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Carrizo Oil & Gas (NASDAQ:CRZO)

Q4 2012 Earnings Call

February 26, 2013 11:00 am ET

Executives

Sylvester P. Johnson - Chief Executive Officer, President, Director and Member of Special Stock Award Committee

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

Andrew R. Agosto - Vice President of Business Development

Analysts

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

Dan McSpirit - BMO Capital Markets U.S.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

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

Yiktat Fung - Jefferies & Company, Inc., Research Division

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Carrizo Oil & Gas Inc. Fourth Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded Tuesday, February 26, 2013.

I would now like to turn the conference over to Chip Johnson, President and CEO of Carrizo Oil & Gas Inc. Please go ahead, sir.

Sylvester P. Johnson

Thank you. Thank you, all, for calling in. As you could see in our press release this morning, our oil strategy transformation is working very well. We had an outstanding year. We want to thank our staff for all the work they put into this. We almost doubled our revenue and EBITDA in the last 12 months and almost tripled our net income, while we reduced our debt to EBITDA from over 4 to close to 2.5 today. We also greatly simplified our story by exiting the Gulf Coast and the Huntington project in the North Sea.

Paul Boling will go over the financial results for the quarter and, to a lesser extent, the year. And then I will give an operations update and then we'll open it up to Q&A.

Paul F. Boling

We achieved record oil production of 9,033 barrels per day, that's a 4% sequential increase over the third quarter of 2012, and a 190% increase over the fourth quarter of 2011. Natural gas and NGL production was 100,924 Mcfe a day.

We reported record adjusted revenue and revenues for the quarter. Adjusted revenues, including the impacts of realized hedges, was $116.7 million in the fourth quarter compared to $105.9 million in the third quarter of 2012.

General guidance for realized gains on derivatives in the first quarter of 2013 is going to be $6.5 million to $7 million based on strip prices as of February 25. EBITDA was a record $93 million in the fourth quarter of '12. $2.34 and $2.32 for basic and diluted shares, respectively, a sequential increase of 8% over the third quarter of 2012.

The lease operating expense was $8.9 million or $3.73 per Boe for the fourth quarter, as compared to LOE of $6.9 million or $3.48 per Boe for the corresponding quarter in 2011. The increase in operating cost per Boe is primarily due to the higher operating cost per Boe associated with the increased oil production. General guidance for LOE in the first quarter is $3.90 to $4.20 per Boe.

Production taxes increased to $3.9 million for the fourth quarter compared to $2 million for the same period in 2011. The increase in production tax 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 natural gas. Our general guidance for production tax in the first quarter of '13 is 4% to 4.25% for the total oil and gas revenues.

Ad valorem tax increased to $1.6 million during the fourth quarter from $0.9 million for the same quarter in 2011. The increase in ad valorem taxes is due primarily, again, to new oil wells drilled. Our general guidance for ad valorem tax in the first quarter of 2013 is $2.5 million to $3 million.

General and administrative expense, excluding noncash items, was $9.4 million during the quarter as compared to $7.6 million during the corresponding quarter. The increase is primarily due to compensation costs related to the increase in personnel in the fourth quarter of '12 as compared to the corresponding period. Our general guidance for G&A in the first quarter of '13 is $10 million to $10.5 million.

DD&A expense for the fourth quarter of '12 increased $17.2 million to $44.2 million, which equates to $18.56 per Boe compared to $27 million and $13.57 per Boe in the fourth quarter of '11. The increase in the DD&A rate for Boe is largely due to the impact of the significant decrease in natural gas reserves, as well as a significant increase in crude oil reserves in the Eagle Ford. Our general guidance for DD&A in the first quarter of '13 is $19 to $20 per barrel. This is consistent with the guidance provided in the previous quarter.

Following the benefit of our U.K. Huntington sale, current liquidity is strong with over $110 million in cash and an undrawn $365 million borrowing base availability on our revolving credit facility. Chip?

