PetroQuest Energy, Inc. Q2 2008 Earnings Call Transcript

Sep.21.08 | About: PetroQuest Energy (PQ)

PetroQuest Energy Inc. (NYSE:PQ)

Q2 2008 Earnings Call

August 6, 2008 9:30 am ET

Executives

Charles Goodson - Chairman, Chief Executive Officer and President

Todd Zehnder - Executive Vice President, Chief Financial Officer and Treasurer

Bond Clement - Chief Accounting Officer

Matt Quantz - Manager of Corporate Communications

Analysts

Ron Mills - Johnson Rice

David Kistler - Simmons & Company

Stephen Beck - Jefferies

Richard Tullis - Capital One Bank

Steve Berman - Pritchard Capital Partners

Rehan Rashid - Friedman Billings and Ramsey

Andrew Coleman - UBS

Paul Joe - Refac Organization

Operator

Welcome to the PetroQuest Energy second quarter 2008 conference call. (Operator Instructions) I would now like to turn the call over to Matt Quantz, Manager Corporate Communications.

Matt Quantz

We would like to welcome you to our second quarter conference call and webcast. Participating with me today on the call are Charles Goodson, Chairman, CEO and President; Todd Zehnder, CFO; and Bond Clement, Chief Accounting Officer.

As you’ve come to expect, we would like to make our Safe Harbor Statement under the Private Securities Litigation Reform Act of 1995. Statements made today regarding PetroQuest’s business which are not historical facts are forward-looking statements that involve risks and uncertainties. For a discussion of such risks and uncertainties, which could cause actual results to differ from those contained in forward-looking statements, see Risk Factors in the company’s Annual Report on Form 10-K for the year ended December 31, 2007.

With that Charles will get us started with an overview of the quarter.

Charles Goodson

Good morning. During the second quarter we produced 8.4 Bcfe or 92.5 million cubic feet of gas equivalent per day, which is up 7% in the first quarter of 2008. Approximately 42% of the production came from our long-life basin which is up from 38% realized in the first quarter of 2008 and 26% from the second quarter of 2007.

Oil and gas revenues were $91 million with product price utilizations averaging $112.48 for barrel of oil and $9.64 per million cubic feet of gas. Net income available to common shareholders was $22 million and net income per share was $0.41 for the quarter, which equals a net income per share for the first half of 2007.

On July 31, 2008 we completed the divestiture of a majority of our Oklahoma gathering systems in Mark West for gross proceeds of $41.3 million. We used the proceeds from this transaction to repay borrowings under our bank credit facility which provides additional liquidity to execute our long-life basin development.

Now let’s move on to operations our drilling program in the Woodford continued in the second quarter with the completion of five operating Woodford horizontal wells. These five wells have an average lateral length of approximately 3800 feet and achieved average maximum daily production rates of approximately 6.5 million cubic feet per day.

Currently each of the five wells or flowing at an average rate of approximately 4 million cubic feet per day. In addition we are currently completing our 20th and 22nd wells; our 20th well is the first in our East Lake McAllister area, a 10 miles step out planned as an Eastern extension of the Woodford trend. Our current plans are to add a fourth rig during the fourth quarter of 2008.

As of June 30, we have increased our acreage position and Woodford trends over 40,000 net acres. We continue to see attractive opportunities to increase our acreage position in this key area. Drilling continues in Fayetteville where the currently has five non-operated rigs.

We have participated in the drilling of 55 gross wells this year, which is on pace to exceed our original forecast, therefore we are increasing our 2008 gross Fayetteville well forecast to between 110 and 130 wells. Our net daily production rate in Fayetteville trended over 5 million cubic feet per day; bear in mind we had no production in the beginning of this year.

Moving on the East Texas, we recently completed our second horizontal well and the weekly prospect targeting oil and (inaudible) objective. The well is currently cleaning up, but has averaged 200 barrels of oil per day so far and recently we have seen rates as high 275 barrels of oil per day. We are currently drilling our third well in the weekly prospect and reach total debt in approximately two weeks.

We continue to see positive results in our Plamer prospects where we recently completed our fifth well. The well logged at approximately 23 feet of net value and will be completed in approximately one week. Current gross production from the four existing wells is approximately 5 million cubic feet per day.

