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Carrizo Oil & Gas (NASDAQ:CRZO)

Q4 2013 Earnings Call

February 25, 2014 11:00 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

Analysts

Will Green - Stephens Inc., Research Division

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

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

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Jeffrey Grampp - Northland Capital Markets, Research Division

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Chad L. Mabry - MLV & Co LLC, Research Division

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

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Carrizo Oil & Gas 2013 Year End Earnings Call. [Operator Instructions] As a reminder, today's conference is being recorded, Tuesday, February 25, 2014.

It is now my pleasure to turn the conference over to Chip Johnson, President and CEO of Carrizo Oil & Gas. Please go right ahead.

Sylvester P. Johnson

Thank you, Lindsay. Thank you, all, for calling in. We'll kick off the meeting now. Paul will go over the financial results for the fourth quarter and the year end, then I'll go over the operation status and then we'll open it up to Q&A. So, Paul, do you want to get started?

Paul F. Boling

Thanks, Chip. We achieved record oil production of 13,033 barrels per day. That's 44% above the fourth quarter of 2012 and also exceeded the high end of our guidance for the quarter. Natural gas and NGL production was 70,435 Mcf a day, within our guidance range.

Adjusted revenues including the impact of cash received from derivative settlements were $131.9 million in the fourth quarter of 2013. Adjusted EBITDA was $101.2 million in the fourth quarter of 2013, or $2.36 and $2.32 per basic and diluted shares. That's 8% above the fourth quarter of 2012. Our total cash cost and expenses were $30.7 million for the quarter, comprised of $18.9 million in production costs and $11.8 million in G&A costs, and was also within our guidance range. Accordingly, there are no material cost variances to report. In the interest of time, please see the disclosure tables in this quarter's press release for further detail including first quarter and full year 2014 guidance.

Our drilling and completion capital expenditures for this quarter were $124.1 million, which was below our expectations for the quarter, largely due to better-than-forecasted deficiencies in both drilling and completions. Approximately 68% of the fourth quarter drilling and completion spending was in the Eagle Ford. We reported that our net-debt-to-adjusted-EBITDA ratio using the trailing 4 quarters is less than 2x for the quarter. The borrowing base on the revolver is currently $470 million with nothing drawn currently, or as of the end of the fourth quarter. Our significant oil hedge positions for the balance of 2014 are 12,000 barrels a day, or nearly 84% of the midpoint of estimated production for the first quarter of 2014. Using the midpoint of guidance, we are also having approximately 70% of our estimated natural gas and NGL production hedged for the balance of this year. Please refer to the hedging table provided in the back for additional detail in regard to our hedges.

We recorded a noncash loss of $45.4 million in the fourth quarter related to the sale of substantially all of our remaining oil and gas properties in the Barnett Shale.

For the first quarter of 2014, we project that our total company realized price for crude oil will be approximately 97% to 98% of NYMEX. We also project that our Eagle Ford Shale realized oil price will be approximately 99% of NYMEX. Our realized price projected for natural gas and NGLs is projected to be approximately 92% to 96% of NYMEX.

Beginning with the first quarter of 2014 earnings, we will make a change in our presentation. We will report noncash interest expense and noncash capitalized interest as a component of adjusted net income in our statement of operations included in the quarterly financial results. Chip?

Sylvester P. Johnson

Thanks, Paul. Our management team is pleased to report another outstanding quarter for the company as well as the completion of our transition from gas to oil. With the sale of our remaining Barnett Shale properties during the fourth quarter, our reserves and production are now both leveraged to oil, meaning about 60% both production and reserves are oil, not liquids; oil. For 2013, we delivered a 485% reserve replacement at an attractive finding cost of $10.93 per Boe. This brought our year-end proved reserves to $101.5 million Boe of 60% versus 2012 after adjusting for divestitures. Even with the asset sales, our year-end PV-10 rose by 44% to $2 billion. Oil now accounts for more than 60% of the proved reserves.

In the Eagle Ford, we're producing from 131 gross, 102 net wells with 3 drilling rigs running and 1 24-7 frac crude. We have an inventory of 30 gross, or 23.8 net wells, representing 8,900 net BOPD at potential initial production. We are currently developing our Eagle Ford position on 500-foot spacing, which gives us an inventory of about 12 years at the current 3-rig rate. We're currently drilling our first 2 pairs of 330-foot space wells and we'll have production results early in the second quarter. 330-foot down spacing could add another 200-plus net locations to our inventory, extending it another 4 years.

