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Carrizo Oil & Gas (NASDAQ:CRZO)

Q2 2013 Earnings Call

August 07, 2013 10:00 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

Jim Pritts - Vice President of Business Development - Marcellus

J. Bradley Fisher - Chief Operating Officer and Vice President

Analysts

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

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Marshall Carver

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Will Green - Stephens Inc., Research Division

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Subash Chandra - Jefferies LLC, Research Division

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Carrizo Oil & Gas Second Quarter 2013 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded today, Wednesday, August 7, 2013. I would now like to turn the conference over to Mr. Chip Johnson, President and Chief Executive Officer of Carrizo Oil & Gas. Please go ahead, sir.

Sylvester P. Johnson

Thank you, moderator, and thank you all for calling in. We had a great quarter, as you've probably seen from our press release. We will go through this in the same order we usually do. Paul Boling, our CFO, will start with the financials, then I'll go over an operations summary and then we'll open it up to Q&A. Paul, do you want to start?

Paul F. Boling

Thanks, Chip. We achieved record oil production of 11,747 barrels per day. That's a 26% increase over the first quarter of 2013 and also exceeded the high end of our guidance by approximately 550 barrels per day. Natural gas and NGL production was 92,890 Mcf a day or just 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 at $136.8 million in the second quarter of 2013. Thanks to our continued growth in oil production, EBITDA was also a record $102.7 million in the second quarter of 2013 or $2.56 and $2.53 per basic and diluted shares, respectively. That's a 10% increase over the first quarter of 2013.

Our total cash costs and expenses of $34.1 million, comprised of $19.2 million in production costs and $14.9 million in G&A costs, was within the guidance range provided for the second quarter. Accordingly, there are no material variances to report.

We've made a number of new disclosures in this quarter's press release, including a cash flow from operations statement; a summary of oil and gas hedges by year, including average fixed and floor prices; a summary table of our 2013 third quarter and annual guidance, including production, realized hedging gains, operating costs, G&A costs and drilling and completion expenditures. So in the interest of time, please refer to those disclosures in the press release for further detail.

Our drilling and completion capital expenditures for this quarter was $133.2 million or about $12 million below the low end of our second quarter's guidance range of $145 million. This favorable variance is primarily attributable to the delay of certain well completions in the Marcellus originally planned in the second quarter of announced schedule for the second half of 2013.

We recently simplified our debt structure with the June retirement of substantially all of the 4 3/8% convertible bonds outstanding. We also upsized the borrowing base in the second quarter by $165 million from $365 million to $530 million. We also reported that our net debt to EBITDA ratio using the trailing 4 quarters was down to 2.5x for the second quarter. Annualizing the second quarter 2013 EBITDA, our net debt to EBITDA ratio was down to about 2.25x. We had $28 million outstanding on our revolver as of June 30.

Our significant oil hedge positions for the balance of '13 and '14 are 10,100 barrels a day, or over 80% of the midpoint of estimated production in the second half, and 9,500 barrels a day, respectively. We also have over 50% of our estimated natural gas production for the second half of '13 hedged as well. Further to hedging -- referring you further to consult the hedging table in the back of the press release.

We also look forward to completing our fall borrowing base redetermination, which is scheduled by mid-October. Chip?

Sylvester P. Johnson

Thanks, Paul. In the Eagle Ford, we are producing from 96 gross, 75 net wells, with 3 drilling rigs running and one 24/7 frac crew. At the end of the second quarter, we had an inventory of 24 gross, 17.5 net wells, representing 6,600 net BOPD of potential initial production.

Our downspaced wells have been drilled at 500-foot spacing and are now being fracked. Given that other companies in the play are already developing their acreage on this spacing, we have high hopes for these wells. The results would be very significant, raising our 417-well drilling inventory by about another 135 wells.

We've also completed our Pearsall Shale test well with encouraging results from a short 1,700 per barrel [ph] and should have a sales line in place later this week so that an extended test can begin.

In the Niobrara, we are producing from 58 gross, 22 net wells with 8 gross, 2.5 net wells waiting on completion, representing 650 net BOPD of potential initial production. We have started drilling 2 60-acre downspace pilots. Our other drilling has all been at 80-acre spacing. These results could also be very significant, potentially raising our drilling inventory from the B bench from about 337 to 447 wells. We have 2 drilling rigs running and plan to stay at that pace for the remainder of 2013.

