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Executives

S. P. Johnson, IV – President, Chief Executive Officer & Director

Paul F. Boling – Chief Financial Officer, Vice President, Treasurer & Secretary

Richard Hunter – Vice President of Investor Relations

[John Bradley Fisher – Chief Operating Officer & Vice President]

Analysts

David Heikkinen – Tudor Pickering & Co. Securities

Leo Mariani – RBC Capital Markets

Brian Corales – SMH Capital

Ronald Mills – Johnson Rice & Company

David Tameron – Wachovia Capital Markets, LLC.

Raymond Deacon – Pritchard Capital Partners, LLC

Joseph Allman – J. P. Morgan

[James Homes – Miller Payback]

Jeffrey Hayden – Rodman & Renshaw, LLC

Carrizo Oil & Gas, Inc. (CRZO) Q1 2009 Earnings Call May 11, 2009 11:00 AM ET

Welcome to the first quarter 2009 financial results for Carrizo Oil & Gas Incorporated conference call. The speakers today are Chip Johnson, President and Chief Executive Officer and Paul Boling, Vice President and Chief Financial Officer of Carrizo Oil & Gas. Also on the call today is Richard Hunter, Vice President of Investor Relations. The conference will now be turned over to Chip Johnson, President and Chief Executive Officer.

S. P. Johnson, IV

Thank you all for calling in for the first quarter earnings release. As we’ve done in the past, Paul Boling will start with the financials then, I’ll go over an operations update and then we’ll open it up to questions. With that Paul, if you want to get started.

Paul F. Boling

Before the benefit of settled hedges, oil and gas revenues for the three months ended March 31, 2009 were $30.7 million compared to $53.6 million during the same quarter ended March 31, 2008. Including the benefited of settled hedges comprised of $19.8 million for gas and $2.8 million for oil, commodity prices decreased as natural gas prices were $6.11 per MCF as compared to $8.05 per MCF in the first quarter 2008.

Oil prices increased to $102.42 per barrel from $88.63 per barrel in the first quarter 2008. Settled hedges for the quarter also included the benefit of a $2.2 million oil monetized hedge and a $3.3 million net gas settled hedge largely attributable to the value of the April hedge positions which were confirmed and accrued in March. Our record breaking first quarter 2009 production level was 8.26 BCFE up 30% compared to the 6.33 BCFE produced during the first quarter of 2008. The increase was primarily due to the continued addition of new production from the Barnett Shale development.

During the first quarter of 2009, EBITDA was $41 million or $1.33 or $1.32 per basic and diluted share respectively as compared to $38.4 million or $1.32 and $1.30 per basic and diluted share respectively during the first quarter of 2008. Oil & gas operating expenses excluding production tax and transportation expense in the first quarter 2009 was $6.1 million or $1.2 million higher than the first quarter of 2008 largely due to increased production.

Our guidance for lease operating expense in the second quarter of 2009 is $0.85 to $0.88 per [inaudible]. Transportation expense was $3.3 million during the three months ended March 31, 2009 as compared to $2.3 million for the first quarter of 2008. Production taxes were a net benefit of $1.3 million comprised of $600,000 in production tax expense on the production for the quarter and offset by a $1.9 million severance tax refund on certain wells that qualified for tied gas sands tax credit for prior production periods.

Depreciation, depletion and amortization expense was $16.5 million or $2.4 million higher than the first quarter of ’08 primarily due to the increase in production volumes partially offset by lower depletion rate primarily attributable to the fourth quarter 2008 ceiling test impairment. Our guidance for the DD&A rate in the second quarter of 2009 will be $1.50 to $1.55 per MCFE.

General and administrative expense decreased to $4.5 million compared to $5.1 million during the same quarter of 2008. The decrease in G&A was primarily due to the absence of an annual cash bonus. General guidance for G&A expense in the second quarter 2009 is $3.3 to $3.5 million. Non-cash stock option compensation expense was $3.4 million compared to $1.5 million in the same period 2008. The increase was due primarily to a payment of non-executive discretionary 2008 bonuses in common stock in lieu of cash.

The significant decline in oil and gas prices indicated by average prices of $3.17 per M for gas and $51.76 per barrel for oil resulted in a non-cash ceiling test write down at the end of the first quarter of $252 million or $163.9 million after tax. The realized gain on derivatives was $22.6 million for the first quarter of ’09 due entirely to commodity derivatives as compared to a realize loss of $1.5 million for oil and gas derivatives and a $.2 million loss on interest rate swaps for the same quarter in 2008.