We exited 2013 with a total of 62,200 net acres of Eagle Ford leasehold and have added 3,300 net acres so far in the first quarter of 2014, bringing our total to 65,500 net acres.

In the Niobrara, we are producing from 84 gross, or 35 net wells, to 7 gross, or 2.2 net wells, waiting on completion representing about 600 net BOPD of potential initial production. We have recently drilled and frac-ed our first 2 60-acre down-spaced pilots and are encouraged based on the early production results from these tests. These results could also be very significant, potentially raising our drilling inventory in the B bench from about 355 to 461 net wells. We have drilled our first A bench test and should have production data early in the second quarter. We have identified 85 net A bench locations at 80-acre spacing across our acreage. We have one operated drilling rig running and our current plan is to stay at that pace for the remainder of 2014 since we have almost one net non-operated rig in our budget.

In the Marcellus, we are producing from 64 gross, or 21.2 net wells, in Susquehanna County and Wyoming County, Pennsylvania, we have gas sales into all 3 major pipelines. We are preparing to drill our final plan, Marcellus well, for 2014, after which the program will focus on completing our inventory of drilled but uncompleted locations, which includes 500-foot infill tests in the lower Marcellus and 2 upper Marcellus tests. We're very encouraged by the logs on the upper Marcellus and Cabot's results next door to us, in the 11 to 13 Bcf range.

We have 30 gross, or 9.0 net wells, waiting on completion. Our production capacity in the Marcellus Shale is approximately 60 net million cubic feet per day but our production continues to be impacted by midstream delays and voluntary curtailments when local prices are especially weak.

In the liquids-rich area of the southern Utica in Ohio, we continue to be very pleased with the performance of our Rector well. The well has now been online for about 48 days and continues to produce over 500 barrels a day of condensate on a small choke. The condensate gas ratio of the well has been holding steady at roughly 250 over the last month. We plan to move the spudder rig into the play in March to begin drilling our next well, the Brown 1H, in northern Guernsey County to evaluate that acreage. We estimate that our 18,400 net acre position in the condensate window holds about 120 net potential locations on a 150-acre space.

Although our first quarter production, especially in the Niobrara, has been impacted by the severe winter weather, we are maintaining our previously provided production guidance. Total company production for the first quarter is expected to range between 14,100 and 14,500 net barrels of oil per day for gas, and NGLs' first quarter production should range between 60 and 66 net million cubic feet equivalent per day. Our 2014 drill and complete budget is currently $650 million to $670 million. 2014 land CapEx of $75 million is expected to be spent primarily in the Eagle Ford and Utica.

And aside from the outstanding operational and financial results, another milestone we achieved was the hosting of the company's first Analyst Day on January 28 of this year. We believe we were successful in demonstrating the quality of our assets by providing a very granular review of all of our project areas and each resource play area, and also showing how favorably we benchmarked versus industry across the different parts of our Eagle Ford play. The presentation materials are archived on our website if anyone missed the event.

With that, we'll open it up to Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question here comes from the line of Will Green with Stephens.

Will Green - Stephens Inc., Research Division

I wonder if we can start on the Eagle Ford and just talk maybe about what, if any, communication you guys are you seeing. And how confident you guys feel about 330-feet spacing?

Andrew R. Agosto

Will, this is Andy Agosto. As Chip just mentioned, we're drilling our first 2 330-foot pads right now. Those will be frac-ed in early April so we should have production data here shortly on that. Like you, we rely heavily on the data we can glean on what other operators are doing. We dissected the EOG release this morning and, obviously, are very encouraged by what they're saying, particularly about the additional information they've given on the Western area which, obviously, is where we are. So on that, I guess, I'll just say be patient, more data to come shortly. But our views, right now, are consistent with those of industry.

Sylvester P. Johnson

And I guess what EOG said this morning is that they're going to 40-acre spacing throughout the play and that's basically what we are testing now.

Will Green - Stephens Inc., Research Division

Great. And if you guys are successful, and it sounds there's at least a high degree of confidence across the industry that you will be at 330 feet, how do guys think about the optimum amount of inventory in the Eagle Ford? Given that you're running 3 rigs, 330 feet would obviously add quite a bit of inventory to the asset. How are you guys thinking about what's the optimum level to kind of bring forward enough present value but keep enough for longevity of growth and that sort of thing?

