Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Carrizo Oil & Gas (NASDAQ:CRZO)

Q3 2013 Earnings Call

November 05, 2013 9:00 am ET

Executives

Sylvester P. Johnson - Chief Executive Officer, President and Director

Paul F. Boling - Chief Financial Officer, Vice President, Secretary and Treasurer

Andrew R. Agosto - Vice President of Business Development

J. Bradley Fisher - Chief Operating Officer and Vice President

Analysts

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Marshall Carver

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Michael Kelly - Global Hunter Securities, LLC, Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the Carrizo Oil & Gas Third Quarter 2013 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded, Tuesday, November 5, 2013. I would now like to turn the conference over to Chip Johnson, President and CEO. Please go ahead.

Sylvester P. Johnson

Thank you, operator, and thank you, everyone, for calling in for the third quarter call. Yesterday, Carrizo issued a press release announcing an underwritten public offering of common stock. We will not be able to discuss that offering on this call or take any questions about it. I refer you to our press release and the preliminary prospectus filed with the SEC.

Both myself and management are pleased to report another outstanding quarter for the company and several significant catalysts that we accomplished. I will start out the call with Paul Boling, our CFO, talking about the financial results; then I will talk about the operational status, and we will open it up to questions. So Paul, do you want to go ahead?

Paul F. Boling

Thanks, Chip. We achieved record oil production of 12,228 barrels per day. That's 41% above the third quarter 2012 and also exceeded the high end of our guidance for the quarter. Natural gas and NGL production was 106,685 Mcfe/d, or approximately 6,700 Mcfe/d above the midpoint of our guidance. We reported record adjusted revenues and revenues for the quarter. Adjusted revenues, including the impact of realized hedges, were $145.5 million in the third quarter 2013. Thanks to our continued growth in oil production, adjusted EBITDA was a record $114.8 million in the third quarter of '13, or $2.84 and $2.80 per basic and diluted shares. That's 33% above the prior-year quarter and 12% above the second quarter of 2013.

Our total cash costs and expenses of $30.8 million, comprised of $20.7 million in production costs and $10.1 million in G&A cost, was also within the guidance range provided for the third quarter. Accordingly, there are no material variances to report.

In the interest of time, please see the disclosure tables in this quarter's press release for further detail, including fourth quarter and full year 2013 guidance, including production, realized hedging gains, operating costs, G&A costs, DD&A, and drilling and completion expenditures. Additionally, see the cash flow from continuing operations statement that was added last quarter.

Our drilling and completion capital expenditures for this quarter were $126.5 million, which was below our expectations for the quarter, largely because of the delay in certain wells completed in our Marcellus play. We reported that our net debt to adjusted EBITDA ratio, using the trailing 4 quarters, is down to 2.4x for the third quarter. Annualizing the third quarter performance, the 2013 adjusted EBITDA is 2.16x. We had $87 million outstanding on our revolver at the end of September.

The borrowing base on the revolver is currently $470 million, following our fall redetermination that we completed recently. And the sale of substantially all of our Barnett Shale assets was also baked into that redetermination.

As of November 1, nothing is drawn on the revolver in connection with the recent receipt of proceeds from the Barnett Shale sale. Our significant oil hedge positions for the balance of '13 and '14 are 10,100 barrels a day, or nearly 80% of the midpoint of estimated production for the fourth quarter of 2013, and 10,500 barrels a day, respectively. We also have over 75% of our estimated natural gas production for the balance of 2013 hedged as well. Referring to the hedging table provided in the back, we'll provide you with additional detail in regard to our hedges. Chip?

Sylvester P. Johnson

Thanks, Paul. I'll now go over the operations summary. In the Eagle Ford, we're producing from 108 gross, 85 net wells, with 3 drilling rigs running and 1 24/7 frac crew. At the end of third quarter, we had an inventory of 32 gross, 24 net wells, representing 8,900 net BOPD of potential initial production.

Our down-spaced wells with 500-foot spacing have enough production and pressure history now to justify changing our development plan to 500 feet going forward. This adds about 145 additional net wells to our drilling inventory, bringing that to 552 wells, or about a 12-year drilling inventory at the current 3-rig rate.

