.91 here in the fourth quarter of 2009 giving us an average of $1.05 for the year and we are projecting for guidance for 2010 a range of $0.90 to $1.10 and a true anticipated very good chance of falling in the low end of that range.

Slipping over to slide 28, looking forward into 2010 in our production group really no change from 2009. Continued focus on optimizing production, reducing LOE on our base properties, all in an effort to maximize our cash flow for reinvestment. For our year-end planning process we assembled a high graded inventory of exploitation projects and anticipate after reviewing it a budget very similar to that of 2009 in that $50-75 million range. We have a deep inventory of projects. Over 450 projects have been identified for 2010. Most of these again are lift recompletion and in-field drilling projects in the Permian and in the mid-continent.

Finally before turning the call over to Paul just a few comments on our overall perception of the service costs. There is no slide for this in the presentation. During Q4 we saw drilling and completion costs appear to bottom out. In general we are about flat from a cost perspective from Q3 to Q4 but we are starting to see some upward pressure in some service costs. Day rates are staying somewhat in check but we are seeing that market tighten especially when it comes to rig crew availability. Although [frag] costs have remained somewhat stable in our core areas like Cana, stimulation costs from more remote or less active areas are feeling some upward pressure.

We have also seen total stimulation costs go up when we have been implementing larger jobs. In general though the efficiencies we have been able to obtain and other cost reductions we have found or put into place with that we have managed to keep our total drilling and completion costs somewhat in check in our four areas of activity.

At Cana our generic well is running about $7.2-7.5 million. In the Permian our shallow Delaware basin horizontals are running $1.5-1.8 million. Our Bone Spring, New Mexico re-entry’s are running $2-2.4 million. Our Abo horizontals are running about $3.6 million. In the Gulf Coast our south Texas wells are AFE’ing for $6.3-7.6 million depending on depth. These dollar amounts are not too dissimilar to where saw costs in November and December.

As we look forward into 2010 in summary, we are set up pretty darned well. We had a good, strong finish to 2009. The first quarter of 2010 is on track to be a record quarter of production for us. We have a deep inventory of drilling and exploitation projects which should allow us to finish 2010 with a strong, double digit production growth. All the while entering the year with reduced production costs and apparent stable market for development costs. Our challenge here is to be to capitalize on all of the above.

With that I will turn it over to Paul.

Paul Korus

Thank you Joe. The first slide I am going to cover is slide 30. Not particularly my area of expertise as most of you know but by default I am going to recap the proved reserves for you.

During the year, net of 169 Bcfe of production and 25 Bcfe of sales we still managed to increase our proved reserves by 190 Bcfe or 15% to 1.5 Tcfe. If you back out the 25 Bcfe of sales that we had, we actually would have recorded a 17% increase. Of course the year-end reserves are calculated differently this year than they have been in prior years according to the new SEC and FASB rules where we use a 12-month rolling average price for both gas and oil as opposed to year-end prices.

Had we used the year-end prices and had comparability to the way reserves were calculated in prior years our oil reserves would have been up by another 2 million barrels and gas would have been about 70 Bcf higher and our reserves would have rounded to more something like 1.6 Bcfe. But no matter how you look at it a very good year. We added 312 Bcfe from our drilling program and also had 74 Bcfe of net positive revisions.

The revisions if you look at gas separately from oil you will see a very small net number. We had significant positive revisions from performance but largely offset by a price revision. The rolling average price we used for the end of last year was $3.56 versus $5.33 at the end of 2008. The higher oil price based on the 12-month rolling average of $57.58 contributed to us getting back some of the negative price related revisions we had in 2008. As I mentioned, the rolling average price was $57.58 versus the year-end 2008 price of $36.34. Of course both of those numbers are way below the $93 we used at the end of 2007. So we haven’t gotten all of those revisions back yet.

Production wise we have talked quite a bit about that already. Just to reiterate that we had a number of good things happen to us in December and January and in early February. Some may ask why do we make one estimate on February 8th and a fairly higher or significantly estimate two weeks later. Joe pretty much covered that already. We felt compelled to put estimates out at February 8th. In hindsight we should have waited. We had analyst estimates out there for 2010 production growth ranging from 0% to something in the teens. So we made our best estimate at the time. We got additional information and so we chose to update it because we think it is important.