Sylvester P. Johnson

Well, I think that the inventory we'd like is about 100 years. But what we'll do is add as much inventory as we can and then add additional drilling rigs and frac crews as we have the EBITDA so that we can keep our debt-to-EBITDA around 2.

Will Green - Stephens Inc., Research Division

Great. So the plan, then, is to still kind of run whatever program allows you to stay at 2x debt-to-EBITDA and fit the rig schedule accordingly then?

Sylvester P. Johnson

That's right.

Operator

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 question on the Utica. How have the pressures held up during the extended production test?

Sylvester P. Johnson

They've dropped a little bit as you would expect. But they stayed at a very high rate where we think we can keep producing the well at this rate and still maintain very high bottom hold pressure. So that's been our goal.

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

Okay. And is there any update on the midstream side of things?

Sylvester P. Johnson

We have our proposals in from the 2 biggest players now and we're evaluating those, but we haven't made a decision yet.

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

Okay. And then the Brown well, I guess that will be the next one in the play. What kind of well design are you looking at in terms of lateral length and plan stages?

Sylvester P. Johnson

The Brown well is going to be on the order of 6,500-foot and 26 stages.

Operator

Our next question comes from the line of Neal Dingmann with SunTrust.

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

Say, Chip, back to the Utica quick. Just what are your plans -- the drilling plans? I know you talked about bringing a rig back in there. What are your plans for the -- I guess, where are you going to be sort of drilling, I guess, for the next year including the 50-50 owned acreage there?

Sylvester P. Johnson

The -- we plan to drill 9 gross wells during the rest of this year and the next well will be on the 50-50 acreage. Then I think we bounce around between North, South and middle, mostly in the middle where the Rector is because we have pads already built there and we'll have infrastructure there. So we want to test all of our acreage in all 3 areas and really get a handle on the EURs before we commit to a bigger program in the future.

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

And how much this year do you assume for Utica production for your guidance this year? Is there much baked in there?

Sylvester P. Johnson

For the year, I'd think it's 400 Boe per day.

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

Okay, just the total out there. All right and then just last...

Sylvester P. Johnson

And we were not expecting -- I mean, most of the production is going to be at the tail end of the year. Even this next well we're going to drill, the spudder rig goes in, in March but the big rig doesn't go in until April. Then after the frac and the resting period, you're out in the third quarter before you have any data. And then we'll make the decisions. Then, we'll be hooking up midstream. So it's going to be a while before we have much production.

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

Okay. And then, last one if I could. Just due to your comments interesting and in the press release about drilling in the Northeast Pennsylvania there on, I guess, it's Wyoming County. What are your thoughts, I guess -- again, I'm not sure what you're hoping to see or I guess, maybe beyond that, how active could you get if you start to see some pretty favorable results there?

Sylvester P. Johnson

Well, I think we're going to be impressed by the EURs we see in those wells, but I'm not sure how competitive the IRRs will be with our Eagle Ford and Niobrara drillings. So my guess is we'll try to prove this up and then we will start working on a plan for how we would develop it, maybe in 2015.

Operator

Our next question comes from the line of Kyle Rhodes with RBC.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

Just wondering how much production data you guys are going to need to see before formulating a new development plan based on the 330-foot spacing in Eagle Ford and 60-acre spacing in the Niobrara?

Andrew R. Agosto

I think we're going to be ready to move pretty quickly after we frac the wells. We'll do some microseismic, and then I think at this point, really for us, it's about validating what we've seen from industry with our own wells. So we're going to be ready to move very quickly.

Operator

Our next question comes from the line of Marshall Carver with Heikkinen Energy Advisors.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

A couple of quick questions. You talked about a weather impact in the Niobrara in the first quarter. Could you quantify that, how much production are you not getting because of the weather?

Sylvester P. Johnson

I think at times we've had as much as 400 barrels a day net shut in. Our biggest weather problem is freezing of our jet pumps, and when that happens, those wells just go down and you have to wait until everything thaws out to get them back on. That's been off and on, so I can't give you what the downtime in the production loss for the entire quarter is.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Okay. And the -- you mentioned the midstream delays in the Marcellus, is that gathering or something to you all or is that more of a big picture midstream delays which are impacting differentials? So you don't want to sell the gas at the current price? Or is it that you can't get the wells on production?