Moving on to the Gulf Coast; we continue to be active in the Gulf Coast area where we are currently drilling our Sand Hills prospect. We estimate gross and rich reserve potential of 21 Bcfe. The well should reach total depth in approximately two weeks and we have an approximate 25% working interest in the well. We recently started our Bluffs prospect which is expected to reach total depth in the third quarter. We estimate gross and risk reserve potential base Bcfe; we have an approximately 45% working interest in the well.

Our Pelican point well is currently flowing at approximately 24 million cubic feet equivalent per day and after three months production. At currently production rates and current commodity prices a well should produce annual gross cash flow in excess of $100 million. We have an approximate 22% net revenue in this well and obviously we are very proud of it. At this time I will turn it over to Todd.

Todd Zehnder

Thanks Charlie. During the quarter, our LOE per Mcfe was $1.18, which was in the range of our second quarter guidance previously issued. Even though we are experiencing a slight increase in material and labor cost we are reconfirming our previously announced full year 2008 LOE guidance of $1.10 to $1.20.

DD&A on oil and gas property during the second quarter was $3.67 per Mcfe which is down from the comparable period of 2007 and down from the first quarter of 2008. These declines are a result of continued positive drilling results and reserve bookings, primarily in our long-life areas.

During the second quarter our G&A expenses were $7.1 million which was above our second quarter guidance. The increase is primarily due to higher employee related costs associated with increased staffing and the payment of employee taxes on the vesting of some restricted stock in May of 2008.

During the quarter we spent approximately $94 million in capital expenditures. The breakout of this CapEx is about $68 million of direct drilling CapEx, $3 million of property and lease acquisition cost and $6 million of capitalized overhead and interest. 77% of this CapEx in the second quarter was spent in our long-life areas.

With the expectation of adding a fourth rig in the Woodford, an increase in Fayetteville drilling activity and a general increase in cost, we are raising our drilling capital guidance for 2008 to $270 million to $ 300 million. We currently have a borrowing base of $95 million of which we had $52.5 million outstanding as of June 30. We also had approximately $9 million of cash as of June 30.

After application of the proceeds from the gathering system sale that Charlie discussed earlier we currently have about $22 million of borrowing to outstanding as we sit here today. The gathering system deal was positive from a cash flow infusion, as well as entering into a long-term relationship with a well established gatherer in the Woodford trend. We expect the partnership with Mark West will reduce our overall line pressures in the field which should have a positive impact on our production volumes.

Our current plans call for producing between 96 and 102 million cubic feet equivalent per day net to company for the third quarter of 2008. We are reconfirming our previously announced full year production guidance of 94 to 100 million cubic feet per day.

Currently we have approximately 8.8 Bcfe of our remaining 2008 production hedge at an average floor of $9.01 and an average ceiling of $11.71. We currently have about 8.2 Bs of our 2009 production hedge at a floor price of 10.27 per Mcfe and a ceiling price of about 14.56 per Mcfe. We will continue to look for optimistic times to add to this hedging portfolio. With that I will turn it back over to Charlie to wrap up.

Charles Goodson

During the second quarter we once again achieved company records in production, net income and cash flow. We also reached a significant company milestone, achieving net production exceeding 100 million cubic feet of gas equivalent per day.

We continue to maintain a healthy balance of Gulf Coast and long-life projects that will allow us to continue to set company records and meet internal goals. After calculating our actual reserve growth rate for the first six months of 2008, we are even more confident in our ability to growth reserves; therefore, we are increasing our previously estimated 2008 baseline reserve growth rate from 30% to 40%.

We plan to achieve this reserve growth through our drilling activity alone, while maintaining a very healthy mix of proved developed reserves making up 68%. That mix ensures that cash flow growth will continue along side the aforementioned reserve growth.

As we stand here today, approximately 71% of our reserves reside in three long-life basins; we entered beginning in 2003 and by year end that mix will be over 75%. Each of our long-life basins are exhibiting excellent growth profiles in both reserves and production.

To end, as CEO I convey my thanks to all the employees, consultants’ advisors that worked tirelessly to transform this company into one of the healthiest, most well balanced companies in the E&P sector today. With that, I think we will open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Ron Mills with Johnson Rice.

Ron Mills – Johnson Rice

A couple of questions for you; just on the Woodford you have three rigs going there now. The fourth rig is that going to be designed to focus on the Eastern portion or where do you expect your rig activity to be focused once you get the four rigs?

Charles Goodson

I think initially you will see it go to the east, Ron. We do have 3D data that is now covering the Western side, so some wells are being pulled there, so I think activity over all on the Western side of our acreage should generally increase, but we have locations and the seismic work more on the east just due to the data, so.