You can tell from those estimates not all quarters may show sequential growth but frankly it may also be too early to tell that for sure. Our second half production is going to be highly dependent upon exploratory wells as opposed to developing wells that we will be drilling west of Beaumont. So as the year unfolds we will update our guidance and as certain new prospects are tested and key wells are drilled and evaluated we will continue to provide additional information.

Having said all of that, volatile prices could impact our level of activity. Uncertain weather, particularly down in the Gulf Coast with rain and mud can have operational implications and of course we always need to deal with operational risks. But we think we have accounted for those adequately in our guidance so far.

Quickly on our financials, a small decrease in production, 4-5% depending upon how you measure it. Obviously our oil/gas sales are only about half of what they were in 2008. So as hard as we work on production prices continue to swamp our operating results including revenues and cash flows. Basically the prices we received in 2009 were only about half of what we received in 2008 and you see that trickle through revenues and cash flow.

But we towed the line and actually under-spent our cash flow in 2009. Unfortunately with the write down in the first quarter reported an annual loss of about $312 million despite earning over $100 million in the fourth quarter. With proceeds from property sales and cash flow in excess of capital investment we reduced our bank debt by $195 million. We were at $220 million at the end of 2008 and we are only at $25 million at the end of 2009.

So our total debt was also then reduced by about $195 million and brought our debt to cap ratio down to a very comfortable 16%. Presented for you on the slide show are other credit statistics which clearly resemble those of investment grade companies.

With that I think it is probably time to turn it over to questions. You can see our capital structure hedges that we have. Operator we would be happy to take questions.

Question and Answer Session

Operator

(Operator Instructions) The first question comes from the line of Bill [Metner] – Macquarie Capital.

Bill [Metner] – Macquarie Capital

I just wanted to dive into the Cana NGL volume versus price breakdown a bit more. On slide 12 it discusses the current production breakdown of 65% gas, 35% oil. Does that apply to the 33 million per day average in the fourth quarter or the 46 million of the rate and a current rate of around 50-55?

Mark Burford

The 55/35 split is actually based on where our mix in current drilling has occurred to date. As Tom mentioned, as we get deeper into the play we could see a lower oil yield and NGL yield. As of currently as our composition of production and our type curve on a historical basis if you look at it if you were looking at tailgate gas with NGL the mix would be 65/35. But that can swing over time. What we are trying to depict is if you drill deeper to the west we will have drier gas but if you go to the east we actually could have more higher liquid yield. The representation of our current mix of production where it is at is the 65/35.

Mick Merelli

I want to make a point. This is principally important where we are comparing Cana wells to other plays that are 1,000 BTU. That is really what it is about. The economics that we have always used have always had the value of the NGLs in there. So it is kind of a cosmetic problem that we are facing here. We are trying to get comparable volumes of 1,000 BTU essentially is what it is so you can compare Cana to other plays volumetrically.

Mark Burford

That’s correct. That is what we are trying to make sure you understand. The liquid component plays a disproportionate part of the economics and volumetrics.

Joe Albi

There is a fine line between transparency and cosmetics here. We think this is more transparent for those that are modeling and have an interest in how this play could impact us.

Bill [Metner] – Macquarie Capital

Along those lines with the acceleration of the plan for the Cana at one point you had been talking about a year-end 2010 exit rate of around 100 million per day. How has that changed with your revised plan?

Mark Burford

At the 100 million exit rate we have accelerated some of the completions and we have gotten a better rate for the first quarter but overall 100 million exit rate is about what we anticipate. Something probably a little better than that hopefully.

Bill [Metner] – Macquarie Capital

The third and fourth quarter average realized prices were quite a bit better than Henry hub. Any sort of guidance to help us go forward on this sort of trade off between the price versus volume and how we are going to capture that and what the differentials or what the percentage realized prices might look like?

Paul Korus

Mark is probably more capable of answering but as we go forward and we have talked about now the impact here in Cana of reporting NGL as production volumes; the impact that is going to have of course is NGL are sold at a lower price per barrel than is oil. Oil differential might widen by $1 or $2. On the other hand, instead of recording those revenues in our gas price you will see our gas price differential narrow somewhat. But that is only in Cana. This whole NGL issue here to kind of frame it in terms others might understand it is kind of like an agent versus a principal.