Sylvester P. Johnson

It's a combination. Our biggest midstream company up there has burned up a compressor that we and everybody else in that area was using to feed gas in the millennium pipeline, so now we have more back pressure than we did before that. We've also had problems with some of the midstream providers in accelerating ways to get around those problems by jumpering lines around the problem. So that's held us all up and that's mostly at the North end where the prices are better. At the South end in Wyoming County, where we go into Tennessee and Transco, that's been less of an operational issue and more of a, "We just don't like the price some days," so we shut the wells in.

Operator

Our next question comes from the line of Jeff Grampp with Northland Capital Markets.

Jeffrey Grampp - Northland Capital Markets, Research Division

I was just curious if maybe we could get an update on some of the older 500-foot space Eagle Ford wells and maybe how those are holding up relative to maybe some of the older wells in your inventory and just kind of how those are comparing?

Andrew R. Agosto

So far, they really look virtually identical to the wider-spaced wells and that's across the board. We've now got several pairs or triples that have been frac-ed and on production for some amount of time and we're seeing results virtually identical to 750-foot spacing.

Jeffrey Grampp - Northland Capital Markets, Research Division

Okay, great. And then, on the 330-foot space wells you guys are doing, are you looking at doing anything different in terms of completions to try to limit the communication you may see between those?

Andrew R. Agosto

That's something we've talked about quite a bit. Our strategy today, because we're drilling many wells across a fairly wide project area, was to complete all the wells the same so that we could make apples-to-apples comparisons between the leases. We've done that now and, yes, we actually are looking at some different formulations on track design.

Jeffrey Grampp - Northland Capital Markets, Research Division

Okay, got it. Makes sense. And then last one I got, I know at the Analyst Day, you guys had talked about doing some acreage trades in the Niobrara to block up some 960s. I just wanted to kind of check up on the progress there and see if you guys have had any success in doing so?

Andrew R. Agosto

Yes, we have -- since the widening trade we did last year, we haven't consummated any additional trades.

Operator

Our next question comes from Graham Tanaka with Tanaka Capital Management.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Great. Just wanted to sort of take a bigger picture view as to optimum growth rates. Your production growth is fantastic. You've got great inventory. I'm just wondering what kind of a longer-term production growth expectation we should have or you can operate at, given your inventory, given the rig availability, given pricing, what is sort of an optimum growth rate, say next 3, 4, 5 years?

Sylvester P. Johnson

Well, we're modeling that out now to see. I mean, for instance, this year we'll grow 50% on oil production. I think that's pretty easy to do again next year. But after that, we have to be running 4 or 5 rigs out in 2016. We're trying to model that out now based on different price projections to see just how much gas that takes, what our debt-to-EBITDA is and what we're comfortable with. So we're trying to find that happy medium for the shareholder between the right amount of debt, the right amount of growth. And right now, we think we have figured that out with debt-to-EBITDA about 2 and oil production growth rate of 50%. We have enough inventory that we have a lot of options. And for instance, it looks like we've almost added a year of inventory already in the last 2 months, so from the land acquisition side. So as long as we can keep doing that, we'll have a lot of options going forward.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

And the inventory additions, meaning both Utica and Eagle Ford or...

Sylvester P. Johnson

That was just Eagle Ford. On the Utica, we haven't had as much success buying acreage, but we have some larger deals we're working on right now. But in the Eagle Ford, we had a pretty good January and February so far.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Yes, I'm just -- you've done a great job of -- we watched your Analyst Day online, but a great job of looking at comparables in the Eagle Ford, actually, fantastic metrics. But I just was wondering if you look at, say, some of the top producers out there like Range Resources, what is different in your inventory production profile of cost and pricing and sort of the balance sheet that would suggest that you could, at some level, at some point in time, maybe closer to a range longer-term, or is that beyond the radar screen?

Sylvester P. Johnson

No, it just takes a long time to catch up with somebody that has an inventory like that. The advantage we have is that we have so little dependence on gas prices, ethane prices, any other NGL prices. So we have kind of a multiplier effect since we're selling oil in the Eagle Ford. We're getting 99% of NYMEX right now. So the cash we generate should give us the ability to add rigs sooner than people that are in gas plays.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Okay. So in other words, we are in a pricing environment now where the move to oil has worked and the pricing has actually firmed up so that it's actually helping out in terms of the longer-term growth rate funding. Is that correct?

Sylvester P. Johnson

That's right. We have very high IRRs and our reserve growth shows that, our positive revisions show that, our BOPD growth shows that and we'll stand by those numbers. That gives us a lot of -- we can accelerate faster than companies can that are producing gas.

