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Carrizo Oil & Gas, Inc. (NASDAQ:CRZO)

Q2 2009 Earnings Call

August 10, 2009 11:00 am ET

Executives

Chip Johnson - President and CEO

Paul Boling - Vice President and CFO

Richard Hunter - VP of IR

Analysts

David Heikkinen - Tudor, Pickering and Holt

David Tameron - Wells Fargo Securities

Michael Bodino - SMH Capital

Ray Deacon - Pritchard Capital

Leo Mariani - RBC

Marshall Carver - Capital One Southcoast

Ron Mills - Johnson Rice

Welcome to the second quarter 2009 financial results for Carrizo Oil & Gas Incorporated conference call. As a reminder this conference is being recorded. The speakers today are Chip Johnson, President and Chief Executive Officer, and Paul Boling, Vice President and Chief Financial Officer for 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.

Chip Johnson

Thank you all for calling in on the second quarter earnings release. As we’ve done in the past, Paul Boling will explain with the financials results, then I’ll go over an operations status and then we’ll open it up to questions. Paul, you want to get started?

Paul Boling

Thanks Chip. Adjusted revenues including the impact of cash-settled hedges were $48.8 million compared to $56 million in the second quarter of 2008. The decrease in adjusted revenues was primarily driven by significantly lower realized oil and gas prices partially offset by increased production.

Commodity prices including the impact of hedges decreased as natural gas prices were $6.08 per Mcf as compared to $8.68 per Mcf in the second quarter of '08 and oil prices decreased to $56.95 per barrel from $113.90 per barrel in the first quarter of 2008.

Our second quarter 2009 production level was 7.9 Bcfe or 86,739 Mcfe per day, that's up 29% compared to the 6.1 Bcfe produced during the second quarter of 2008. The increase was primarily due to the continued addition of new production from the companies Barnett Shale development.

Adjusted net income for the quarter ended June 30, 2009, was $12.9 million or $0.42 and $0.41 per basic and diluted shares respectively. Excluding the net $19 million non-cash after-tax charge, comprised of a mark-to-market unrealized loss of $16.4 million on derivatives, due in large part to the open positions that were closed and cash-settled during the quarter and in part to the increase in commodity spot prices at June 30 as compared to March 31, 2009; stock compensation expense of $1.5 million; non-cash interest expense of $1 million associated with the amortization of the equity premium on the companies convertible notes per APB 14-1; and $0.1 million of bad debt expense.

The company reported a net loss of $6 million or $0.19 per basic and diluted share for the quarter ended June 30, '09 as compared to a net loss of $12.8 million or $0.42 per basic and diluted share for the same quarter during 2008.

During the second quarter of 2009, EBITDA was $35.3 million, or $1.14 and $1.13 per basic and diluted shares respectively, as compared to $35 million, or $1.14 and $1.12 per basic diluted shares respectively during the second quarter of 2008.

Lease operating expense excluding production taxes in the second quarter of 2009 was $6.3 million, or $0.5 million higher than the second quarter of 2008 largely due to increased production. Our guidance for lease operating expense in the third quarter of ‘09 is $0.80 to $0.85 per annum.

Transportation expenses were $3 million during the three months ended June 30, as compared to $1.8 million for the second quarter of 2008. The increase in transportation cost was largely due to a greater portion of the company’s total production volume that is attributable to the Barnett Shale Tarrant County area, which has a weighted-average higher transportation cost per Mcfe. Our guidance for transportation costs in the third quarter of 2009 is $0.38 to $0.40 per annum.

Production taxes were $0.3 million during the three months ended June 30, as compared to $1.6 million for the second quarter of ‘08. The decline was primarily due to the decline in oil and gas revenues and in part to a $0.2 million severance tax refund from certain non-operated producing properties that qualified for a tight-gas sands tax credit for prior production periods.