With 500-foot down-spacing included, we've increased our estimate of net reserve potential in the Eagle Ford by over 30% to roughly 224 million BOE. We've also identified 2 wells to drill and test 330-foot spacing, what some of our competitors are already assuming is normal.

In the Niobrara, we're producing from 67 gross, 27 net wells with 10 gross, 3.3 net wells waiting on completion, representing 1,090 net BOPD as potential initial production. We drilled 2 60-acre downspace pilots in the B bench, which will be frac-ed within the next 60 days. These results could also be very significant, potentially raising our drilling inventory in the B bench from about 337 to 447 net wells. We have 2 drilling rigs running in the play and plan to stay at that pace for the rest of 2013 and into 2014.

In the Marcellus Shale, we are producing from 56 gross, 18.6 net wells in Susquehanna County and Wyoming County, Pennsylvania, with gas sales into all 3 major pipelines. We're currently running 1 drilling rig with a frac crew scheduled to start on November 12.

We have 26 gross, 8.0 net wells waiting on completion. Our production capacity in the Marcellus Shale currently exceeds 60 net million cubic feet a day, but we're electing to limit our production when local prices are especially weak. These stream bottlenecks are slowly being resolved with additional interstate pipeline capacity and compression modifications by Williams currently in progress.

In the liquids rich area of the southern Utica in Ohio, we have closed on an acquisition of about 5,900 net acres from our JV partner, Avista Capital. Including these acres, we now have 21,700 net acres in the play and about 120 potential drill sites in the core of the high condensate window of the play at 150-acre spacing, equating to net resource potential of 134 million Boe.

We continue to lease in the eastern Guernsey County and northern Noble County areas. On our Rector well, we had finished the 31 frac stages last night on the 7,890-foot lateral and have began a resting period of 60 days, so flowback should start around year-end.

We were successful in the closing of the sale of our Barnett Shale assets, October 31. With the sale of the Barnett, along with the sale of other non-core asset previously announced, we continue our transition to a portfolio of premier oil assets and also improved the balance sheet, as Paul noted. Total company production for the fourth quarter is expected to range between 12,600 and 13,000 net barrels of oil per day, an increase -- midpoint of this range represents an increase of 47% for the year versus 2012, an increase over the 45% we were using previously.

For gas and NGLs, fourth quarter production will range between 68 to 75 net million cfe per day, representing or reflecting the sale of the Barnett Shale on October 31. Our 2013 drilling and complete budget ended up at $555 million, $513 million for the original budget, and an additional $42 million Eagle Ford fracs in November and December. Third quarter operated drilling and completion CapEx of $126.5 million was under our projected budget. Land CapEx of $26.3 million in the third quarter, $26.3 million in the third quarter was spent primarily in the Eagle Ford and Utica. This is excluding the Avista deal and represents an $11 million increase in budget as a result of identifying and acquiring additional opportunities around our existing acreage blocks. With that, we'd like to open it up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Neal Dingmann with SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Chip, just your thoughts now when you look at the Utica after you've obviously been active in the play and very familiar what's going on now. Your thoughts as far as the different windows, as far as now when you add or potentially add additional acreage, your thoughts on the oil -- the condensate or the oil versus the condensate, versus the wet gas, versus the dry gas. Maybe you could, first of all, just sort of comment on your thoughts on each of the windows.

Sylvester P. Johnson

We've added some economic slides to our corporate presentation that will be on the website. And we basically think that the condensate window we're in is going to have about a 34% condensate proportion. Basically, we're using an average of Antero, PDC and Gulfport to come up with our numbers because that's the window we're in. We like the economics shown by Antero on their IPO. Ours aren't quite that good yet, but we don't have a well producing yet to base that on. So that's what we're using. We still think the condensate is going to be the most profitable. We still have concerns about ethane sales in the future. Although the industry is trying to find ways to move that ethane around and find a market for it, we'd still rather be producing condensate that we can sell through refineries.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

And, Chip, what do you see in an M&A activity? Just, I mean, in generalities. I mean no details, obviously, just in the play. I mean, are you still able -- I mean, obviously, besides this latest deal, are you still able to pick up some blocks in that? And maybe on -- if you could add to that, I noticed were you able -- year-to-date, you've obviously added about 9,000 acres also in the Eagle Ford. If you could maybe comment on that, too, just your thoughts on maybe picking up additional Utica acreage. I mean, would you look in the dry gas? Would you look in some of the areas, is that available? And then, two, is there more, call it core Eagle Ford acres like you have available, like the 9,000 you picked up year-to-date?