Todd Zehnder

And also Ron, because of our successful activity on the Western side of our acreage block, west of the lake, we are seeing more outside operated wells and so the rig moving over to the east side will probably spur additional activity over there.

Ron Mills – Johnson Rice

And you said as I recall, the first well to the east has finished drilling and now what’s the expectation of timing from a completion of that well?

Charles Goodson

I would say probably within the next two weeks we ought to be completed with frac job and then just a matter of time before we get a flow test on it.

Todd Zehnder

And we’ve also got a second well drilled already and we’ll be completing that behind the first well.

Ron Mills – Johnson Rice

And that second one is also to the east?

Charles Goodson

Yes, and we have commenced the drilling of our third well on that side of ’08.

Ron Mills – Johnson Rice

Is there any other activity on that side of the lake besides yourselves at this point?

Charles Goodson

Yes there is.

Ron Mills – Johnson Rice

Okay. Is the relation to the British Petroleum Chesapeake transaction, obviously a very attractive purchase price, can you discuss little bit where some that acreages relative to yours and the relative activity level/data points that you’ve gained versus what they may have had to try to put it into comparison for us?

Charles Goodson

I think that the vast majority of that acreage is to the West and Southwest of our acreage. We do have acreage that’s interspersed among the area that Chesapeake sold to BP and I think they retained acreage over the area that we have our dominant position in within the area.

The thing I would like to add is this was not something concocted in a back room in London. We know the people that run the Oklahoma division or mid continent division of BP very well and they very patiently set back looking for a way to enter this trend and we feel like we’ll be very active there and they target it as a place to I think double there Oklahoma production from what I’ve heard. So we’re very excited about them being involved.

Ron Mills – Johnson Rice

Should their involvement help ease the perception of infrastructure issues and gathering system issues and what not because once you have a major in there, don’t some of the infrastructure issues become taken care of?

Charles Goodson

They can definitely help that, Ron, and before they got in with their, I guess what you would call their own organic leasing or with this purchase, they had already spearhead some line activity, because as a producer and at that time a gathering system owner, we had some discussion with their marketing arm or their infrastructure arm about some activity that they had plan to go south.

So I think is very positive to have a large company like that come in and time will tell as far as the infrastructure activity. The one thing about infrastructure out there is, you have a main transmission line going south or that’s planned to go south already with existing lines on the east so, we haven’t had any major infrastructure at this point.

Ron Mills - Johnson Rice

And at lastly the gathering sale, did you all kind of deal with MarkWest where you protected yourself from a capacity issue?

Charles Goodson

To a certain extent we have, but the MarkWest doesn’t necessarily have the lines that go all the way to east, so you still have to worry about transmission line issues and we’d already put some deals in place, where we have some foreign transportation cut going over to these. This really helps us more from an infield gathering; quite honestly we had outgrown ourselves and the results that art and history have been posting have been exceeding our expectation. We felt like, we needed a full-time gather in there to run this thing.

Operator

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

David Kistler - Simmons & Company

I wanted to ask you guys about the weekly field and looking at the rates that came out of the second well. My understanding is its still cleaning up, so those rates could go higher. So can you talk to us a little bit about kind of your expectations for wells going forward realizing the first well was a home run and maybe give us a little color on what cost you expect for each one of those wells?

Charles Goodson

Well on the rate side, when we originally got in this area kind of our model was wells that would produce 200 barrels to 250 barrels a day, so this ones falling right in our original expectations. Clearly, the first well produced at a much higher rate than that and we seem to like that.

Eventually you’re going to see wells that land on the upper side and we’re just on our third well and this is a horizontal trend and probably all of us are board for a while as far as rates, but we’re still with our acre position which continues to grow in the area very exciting. Cost structure, I’ll let Todd jump into that.

Todd Zehnder

Yes, I think in general Dave, with the increase in cost we originally think and these things will cost $4 million to $5 million to drill horizontally; it’s probably going to come under a little pressure as far as the total well cost and one thing to add is these natural fractures, it just depends on what has the highest pressure.

Right now, we have a natural pressure that has a little bit more water than oil. When we were drilling this well, we saw plenty of oil coming in, so the natural fracture that’s making a little bit more water, the fleets we do expect to see a continued increase in the oil rate. So, like Charlie said, it came on kind of where tight curve was built; increase in oil and the prices that we’re realizing it’s still a very, very economical play.