Depreciation, depletion and amortization expense was $12.2 million, or $1.55 per Mcfe during the three months ended June 30, or $1.7 million lower than the second quarter of ‘08 at $2.27 per Mcfe, primarily due to the impairment charges, which reduced the depletable cost pool in the fourth quarter of ‘08 and also in the first quarter of ‘09. This was partially offset by increased production.

G&A expense decreased to $4 million compared to $4.2 million during the same quarter of '08. General guidance for our G&A expense in the third quarter is $3.7 million to $3.9 million.

Non-cash stock option compensation expense was $2.3 million compared to $1.5 million for the same period in '08. The increase was due primarily to the issuance of common stock, in lieu of cash, to pay quarterly bonuses and certain 2008 discretionary bonuses.

A $2.3 million net loss on derivatives was recorded for the second quarter of '09 comprised of a $25.3 million unrealized marked-to-market, non-cash loss on natural gas derivatives, a $23 million gain for cash-settled natural gas derivatives.

Cash interest expense, net of amounts capitalized, was $3.1 million for the three months ended June 30, '09 compared to $1.3 million for the three months ended June 30. The increase was primarily attributable to interest expense associated with higher debt level on the company's revolver facility.

Interest expense non-cash, net of amounts capitalized increased to $1.4 million from $0.3 million in the prior period primarily due to the amortization of the equity premium in accordance with APB 14-1 associated with the company's convertible notes.

Moving on to the company's year-to-date results, financial performance for the six months of '09 included adjusted revenues including the impact of cash-settled hedges of $102 million compared to $108 million in the first half of 2008. The decrease in adjusted revenues was primarily driven by significantly lower realized oil and natural gas prices, partially offset by increased production.

Commodity prices including the impact of hedges, decreased for the six months ended June 30, '09 compared to the same period in 08. Carrizo's average oil sales price decreased 20% to $80.52 per barrel compared to $100 per barrel and the average natural gas price decreased 26% to $6.10 per Mcfe compared to $8.27 per Mcfe.

Our production volume for the first half of '09 was a record 16.15 Bcfe, 30% higher compared to the 12.43 Bcfe produced during the first half of 08. The increase was largely due to new production contributions from our Barnett Shale development.

For the six months ended June 30, 2009, the company reported adjusted net income of $27.7 million or $0.90 and $0.89 per basic and diluted shares respectively, excluding a net $157.9 million non-cash after-tax charge, comprised of a non-cash impairment of oil and natural gas properties of $140.6 million, which reflects the impact of a correction for a computational error as discussed in the companies Form 8-K filed on the same day.

A mark-to-market unrealized loss of $11.6 million on derivatives, due in large part to the open positions that cash-settled during the six months ended June 30, '09 and the increase in the commodity spot prices from December 31, 2008 to June 30 of '09.

Stock compensation expense of $3.7 million, non-cash interest expense of $1.8 million, primarily associated with the amortization of the equity premium on the company’s convertible notes and $0.2 million of bad debt expense.

Our EBITDA was $76.3 million for the six months ended June 30, '09 or $2.47 and $2.44 per basic and fully diluted shares respectively, as compared to $80 million or $2.69 and $2.67 per basic and diluted shares respectively during the first half of '08.

Lease operating expense excluding transportation costs and production taxes increased to $12.3 million or $0.76 per Mcfe during the six months ended '09 as compared to 10.8 or $0.87 per Mcfe for the same period in 2008, largely due to the 30% increase in production volume from 12.4 Bcf for the six months ended June 30 to 16.2 Bcf for the six months ended June 30, 09.

Transportation costs were $6.3 million during the six months ended June 30, '09 as compared to $4.1 million during the same period in 2008. The increase in transportation cost or $0.06 per Mcfe was largely due to the greater proportion of the companies total production volume attributable to the Barnett Shale Tarrant County area, which has a weighted average transportation cost that's higher.

Production taxes were a net benefit of $1 million during the six months ended due to a $1.9 million severance tax refund from certain wells that qualified for a tight-gas sands tax credit for prior periods.

