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Executives

Sylvester P. Johnson – President, Chief Executive Officer & Director

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

Analysts

Will Green – Stephens Inc.

Leo Mariani – RBC Capital Markets

Leo P. Mariani – RBC Capital Markets, LLC

Jeffrey Hayden – KLR Group

Michael, A. Glick – Johnson & Rice Company L.L.C.

Marshall Carver – Capital One Southcoast, Inc

Maggie Savage – Robert W. Baird & Co

David Tameron – Wells Fargo Securities

Marshall H. Carver – Capital One Southcoast, Inc.

Carrizo Oil & Gas, Inc. (CRZO) Q2 2012 Earnings Call August 7, 2012 11:00 AM ET

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Second Quarter 2012 Earnings Conference Call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, the conference is being recorded Tuesday, August 7, 2012.

I would now like to turn the conference over to Chip Johnson, President of Carrizo Oil. Please proceed.

Sylvester P. Johnson

Thank you for calling in. To summarize the quarter, we beat guidance on oil production, we beat on gas production. We realized almost a $101 of barrel for our Eagle Ford production. We came in under our LOE guidance. We didn’t take any write-downs of our reserves like many of our peers, and we cut CapEx by cutting drilling rigs and frack jobs and they’re still growing oil production at one of the industry’s highest rates.

Paul Boling will now go over the financial results, and then I’ll go over the operational progress and then we’ll take questions. Paul?

Paul F. Boling

Thanks, Chip. We achieved record oil production of 76, 18 barrels per day, or 28% sequential increase from the first quarter of 2012, a record total production in the second quarter 2012 was 2,393 MBOE, or 26,297 BOE per day, a 4% sequential increase from the first quarter of 2012, production of 2,311 MBOE.

The 4% sequential increase in production was due to the contribution of new wells brought on during the quarter. Second quarter production growth would have been substantially higher had it not been for the impact of the sale of the Barnett Shale production to Atlas on May 1, 2012. We reported record adjusted revenues and revenues for the quarter adjusted revenues, including the impact of realized hedges, we’re $92 million in the second quarter, compared to $91.7 million in the first quarter of 2012.

Oil and gas revenues for the second quarter were a record $83.8 million, compared to $80.7 million during the first quarter of 2012. Similarly, oil revenue was a record $68.6 million in the second quarter and 82% of total oil and gas revenue. This compared $59.4 million of oil revenue in the first quarter, which totaled 74% of total oil and gas revenue. These increases were primarily driven by increased oil production and higher realized gain hedges, partially offset by lower gas prices.

Average realized oil prices, including the impact of realized hedges, decreased to $97.97 per barrel, or a 11% in the second quarter, as compared to $109.65 per barrel in the first quarter of 2012. While average realized gas prices decreased 27% to $2.22 per Mcfe from $3.05 per Mcfe in the first quarter of 2012

As discussed before, we have an implied basis differential to WAHA for the Barnett Shale gas market at the well head, which averaged about $0.85 per Mcf for our second quarter gas production. General guidance for realized gains on derivatives in the third quarter of 2012 is $9.3 million to $9.8 million based upon strip prices as of August 6.

Adjusted net income for the second quarter was $10.5 million, or $0.27 and $0.26 per basic and diluted shares respectively, as compared to $9.5 million, or $0.25 and $0.24 per basic and diluted shares respectively during the second quarter of 2011.

Adjusted net income was essentially flat, compared to the second quarter 2011, due largely to higher DD&A, primarily attributable to the April 2012, sale of natural gas properties to Atlas.

Company reported net income of $28.5 million, or $0.72 and $0.71 per basic and diluted share respectively for the second quarter of 2012, as compared to net income of $7.7 million, or $0.20 per basic and diluted share for the same quarter during 2011.

EBITDA was $69.3 million in Q2, or $1.75 and $1.73 per basic and diluted share respectively, as compared to $41.8 million, or $1.7 and $1.6 per basic and diluted shares respectively during the Q2 of 2011.

Lease operating expense including transportation cost of $1 million, or $7 million or $2.94 per BOE for the second quarter, as compared to LOE of $7.4 million, or $3.99 per BOE for the corresponding quarter in 2011. The decrease in operating cost per unit is primarily due to the Atlas and KKR property sales, partially offset by the higher operating cost per unit associated with our oil production. General guidance for LOE in the third quarter of 2012, is $3.90 to $4.20 per BOE.