In Cana we own those volumes through the end of the tailgate. The processor is only an agent. That is unlike what happens in the Gulf Coast in Beaumont where the processor actually takes possession at the well head and becomes the principle so we turn over title at the well head in which case that high BTU gas is going to continue or the NGL percent of proceeds that we get is going to continue to filter back in our gas price. So as our production mix is influenced by a lot of output in west of Beaumont you are still going to see us as an overall company have a very positive differential to benchmark prices.

Then of course we have to deal with the fact that mid-continent prices in February were actually higher than Gulf Coast index prices. So trying to predict basis differentials as the year unfolds, we will leave that up to you. All in all you are going to continue to see us as long as we have a lot of this Gulf Coast production we have a differential to Henry hub that is going to be $1 or more.

Bill [Metner] – Macquarie Capital

On some of the recent Gulf Coast completions I want to make sure I have this straight. The Amazon Queen well came on at 26 million on gas and 1,300 barrels per day condensate. When was that turned to sales?

Joe Albi

The Amazon Queen came on in January and it was producing at those rates when we had some constrained production and unit difficulties on the Two Sisters well. Both those wells are going into a decline and are sharing an allowable and right now the Amazon Queen is making 16 million a day and the Two Sisters is making 25.

Bill [Metner] – Macquarie Capital

Jefferson Airplane, has that well completed yet or do you expect to complete that soon?

Joe Albi

Jefferson Airplane 1 has come online here this past weekend and is currently making 26 MMcfe/d and 1,300 barrels of condensate.

Bill [Metner] – Macquarie Capital

The number 4 and the 9 Dragons that are currently drilling what is the timeline for completion of drilling and then actual completion of the wells and turning those to sales? Any sort of estimate for those and also at what rate or size do you expect those to come on at?

Tom Jorden

The Jefferson Airplane 4 spun over the weekend. So we expect 45 days more than likely to sales. That is a trouble free estimate and one of these days we are going to get one of those. The 9 Dragons and their immediate [liner] point so we probably have a few weeks left on that and that is a high risk exploratory test so we wouldn’t be projecting a volume or a rate on that. We are crossing our fingers and hoping for discovered.

Bill [Metner] – Macquarie Capital

The year-end exit rate of 94 MMcfe/d per day from that southeast program from what I am assuming is only four wells it looks like you are starting to see some declines at least in some of the initial wells that were drilled in the middle of the year. Is that fair?

Joe Albi

I would say that isn’t a fair statement. Some of the Jefferson Airplane wells are going to decline quicker. We anticipate by the second quarter of this year they will start declining but what happened there is we had these wells coming on at various points in time during the fourth quarter. In fact if you look at our jump from Q4 to Q1 of about 100 MMcfe/d worth of production about 70-80% of that we anticipate is going to be coming from South Texas and the Beaumont County wells.

Tom Jorden

There is also an overprint there. There were some competitive reservoirs. We have some choices of pipelines to sell into. We talked about this NGL and in some of those pipelines we get a much better contract and more valued liquid stream. Remember this is very wet gas so there is a tremendous uplift in liquids themselves. So where we have competitive reservoirs we have chosen to sell into two different lines. One has a more favorable marketing contract than the other but because it is a competitive reservoir and it is a race for reserves we have gone ahead and decided to take that hit if you will. Where we are not competitive we are just taking our allocated volume in our highest value line and [inaudible] the oil back. So those wells are not producing; the Amazon Queen and Two Sisters are not producing at their capable rates.

Paul Korus

I will add one thing. Four wells that average 40 million a day, that is 120. Remember we only have a 75% revenue interest out there on average so that is the 90 MMcfe/d.

Bill [Metner] – Macquarie Capital

I was coming up with 111 million net interest and comparing that to the 94 but it sounds like there are some other complications.

Paul Korus

And ups and downs.

Operator

The next question comes from the line of Nicholas Pope – Dahlman Rose.

Nicholas Pope – Dahlman Rose

With the Cana program for 2010, six operated rigs right now. How many non op rigs do you have running and where do you see that going?