DD&A expense was $27.5 million during the six months ended June 30, '09 as compared to $28 million during the same period of '08. The decrease in the DD&A expense was due primarily to a lower depletion rate associated with the impairment charges incurred in the fourth quarter of '08 and the first quarter of '09.

G&A expense decreased to $8.2 million during the six months ended compared to $9.3 million during the same period in '08. This is largely due to lower employee-related costs including the payment of bonuses with the stock of the company's in lieu of cash, decreased insurance cost and lower legal professional fees.

The significant decline in oil and natural gas prices during 2009 caused the discounted present value of future net cash flows from proved oil and gas reserves to fall below the net book basis of the company. This resulted in a non-cash, ceiling test write-down as I mentioned earlier, of $216.4 million $140.6 million after tax, which has been revised for a $35.8 million credit adjustment to correct for certain computational errors largely related to deferred taxes and the company's originally reported first quarter 2008 impairment of $252.2 million. There is also a 8-K that was filed today. You can refer to which has a detailed explanations with regard to that correction.

$27.8 million of net gain on the derivatives was recorded for the first half of ‘09 comprised of a $17.8 million unrealized marked-to-market, non-cash loss on oil and gas derivatives and a $45 million gain for cash-settled hedges for oil and natural gas derivatives.

We are very encouraged by the company’s second quarter and year-to-date performance, including continued results from our Barnett Shale play. We remain vigilant in our focus on preserving liquidity and funding our CapEx from free cash flow given the low commodity price environment that we are currently in. Chip?

Chip Johnson

Thanks, Paul. Now I will give an update on operations status. Current production is about 95 million cubic feet equivalent per day, with 80 million a day coming from the Barnett Shale and 15 million a day coming from the onshore Gulf Coast. We still estimate the third quarter production will be between 84 and 87 million cubic feet equivalent per day.

We tracked 12 wells in June and July of which brought production up to 80 million a day. The next round of fracs on nine wells in the Barnett will impact the fourth quarter. We still estimate that our year-end production will be a 100 million cubic feet equivalent per day for the company and that should happen right at the end of the fourth quarter.

We have three drilling rigs in the quarter, the Barnett, and no rigs running in the Gulf Coast. We currently have 39 net wells drilled, but not completed, totaling an estimated 87 million of cubic feet equivalent per day of initial rate.

We fraced our first vertical Marcellus Shale well in Center County, Pennsylvania and have begun flow back, tubing was run and gas lift to get the frac water out should start today. We plan to test the well for an extended time period before planning a pipeline route.

The next wells we plan to drill in the Marcellus are five vertical wells across our northern West Virginia acreage, the drilling should start around October 1st and continue back-to-back until finished.

From a CapEx standpoint, we will be spending Carrizo dollars for 50% of these wells, as we have used the last of the 100% Avista funds in making a large land acquisition of 6500 acres in Susquehanna County in Northeast Pennsylvania. As currently planned the five vertical wells are all we plan to spend anything on until early 2010.

In our North Sea project, Premier Oil & Gas has taken over Oilexco’s working interest and the partners are proceeding with development planning. The goal is to submit the plan to the UK government by year-end. First production should occur in mid-2011 in our estimation. We have started talking to advisors about a possible sale of the assets, now that the Oilexco issue has been resolved and a development plan is more imminent.

We plan to continue drilling out of cash flow in the Barnett with a minimum drilling program and a minimum frac program designed to keep the borrowing base reserves flat. We intend to maintain the undrawn revolver through the next redetermination probably in November.

The current gas price is more than $2 below the 2010 strip. We're in no hurry to accelerate our gas production. We would like to acquire more acreage in the Barnett Shale core and certain areas of the Marcellus, and are looking at creative ways to raise non-debt capital for that purpose from land banks to pipeline sales. We have made substantial progress on the sale of an interest of our Mansfield Texas gathering system and hope to have a closing in the third quarter.