Sylvester P. Johnson

In the Utica, we've been able to add 500 to 1,000 gross acres per month just with the hard door-to-door leasing. We would look at the dry gas and the wet gas areas, also. The economics are good enough there, and we've been able to trade acreage with some of the dry gas players in our core areas. So the acreage is useful there. In the Eagle Ford, again, we've been able to add about 1,000 net acres per month this year. One of those big acquisitions was about 5,000 of that at one time. It's harder and harder to find good acreage blocks to buy. There aren't a lot of small companies left in our area that want to sell. But there are a lot of acres that are starting to become available that were leased back in 2010, and maybe they were stragglers that somebody wasn't able to put into a unit, and we can lease those acres now and put those in one of our units. So that's been working for us.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay, then just very lastly, and maybe from a generality is, I know on the slides, you talk about sort of expected -- and you mentioned this in your Utica economics, kind of expected the economics from between there at Eagle Ford, Niobrara and Marcellus. Given kind of what you are expecting, is it fair to say you would continue with that 2-rig program in the Niobrara or would you add, maybe take a rig from there? I mean, how -- I guess, what I'm asking is how fluid is that capital spending program next year if your economics are higher in the Eagle Ford and the Utica? Could you potentially take a rig from the Niobrara? I mean, obviously, not that rig, but take -- move a rig out of Niobrara and add one to one of those higher economic areas?

Sylvester P. Johnson

I think we'll be in a position at the end of next year to shift capital around to the highest IRRs. But right now, in the Utica, because of the lack of midstream and the delays in getting things online, that we're not trying to accelerate that until we have pipelines in place and some actual well data that we have instead of everybody else's data, which will probably around the end of 2014. So our plan next year is one rig in the Utica starting sometime early in the year. We'll stay at 2 rigs for now in the Niobrara, and we like 3 rigs in the Eagle Ford. We're already drilling more than we can afford to frac.

Operator

And our next question comes from the line of Adam Michael with Miller Tabak.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

When you're adding acreage in both the Eagle Ford and the Utica, do you have -- are your respective partners participating with you? So like, if you were to add, say, 500 to 1,000 acres a month in the Utica, is the vested capital still going along with you on that?

Sylvester P. Johnson

Post the acquisition of a business, 5,900 acres, we now have basically 2 areas with them where we still have acreage 50-50 with them. We have an area of mutual interest with them right around those acres. So when we buy there, they buy as much as we buy. In the rest of the play, we no longer have an AMI with them. So we're -- we can buy acreage there 100%. In the Eagle Ford, we've been buying some acreage and sometimes, our partners go along with it. GAIL has gone along with most of our acquisitions. CNOP [ph] doesn't always go along with our acquisitions, but they are our biggest partner now because of some acreage -- our biggest partner in one area because of some acreage we bought from Chesapeake.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Okay. And then in the Eagle Ford, where you picked up the 3,500 net acres, what would be the average working interest there? Is it like a 50-50 with GAIL or how does that work?

Sylvester P. Johnson

Andy, do you want to address that?

Andrew R. Agosto

Yes. Specifically on those 3,500 acres, the majority of that was 100%. As Chip mentioned, the -- for GAIL specifically, we have a small AMI near the acres they originally acquired from us back in 2011. But for the third quarter, most of the acreage we picked up was 100%.

Operator

And our next question comes from the line of Michael Glick with Johnson Rice.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Just a quick question on the Utica. Can you kind of just walk us through what percentage of your acreage you think is amenable to the longer laterals, like 6,500, or 7,000 feet-plus?

Sylvester P. Johnson

Jim or Brad, do you want to take that question?

J. Bradley Fisher

Yes, on our acreage position where we kind of have planned out our pads, the majority of our acreage, I'd say, well over 80% of it is amenable to the longer laterals. There will be some pooling that will have to go on in unitizing with other operators, but in general, a lot of our pads with our existing position layout for very long laterals.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Okay. And then could you just walk us through maybe the thought process of buying the 5,900 acres versus the whole of this package?