Tom Jorden

I believe there are 12-14 rigs in total working in the play. We have interest in not quite every well drilled but pretty close to every well drilled. I will say that our six operated wells are generally fairly high interest, 65% or better and our non-operated wells are fairly low interest. That is just the way it is working. Typically our non-operated wells are 25% or less. So looking ahead we will participate in a lot of non-operated activity. It is very difficult to project that because where other operator’s rig schedules we don’t control, we currently have six operated rigs and some of those rigs are under long-term contract and those contracts expire this year.

Based on prevailing conditions at the time we will make a decision as to whether to keep those rigs deployed or to release them. Not to totally hem and haw on your question but right now we are in a debate as to whether keep our current rigs or drop or add. We are really based on results and project price. What I am really telling you is we have a lot of flexibility. Our midpoint case for 2010 is 6 rigs and that is our expectation but it could go up and it could go down.

Nicholas Pope – Dahlman Rose

Whenever I am looking at my estimates the whole range of your CapEx it looks to me like you are probably going to be generating free cash flow for the year. Where do you think your first options are for deployment if there is an excess? Where does it start to go first? Or would you all just plan to hold onto the cash for now?

Mick Merelli

Right now that is an interesting problem. I don’t know if it is going to happen or not. I think the most important thing is we have a deep inventory of projects. The way we run our economics on those projects are that we run it at the then existing strip and look at the rate of return. Then we run what we think is a low price scenario which is $3.50 gas corrected for whatever location and so forth and $45 flat oil. When we run that downside it is not for economics it is just to rank the inventory. A lot of our inventory we are going in right now gets over our hurdle record cost of capital by a few percentage points. That is again on that kind of a flat case held forever flat.

So what we are going to do is we are going to get as much of that drilling done as we can as long as that flat case looks like it makes sense. We have a lot to do. We won’t be…it is a case of capital. We can borrow money. We are low debt. We can keep moving ahead. We are going to try and get those projects done. The limitation there for us is going to be organizationally can we get that much done or not. It is a nice idea like running one year to the other and you have too much money this year and not enough the next. If we get a little ahead we have a big, big capital program. We don’t understand our ultimate spacing in Cana yet. That could change things a lot.

If we wind up with a little bit lower debt or something going across the year it won’t spoil. We have lots of opportunities. We are very opportunity rich right now. I am not trying to duck your question. I am saying as I see it we are not going to wind up with great piles of money left over and if we have a little bit one way or the other we will figure out how to take care of that. We have lots of opportunity.

Nicholas Pope – Dahlman Rose

To clarify, there is no Gulf Coast exploration success modeled into the production guidance, is that right?

Joe Albi

There is forecasted Gulf Coast contribution to our drilling wedge based on the known inventory we have through June on a risk basis.

Nicholas Pope – Dahlman Rose

On these Gulf Coast wells I know whenever we first started drilling them there was a lot of talk about kind of what they expected the size of some of them are and how compartmentalized some of the wells were. Where do we feel we are now in terms of just size of some of these Gulf Coast wells at this point and how compartmentalized they are?

Joe Albi

We have talked about our Two Sisters Amazon Queen being in the 30-40 Bcf range and that is certainly where we see it today. We are still collecting data and revising that estimate as we get more data. The Jefferson Airplane Complex is a little more vexing problem because we have our data but there are wells producing across the lease line. We think the overall feature will be a little bigger than that number but there is also probably going to be 10 wells in it. So it is a horse race. I think those wells will probably all be richly economic and it wouldn’t surprise me if that whole feature went north of 50 BCF by the time it is all said and done. I am speculating based on early sign data on depletion to our reservoirs.

I will tell you for our prospect set going forward we have a few prospects that are in the high teens to low 20 BCF and then we have some features we are currently evaluating we haven’t sized yet. We have a lot of opportunity. I think we will be busy. We currently have two rigs drilling that project and I think we will be busy out there for certainly most of 2010. We are talking about 15 gross wells and I think we will get that done.

Nicholas Pope – Dahlman Rose

In terms of production guidance again, I think you were saying that increase of 100 million you were saying 70 million from the Gulf Coast and 30 million from Cana. Does that imply you are all thinking mid-con and Permian are starting to grow slightly or where do you all see the more conventional assets growing from fourth quarter?