Charles Goodson

At $100 a barrel plus which I think we can say right now is still safe. Your cash flow is something like that; even disposing off some water is very economic.

David Kistler - Simmons & Company

With respect to your announcement about the reserve increases Charlie, could you talk a bit about the areas that are driving that most; I’m guessing Woodford, Fayetteville, but are there incremental Gulf of Mexico wells etc?

Charles Goodson

Yes, I mean clearly driver is the Woodford and the Fayetteville and because as we’ve managed our spending in the Gulf Coast to grow that at a reasonable rate, but still transferring a lot of the capital out of the Gulf Coast into East Texas, but primarily into the Woodford and as the Fayetteville, the activity level there has increased faster than we originally anticipated because of the success, we’re clearly deferring capital from the Gulf Coast into that area. So there’s those two primary areas, but certainly we expect growth out of our guys and girls that are running the Gulf Coast and East Texas.

David Kistler - Simmons & Company

Then kind of jumping over to East Texas for a second, obviously you have some acreage through JV with Chevron that’s exposed to the Haynesville, but I understand you’re kind of negotiating with them to figure out what each others percentages would look like. Can you give us any color around that or is there any timeline for when you think you’ll come to an agreement there?

Charles Goodson

We’re exchanging ideas. I mean we clearly with surface rights and the Travis Peak, Cotton Valley and clearly the vast majority of the shale rights in there are without question, on an overall vertical basis. We’re changing ideas and I can add to it that we’re seeing some pretty interesting things being developed from the west side, which are clearly in those upper shale rights and so the bottom line is we’re all watching what’s going on around us and we do have a 100% acreage in it and we do have all rights. So, it’s more than a rounding error. We’re excited about what’s going on.

Operator

Your next question comes from Subash Chandra with Jefferies.

Stephen Beck - Jefferies

This is Stephen Beck for Subash. Just have a couple of question. I guess first, can you tell us what the current volume are in the Woodford?

Charles Goodson

They’re probably up in the mid 30s right now, Stephen. I don’t have an exact rate on me.

Stephen Beck - Jefferies

Okay. Can you tell me how many wells sort have been completed now in the Woodford?

Charles Goodson

In what period?

Stephen Beck - Jefferies

In total.

Charles Goodson

Since we started the program?

Stephen Beck - Jefferies

Yes.

Charles Goodson

I guess we completed 20 wells now.

Operator

Your next question comes from Richard Tullis - Capital One Bank.

Richard Tullis - Capital One Bank

What was the EBITDA for the first half of the year generated from the midstream assets?

Todd Zehnder

Probably a little bit under $2 million, Richard. Maybe somewhere between $1.5 million to $2 million.

Richard Tullis - Capital One Bank

What are your estimated EURs; I know it’s still early on those weekly wells.

Todd Zehnder

No, we got in, we’re running these things on about 300,000 barrels of oil. I don’t think anything has exchanged to that. We just got two data point at this point. So I think that’s probably still fair.

Richard Tullis - Capital One Bank

Jumping back over to the Haynesville question that came up just a few minutes ago; how deep do you have clear rights that you’re certain of?

Charles Goodson

Through all the (Inaudible) sections and really it all depends Richard, on what you interpret. We know exactly where our rights exist, but without a lot of control in the area, you’re going to have to see some penetration to see exactly if you don’t enough with rise in the deeper part, what was the effect is.

Richard Tullis - Capital One Bank

Okay; is there any cutoff as far as footage or is it just?

Charles Goodson

No, it’s not depth-driven.

Operator

Your next question comes from comes from Steve Berman with Pritchard Capital Partners.

Steve Berman - Pritchard Capital Partners

Can you guys talk a little bit about drilling cost and completion cost trends in the Woodford as you’ve successfully moved up the curve, what you’re seeing now in your most recent wells?

Charles Goodson

I think in general, Steve, we have driven the well cost down to where we’re getting to pretty comfortable to say we’re going to be drilling between $4 million and $4.5 million. Just recently we’ve done a couple of things different. We have, one started drilling longer laterals at all times assuming that geology let us. So when we drill longer laterals, we will put more frac stages in and those two events probably get you up about $0.5 million to may be $750,000; just due to increased distance, increased EURs will come with that.

On top of that, the cost pressure, the main two items that we’re seeing right now are in tubulars; basically the casing program that we we’re running as well as diesel cost and those two items alone probably are getting close to $0.5 million higher. So, I think in general right now as we sit here we would say that costs are probably going to be between $5 million and $5.5 million and up of that we would expect to see increased productivity due to like I said about $0.5 million to $0.75 of $1 million.