Sylvester P. Johnson

Thanks, Paul. Current production is 24,500 net Boe per day or 147 net MMcfe per day. We have 93 million cubic feet a day of natural gas production and 9,000 barrels a day of oil production. Oil production is comprised of 8,050 net BOPD from the Eagle Ford, 800 net BOPD from the Niobrara and 150 net BOPD, other. Barnett production is about 47 million cubic feet per day net; Marcellus, 33 million cubic feet per day net; and Eagle Ford and other, 13 million cubic feet per day net.

In the Eagle Ford, we are producing from 77 gross wells with 3 drilling rigs running and one 24/7 frac crew. We currently have an inventory of 22 gross, 18 net wells with 6,600 net BOPD of potential production. Our 80-acre down-spaced wells confirm 750-foot spacing. Tighter spacing will be tested in the future. We have completed the drilling of our Pearsall Shale well with a 2,000-foot lateral and plan to frac it in April.

In the Niobrara, we are producing 800 net BOPD, 33 gross wells, with 5 gross 2.4 net wells waiting on completion with 650 net BOPD potential of production. Our first 160-acre down spaced wells are producing with no apparent interference and we will drill at that spacing until an 80-acre test is completed. We have 2 drilling rigs running and plan to stay at that pace.

In the Marcellus, we entered an alliance of producing in Susquehanna County from 21 gross wells and from 14 wells in Wyoming County. 5 wells are temporarily shut-in due to drilling activity, but should be back online at the end of March. 3 new wells are starting flow back this week. We are currently running 1 drilling rig and 1 frac crew. We have 29 gross and 9 net wells waiting on completion. Current shale activity is focused on workovers and production optimization with no new wells or fracs planned.

In the liquids-rich area of the Southern Utica in Ohio, our JV with Avista Capital has now closed on about 34,000 acres. We have a 50% working interest after exercising power option in January. We continue to lease in the Guernsey, Noble and Tuscarawas County areas. We plan to drill our first well in Guernsey County this summer and hope to have a post-frac, post-marination well test in the fourth quarter.

Total company guidance for first quarter is expected to range between 92 to 96 net MMcfd, and 8,800 to 9,200 net BOPD or 22,133 to 25,200 Boe per day. Our 2013 budget allocates $500 million to drilling and completion, with $124 million allocated to land. We still expect 28% growth in oil production and a 3% reduction in gas production from 2012 to 2013.

Our first quarter CapEx should be spent in this proportion: Eagle Ford drill and complete should be $81.2 million; Niobrara drill and complete, $16.9 million; Marcellus drill and complete, $19.0 million; and other including facilities, $19.2 million.

In addition, we pay a carry in the Eagle Ford of $6 million, $6.0 million, in the Niobrara we receive a carry of $9.4 million, which brings the total for the first quarter to $132.9 million. That falls in line with the third and fourth quarter of last year. We'll probably be about the same number in the second quarter of this year before the CapEx starts dropping off, as some of the carries we pay go away and some of the frac holidays start, especially in the Marcellus.

So with that, we'd like to open it up to the Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first 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 Barnett. It seems like there's a pretty healthy appetite for a load of client gas assets out there. Would you guys consider selling out of your position altogether?

Sylvester P. Johnson

We would always consider it at the right price. Now that we have a brand-new third party reserve report, I think we'll start analyzing what we could get for that and what we think the impact on cash and cash flow will be by doing that.

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

Okay. And then shifting to Eagle Ford. If you look at your most recent presentation, it looks like some of the older wells, particularly as you get about 6 months out, are outperforming your 400,000 Boe-type curve. Do you think there's any upside to that type curve you have out there?

Sylvester P. Johnson

We just finished our reserve report with Ryder Scott, and I think they have given us higher reserves per state than we were using in the past. And we'll be trying to roll that out at conferences over the next month. We're adding -- generally, we have more stages going forward and I think we have higher recovery per stage than we were using in the past.

Operator

[Operator Instructions] And our next question comes from the line of Dan McSpirit of BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

What should we expect in terms of further high grading the asset base this year, that is -- what ranks lowest in terms of returns at the field level and what's a divestiture candidate? I guess that's another way of me asking, what would you sell to buy more Utica?

Sylvester P. Johnson

Probably the most obvious thing would be the Barnett, just because we don't have much near-term upside there. We need gas prices to go up before the rate of return on that drilling can compete with the oily plays or even the Marcellus. So that would probably be the most obvious. I think our other shale plays, none of them have gotten to the point where we have really flat production rates because we're still drilling and adding production, which makes them less attractive to MLPs, which seems to be where most of the capital is coming from right now.