Joe Albi

That is a lot of questions. What I would say about the Permian is that just given the fact that we had limited to little activity last year and we saw somewhat of a production decline with current rig count as it sits now with the possibility of increasing two or some odd more rigs and improved economics and we will see if the Permian starts to grow again. In the mid-continent I think with Cana and deploying six rigs has all the chances in the world to continue growing too. Where you really stand with Q1 is South Texas. What you are seeing in that tail guidance as Paul touched on is it isn’t that everything else is shrinking. It is that we have built in some production declines, in particular that Jefferson Airplane feature where we know we are in competition and those are big wells. So that is forecasted in our guidance and that is why our full-year guidance is lower than our first quarter guidance.

Operator

The next question comes from the line of Eric Hagen - Lazard Capital.

Eric Hagen - Lazard Capital

A follow-up on what Nick asked about the Gulf Coast, of the 12-15 gross wells you are going to drill there this year are those all exploration or are some of those development wells, for example, to develop the Jefferson Airplane structure?

Tom Jorden

Certainly Jefferson Airplane I would say is development. Everything else we would term exploration. But it is important to understand we don’t really have a basket where we call exploration and a basked we call development. We just have a risk profile. So historically, and I think this also speaks to some of this guidance issue, historically we have run a 65% success ratio in these Abo geophysically driven plays. Even though we think we see the signature of gas or signature of high geo or oil, 1/3 of our wells historically have been dry holes.

In fact we have had really good years where we spent more on dry holes than we have on producers. So hence the risk. The thing that is kind of surprising us is we are having more success than we have modeled. On this project we have a good set of data logs. We really haven’t drilled a dry hole yet. We have one well that is temporarily abandoned but I think we will probably re-enter it and we believe we just flat out missed the target given the missed image. So yes, to answer your question directly the Jefferson Airplane 4 I would term a true development well. The Nine Dragons I would term an exploration well and everything else out there an exploration well.

Now, based on our success that 65% risking is probably a little harsh for some of those. Our Two Sisters well, pre-drill we carried that as 50% chance of success. Here we are 8-9 wells into the project without a dry hole. So as we go deeper into that trend and one of the things that the next frontier is looking at deeper objectives, we are going to be right back there to that 50% risk. Until we get there and calibrate it, we really have to get down there, sample those rocks and understand the geophysical response and be prudent.

Again, speaking to our guidance that explains the disconnect. Joe has done a really nice job historically of modeling and risking what the exploration group gives him. We have surprised ourselves with our success this year.

Eric Hagen - Lazard Capital

Can you tell us the chance of success you are using on Nine Dragons and your pre-drill estimate of the site structure and so on?

Tom Jorden

Nine Dragons is run at I believe about an 80% chance for success. In full disclosure we had an offset operator drill a down bit well to us, down dip from the Nine Dragons location. They discovered 40 feet of gas on water and we think we are going to be 200 feet high to that on the same feature. But I have to tell you we have been surprised many times in this trend. We are really hesitant to start a $7-8 million well in this environment and an 80% chance of success is near gut certainty from our standpoint. [Inaudible].

Eric Hagen - Lazard Capital

Moving over to the Permian and the Eddy County Bone Springs play are you still competitively leasing acreage there? Do you have the bulk of your acreage put together? If you could you give us an idea of what your gross net acreage is in that play?

Tom Jorden

I don’t have that acreage number in front of me but if you want to call later we can get that to you. We are still leasing. We picked up a nice position at the estate sale yesterday in that trend. If you look at the land map out there it is a quilt patchwork of held acreage. There is very, very little acreage to just lease. We are typically it is hand to hand combat. We are typically getting deals and farm out deals, taking term assignments, going to estate sales as soon as acreage expires. It is really as competitive and tough a land environment as anywhere we operate.

So it is not a situation where we are going to report to you that we have been actively leasing and we have put 100,000 contiguous acres together. It is going to be a deal where we may have 3,000 here; 2,000 there, 160 acres here. Through that we stitch together drilling opportunities. We anticipate having two rigs running in that play during much of the year and we are just pretty happy with the results we have seen.

Operator

The next question comes from the line of Andrew Coleman – UBS.

Andrew Coleman - UBS

I have a question on the PV10 numbers in the slide deck. It looks like just short of $2.3 billion in pre-tax PV10 which was just a hair above where it was last year? Am I adding right?

Paul Korus

You can actually look at our February 8th operations release. We have put those pre-tax PV10 numbers in there. 8.5 billion of pre-tax PV10 at the end of 2009. That is right.