Production taxes increased to $3.1 million, or 3.7% of oil and gas revenues for the second quarter, compared to $1.5 million, or 2.9% of oil and gas revenues for the same period in 2011.

The increase in production taxes as a percent of oil and gas revenues was primarily due to increased oil production, which has a higher effective production tax rate as compared to our natural gas production.

Our general guidance for production taxes in the third quarter is 3.75% to 4.25% of total oil and gas revenues. Ad valorem taxes increased to $2.3 million during the second quarter from $1 million for the same quarter in 2011. This increase in ad valorem taxes is due primarily to the new oil wells completed in 2011, which have higher property tax valuations as compared to our natural gas wells.

General guidance for ad valorem taxes in the third quarter of 2012 is $2 million to $2.5 million. General administrative expense, excluding non-cash items, was $10.2 million during the quarter as compared to $5.7 million during the corresponding quarter in 2011. The increase was primarily due to increased compensation costs related to an increase in personnel since the second quarter of 2011.

Our general guidance for G&A in the third quarter is $8 million to $8.5 million. DD&A for the second quarter of 2012 increased $22.8 million to $43.4 million, which equates to $18.12 per barrel equivalent, compared to second quarter 2011 of $20.6 million, or $11.04 per barrel.

The increase in DD&A rate per unit is largely due to the impact of the significant decrease in natural gas reserves in the Barnett Shale as a result of the Atlas sale, as well as the predominant increase in crude oil reserves in the Eagle Ford that were added in 2011, which have a higher finding costs per equivalent unit in our natural gas reserves.

Cash, interest expense, net of amounts capitalized increased to $9.1 million for the second quarter, compared to $6.1 million for 2011 second quarter.

The increase was primarily attributable to interest on the $200 million aggregate principal amount of our 8.65% senior notes issued in the fourth quarter of 2011. An unrealized gain on derivatives of $30 million was reported for the second quarter of 2012, compared to an unrealized gain on derivatives of $8.1 million for the second quarter of 2011 due primarily to a relative decline in natural gas prices, which in turn, increased the fair value of our open derivative positions period.

Non-cash, stock-based compensation was $1.5 million for the second quarter, compared to $6.8 million for the same period in 2011. The decrease in stock-based compensation expense was primarily driven by a decrease in the fair value of cash settled stock appreciation right due to a decrease in stock price during the second quarter of 2012, as compared to an increase in stock price during the second quarter of 2011.

This is partially offset by higher stock-based compensation expense due to a higher number of restricted stock awards outstanding during the second quarter of 2012, as compared to the same period in 2011.

Our estimated effective income tax rates for the second quarter of 2012 and 2011 were 37.1% and 36.7% respectively. The actual effective income tax rates for the second quarter of 2012 and 2011 were 34.2% and 31.8% respectively, which were lower than the estimated annual effective income tax rate due to the foreign tax benefit of our UK Huntington field development project. Chip?

Sylvester Johnson

Thanks, Paul. Current production is $23,230 net BOE per day, or a 139 net million cubic feet equivalent per day, with 92 million cubic feet per day of natural gas production and 7,900 barrels per day of oil production. Oil production is comprised of $6,600 net BOPD from Eagle Ford $1,100 net BOPD from the Niobrara, and $200 net BOPD other.

Our net production is about 55 million cubic feet per day net, Marcellus 25 million cubic feet per day net, and Eagle Ford and other 12 million cubic feet per day net. In the Eagle Ford we are producing from 49 gross wells with three drilling rigs running and one 24\7 frack crew, which is our plan for the rest of the year. We currently have an inventory of 20 gross, 15 net wells, composed of three fracking, three starting flow back, and 14 waiting on frack, with 4,600 net BOPD of potential production.

480-acre down space wells have been drilled, two are starting to flow back oil, and the other two are being fracked. In the Niobrara we are producing a $1,100 net BOPD from 20 gross wells with two additional wells cleaning up after frack. Our first 260-acre down space test wells are producing with no apparent interference and two more 160-acre down space wells have been drilled and are being fracked.

We have one drilling rig running and plan to stay at that pace through the year-end. In the Marcellus, we are producing in Susquehanna County from 21 gross wells, we’re currently running one drilling rig and one frack crew in Wyoming County, preparing wells to go online into the southern laser pipeline, which William should have operational in October.