Sylvester P. Johnson

When Avista ran a process to sell their acreage, they had different kinds of bids, some conforming, some not. Some of the bids were actually addressed to them and us, which helped us come up with market price. We felt like this was a fair price. It's about 12,500 per acre for the -- really, the core acreage between Antero, the PDC area and the Gulfport area. As we went west from there, we disagreed on the price. There's not as much well control out there. Avista had reached a total proceeds that they were comfortable with, and they said we're happy with this number, let's stop. We can talk about the other acreage later. And they also transferred full operations to us, so now, we're the operator, not the cooperator of those other acreage blocks.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Okay, great. And then maybe just generally, curious on your thoughts on the appropriate resting period in the Utica.

Sylvester P. Johnson

We're not experts on this by any means, since we're on our first well, but we're basically going off of what both Gulfport, Antero and PDC have said. And it seems like 60 days has been the number. I know a couple of days ago, PDC handed that it might -- they might start going a little less than that. Gulfport tried a lot less than that, I think, in September. And my take on that was that they would probably go back to longer resting periods. I think we'll go with 60 just not to take any chances on our first well.

Operator

And our next question comes from the line of Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Can you maybe comment on how thick your section is in the Eagle Ford and if there's potential to drill in the upper Eagle Ford wells in your acreage?

Sylvester P. Johnson

I guess our Eagle Ford, most of La Salle County, is around 125 to 175 feet thick. Not everybody agrees on where the top of the Eagle Ford is and the bottom of the Austin Chalk. There is some section that we see above what we think is productive that has some thickness and low porosity. And it looks just it wouldn't support a standalone well. But it's probably worth to test higher up in the section to see if that's a better place to put a lateral than towards the bottom. And we've tried that in some cases already, but we'll be following other companies' test in the upper Eagle Ford this year. Some of those are in Weld Country. Our thickness is not a lot different than theirs, and the porosity doesn't look a lot different. But it still could work and it could be a better way to drilling the whole system than the way we're doing it now. We just have to keep trying all these things.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then, I know 2013, you're kind of drilling more than competing, and you're going to accelerate that a little bit for the remainder of the year. How does -- I mean, are we going to -- are you going to see that backlog grow again in 2014? Or when do you get to the point where you're potentially frac-ing more wells than you're completing -- than you're drilling?

Sylvester P. Johnson

As planned right now, it still grows again in 2014. And there's obviously 2 ways to fix that. You can slow down the drilling once you've HBP-ed [ph] everything for a while, and we constantly look at that. And you can also accelerate frac-ing once you have the cash flow to be able to do that and stay within your debt-to-EBITDA guidelines. So that's something we also look at constantly.

Brian M. Corales - Howard Weil Incorporated, Research Division

And your debt-to-EBITDA guidelines, is it sub 2.5 now or what is that?

Sylvester P. Johnson

We want to be between 2 and 2.5. And so, sometime next spring will be a good time to look at that again because that will be the first time we have another frac holiday, will be sometime in the spring. Well, basically, now with this acceleration not going to slow down for 3 months.

Operator

And our next question comes from the line of Adam Leight with RBC Capital Markets.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Can you tell me what your current natural gas production is and how we should think about the trend in '14, given your drilling program and your price cuts?

Sylvester P. Johnson

Brad, you can probably address the current production. Going forward, though, I think we'll be bringing on additional production in the Marcellus all spring as we frac the big backlog we have there and frac water is available, and as gas markets are better. The -- what we have to do is figure out a way to guess long-term contracts to get us through next summer because we think there will still be a gas glop in Appalachia next summer since there's not going to be that much more gas demand along the East Coast. So what we're going to try to do in the winter, when all our gas is flowing and people are getting good prices, is try to lock in something for next summer. Right now, our capacity in the Marcellus is about 60 million cubic feet a day. I don't know what we're selling today. Fortunately, Transco lighty [ph] really popped up nicely yesterday, which must reflect some cold weather. So we'll be able to fill up that line as much as we can. Next year, by the middle of next year, our Marcellus position, total gross can get up to about 300 million cubic feet a day and with our NRI on that is about 30%. So we would have a lot of capacity next year -- or maybe 25%. And we just don't know what the markets will be like next year, and that's why we're waffling on our guidance next year. It's pretty easy to predict Eagle Ford gas because it's kind of a byproduct of our oil, but on the natural gas side, we have some work to do before we come out with some good guidance on that.