Operator

[Operator Instructions] And our next question here comes from the line of Chad Mabry with MLV & Co.

Chad L. Mabry - MLV & Co LLC, Research Division

A quick question. I think you said that CapEx in Q4 was up 64% Eagle Ford, or at least D&C CapEx. Curious if you could split out by play, the remainder there?

Paul F. Boling

Yes. This is Paul, I've got that.

Chad L. Mabry - MLV & Co LLC, Research Division

And I guess while you're looking that, if I could, appreciate the guidance on price realizations for Q1. Just curious if that's kind the best guess at how 2014 is going to look for you on the price realization side at this point, as well.

Sylvester P. Johnson

Well, given the volatility that we're seeing in realized prices, and I'm talking primarily in the fourth quarter last year and also we're seeing improvement in the first quarter, I would say it's difficult at this point to make a fairly accurate projection. We'll -- our plan is to continue providing forward-looking projections each quarter as we look out, but right now we're not prepared to do anything for the latter quarters in the year. The good news is though, at least for the first quarter, all 3 months have been relatively close to each other. Whereas last year, the first 9 months of the year were huge premiums and then the last 3 months had about a $4 deduct. So it looks like things are stabilizing right now. But like Paul said, we'll just have to guide to this every time we do a call.

Paul F. Boling

And I have the CapEx numbers. The first number I'm going to give you is the drilling and completion CapEx in the fourth quarter: for Eagle Ford, that was $83.8 million; for Marcellus, that was $7.2 million; Niobrara, $18.6 million; Utica, $12 million, for a total of $124 million. And then our leasehold and seismic was $90.7 million, most of that in Utica.

Operator

Our next question comes from the line of Kyle Rhodes with RBC.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

Wanted to get a quick acreage price and location for the Eagle Ford bolt-ons you have done so far this year?

Sylvester P. Johnson

We can't say what all of it was, but it ranged from about 2,500 per acre to 6,500 per acre. And every deal was different and some are confidential.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

Got it. And is that mostly in La Salle or is it kind of spread out across?

Sylvester P. Johnson

It was all in La Salle.

Operator

Next, we'll hear from the line of Adam Michael with Miller Tabak.

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

I wanted to go back to the, I guess, the benchmarking study you guys presented at your Analyst Day, kind of compared the returns you're seeing in the Eastern and Western Eagle Ford, and it was nice to see EOG kind of confirm that this morning. I realize that EOG has also said they saw a 30% increase in their Western acreage as far as cumulative oil production from 2000 -- excuse me, 2013 compared to 2012. And I was wondering if you guys could give us a little detail on how much better the wells are getting compared to maybe something drilled a year ago in the Western? And do you see the potential to take those EURs up higher?

Andrew R. Agosto

Well, obviously for us, all the comparisons are going to just be within the Western area since that's where our acreage is. But at Analyst Day, the new reserve number that we provided for an average well going forward, I think, was around 25,000 MBoe higher than the previous model. I'm not sure what percentage that was. So that was up slightly. I mean, our anticipation is that in some areas, EURs will go up, some will stay the same. But until we continue to drill out the projects, we're not going to know that. From a technology and completion standpoint, there's probably some additional room there for growth in EURs as well.

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

Okay. Great. Just one quick follow-up on the Utica. What kind of line pressures are you guys flowing into with that Rector well?

Sylvester P. Johnson

We're not -- we're flaring the gas right now.

Operator

Our next question comes from the line of Marshall Carver with Heikkinen Energy Advisors.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Yes, just a quick follow-up. In the press release, I'm reading that the Eagle Ford position is now at 62,200 net acres. Would that now mean a year-end number? I think earlier in the call, you talked about it being 65,500. Or are you haircutting acreage for some reason?

Sylvester P. Johnson

You're right, Marshall. The one in the press release is as of year-end and now we've added the extra acreage.

Operator

We have no further questions at this time.

Sylvester P. Johnson

Well, if there are no further questions then we'll wrap it up. We're off to a great start this year with all this data out now and the 10-K coming out, we think the market will recognize our shift to oil, start including us in a different group and also see that our excellent balance sheet has also transformed us. The strategic issues we were focused on in the past are behind us now and now we can focus on improving efficiencies, reducing costs, improving EURs, testing downspacing and adjusted reservoirs and evaluating our Utica acreage. So we should have results on this over the next 2 calls. Thank you for calling in and we'll talk again in probably early May.

Operator

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

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