The non-cash unrealized gain on derivatives was $7.5 million in the first quarter of ’09 and was comprised entirely of commodity derivatives. The non-cash unrealized loss on derivatives for the first quarter of ’08 was $28.1 million comprised of a $25.9 million loss on commodity derivatives and $2.2 million loss on interest rate swaps. Interest expense and capitalized interest for the first quarter of ’09 was $9.1 million and $5 million credit respectively as compared to $6.5 million and a $3.7 million credit for the same periods of 2008.

The three months ended March 31, 2009 included approximately $3 million in non-cash interest expense associated with a debt discount on the company’s senior convertible notes as prescribed by APB14-1. Excluding a net $161.4 million non-cash after tax charge comprised of a non-cash impairment of oil and gas properties $163.9, a mark-to-market unrealized gain of $4.9 million on oil and gas derivatives, stock compensation expense of $2.2 million and a $.1 million bad debt expense, adjusted net income for the first quarter 2009 was $13.1 million or $0.43 and $0.42 per basic and diluted shares respectively as compared to the first quarter of 2008 of $13.9 or $0.48 and $0.47 per basic and diluted shares respectively.

We are encouraged by the company’s first quarter performance including the continued growth in our Barnett Shale play which continues to support our business model. In the current low commodity price environment we remain focused on preserving liquidity and funding our capital expenditures program using free cash flow.

S. P. Johnson, IV

Current production companywide is about 88 million cubic feet equivalent per day with 71 million per day in the Barnett Shale and about 17 million a day in the onshore Gulf Coast. Second quarter production should be between 84 and 87 million cubic feet a day as production keep declining as no new fracs are planned until June when we’ll frac about four wells. Those four wells should prop up third quarter production to average the same as the second quarter.

Sometime in the late third quarter we will begin fracing in anticipation of better commodity prices and our next borrowing base redetermination in November. We still think we can hit our year end goal of having a burn rate at the end of the year of 100 million cubic feet equivalent per day. We currently have three H&P flex rigs running in southeast Tarrant County, that includes one at UT Arlington and one in the town of Pantego where we just began drilling.

We’ve drilled 14.2 net wells since the beginning of the year with only 3.4 in the second quarter as we’ve got back on our drilling and drilled more wells where partners have working interest. We currently have 35 net wells drilled but not completed with a total of 82 million cubic feet equivalent a day waiting on completion.

In the Marcellus Shale we finished drilling our first operated vertical well, an 8,600 foot test in Centre County Pennsylvania. Logs and sidewall cores are being analyzed to design fracture stimulation for which we already have a permit. Drilling permitting is proceeding on five vertical wells to test our acreage in Northern West Virginia. Leasing is almost shut down except for Susquehanna County and a JV or possible farm out in West Virginia.

Marcellus well results by industry continue to improve and are clearly among the best of any shale plays. We currently control more than 200,000 net acres with our 50/50 private equity partner Avista Capital. Our goal is to finish 2009 using Avista’s capital for the vertical well drilling at which point we will move forward with each party paying 50%.

In the North Sea we anticipate that Premier Oil & Gas will buy Oilexco’s assets out of bankruptcy by the end of May. At that time development planning can resume and our change for an attractive sale of the assets will increase. We expect no significant development capital before the second half of ‘010 on this asset.

With that, we’ll open it up to questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from David Heikkinen – Tudor Pickering & Co. Securities.

David Heikkinen – Tudor Pickering & Co. Securities

I had a question on kind of the Marcellus, thinking about first the wells that you’re drilling in each area vertically and then the potential plans around what you mentioned in West Virginia either sell down or joint venture. I kind of just wanted to get an update on when you’re drilling verticals and when you drill the horizontals and then the sell down?

S. P. Johnson, IV

The first question, when we’ll start drilling verticals in West Virginia, hopefully that will be this summer. We have locations picked based on well control and 2D seismic and we should be able to get that started in the fall. Horizontal drilling everywhere is basically still dependent upon vertical well results. If there’s enough good control around us, say in Susquehanna county, we might be able to skip a step and go straight to horizontal drilling but we’d like to get 3D seismic before we do that. As far as the – it was not a sell down, we were trying to acquire some more acreage in West Virginia through a farm out or some kind of potential JV with the land owner.

Operator

Your next question comes from Leo Mariani – RBC Capital Markets.