With that we'd like to open it up to questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from the line of David Heikkinen with Tudor, Pickering and Holt.

David Heikkinen - Tudor, Pickering and Holt

Just thinking about the Marcellus capital program, can you walk us through how much you spent on leasing and then what you spent for the first vertical well, any coring, and then your plans for the five vertical wells as you go forward?

Chip Johnson

Nearly all of the money has been spent on leasing. We have drilled some wells with partners in Northeast Pennsylvania and in Southeast New York, but our interest was small in all of those. The vertical well and the Marcellus will, probably including frac be about $2 million, because we ran every log, every kind of tracer log, took cores, did every kind of analysis we could. So, we think the costs will come down in the future once we go in to full development.

In the West Virginia wells, we have a range of depths I think from about 4,000 feet to 9,000 feet. So we're assuming the average cost will probably be about $1.5 million per well.

David Heikkinen - Tudor Pickering and Holt

Can you bracket or ballpark what you'd consider good results or encouraging results for vertical wells in each of those areas?

Chip Johnson

We're hoping to get vertical wells that are similar to the frac stages that Exco got in their wells and the EOG vertical well in Clearfield County, which is pretty close to us and anything over $1 million a day, $1 million to $1.5 million a day would be very profitable in our opinion.

We would like to get some bigger rates, maybe like the [Atlas] Wells in Southern Pennsylvania, but we're not sure that we have enough frac barriers in the well to get those kind of rates.

David Heikkinen - Tudor Pickering and Holt

Okay. These wells are close enough to pipeline that you'll put them to sales or will they just be flared while you're testing them and that's it.

Chip Johnson

They will be flared while we're testing them. We're probably eight miles from the nearest big pipeline or LDC that we think we could sell into, so we need a lot more data before we start planning sales.

Operator

Our next question comes from the line of David Tameron with Wells Fargo.

David Tameron - Wells Fargo Securities

Good morning. Chip, can you talk about what's the decision metrics to recomplete these or not recomplete but bring these wells online in the Barnett or as far as what gas price level you're looking for? Is it a bank redetermination decision or how do you think about that?

Chip Johnson

Well, it's a combination of both. I mean, at some price if we can sell all the gas at $6 NYMEX, which is what the strip is now, I think for 2010, we’d probably produce it no matter what the bank debt looks like. I think in 60 to 90 days we'll have a much clearer picture on how this is will look and we just don't have any problem constraining our production until we see something get better.

If the whole world comes down to $4 or $5 NYMEX and looks like that for a long time then we would probably produce, but in light of how much money we can make by waiting 60 or 90 days. We think it would be foolish to be gutting these wells.

David Tameron - Wells Fargo Securities

All right and how fast can you bring these on once a go decision is made? I think you said 87 million a day was the number you put in the press release. What kind of ramp can we see from those if January 1, the price is the $6?

Chip Johnson

I think we can frac about one well per week for frac proof and we have something like 40 wells that we need to fracked. So, if we ran three crews, you can see how fast we could get those on. It wouldn't take, but about a quarter.

David Tameron - Wells Fargo Securities

Okay, all right and then the Marcellus side, and you might have mentioned this, but you chase any expiration at all on the leases?

Chip Johnson

No. We have a long-time left on our leases.

David Tameron - Wells Fargo Securities

Okay.

Chip Johnson

We have drilling commitment in Centre County and that's one of the reasons we drilled that well first, but that satisfied an obligation on a big package of leases.

Operator

Our next question comes from the line of Michael Bodino with SMH Capital. Please proceed with your question.

Michael Bodino - SMH Capital

Just a couple follow-up questions. You mentioned the 6500 acres in Susquehanna County that were picked up. Was that gross or net?

Chip Johnson

Net. After the partnership so, half of it and half us.

Michael Bodino - SMH Capital

Okay, just another follow-up question. Relative to your drilling program this year, and I know it's not a whole lot of dollars being spent incrementally, but is this dollars that are being moved away from other parts, other areas of the company or is this incremental dollars being spent this year, to drill the five additional wells?