Andrew Coleman - UBS

Did you also give what it would look like at current prices?

Joe Albi

If you would have looked at the same pricing methodology here in Q4 that we did in Q4 2008 NPV would bump up to about $3.9 billion.

Andrew Coleman - UBS

I am still struggling with this competitive reservoir jargon. How does that impact what you can book? I assume you are talking about competition effects from the transients. Are you going to be able to book or were you able to book a full [inaudible] for some of these South Texas wells?

Tom Jorden

We are booking it based on our flat out estimate of what we think we will capture. Then on consideration of what is under our leasehold. I think we are able to book the volumes that we think the wells will produce. But that said, it is a horse race. If we don’t produce them we are going to lose them across the lease line.

Andrew Coleman - UBS

Looking at my model, a little bit of free cash here for the year. Could you prioritize what you would be doing with that? I assume it is going to be picking up some more acreage, paying down debt and maybe increase the dividend. Is that fair?

Mick Merelli

In terms of where we commence drilling it is going to fall out pretty much if we find more ideas that are built around a higher risk, higher return projects they get funded because they are almost bullet proof from a commodity price standpoint. That is where the money will go first. Then we have to see what happens in Cana. That is a long-term project for us. We don’t understand the future in terms of spacing and how big a program that is going to have to be. So there is a lot of things up in the air.

Then the horizontal oil wells in the Permian they will attract a lot of capital. The answer is basically Cana is going to get a piece of it because it is a long-term project. The rest of it is going to compete on the basis of rate of return and how resistant it is to what the price volatility. Those projects are going to get funded. What we know about it right now is it is pretty hard to beat the Yegua-Cook Mountain economics from a rate of return from a financial standpoint. So it is going to get funded. I hope I haven’t garbled that too much.

Andrew Coleman - UBS

A modeling question for Paul is there no guidance on deferred taxes but should we think of that as trending up a decent amount here in 2010 in the higher CapEx?

Paul Korus

Well you make money and you pay taxes. So in the fourth quarter our provision was like $56 million of which $52 million was deferred. As we go forward into 2010 maybe 1/3 of it will be current and 2/3 deferred or 30/70 things like that. That has kind of been our historical average.

Operator

The next question comes from the line of Mitch Wurschmidt – Keybanc Capital Markets.

Mitch Wurschmidt – Keybanc Capital Markets

Could you give me a breakdown on your Permian basin drilling? Just in terms of the 60 net wells how that breaks down between the three different plays you are focusing on over there?

Mark Burford

I can follow-up with a formal breakdown on the drilling. Part of this piece will be Bone Spring. Next will be the Abo and third will be the shallower stuff that we will be doing. I can give you a bigger break down.

Tom Jorden

I don’t have that in front of me. Just off the top of my head which usually means I will correct that later, I think it will probably be around 40/40/20. I would guess. 40 Bone Spring, 40 Abo and 20 other.

Mitch Wurschmidt – Keybanc Capital Markets

You are going to be drilling a well and are doing some drilling in the Texas panhandle with one rig. Any update or comment on that?

Mark Burford

We are drilling right now a vertical well. It is really nothing that we can update our operations on. We have an active and ongoing project in the Texas panhandle. We drill some vertical wells. We drill some horizontal wells. We drill some geophysically based oil prospects. We have been in the Texas panhandle as an active driller for quite a few years. Our current activity is one rig. It is part of normal business.

Mitch Wurschmidt – Keybanc Capital Markets

Is that ground and water drilling over there?

Mark Burford

It is ground and water. Our current rig is operating in our Hobart Ranch field.

Mitch Wurschmidt – Keybanc Capital Markets

In terms of capitalized interest, what is a good level to be using for that for our models?

Paul Korus

I hope you understand the economies rules for capitalized interest. You basically take the value of your unproved properties and apply your average interest rate. It just so happens the value of our unproved properties is about equivalent to our total debt outstanding so we are capitalizing virtually all of our gross interest expense. Not necessarily by choice but by rule.

Operator

The next question comes from the line of Greg Brody - JP Morgan.

Greg Brody - JP Morgan

It is clear that you have this [unjoined program] and a lot you can do there. What I am curious about is what does the acquisition market look like right now? Are you seeing packages that make sense that you are looking at? Or are you kind of focused on your own drilling program?