Leo Mariani – RBC Capital Markets

A couple of questions here, on the Barnett obviously you’ve got a lot of wells in backlog waiting on completion. Can you give us a sense in terms of when you think those are going to turn to sales? What are you guys looking for? Is it service cost coming down, gas prices going up, kind of a combination of the two? Should we kind of be thinking about brining those on in the winter, is that the plan?

S. P. Johnson, IV

The plan is based on both. We are seeing the service cost come down, our frac costs are now 50% lower than they were in January but, the commodity prices even though they’ve rallied in the last week, we’re not convinced that it’s time to start spending the money yet. The other price deck we have to pay attention to is of course the bank price deck, as much as we look at any futures prices. So, we think it’s probably prudent to wait and frac about four wells in June and then right now we’re planning on fracing about 10 more wells sometimes towards the end of the third quarter.

Leo Mariani – RBC Capital Markets

Can you give us an indication of where your Barnett well costs are these days? You mentioned the frac costs coming down so I’m just trying to get a sense of what the all in costs is looking like?

S. P. Johnson, IV

On the bigger Southeast Tarrant wells we’re drilling we’re using about $3 million on average for drill and complete and frac and facilities. We’ve seen most costs come down but, we’ve seen some costs go up, sometimes water is more expensive permitting has gotten more expensive all through the play but, that’s about it. Most of the costs have come down.

Leo Mariani – RBC Capital Markets

Is there still acreage to pick up there in Southeast Tarrant County that you guys are buying?

S. P. Johnson, IV

There is acreage to pick up. Right now we’re only leasing along our well paths in the units where we want to drill in the near term. We are looking for ways to find private equity money that would come in and let us buy more acreage.

Operator

Your next question comes from Brian Corales – SMH Capital.

Brian Corales – SMH Capital

Just kind of a follow up to the last question, in terms of the acreage would that be a similar deal as the Avista deal for the Marcellus or is kind of everything on the table?

S. P. Johnson, IV

Right now everything’s on the table. We’d rather do a land bank rather than a private equity deal just because the terms are better for us and we’re really not looking for something of the scale that we did in the Marcellus. I don’t think there’s that much acreage available. We’re probably looking at $10 to $20, maybe $30 million type land bank.

Brian Corales – SMH Capital

What are you seeing for the acreage costs say in Southeast Tarrant?

S. P. Johnson, IV

We’re seeing costs anywhere from $2,500 per acre to $10,000 depending on how well things are blocked up and how much pressure people have been under in the past. Someone who was offered $25,000 per acre last year is reluctant to go to $2,500 per acre but some of the new areas that we’re looking at leasing in have never been approached before so it’s a little easier.

Brian Corales – SMH Capital

Just one final question, you had 35 wells in backlog as of today, where do you see that number in the Barnett at year end 2009 or does it depend on the commodity?

S. P. Johnson, IV

Well, it really depends on the commodity price. We should drill something like 45 wells this year but we’re only planning on fracing another 15 between now and the end of the year. So, we end the year I believe at 54 gross wells still drilled but not online at the end of the year. We started the year at 52 gross wells.

Operator

Your next question comes from Ronald Mills – Johnson Rice & Company.

Ronald Mills – Johnson Rice & Company

I actually have a couple of questions for Paul from a guidance standpoint, one on the non-cash D&A, is that extra $3 million or so of incremental non-cash interest due to accounting rules, is that a pretty good number to use every quarter?

Paul F. Boling

It is I’d say for this year. Next year, that number will continue to decline but I’d say this year it’s a reasonable estimate each quarter. Effectively what you see there Ron is as you record that interest of $3 million, if you look at the balance sheet the other side of the entry has increased the convertible debt component by the same amount. So, it’s really just an amortization technique to build the convertible debt component back up eventually to what the amount is on the put date in 2013.

Ronald Mills – Johnson Rice & Company

On the non-cash G&A should that return to your more normalized level kind of $1.5 to $2 million the remainder of the year?

Paul F. Boling

Yes, it should.

Ronald Mills – Johnson Rice & Company

Can you provide any guidance on the production tax and the transportation, particularly production taxes?

Paul F. Boling

Production taxes Ron I’d say about 2.2% should be the right number for on gross revenues for the second quarter.

Ronald Mills – Johnson Rice & Company

And transportation?

Paul F. Boling

Transportation I would say is going to be about $0.30.

Ronald Mills – Johnson Rice & Company

Will that production tax, will that account for all, at least to the best of your ability to [tie] cash credits?