Dan McSpirit - BMO Capital Markets U.S.

Okay. And turning to the Niobrara, where do you put the EORs on the Niobrara wells recently completed, the ones that both flowed at over 1,000 barrels per day? And how does the product mix on these wells change over time or how is it expected to change over time?

Andrew R. Agosto

This is Andy Agosto. Some of the more recent wells would be on the order of 300,000 Boe EOR. We still are looking at about an 80-20 oil/gas split.

Dan McSpirit - BMO Capital Markets U.S.

Okay. Great. And is the gas -- is it sold here in Colorado? What's the market for that gas? And what are the netbacks on that gas?

Andrew R. Agosto

Yes, we sell to a local gatherer that tailgated their processing plant. And I don't have the netback off the top of my head, but I think the all-in deduction that we see, including processing, is on the order of $1.25 per Mcf.

Dan McSpirit - BMO Capital Markets U.S.

Got it. Okay. And then one more for me, if I could. Just turning to the Utica, recognizing that it's very early innings. What are your expectations on the product mix from wells drilled on the Guernsey County leasehold? That is, how much oil, NGLs and natural gas? And then lastly, and again, appreciating that it's very early innings, how do the returns in the Utica compare to that in the Eagle Ford and the Niobrara?

Sylvester P. Johnson

I think, based on the well tests from Antero and PDC and Gulfport, which are all around us, we're expecting 50% to 75% oil and the rest, white gas. Because of the lower royalties, I think the economics will probably be like the Eagle Ford. I think the well costs are going to be higher initially, the terrain is rougher, there are more infrastructure problems, but the lower royalty and some of the higher rates people have seen should make up for that.

Operator

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

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

I was just wondering if you could speak to your NGL production fourth quarter. Looks like it's up pretty good over third quarter, and the pricing came in a little higher than we were expecting as well. Just kind of if you could touch on any of that?

Sylvester P. Johnson

Paul, you want to deal with that?

Paul F. Boling

Yes. The NGL production that we're showing in the fourth quarter, this is in Mcfe per day. We're showing 583,000 or 6,337 Mcfe per day for Eagle Ford. And in our other regions, collectively, it's another 56,600 or about 615 Mcfe per day. The grand total of that is about 7,438 Mcfe a day for our NGLs.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

And then, I guess, on the pricing going forward, how should we think about that? Do you have any improvement in the fourth quarter?

Sylvester P. Johnson

I'm sorry, you cut out.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

Just in terms of your NGL pricing in the fourth quarter, it showed a decent improvement over third quarter. Is there any change in the mix there or just how should we think about that going forward?

Sylvester P. Johnson

Well, one of the things we do is most of our Eagle Ford gas, which is where the bulk of the NGLs come from, we have multiple pipeline options there. And so our marketers are constantly looking to better the price on NGLs and the processing deal that we get. Without going into nitty-gritty detail on all the various wells, there's probably some component of that going on, Kyle. But in terms of overall NGL pricing, I'm not sure I would expect a premium that you saw in the fourth quarter to continue going forward.

Operator

Mr. Johnson, there are no further questions at this time. I'll now turn it back over to you. I'm sorry, we do have a question from the line of Adam Leight with RBC Capital Markets.

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

Let me just start following-up from Kyle. On the ethane production, remind me how much of that is -- excuse me. How much of your NGL production is ethane in Eagle Ford?

Sylvester P. Johnson

I believe it's roughly 50%.

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

Are you having to reject any at the moment?

Sylvester P. Johnson

I'm not aware if we're rejecting now or not.

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

Okay. And then on the operating and G&A costs, should we expect those to trend up a bit over the course of the year as your production mix [indiscernible] or is that...

Andrew R. Agosto

I'm sorry, to get back to your point on ethane, and I think Chip has been pretty clear about this over the past year. 90-plus percent of our revenue in the Eagle Ford is oil related. So although we are concerned about NGL pricing and try to get the best price, by far the biggest piece of the revenue is the oil. I think our total NGL revenue is on the order of 5%.