J. Bradley Fisher

Chip, on the current production, with the exclusion of the Barnett, which obviously closed, we're about 50 million a day. And as you alluded to, we have about 30 million a day right now shut-in, in the Barnett for price. So we have...

Sylvester P. Johnson

In the Marcellus.

J. Bradley Fisher

Pardon me, in the Marcellus for price. So we have the capability right now to produce a bit over 8 million a day.

Operator

[Operator Instructions] And our next question comes from the line of Marshall Carver with Heikkinen Energy Advisors.

Marshall Carver

Utica, you're going to be running one rig starting early next year. About how many wells could that drill? Would those be all 100% wells? And about how many of those wells do you think could go on line next year? Will it be a big -- will the completions match the drilling or will it be a big delta between those?

Sylvester P. Johnson

No, I think right now, we assume we'll have about 9 net wells next year. And so some are 100%, some are 50%. Probably all of them will have somebody else in them, whether it's Gulfport, Antero, Eclipse, PDC, just because there's so many people in these units. We will, of course, have the resting period after we drill them. So we're not expecting a lot of production next year. We're still modeling that and we'll have some guidance on that probably in January.

Marshall Carver

Okay, do you -- would you expect that you'd have infrastructure available? Or is that...

Sylvester P. Johnson

No, we should. I mean, because we're drilling around other people's existing production, MarkWest and Blue Racer already have pipe into those areas and they're both bidding to get our business, and we just need to make some choices about a global partner, midstream partner or specific smaller area, the midstream partners, and then that shouldn't be a problem to get those wells hooked up.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Okay. One more question. On the Barnett, how much of the production is NGLs? Or how -- or what is your current NGL run rate? You gave it to us, but do you have the NGLs as well separately?

Sylvester P. Johnson

Barnett was essentially 0. So everything else is coming out of Eagle Ford and Niobrara. Marcellus is essentially 0.

Operator

And our next question comes from the line of Graham Tanaka with Tanaka Capital Management.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Just wondering with the long inventory that you have of drilling product mix, what you're going to be doing in terms of rig growth going forward, say, next 5 years, relative to...

Sylvester P. Johnson

Right now, the plan for 2014 is to stay at 6 gross rigs, 3 Eagle Ford, 2 Niobrara, 1 Appalachia, which next year will be Utica. If we have the cash flow at the end of next year to add a rig in 2015, we'll do it and we'll put it in, whatever has the best IRRs and the easiest logistics.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

So I'm just wondering, your inventory fairly goes pretty far out. I imagine then you were anticipating longer gross in years 3, 4, 5, and continued growth in rig count?

Sylvester P. Johnson

Yes, any time we have the capital to add another rig, we will. I mean, it would certainly pay us to bring forward a 12-year inventory in the Eagle Ford. It helps the PV, and that's just what we should do. But we just have to be mindful of how much that costs to do. So we'll add rigs in the future as we have the capital available to do that.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

So how consistent are you seeing -- well, you have one well drilling now, but I mean, in Utica [indiscernible], it implies you're happy with what you've seen with the neighbors. I'm just wondering where there might be upside or downside in terms of what drilling results you might be seeing.

Sylvester P. Johnson

I think there's upside and downside in the Utica just because the play is so new in the Southern area. We've seen some tremendous rates, production rates in condensate, NGLs and dry gas in the southern end of the play. And it seems like the numbers just keep going up. Antero's have some incredible rates lately. Some of the early wells weren't drilled with very long laterals. Now we've been able to do that and we've been able to put drilling units together with people around us so that we can drill longer laterals, that's going to help the economics. The downside is just there's not that much history in the Utica in the southern end of the play and we just need more time. Based on these really high rates, it's hard for us to imagine that you will ever want to down-space this reservoir. You just don't need to. The permeability looks high enough that 1,000-foot spacing at this point looks like that's enough. If you down-space, you're probably just accelerating. But again, we're saying all this with our first well frac and not on production yet.

Operator

[Operator Instructions] And our next question comes from the line of Michael Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Chip, you guys obviously had a pretty full plate now, having scale in the Eagle Ford, Niobrara and now Utica. But I'm curious what your thoughts are on the new ventures from. Really haven't talked new ventures with you guys in a while, but the balance sheet now looks to be in great shape. You got the revolver completely, pretty clear. You guys have been pretty good at assessing this kind of new resource plays in the past. Just kind of wondering if you can start to do that type of work. I'm sure you are, but if that becomes a bigger part of the program as you progress in 2014.