Paul F. Boling

Yes, Ron I’m not expecting any more adjusters coming through for tie gas and credits. That was really kind of a catch up adjustment that we got due to an independent audit that we completed but I wouldn’t model anything in going forward.

Ronald Mills – Johnson Rice & Company

Then lastly, Chip just from an activity outlook or standpoint in the Barnett with the completion costs coming down and the prices moving up a little bit recently, when you look at kind of the economics of that play at what point do you think you’ll at least pick up or potentially pick up another rig?

S. P. Johnson, IV

Probably yearend, if things happen like we think in that supply and demand ought to start getting closer, maybe even equilibrate the first quarter then we should see the prices start up in the fourth quarter and I think at that point we’ll all have a pretty good understanding of what the impact was on gas supply by cutting all the drilling rigs in the country and we’ll use that data to decide when we want to start adding more rigs.

Operator

Your next question comes from David Tameron – Wachovia Capital Markets, LLC.

David Tameron – Wachovia Capital Markets, LLC.

Chip, I think you just gave a well count of how many operated wells you have in the Barnett. Can you give that to me again, or maybe you didn’t?

S. P. Johnson, IV

No, but if you wait a minute I can give that to you.

David Tameron – Wachovia Capital Markets, LLC.

What I’m trying to figure out is it doesn’t sound like you’re going to frac any wells till June so whatever your decline rate is apparently is holding up. I’m trying to figure out what your line decline rate is. For instance, in May what does that look like without any new fracs?

S. P. Johnson, IV

I think we would probably drop about 4 million a month with no new fracs.

David Tameron – Wachovia Capital Markets, LLC.

The decision no

t to frac anything till June, that’s a voluntarily decision, that’s your decision or is that driven by some of the urban nature of the fracs or is it service provider?

S. P. Johnson, IV

That’s all self imposed. We could be running two to four frac crews right now no problem if we wanted to.

David Tameron – Wachovia Capital Markets, LLC.

Can you remind me, where does most of your gas get sold in to?

S. P. Johnson, IV

It’s about out of say 90 million a day probably 10 ends up at ship channels or Henry Hub because it’s out of Louisiana or South Texas, as far as gas. About 30 of the Barnett ends up at Houston Ship channel and about 40 to 50 ends up at Waha. Or, at least that’s where we get priced.

David Tameron – Wachovia Capital Markets, LLC.

I think you just answered this but you kind of said based on, and I asked you the same question at [inaudible] but what are you waiting for as far as to get more aggressive in the field, as far as increasing activity? Is it simply price, the banks, is it a combination of both?

S. P. Johnson, IV

It’s both. We want to see the banks get confident and we also want to see some kind of price increase that is caused by better fundamentals on supply and demand. If price jumps up but supply hasn’t come down then we’re not going to get aggressive unless you can prove to me that demand has gone up which no one has been able to do that.

David Tameron – Wachovia Capital Markets, LLC.

With that being said, if you see a spike that you deem not fundamentally driven, more speculatively driven would you consider locking in more of your 2010 program?

S. P. Johnson, IV

That’s what we were doing last week.

Operator

Your next question comes from Raymond Deacon – Pritchard Capital Partners, LLC.

Raymond Deacon – Pritchard Capital Partners, LLC

Chip, I guess do you see any downside to that $3 million well cost in Southeast Tarrant or do you think that’s as low as it goes?

S. P. Johnson, IV

It can go a little lower. Brad, are you on here?

[John Bradley Fisher]

Yes I am.

S. P. Johnson, IV

Do you see any way we can get the cost down lower to say $2.5 million?

[John Bradley Fisher]

In order for that to happen, if we pick up another rig other than the flex rig that we have contracted, we can get it down in to that range. But, with the rig contracts we have right now probably with additional cost reductions we can probably get it down to about $2.7 million average without rig dropping.

Raymond Deacon – Pritchard Capital Partners, LLC

Can you just talk about where do you see the bank debt going over the next couple of quarters? And, where was it at the end of the first quarter?

S. P. Johnson, IV

Bank debt at the end of the first quarter is $180, basically our cash model right now is projecting that at the end of the year we should be somewhere around $190 million drawn on that borrowing base.

Raymond Deacon – Pritchard Capital Partners, LLC

I guess could you just talk about infrastructure in the Marcellus and how quickly you might be able to tie in these wells or will there be a delay?