Todd Zehnder

And one thing I want to add to that is we have our longest lateral plan right now of 7200 feet and at some point in time you look at EUR per horizontal foot drilled and you start eliminating the surface, I mean the vertical part of that hole and so those wells could clearly be looked at as one and a half or two horizontals, from the original expectation of, 1500 and 2500 feet. So, we are making a lot of progress as far as costs; we are eliminating some of the vertical section that’s required to develop this area with our three rigs.

Steve Berman - Pritchard Capital Partners

And in terms of the 40,000 or so net acres, location wise where you’re drilling, are there areas you haven’t even touched the surface yet. I mean how are you kind of spreading out your drilling plans in terms of exploring what you have?

Charles Goodson

We have probably bracketed somewhere around 75% of our acreage with wells that have high rates. We’ve successfully developed those areas, some of the five wells that we announced earlier this quarter, we are now on our third well on the East of Lake McAllister which would probably take another 15% of our acreage and then the remainder of it is continued east of there as we continue to extend the trend onto the east and so I’d say that sometime, probably about either at the end of this year or early, certainly early next year waiting on 3Ds will have all of our acreage bracketed by wells.

Operator

Your next question comes from the line of Mike Jones with Friedman Billings and Ramsey.

Rehan Rashid - Friedman Billings and Ramsey

This is Rehan, how are you? Two quick question from a broader maybe thinking about ’09 thought process; what will it take to take up the rig count from four to call it five, six, seven and also just wanted to conform that did you say a 7200 foot lateral or a 4200 foot lateral?

Charles Goodson

7200 foot.

Rehan Rashid - Friedman Billings and Ramsey

This is for the Woodford?

Charles Goodson

That’s correct. We’ve had such excess already, I mean for me to sit there and say effortlessly drill a 4000 foot lateral, our engineers would probably want to hang me, but we have basically in my mind done it relatively speaking effortlessly and they are very, very comfortable that we can drill and so that basically takes you across an entire section or across the entire unit.

Rehan Rashid - Friedman Billings and Ramsey

And there weren’t many associated lease line issues kind of thing, you will find there?

Charles Goodson

It was pooled a little bit differently. Rehan we had pooled it north/south instead of just a pure 640 acre square. So, that’s going to be the first one we’re trying like that and stay tuned for results on that.

Todd Zehnder

As far as cost, I mean we are driving cost down up there and we’ve seen a little pressure with casing and diesel cost and things like that, but when you start drilling these extended laterals and you eliminate possibly a second vertical part of that well, going to four and then onto five, we want to continue moving up that rig count and certainly as we’ve developed this Eastern areas it’s a very concentrated set of acreage that is going to require probably maybe two or even three rigs to develop that area alone.

Charles Goodson

And I think at that point Rehan it just becomes getting the data, getting the rigs, getting the people to run it and it’s an allocation of capital and you clearly see the majority of our capital now is going to the Woodford. The Gulf Coast has done really good at funding that and it just becomes what we do everyday around here, which is grow the business and it’s an allocation of capital and I would continue to expect more rigs operating in the Woodford as it becomes our core asset.

Rehan Rashid - Friedman Billings and Ramsey

Going back to the 7200 foot lateral from a number of frac stages standpoint, it’s still going to be a 500 ‘ish kind of number or so this is going to be 10, 50 kind of stage frac or how about …?

Charles Goodson

It’s probably up there around a 20 stage frac is what we’re thinking. We’ll look to at the well bore, we’ll monitor it and we’ve actually started down spacing from that 500 foot stages to where we feel like breaking up more rock in closer proximity to each others frac, it’s probably the most economical thing to do. So I would say right now, I think you could probably expect about 20 stages.

Rehan Rashid - Friedman Billings and Ramsey

And just a rough cost for this kind of a well and timing; how long will it take?

Charles Goodson

About $7 million roughly, is what we’re thinking, because the drilling date to get the extended lateral is not too significant. Once you’re in Woodford, you can drill it pretty quickly. The incremental cost is really just to put the additional stages on there and timing shouldn’t be much more than one you have seen the exact increase, but I would say probably 14 to 20 days more just due to extended drilling time and putting more even more stages of fracs in there.

Rehan Rashid - Friedman Billings and Ramsey

So, from about a 35 to 40 day well, does it become a 60-day well or does it take less time to drill the one?