Some of our Wyoming County wells are tested over 10 million cubic feet per day. All of our current JV gas with Reliance is being sold north on the laser pipeline to millennium pipeline, which is not as backed up as the Tennessee pipelines. So we are netting about a $1 per Mcf better than the Tennessee pipeline, which has been in the news this week. In the [C Counties] we have two fracks left, which should be complete by Mid-September.

After those fracks, we plan to stop all Marcellus fracking until late November, early December. In West Virginia we finished fracking and begin testing our horizontal wells and are investigating in nearby pipeline to begin producing for a long flow test. Our Barnett shale activity is currently focused on work overs and production optimization.

In the North Sea, we have completed the drilling of four producers and two injection wells and the released the drilling rig. The FPSO upgrade is nearly complete and is now scheduled to sail to the field next month with first oil currently expected in the fourth quarter. Carrizo’s working interest share of plateau production is now expected to be up to 5000 net BOE per day based on the success of our drilling program and recently completed FPSO de-bottlenecking study.

Total Company guidance for the third quarter is expected to range between 92 and 96 net million cubic feet per day and 7800, 8200 net BOPD. In the liquids rich area of the Utica in Ohio, our JV has closed on about 29,000 acres with another 15,000 expected to close, Richardson Barr RBC ran a sales process for invested capital in our JV partner through some of our joint acreage in the Northern Counties. Multiple acceptable bids were received and we are joining with the Vista to begin working on the sales documents in the potential third quarter closing.

We currently expect that we will ultimately receive net proceeds of approximately $40 million of the consequence of this sale. In the second quarter, we engaged Scotia Bank to put together a sales packet for North Sea Huntington asset, aiming for bids by mid summer, we received multiple bids for interest and are currently working with the bidder to obtain financing, we also continue to discuss this opportunity with other bidders.

We have advanced our search for a Niobrara joint venture partner and have begun working on purchase and sale documents for a 25% to 30% partner. That is it for the operational update, we will be glad to take questions.

Question-and-Answer Session

Operator

(Operator Instructions). And our first question is from the line of Will Green from Stephens. Please proceed.

Will Green – Stephens Inc.

Good morning, guys.

Unidentified Company Representative

Hi Will.

Will Green – Stephens Inc.

I wonder if we could start on the acreage adds – the La Salle County acreage – is that contiguous to anything, you’ve already drilled, where is that in relation to the other stuff that you guys have?

Unidentified Company Representative

The acreage we bought in the Eagle Ford was all contiguous or tucked in to acreage we already have and we feel like we’re buying essentially what will be PUDS for about a $1.60 a barrel.

Will Green – Stephens Inc.

Gotcha. And then on the Niobrara the acreage you added there, when would you guys look to start drilling in that zone? Would you look to have that JV by that point? Are you kind of at a standstill until the JV gets done or are you guys looking to take it over there pretty shortly and start drilling that up?

Sylvester P. Johnson

No, I don’t think we’ll start drilling there in the next few months because we have a plan already for HP being the acreage we have northeast of Denver. But it won’t have any bearing on the JV. The JV partner would be in that acreage too and we would probably start drilling that early next year.

Will Green – Stephens Inc

Okay, great. And then one other I had, dry gas pricing for you guys has been running about in the $0.90 off NYMEX or so the last couple of quarters. Obviously that has to do with Barnett production versus Marcellus. How will that look? Or can you give any color as to how that will look now that a big chunk of Barnett has been sold?

Sylvester P. Johnson

I don’t think it changes it very much. To get the gas out of Mansfield, or really anywhere in Tarrant County, is going to involve those kind of price deducts so that’s just the price to get out on three different lines to get to WAHA or Carthage or Houston Ship Channel.

Will Green – Stephens Inc

I guess my point is, is now that you have a bigger chunk of dry gas coming from Marcellus, should we expect that to help the differential a little bit going forward for the total Company?

Sylvester P. Johnson

I mean our net price in the Barnett was $1.15 for the quarter and for the Marcellus it was $1.56.

Will Green – Stephens Inc.

Okay, great. Thank you for that. I will let anyone else will get a chance.

Operator

Our next question is from the line Leo Mariani from RBC. Please proceed.