S. P. Johnson, IV

Infrastructure wise in the Centre County area I think we can get a couple of vertical wells online quickly. There is low pressure, low volume infrastructure in the area if a lot of horizontal wells get drilled, that’s probably not going to happen. In Susquehanna County there is infrastructure being built right now, in West Virginia one of the places we’re looking to drill has infrastructure around which is one of the things we find appealing. In some of the other areas there is not and it would probably take years to get the gas out.

The whole play is constrained by infrastructure and I think a lot of people are up there right now trying to figure out if we ramp up production like we did in the Barnett where is it all going to go, how many mid stream mid level gathering systems are going to be needed and then how do you reroute the gas on those big interstate pipelines of which there are a lot. But, there’s a lot of gas already flowing through those coming from somewhere else.

Raymond Deacon – Pritchard Capital Partners, LLC

What’s your acreage position in Susquehanna? Is it around 12,000, is that about right?

S. P. Johnson, IV

That’s probably about right. We had some acreage that we bought last year with partners, we’ve been buying up there now with partners and that’s probably about the right number. We have a little bit in Wayne County, we have some north of that in New York and Cuyahoga County that we kind of put all in that same area as far as thickness.

Operator

Your next question comes from Joseph Allman – J. P. Morgan.

Joseph Allman – J. P. Morgan

In terms of the West Virginia JV that you’re talking about, if that happens what kind of capital requirement do you think you would have to assume this year and how about next year?

S. P. Johnson, IV

The plan that we’ve put on the table is that it would be minimal. It will probably be a well commitment, one or two vertical wells to prove up some acreage and if that works then we’d start probably buying some acreage next year if we’re successful.

Joseph Allman – J. P. Morgan

Then a different topic, in terms of right now you’ve got 35 net wells drilled but not completed and you said beginning of the year it was 52 I think. What’s a normalized number of wells not completed? I mean, drilled but not completed?

S. P. Johnson, IV

It’s not really normal now, we’d have to go back and look at what it was most of last year when we were trying to keep up fracing as much as we did. We started the year with 52, we should end the year at about 54. We did frac some wells in the first quarter, we fraced about nine gross wells and hopefully we’ll frac 15 in the rest of the year.

Joseph Allman – J. P. Morgan

But I mean, it’s typical to have some backlog of wells that are drilled but not completed?

S. P. Johnson, IV

Well normally, we had a backlog because we were trying to get infrastructure built on the gathering line side to hook up with Energy Transfer’s pipelines. Now, we have all that, or pretty much all of that built and the reason the wells are shut in are just we’re waiting for prices to go up.

Operator

Your next question comes from [James Homes – Miller Payback].

[James Homes – Miller Payback]

Could you tell me I just wanted to check pro forma for the new borrowing base, the availability was $79 million at quarter end, does that sound about right?

Paul F. Boling

I think it’s about $70 million at the end of the quarter and currently it’s about $75 million.

[James Homes – Miller Payback]

One more item, cap ex for the first quarter what was that number please?

Paul F. Boling

It’s $48 million.

Operator

Your next question comes from Jeffrey Hayden – Rodman & Renshaw, LLC.

Jeffrey Hayden – Rodman & Renshaw, LLC

First, just a quick follow up to Ray’s question, on the Susquehanna acreage, that 12,000 is that net to JV or net to you guys?

S. P. Johnson, IV

Net to the JV.

Jeffrey Hayden – Rodman & Renshaw, LLC

Chip, looking at the Marcellus program you guys have for the remainder of the year, what are you kind of thinking of where the remaining wells are going to be located, kind of which counties?

S. P. Johnson, IV

There are about four different counties in West Virginia, we’re probably going to drill a well or two that we won’t operate in Susquehanna regardless of what we do and we are still looking at permitting one or two wells in the Centre County Clearfield are.

Jeffrey Hayden – Rodman & Renshaw, LLC

So still thinking about maybe six to eight total wells for the year?

S. P. Johnson, IV

Well, we’d still like to get to 10, I’m just not sure we’ll get all the permits to do that. So, if we get eight that will be great.

Jeffrey Hayden – Rodman & Renshaw, LLC

Then, Barnett midstream still looking at potential sales of part of that?

S. P. Johnson, IV

We’re going through some exercises with different finance companies and midstream companies to see whether we should sell that or not or should we do a sale leaseback. There are a lot of different variations there but we’re going to keep looking at that. It probably makes sense to do that in almost any case.