Chip Johnson

No. That actually I think our budget is going up a little bit and you'll see that in our presentation. Our cash flow looks like it's going to be a little higher than we had planned four or five months ago. So, I think we can pick up those five wells really without cutting back anywhere.

Michael Bodino - SMH Capital

Okay.

Chip Johnson

Those five wells isn't that much money is part of the answer.

Michael Bodino - SMH Capital

Yes, I knew that. I just wanted to ask the question on CapEx, just to make sure we had it additive in our models. Other question on the North Sea, you're talking to advisors, if you move forward with an advisor to monetize that asset, is it something that you are trying to get accomplished this year or is that you timeline uncertain, it doesn’t really matter just as along as it would be appropriate price for it.

Chip Johnson

Well, we would like to get the best price we can, but I think what's going to influence it is taxable income. There is some issues that have to do with when you sell it relative to the government plan being approved and we're working through those issues and then.

What we've been told and what we felt was that we get more value for it once the group had put together a development plan that we all agree on so that time to first production and all of the capital costs to develop are more well understood.

Michael Bodino - SMH Capital

That plan of development hasn't been submitted yet, correct?

Chip Johnson

That’s correct. We still have several options on how we can get the hydrocarbons to market and the group is working on that led by E.ON Ruhrgas.

Operator

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

Ray Deacon - Pritchard Capital

I was wondering could you tell me that the five verticals that you’re going to planning to drill in the Northeast? Are those all likely to be in Susquehanna or in more than one county?

Chip Johnson

No, those are all in West Virginia, in the Northern Counties of West Virginia.

Ray Deacon - Pritchard Capital

So, like [Dodge ridge] or [Pelham Manor]?

Chip Johnson

We’ve got them all named by code names. So, I couldn't even tell you what the counties are but [offshore is one of them].

Ray Deacon - Pritchard Capital

[Offshore], I got it. Can you kind of ballpark number to the midstream asset sale, what kind of proceeds you would net out of that or…

Chip Johnson

We were targeting $30 to $40 million and that’s based on what we think the throughput is and multiples of cash flow that recent pipeline deals have gone forward.

Ray Deacon - Pritchard Capital

Okay, got it. So, I guess may be a question for Paul, I guess, where would you expect to be on the revolver at year-end, netting out a little bit higher CapEx on the drilling side and assuming the proceeds from this come through?

Paul Boling

I would say, we’re probably going to be looking at somewhere around 190 to 195.

Ray Deacon - Pritchard Capital

Got it and I guess when would you expect, last question on, to move into the horizontals? Is it kind of early 2010 in the Marcellus? Is that kind of a fair guess?

Chip Johnson

Well, we're trying to figure that out. Now the only area where we have acreage, which we think is de-risked enough to start drilling horizontals would be in Northeast Pennsylvania. As we gather data in Central Pennsylvania and Northwest Virginia, we might have some new ideas on that, but I think the first horizontal wells we drill will probably be in Susquehanna County.

Ray Deacon - Pritchard Capital

Okay, got it and then if Clearfield or Westmoreland looks like its perspective, there might be some activity there I guess?

Chip Johnson

Right. The problem with those counties is there is no 3D seismic data yet and there are 3Ds being shot in Bradford and Susquehanna right now and some of that goes over our acreage. So we think we'll be able to get that.

Also there are some 2D data sets up there that show the area is not very broken up and there are some areas like that in Clearfield County too, but we've heard stories from other operators where drilling of horizontal wells in the C-counties without 3D caused a lot of problems during the drilling phase and limited the number of stages they could frac.

Operator

Our next question comes from the line of Leo Mariani with RBC.

Leo Mariani - RBC

I just wondered if you guys could comment on what type of acreage prices you guys are seeing in the Barnett these days?