Sylvester P. Johnson

Yes, I don't think it's going to be a big part of the program going forward. We have 3 or 4 people, geologists and engineers and business people, that are always looking for the next play. We also have some well-financed partners now that want to invest more money in the U.S. and want some new plays. But we just haven't found anything yet that fits the bill of being, have upside, be very safe, and they will pay 90% to 100% of the upfront capital on. So that's -- we keep looking for those, but we just haven't just found anything in a year.

Operator

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

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Chip, let me take the other side of Mike's question. If I think about your portfolio, and the Utica does look -- do you think you can do with the Eagle Ford, what's your longer term plan for the Marcellus, and then, secondarily, for the Niobrara? Should we think about those as potential [indiscernible candidates?

Sylvester P. Johnson

We're not sure. I mean, the Marcellus, we still need to test the upper Marcellus. Cabot had some good results in their area and we're all around them. We drilled 2 upper Marcellus wells and we'll be frac-ing those probably in the first quarter. So that could be a significant upside. I mean, in the past, once we've gotten an asset to the point where we don't see much upside and the declines are fairly predictable, we've sold it. But we're not going to be at that point. I don't think we'll be at that point in the Marcellus for some time. We still have some things to do to test that. I don't think down-spacing is going to work there, again, because the well -- the reservoir is so permeable, it seems like we're draining it pretty efficiently at 1,000-foot spacing. But we do need to test the upper Marcellus, and that will act as our pseudo-down-spacing pilot because we'll use a stagger stack approach there where we drill the upper Marcellus in between the lower Marcellus. On the Niobrara, if we're making a 56% rate of return with that asset, it's going to be hard to sell it. If somebody made us the right price, we -- or right offer, of course, we'd sell it and put that money into something with a higher IRR. But it does represent a lot of reserves and a lot of value. And so we're going to keep testing and also try to figure out what the right down-spacing and the contribution from the A and the C benches before we do anything with it.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. That's helpful. And then you might have mentioned this, but your plans on testing the 300 -- I guess, the 40-acre space in the Eagle Ford, I know others have had success, but what's your type in for that estimate?

Sylvester P. Johnson

I think we'll probably drill the wells in the next 3 or 4 months. And it'll take them probably 90 days to frac them and test them. The Irvin Ranch wells that we just tested have a -- for the 500-foot downspacing have about 75 days of production history. Maybe we didn't need to wait that long. But there's a lot more competitor data on 500-foot spacing than there is on 330-foot spacing. So it'd probably take at least 90 days to make that decision. Once they're producing, there's not much interference or at least quantifiable interference.

Operator

Thank you. And there are currently no further questions on the phone lines. I'll turn the call back to you now.

Sylvester P. Johnson

Okay. Well, thank you all for calling in. It was obviously a great quarter. Just to summarize all the major catalysts that have happened in the Utica, we bought 5,900 net acres from our partner, Avista Capital, giving us over 20,000 net acres in the play now. We also, last night, finished frac-ing our 7,900-foot lateral with 31 stages, started resting the well and that will come on IP test at year-end. In the Eagle Ford, we feel like we've justified down-spacing to 500 feet now, which raises our well inventory to 552 wells, which is about a 12-year inventory at our current pace. And by accelerating the frac-ing in the fourth quarter, we're able to increase our 2014 oil guidance to more than 40% growth rate, which we think will be one of the best in the industry. We finished our non-core asset sales. That brings our debt-to-EBITDA down to our target level close to 2.0. And it was bittersweet to sell Camp Hill in the Barnett Shale. Camp Hill was how we started the company 20 years ago this month, and the Barnett was how we grew the company from 2003 to 2008. We worked with some good partners, and specifically, the cities of Arlington, Mansfield and Pantego, and the University of Texas at Arlington. So thank you, all, for being on the call, and we'll talk again in 90 days.

Operator

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

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

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

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

Source: Carrizo Oil & Gas Management Discusses Q3 2013 Results - Earnings Call Transcript
This Transcript
All Transcripts