Charles Goodson

That’s probably, that’s fair. We’ve been drilling these things for say about drilling in 30-days, you probably add on about 10 to 15 days there at the most, 10 days and then the completion time, add a few days. I will get you a better number than that Rehan, but...

Rehan Rashid - Friedman Billings and Ramsey

That sounds like a very low number. So, I’m just kind of wondering I mean cost per stage of frac and maybe we can talk offline on this.

Todd Zehnder

Yes, we can talk offline, but you got to remember the incremental stages of frac are not as an expensive. You bring down your total job cost when you put these incremental stages on.

Operator

You next question comes from the line of Andrew Coleman with UBS

Andrew Coleman - UBS

A quick question; I missed parts of the call here so if you’ve already stated let me know I’ll go through the transcript, but did you guys comment at all on what the Woodford leasing picture looks like with some of the recent M&A activity in the region?

Charles Goodson

We are continuing to pick up acreage.

Todd Zehnder

They are obviously on a smaller scale than the last transaction you saw by BP, but we’ve been very successful; we were over 40,000 and we’ve grown our acreage over 50% this year alone and it continues to go up.

Andrew Coleman - UBS

Okay and then have you guys thought about swapping out some your Fayetteville acreage to gain leverage, maybe to add some Haynesville potential or to gain more Woodford? Would that be of a benefit to you?

Charles Goodson

No, we like everything we’re seeing out of Fayetteville right now Andrew; there is no reason for us to be divesting of that core asset that we see growing. We’ll monetize asset by the gathering systems or late life Gulf of Mexico or something like that, but our growing asset where we’re zero production and up to over $5 million net in six months, we see no reason to even consider monetizing that.

Andrew Coleman - UBS

Okay and then talking about those gathering assets one more time, will you see much of an LOE change by having divested those or did you get a pretty rock solid agreement that keep access to those pipes at the current cost?

Todd Zehnder

We’ve got a great agreement within. You’ll see no increase in LOE, the way it’s been shown in our books to begin with as we’ve been charging ourselves if you will and you’ve been seeing gathering system revenue. So obviously the gathering system revenue up in other income and the gas gathering cost will drop dramatically, but it’s still clean as far as the MP assets in our income statement.

Andrew Coleman - UBS

And last one here was you had mentioned that 71% of onshore reserves here at mid year, what was the production from the onshore assets?

Todd Zehnder

For the second quarter it was 42%.

Operator

Your final question comes from the line of Paul Joe with Refac Organization.

Paul Joe - Refac Organization

I just want to follow-up on that last question, for the Gulf of Mexico, Gulf Coast and East Texas, for your 2008 what percentage would that be of your production?

Todd Zehnder

For the Gulf Coast we’re expecting about 55% when you add the Gulf of Mexico and onshore Louisiana and that’s down from about 75% last year. So, the trend continues to get out of the Gulf Coast or lower production as a percentage. Its production is actually growing a little bit, but it just shows the growth of the overall company. East Texas as we sit here, about 14%, 15% for our daily production for the year is expected to come from there.

Paul Joe - Refac Organization

And that was that in 2007?

Todd Zehnder

Well up 13%.

Paul Joe - Refac Organization

And then just a final question of tubulars or CTG; how are you set for that. The market it’s clearly getting tighter on that?

Charles Goodson

Yes, it’s most definitely getting tighter. We have gone ahead and stepped out and got the Woodford chasing program. We have enough pipe and inventory now to make it through the second quarter of 2009 as we sit here today, we had prepaid a significant amount casing.

From the Gulf Coast standpoint, we have several of our wells that were drilled here in the back half of the year that are already in stock ready to go and we’ll continue to monitor that; those obviously at differentiating programs in most of these horizontal resource trends. Our major one, which is the Woodford, we have about nine months of inventory or so.

Paul Joe - Refac Organization

And is that at a, you’ve prepaid it or you’ve locked in your price or you guaranteed availability?

Charles Goodson

We have the pipe sitting in a yard, we prepaid it.

Paul Joe - Refac Organization

So, that’s the large increase in your prepaid drilling cost?

Charles Goodson

That has a significant portion of it, yes.

Operator

There are no further questions at this time. I would turn the call back to Todd Zehnder for any closing remarks.

Todd Zehnder

Okay, well we appreciate everybody tuning in and we look forward to seeing you guys on the road as we continue to get out.

Charles Goodson

Thank you.

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