Leo P. Mariani – RBC Capital Markets, LLC

Hi, guys just wanted to delve a little bit more into the purchase of the Eagle Ford acreage, what are you guys paying for that in terms of dollar per acre.

Sylvester P. Johnson

Generally running around 4,500 per acre to 5,500 per acre.

Leo P. Mariani – RBC Capital Markets, LLC

Okay, I guess similar question in the Niobrara in terms of what you picked up there.

Sylvester P. Johnson

I believe we paid about 3,000 per acre on that deal.

Leo P. Mariani – RBC Capital Markets, LLC

Okay, and I guess on the financial side, I wanted to get a sense of where your bank debt was, I guess as of June 30 and then what your CapEx was in the second quarter?

Paul F. Boling

Yeah, let me – I will take the CapEx, this is Paul. We are looking at total CapEx in the second quarter of about $183 million, that’s domestic. The North The North Sea CapEx is another $10 million, so the total is about $192 for the quarter.

Leo P. Mariani – RBC Capital Markets, LLC

Does that include the acreage purchases that you guys disclosed or not?

Paul F. Boling

It does. The acreage relative to that total is about $41 million.

Leo P. Mariani – RBC Capital Markets, LLC

Okay. And then how about on the bank debt side?

Paul F. Boling

We had $130 million outstanding at June 30.

Leo P. Mariani – RBC Capital Markets, LLC

Okay. And I guess, just on your oil production – obviously you guys had a massive surge this quarter, guiding towards less growth as we get into third quarter. Can you kind of walk us through the mechanics? Is a lot of this just sort of the way the timing is happening on the completions and would we expect kind of a reacceleration in the fourth quarter? Just any color you have on that?

Sylvester P. Johnson

That’s probably fair, I mean, what we are dealing with this month is we are starting to drill pads next to existing pad. So we have to shut the existing ones down. And so we built all of those shut-ins of production into the model. In the past, we were nearly always drilling pads out by themselves to hold acreage. So we just have to factor that in.

Leo P. Mariani – RBC Capital Markets, LLC

Got you. All right. Thanks, guys.

Operator

Our next question is from the line Jeff Hayden from KLR Group. Please proceed.

Jeffrey Hayden – KLR Group

Hi, guys. One quick follow-up to Leo’s question on CapEx. The $10 million in the North Sea, was that covered on the project financing side or is that in addition to that?

Sylvester P. Johnson

That is correct. The project financing is covering all of our CapEx in the North Sea for this year.

Jeffrey Hayden – KLR Group

Okay, great. And then, just wondering if you guys could elaborate a little more about what you’re seeing in the Marcellus? You guys referenced flatter tight curves. Wondering should we be looking for any impact on, or it should be a flatter decline rate, should we be looking for any impact on your tight curves or kind of what you are expecting to get up there in the northeast PA?

Brad Fisher

This is Brad Fisher. No, I don’t think we’re really adjusting out tight curves at this point. What we basically sacrifice was a little bit more peak rate for some flat rate. So from an overall reserves standpoint, I think the northeast PA, we’re still thinking 6 Bcf to 7 Bcf per well, and as far as rate goes, I think we just flattened it out on the front end.

Jeffrey Hayden – KLR Group

Okay. And then looking at the mid-year reserves, what kind of price related write down was embedded in those mid-year numbers versus year-end?

Sylvester P. Johnson

We had no impairment during the second quarter.

Brad Fisher

Yeah, so the gas reserves were okay. There wouldn’t have been any oil reserve write-downs anyway and most of the reserve adds were basically Eagle Ford and Niobrara drilling results.

Jeffrey Hayden – KLR Group

Okay. I appreciate it, guys.

Operator

Our next question is from the line of Michael Glick from Johnson Rice. Please proceed.

Michael, A. Glick – Johnson & Rice Company L.L.C.

Good morning. Just a question on the Utica. I’m just curious as to your plans with the capital from the potential sale, do you apply that back into the southern Utica acreage to add more acreage or potentially drill a well down there?

Chip Johnson

In the Southern Utica we are still trying to buy acreage. It’s gotten very competitive. So we might be running up against a wall here. The majors are now in the courthouse with us along with all the normal competitors we have in the independent world. So that money we bring, we’ll just use that immediately to pay down the revolver and then we will think about what to do with it next. We’ve been trying to work on a drill site that would get us some good information since there’s not a lot of great public information there aside from press releases, but we haven’t made a decision yet to drill that well.