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

Got that. And then on costs, is there a trend we should expect on operating costs for the rest of the year?

Paul F. Boling

On operating costs, including LOE, severance and ad valorem, I would say we're not expecting a trend -- an increase. I think that the ranges that we provided as guidance in the first quarter are probably going to be reasonable throughout the rest of the year. The G&A we guided, which is about $10 million to $10.5 million, that's taking into account the benefit of some quarterly cash bonus. I would say that probably we would see a decline in the second and third quarter on G&A, probably in the $9.5 million to $10 million range. But then it should probably be around $10.5 million to $11 million in the fourth quarter. So overall, it's going to be relatively flat. It just reflects the variance as it is tied to the company's bonus pool.

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

Okay. And then on CapEx, what might make your drill and completion expenditures flex on this success in the Niobrara, or Pearsall test, kind of the key there?

Sylvester P. Johnson

We're not planning to flex our CapEx at all. We kind of zeroed in on a combination of oil production growth and reduction in debt to EBITDA. And that's where we want to be. So we might be able to reduce a little bit of CapEx by dropping our unfrac-ed inventory by the end of the year. We actually drill more net wells than we frac in the Eagle Ford this year, part of that is holding acreage, so we might be able to trim that back. Later in the year, we'll be looking at that.

Operator

The next question comes from the line of Yiktat Fung with Jefferies & Company.

Yiktat Fung - Jefferies & Company, Inc., Research Division

With regards to the production beat [ph] in the quarter on oil, and I was wondering if you could give us a little bit more color as to what differed from your expectations that -- and I guess the latest update guidance, which is from a couple weeks ago, what were the deltas there?

Sylvester P. Johnson

I think when we -- one thing we've been doing is drilling longer laterals, kind of consistently longer and longer laterals in the Eagle Ford. And we were conservative, I think, in how those would impact production. And I think it's been better than we thought, so I think that was a big part of it. We also had some really good Niobrara wells in the fourth quarter in one certain area that looks like it's our best area. And we try to get this right based on -- our forecast right based on offset production. Some of our wells are gassier than others in the Eagle Ford, some are in better areas in the Niobrara. We try to factor all that in, but we still like to have a little bit of conservatism in the outlook.

Yiktat Fung - Jefferies & Company, Inc., Research Division

Great. And as for the first quarter guidance, I think you got to -- I think it was 8,200 to 9,200 barrels per day. It seems kind of flat or even a little bit down at the midpoint versus fourth quarter. And I guess part of the impact would be the impact of the Niobrara JV, I would think. But are there any other moving pieces there that we should think about?

Sylvester P. Johnson

You're right on the Niobrara. I think that ended up impacting us by almost 200 barrels a day quarter-to-quarter, because that deal didn't close until mid-December. The other thing that we're doing right now, we have several wells in the Eagle Ford that we're putting pump units on. All of our wells have been flowing up until now. We have some wells shut down while we do that. And then we'll -- at least, we'll -- I know that then we'll have a little flatter production rate, but in the meantime, some of those are shut down.

Yiktat Fung - Jefferies & Company, Inc., Research Division

Okay. And then finally in the Utica, assuming that the well tests go as you planned, how many rigs do you think you need to get down there in '14 to get that acreage held?

Sylvester P. Johnson

In '14, we don't have much problem with leases expiring, I think more of it's in '15. But what we would probably do, since there's not a lot of infrastructure in the Utica, is just wait until we quick drilling in the Marcellus, which will probably be in about mid-'14, and then move that rig into the Utica.

Operator

Mr. Johnson, there are no further questions at this time. I'll turn the call back to you.

Sylvester P. Johnson

Okay. Well, thank you, all, for the questions we did get. Again, we had a great quarter and a great year. Congratulations to our team for getting this done. We had -- we now have 9 quarters in a row of revenue growth. We had a very busy year with strategic divestitures and JVs and acreage acquisitions in the Utica, that I think all advanced the NAV of the company and made us that much more valuable, not only in terms of multiples but also in terms of potential for our reserves in our PV-10. So with that, we have a great start to the year. And we will let you know how it came out in 3 months.

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 line.

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