Chip Johnson

No. In some areas in the Barnett, the prices have dropped as low as 3 to 5,000 per acre in areas where they were 20,000 per acre last year. We haven't even become in the market in Tier 2 or Tier 1. So, I can’t tell you what those prices are. There are some holdouts in the core that still think they can get 15,000 per acre, but in general it’s dropped off below 10,000.

Leo Mariani - RBC

Okay. Jumping over to the Marcellus, in terms of what you guys are saying about the Avista deal, it sounds like you guys are out of the carry at this point in time. I guess I’d understood that was going to last into 2010.

Could you give us some more color around how much money was spent out there? It sounds like it was just basically on acreage and what the details are on that?

Chip Johnson

Yes, what we did was make a land purchase in Susquehanna County and that used up the $5 million on our side. We thought we would spend drilling these wells in Northern West Virginia. So, now we have to come out of pocket for that, but that's about the delta on the total $100 million that Avista put into the deal.

Leo Mariani - RBC

Okay. So, I guess can you refresh my memory about the terms of that? I guess they had been 100 million; obviously you guys had contributed acreage. Was there some equalization of value between what you contributed and what they put in at this point? I guess. I thought there was some additional carry that was going out a little further?

Chip Johnson

Well, the way it works is, last summer when we did the deal, they valued our position at about $100 million and agreed to put in the next $100 million and then at that point we would go forward 50/50.

They have a waterfall typical of a private equity deal, where if they make certain hurdle rates on their investment then we back into their working interest and pick up some of their working interest. So, that's still out there. That's still the big part of the promote for us.

Leo Mariani - RBC

Okay. So, they haven't actually contributed $100 million capital at this point or have they in terms of acreage purchases?

Chip Johnson

No, they put a 100 million in and that has gone into mostly acreage purchases, but also some drilling and completion of the well. We drilled and the partner operated wells.

Operator

(Operator Instructions) Our next question comes from the line of Marshall Carver, Capital One Southcoast. Please proceed with your question.

Marshall Carver - Capital One Southcoast

Yes, on the gathering system sale, what's the EBITDA or cash flow associated with that?

Paul Boling

Really rather I’d not say.

Marshall Carver - Capital One Southcoast

Okay.

Paul Boling

Because we are still in negotiations with two or three parties so.

Marshall Carver - Capital One Southcoast

Okay, fair enough and the North Sea asset sale, is that both 40’s and Fulmar discoveries to that both of them?

Paul Boling

Well, our choice would be to just sell the 40's, because it's pretty well understood and we think we know what the upside and downside is. The Fulmar is still a big mystery and I'm not sure anybody would pay us as much as we think is there.

So, the advisors are trying to figure out how we would market this and who the parties would be that would buy one and not both, or if you had to sell both, how you would market that and what’s you might expect to get for it.

Marshall Carver - Capital One Southcoast

Okay. Remind me, are those associated with each, with the controlled reserves?

Paul Boling

We think there are something like a 110 million barrels to the [8-8s] between the two reservoirs, we have 15%. The partners come up with numbers from about that size to 2.5 times that size, but the big mystery is just in the Fulmar, because we have only penetrated it twice.

One was an excellent oil well that produced at high rates and the other one we were trying to find the oil water contact and we really didn't.

So we have a very big structure but we only have one good control point and it's very difficult to image this on seismic, So we need another control point and that well won't get drilled until some time next year.

Marshall Carver - Capital One Southcoast

So, on the 110 on the low end size, how much of that would be [40s] and how much Fulmar?

Chip Johnson

I think we've said the [40s] is around 40 million barrels and the Fulmar is about 70 million barrels.

Marshall Carver - Capital One Southcoast

Okay, thank you. Last question, just the timing of the next slug at Barnett wells right, I know you said it but I didn't catch it on my notes.

Chip Johnson

We have a nine well package that will start fracking, some will be fracked immediately, some will probably be in September, and then we'll probably bring that production on in October, in time to get well tests on it and reserve estimates for the borrowing base.