Michael, A. Glick – Johnson & Rice Company L.L.C.

Okay. And then, in the Niobrara, I know you guys have kept a one rig program because it’s a little bit riskier on a profile compared to the Eagle Ford, but what’s the thought process regarding, adding another rig there, maybe next year if you do get proceeds from the North Sea and maybe drilling some lower risk on down space wells?

Chip Johnson

We can do that. It’s just going to depend on capital availability. We have the capital to do it. We might be comfortable enough there now and knowing where the sweet spots are to spend more capital there and, but our choice would be spend capital in Eagle Ford or spend capital there. We also are working on this joint venture and that could have some bearing on what we do in the Niobrara next year.

Michael Glick – Johnson Rice & Company

Okay. And then on that southern acreage, you bought in the Niobrara, I mean do you see any potential for the A and C benches or the code out down there?

Sylvester P. Johnson

We think all of that could work down there. That’s in an area where you probably trade off gas oil ratio for less geological risk. But we felt like this was a pretty strategic acquisition because it puts us in an area of where there is acreage around us in some cases owned by the city and the state that could be available and we bought this acreage for less than half of what Conoco paid for their acreage.

Michael Glick – Johnson Rice & Company

Okay. Thank you.

Operator

(Operator Instructions) Our next question is from the line of Marshall Carver from Capital One Southcoast. Please proceed.

Marshall Carver – Capital One Southcoast, Inc

Yes, with the new CapEx budget, could you give us a breakdown for the full year on drilling versus land and seismic and other?

Paul F. Boling

Yeah, this is Paul again. The revised budget indicates we are going to have drilling and fracking for the full year of $525 million, and for land and seismic about $74 million. Again that’s our domestic budget.

Marshall Carver – Capital One Southcoast, Inc

Okay, thank you. And how many acres did you have in the northern part net acres in the Utica and then how much do you have remaining for the southern part now?

Paul F. Boling

That’s a trade secret.

Marshall Carver – Capital One Southcoast, Inc

Okay.

Paul F. Boling

And just we are in the middle of negotiations on a lot of things there and that’s all we can say.

Marshall Carver – Capital One Southcoast, Inc

Okay. Well, that’s it for my questions. Thank you.

Operator

Our next question is from the line of Maggie Savage from Robert W. Baird. Please proceed.

Maggie Savage – Robert W. Baird & Co

Hey, thanks for taking my question. Can you give any color on the confidence you have around your North Sea shale or just any additional details?

Sylvester P. Johnson

I am afraid, we can’t. We are just right in the middle of negotiations right now, and do not want to say anything else...

Maggie Savage – Robert W. Baird & Co

Okay. And is there anything, aside from financing, that needs to be complete like any environmental consideration or any other sorts of approvals we need to think about?

Sylvester P. Johnson

I cannot say.

Maggie Savage – Robert W. Baird & Co

Okay, that’s it from me, thanks,

Sylvester P. Johnson

Sorry.

Operator

Our next question is a follow-up from the line of Jeff Hayden from KLR Group. Please proceed.

Jeffrey Hayden – KLR Group

Hi, guys I was just wondering if you had any updated thoughts on the Pearsall potential on your La Salle stuff?

Sylvester P. Johnson

We own a lot of Pearsall rights underneath our Eagle Ford acreage. We’ve been intrigued by the results that Cheyenne has had. We’re very intrigued by the deal Cabot did with Osaka, because we own some of the acreage in the box that they put in your presentation. There are other wells being drilled around us, that we are going to watch and we put together some plans on what it would take for us to test with the vertical well or with a horizontal well in some of our acreage, but right now we are, since we really don’t have to do anything in the near term, we’re watching the industry wells around us to get some idea on what oil rates are.

We don’t think that unless the wells make oil or condensate that they’re going to be profitable. There’s just not enough profit in dry gas and NGLs to pay for some of these wells, so because they are three or four thousand feet deeper than the Eagle Ford.

Jeffrey Hayden – KLR Group

Okay. And do you guys based on your lease terms, are you actually holding the Pearsall with the Eagle Ford wells or do you need to drill down to that depth to hold it?