Operator

Your next question comes from David Tameron – Wachovia Capital Markets, LLC.

David Tameron – Wachovia Capital Markets, LLC.

If you think about the acreage that you have up in the Marcellus how much do you have to drill, is 10 the magic number to hold acreage for this year? How much do you have expiring?

S. P. Johnson, IV

We have almost nothing expiring this year. Most of the leases we took were five year leases with five year options. That 10 is just something we set as a goal because that works out if we get the acreage evaluated now with the vertical wells then we can be drilling starting an horizontal program sometimes next year and hopefully all of our wells will start being drilled and come online about the time infrastructure gets there and the seismic gets there.

David Tameron – Wachovia Capital Markets, LLC.

Just thinking about the West Virginia acreage, is that something that gets unitized over time and if so kind of what’s that look like?

S. P. Johnson, IV

Well, everywhere we are we’ll be trying to form units. We know who’s around us there right now and what’s still unleased and I don’t think we’re worried about somebody coming in and busting our block. We have enough acreage blocked up now that if it works we’ve already got a sizeable position and there are one or two other sizeable companies that have the rest.

David Tameron – Wachovia Capital Markets, LLC.

So forming a unit sometime next year then? That would kind of be the tentative plan?

S. P. Johnson, IV

Probably forming several units next year.

Operator

Your next question comes from Ronald Mills – Johnson Rice & Company.

Ronald Mills – Johnson Rice & Company

Paul, on the first quarter cap ex did that include carry over on your cash flow from your ’08 program? I’m just trying to mesh that with your $105 million announced budget.

Paul F. Boling

That’s total cap ex for period so that includes any carry over from our accruals that we had built in for the prior quarter.

Ronald Mills – Johnson Rice & Company

Do you know how much those are? I’m just trying to get a sense for what’s left for your 2009 program?

Paul F. Boling

Yes, I think – I don’t have the number right in front of me Ron but I can share that with you later.

Ronald Mills – Johnson Rice & Company

Then lastly on the hedging, it sounds like you monetized the whole oil hedge that you had over the remainder of the year?

Paul F. Boling

That’s right, it was about $2.2 is what we monetized in the first quarter.

Ronald Mills – Johnson Rice & Company

So that hedge is now gone?

Paul F. Boling

That hedge is gone, that’s correct.

Ronald Mills – Johnson Rice & Company

Then you said something that you were also able to book an accrual for the April realized hedge gains, did I hear that correctly?

Paul F. Boling

That’s right. What we did back at the end of last year is we instituted an accounting method whereby we recognized the leading months hedge position once it’s confirmed with the trader. That’s typically around the 28th or 27th of the month. So, for example, on March the 27th we had confirmed the amount of the April hedge and set up a receivable for it. So, that accounting method obviously is a new presentation.

If you’re looking at your cash model trying to figure out what the benefit of that accounting method is to your first quarter, it works out to about $3.3 million benefit because in effect what’s happening is we’re recording April and we’ve already recorded the January hedge back in December. So, the net benefit in the quarter works out to about $3.3.

Ronald Mills – Johnson Rice & Company

But in terms of forecasting price and including the impact of hedges, we really only have to include the May and June months in the second quarter hedging, is that right?

Paul F. Boling

May and June and then you’ll have to pick up your estimate from the July hedge. You’ll still have three months in each quarter, in effect what you’re doing is stepping out one month to pick up the benefit of the hedge from the month following the quarter end.

Operator

Now, I’ll turn it back to Mr. Johnson for your concluding remarks.

S. P. Johnson, IV

Thank you all for calling in and for your questions. As Paul said earlier, our strategy will continue to be protection of our assets and liquidity until commodity prices improve and the financial markets return. The confidence shown by our banks with respect to our revolver should let us weather the storm and we think even through the next borrowing base redetermination.

Our acreage positions in the Barnett core and the Marcellus Shale gave us tremendous upside leverage in a $6 to $8 gas world. We saw that back in ’07 and we didn’t need the prices we saw early last year to see the kind of profitability and the increase in our equity value that we saw in ’07. We think the natural gas markets could be in supply demand equilibrium next spring and the stock markets and future markets will price that in much sooner. When we see that we can respond rapidly because we have this huge inventory of shut in production. With that, thank you all very much for calling in. We’ll talk to you in three months.

Operator

Ladies and gentlemen that does conclude the conference call for today. We thank you all for your participation and ask that you please disconnect. Thank you once again. Have a great day.

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