Mick Merelli

We are going to focus on the drilling program as you know every so many years we find something we like. We will do a transaction. So the answer to your question is obviously we have the financial capability of doing some things and if we find something we really like and that probably means it drives our drilling program in the future, if we find something like that we would get out and get it done. But just to say now we are going to have a plan to spend so much money on acquisitions and so much money on drilling, our plan is the we are going to spend the money on drilling. In terms of whatever the market is out there, if we find some sort of an opportunity that we really like as we have in the past we would probably stretch to try and get it. So I don’t know. When we find it, we find it. So far we haven’t found anything like that recently.

Greg Brody - JP Morgan

Do you think you would be willing to step outside of your core drilling plays to do that?

Mick Merelli

Oh yeah. We are not strategic enough to figure all that out. If it is out of one of our plays and we think we understand it and we like it we would do it. But basically what I am saying is we knew what we liked about [inaudible]. We knew what we liked about Magnum Hunter. We knew what we liked about the Woodford acreage. We really like that stuff so we stepped up and did it. So right now there is no one out there that we feel we like that much. So we will concentrate on our drilling program and just keep moving it ahead. It is a good rate of return. If we see something else out there that represents a great opportunity for us we have done it in the past and we would do it again.

Operator

The next question comes from the line of Ray Deacon - Pritchard Capital.

Ray Deacon - Pritchard Capital

Tom I have a question if you could compare the Bone Springs to the other two plays in terms of economics. It looks like two of the wells were significantly higher 30 day rates than what you talked about last quarter and the well counts look fairly moderate compared to the Abo. Do you think you are getting better rate of returns and could you maybe quantify how many locations you could have I guess?

Tom Jorden

We really all I can say is we have drilled two wells and that is [much greater] than we modeled. We haven’t had a drilling trend to know if that is going to be an extrapolative answer or not. We are pleasantly surprised over a couple of our first [inaudible] wells. We did some re-entry’s and they came in better than modeled. Now the trend in aggregate is highly variable. It is not one big blanket deposit. It is sands that come and go. So whether those results will be transferrable to the trend in aggregate we just need to do more drilling.

Now we have lots of opportunity. I don’t have in front of me the exact well count or acres we control but we certainly have enough land to have a couple of rigs running through the end of the year and we are acquiring more land. I can get you the number but we have dozens of opportunities based on our existing leasehold. We just need to get a little more drilling behind us before we can know the results you are looking at can move our average. We haven’t moved our pre-drill estimate for new wells. So that tells you we are not ready to reset.

Ray Deacon - Pritchard Capital

Is takeaway in the Cana play anything…where do you see takeaway at the end of this year and maybe in 2011?

Joe Albi

You mean from a marketing perspective?

Ray Deacon - Pritchard Capital

Exactly. How much have you locked in?

Joe Albi

Well we have some dedicated commitments with one of the gathering and processing. They are in the process now of expanding their system. In general especially with [inaudible] plans to put in their own processing facility to the East of us that is going to put up capacity. So right now I think we are just finding ourselves at a little bit higher line pressure in certain situations but working hand in hand with [One Oak] to get our guess. So we haven’t run into any real obstacles there. I anticipate it is going to smooth itself our here come December or next year when [Devern] gets their facility in.

Ray Deacon - Pritchard Capital

So based on the results of the drilling this quarter what is your best guess as far as the size of the sweet spot for the field where you will get very economic wells?

Joe Albi

We just don’t know. That is not to be coy. We just don’t know.

Mick Merelli

The good news is we haven’t been able to define it.

Joe Albi

Some of our recent wells, I will say this, have extended the size of the sweet spot but we are just in, as I said earlier, we are in the throes of a science project and we just don’t know.

Ray Deacon - Pritchard Capital

I would think a couple of quarters before you know whether 80 acre spacing is appropriate or not?

Joe Albi

Our hope is certainly in the second half we will be able to discuss the results of that project.

Operator

There are no further questions.

Mark Burford

Thank you very much everyone for joining us. We went over a lot of detail. Thanks for your interest and we had a very good start to this year, a great finish to 2009 and we look forward to a good 2010 here.

So thanks everyone for their interest. If you have any other questions please don’t hesitate to give us a call.

Operator

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

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

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

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