Sylvester P. Johnson

Hi, it’s mixed. I think about a third of our acreage can be held with the Eagle Ford production, another third we have to drill with the Pearsall and about a third, we’re not really interested in because it’s so deep.

Jeffrey Hayden – KLR Group

Okay, great.

Operator

Our next question is from the line of David Tameron from Wells Fargo. Please proceed.

David Tameron – Wells Fargo Securities

Good morning. I don’t know if Chip or Paul – whoever wants to address this – and I apologize if I missed it but can you just give us a liquidity snapshot as far as revolver outdrawn, where you think that is up at year-end and head in to ‘13?

Sylvester P. Johnson

I don’t think, we could say what is going to be a year-end but it won’t be drawn. Right now we have $150 million to $200 million on it and we’re going through re-determination to see how much it goes up.

David Tameron – Wells Fargo Securities

Okay, so I mean right now there’s nothing drawn on the revolver, Chip?

Paul F. Boling

This is Paul. Right now the outstanding drawn revolver is about 185. And as Chip…

David Tameron – Wells Fargo Securities

Okay, so…

Paul F. Boling

And as Chip mentioned, we are in the process of scheduling a redetermination in September and we expect a substantial increase in the availability on that borrowing base as a result.

David Tameron – Wells Fargo Securities

Okay. So do you need the North Sea to close for 2013 funding?

Sylvester P. Johnson

No. we think we’ll probably be with our current plan whether we sell the North Sea or not. Our debt-to-EBITDA will be somewhere in the mid-twos, around the end of the first quarter next year. So at that point we are pretty comfortable.

David Tameron – Wells Fargo Securities

Okay thanks for the color. That’s all I have got.

Operator

There are no further questions from the phone lines. Okay, you have one actually who just queued up from Marshall Carver, Capital One Southcoast. Please proceed.

Marshall H. Carver – Capital One Southcoast, Inc.

Yeah, thank you for giving in last second. I did have a follow-up. So, with the higher drilling CapEx, do you have how many additional net wells by area that would be or could you give us some clarification between how much of that is higher, more well being drilled and completed versus is there any component for higher well cost?

Sylvester P. Johnson

I think there are a couple of questions there. We drilled more net wells than we thought we would in the first half, because we had an extra rig and we thought until this day we could drill an HBP some leases and decide later if we were going to frack them, so we now dropped that fourth rig and running three rigs. But as far as new wells coming on, the number didn’t go up that much.

What we did was we started getting so efficient fracking once we went to as many as six stages a day that we were burning through our inventory in spending a lot more capital than we anticipated within the first four or five months, so that’s why we’ve now gone to frac holidays where we released the rig or frac crew for two or three months a quarter that keeps us on the same track as far as wells bought on line, so we end up with about the same plan of well productions but we are working some of the time, we did drill some longer lateral wells and that’s where some of the extra capital went and we’ve seen great results from that, but in a lot of cases we can’t drill longer lateral wells just because of the lease geometry.

Marshall H. Carver – Capital One Southcoast, Inc.

Okay. So with the overall CapEx increase, what percent would you say is more activity versus higher cost?

Sylvester P. Johnson

Probably, all activity.

Marshall H. Carver – Capital One Southcoast, Inc.

Okay.

Sylvester P. Johnson

Our frac cost have come down per stage. The drilling rates haven’t come down but the frac costs have come down in the Marcellus and in the Eagle Ford. So that part has come down a little bit and the efficiency just fell, but we just drilled more wells and it’s long well.

Marshall H. Carver – Capital One Southcoast, Inc.

Okay, thank you.

Operator

There are no further questions from the phone line.

Sylvester P. Johnson

Okay, well, we are sorry, we couldn’t provide more detail on our ongoing property sales and potential JVs, but all of those are sensitive negotiating points and some are restricted by confidentiality agreements. More information should be available in the next 30 days. We continue to grow our oil production, oil revenue and oil cash flow. We also have significant Marcellus gas production come on line in Wyoming County at the same time the winter prices and pipeline availability are anticipated.

But still to summarize, we beat guidance on the oil production, we beat on gas production, we beat on LOE guidance, we didn’t take any write-downs, we cut CapEx and still maintain a high growth rate, we bought Kentucky and Eagle Ford acreage that is essentially a part. So thank you very much.

Operator

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

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