Marshall Carver - Capital One Southcoast

How many wells would be in that final Slug of wells to get you to the 100 million? How many wells on top of that nine?

Chip Johnson

I think those will get us there.

Operator

Our next question comes from the line of Ron Mills from Johnson Rice.

Ron Mills - Johnson Rice

Just a little clarification on Northeast Pennsylvania. It sounds like you still probably wouldn't plan to spend or drill any horizontal wells up there until next year. I just want to make sure I understood the reason; it's to wait for some of the 3D seismic that's being acquired to be able to help you plan that drilling process?

Chip Johnson

That's primarily it. We have acreage that's very close to horizontal wells drilled by Cabot, Epsilon and Chesapeake, and private operators up there are about to drill some horizontal wells so there is going to be a lot more data available. We're just not in a hurry to do it.

Ron Mills - Johnson Rice

Okay. Then in response to David's question earlier about the Marcellus and in flaring while testing, it sounds like you're only eight miles away but where are you in the process in terms of lining up cap sites to be able to start hooking production up as you go to your 2010 program?

Chip Johnson

All we've done in that area is talk to the mid-stream operators, some that are already there and some that want to be there, about potential ways to link up that whole area. I mean in one case we have a 20,000 acre block that would probably all go through one system, so we need more data before we start committing to things like that.

There is a little bit of low pressure infrastructure in that area, and there are some towns around there that would buy gas from us, but in general, I think we and in that area, Exco, Rex, EOG, XTO Chief are all going to be trying to get more data before we decide how to build a major system that ties all of that together.

Ron Mills - Johnson Rice

Okay, and in overall activity in the Marcellus this year in terms of the vertical program, it sounds like you're now planning is it six wells? Is that down a little bit and is part of that lower activity just due to the leasing that you have done and the resultant Carrizo portion of funding going forward?

Chip Johnson

Yes. We thought we could drill a couple of more wells in the C-counties and we're just going to hold off on those and it's basically just living out of cash flow. The same reason we've cut our Barnett program back from six rigs to three.

Ron Mills - Johnson Rice

Right, and then Paul, just two quick ones for you. Any sort of guidance on what you think your non-cash G&A expenses will be, and I assume your DD&A should be pretty similar to the second quarter and your production taxes. How do you guide towards that in terms of any additional tight-gas credits or anything coming your way?

Paul Boling

No, I think we should be back to a normal rate that I gave guidance on. So, I think that's pretty much back in the normal range. As far as non-cash G&A, I assume you're referring to the stock-based compensation expense, that should be fairly comparable to the second quarter expense.

Ron Mills - Johnson Rice

On the interest side, should that non-cash component related primarily to that APB issue stay around that $3 million a quarter?

Paul Boling

It should. It's basically amortizing over the period to the June 2013 date, amortizing about $55 million, which works out to about $3 million per quarter.

Operator

Mr. Johnson, there are no further questions at this time, sir. I'll turn the call back to you. Please continue for presentation or closing remarks.

Chip Johnson

Okay. Well, thank you all for calling in. We would like to thank our staff for doing a great job in the quarter and hitting the high-end of our production estimate range.

Our strategy in this low price environment continues to be preservation of our assets, primarily our land positions in the Barnett core and the Marcellus Shale and preservation of our liquidity until the next bank redetermination in a more positive and understandable macro picture.

We encourage you to look at our new company presentation, which we will present at Entercom tomorrow in Denver and after that it should be on the website.

We have added a slide that illustrates, what I think is our key attribute of being a small technically excellent company with an enormous acreage position relative to our share count in the Barnett core and in the Marcellus Shale. Only Devon has more core Barnett acreage per share than we do and only three companies of the 19 we track have more Marcellus acreage per share than we do.

So, with that, thanks again for calling in and we talk again in three months.

Operator

Ladies and gentlemen does conclude today's conference call. We thank you for your participation and ask that you please disconnect your lines.

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Source: Carrizo Oil & Gas Inc. Q2 2009 Earnings Call
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