In the Marcellus Shale, we are producing from 58 gross, 17.8 net wells in Susquehanna County and Wyoming County, with gas sales into all 3 major pipelines. We have 28 gross, 11.1 net wells waiting on completion. We are currently running 1 drilling rig and 1 frac crew, although our frac holiday should begin about August 16 and lasts until November. Our production capacity in the Marcellus Shale currently exceeds 60 million cubic feet a day net, but we are likely to limit our production when local prices are especially weak.

In the liquids-rich area of the Southern Utica in Ohio, our JV with Avista Capital has now closed on about 31,000 acres, with 50% or 15,500 acres net to Carrizo. We continue to lease in the Eastern Guernsey and Northern Noble County area.

On our rector well, we have drilled and cored through the Utica with results as we expected and now are beginning to drill the horizontal section.

Our Barnett Shale sales process is underway, and bench should start coming in this week. Given the advanced stage the sales process is in, we will not be providing additional commentary on the sale on this call.

Total company production for the third quarter is expected to range between 11,800 and 12,200 net BOPD and 95 and 105 net known [indiscernible] of gas and NGLs per day. Our 2013 budget still allocates USD 530 million to USD 540 million to drilling and completions, with $140 million allocated to land, a $16 million increase in the land budget due to additional success in the Eagle Ford. We now expect 45% growth in oil production year-over-year and remain at a 3% reduction in gas production year-over-year.

Second quarter operating drilling and completion CapEx of $133.2 million was under our projected budget. Land CapEx of $30 million was primarily in the Eagle Ford and the Utica.

The drill and complete budget for the year is unchanged at $530 million to $540 million. We have spent about $270 million in the first half, so we think we're right on track.

Land CapEx in the second half should be at around $20 million, split between the Eagle Ford and Utica shales.

With that, I'll stop and we'll open up to Q&A.

Question-and-Answer Session

Operator

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

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

Say, Chip, I just want a little more color on the Utica, if you could, as far as sort of total acreage there today, then maybe what it would take or what you'd want to see before you maybe -- you would start bumping up activity.

Sylvester P. Johnson

I guess our acreage count right now is 15,500 net to us. We basically held off on activity until midstream was in place. A lot of that is now present in 2 of our 3 main areas. So what we plan to do is drill this rector well, test that and start building some locations so that next year, as we wind down the Marcellus, we can wind up the Utica.

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

Okay. And then on the Eagle Ford, just moving over there, Chip, what are you assuming on well cost? And then does that include sort of your newer completion technique and more on pad drilling?

Andrew R. Agosto

This is Andy Agosto, Neal. We have been pad drilling really since the inception of the program. We've managed our costs down. The average well cost is obviously a punch [ph] of the length. Our current completion cost per stage is on the order of $230,000. Our drill costs are in the $2.5 million to $2.8 million range. Right now, it looks like the program for 2013, as we show in our presentation, is about 27 stages per well. For the remaining program, going forward, closer to probably 24 stages per well. So I'll let you do the math on that cost, but I think you can get to it with those numbers.

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

No, you're correct. And then the last one for me. Just on the Marcellus, Andy, for you or Chip, will you continue to have some shut-ins due to the offset completions? Or was that -- do you think that will end on the last quarter?

Sylvester P. Johnson

That should pretty much stop now because we're going to be on frac holiday for a long time. So most of the wells should be producing, unless there's a drilling rig next to them, but that's small compared with having a frac crew on-site. The bigger problem there is just that gas prices in Pennsylvania have been all over the page in the last month. And we've cut back -- in some of our wells, we've got 50% of what they could flow if we don't like the prices we're getting.

Operator

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

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just a question on lease activity. Obviously, you guys have kind of continued to pick up Utica and Eagle Ford leases here. It sounds like your budget in the second half is certainly lower for leasing. And where do you think the totals can sort of go to in the Utica if you're at 15,500 now? And what are you guys seeing in terms of availability of Eagle Ford leasehold as well?

Sylvester P. Johnson

Well, we had some good lease pickups in the first half. But right now, based on what we've seen in July and August, it's slowed way down. I think in the -- or in the Utica, we keep thinking we can lease about 1,000 gross acres per month, barring any bigger deals. And in the Eagle Ford, we're probably about half that number, maybe 500 to 1,000 acres combined.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right, that's helpful. I guess, obviously, you guys are working on some in the Barnett. What do you plan to do with the proceeds?

Sylvester P. Johnson

Basically, we were selling the Barnett to plug the spending hole for this year, so that's the plan. So we're still out spending our cash flow. But if we sell the Barnett, we kind of taper through the rest of this year so that we cover that outspend, and then next year we're pretty close to neutral.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right. And do you guys have any testing in terms of other zones in the Niobrara outside of the B, and what do you think the potential is on your acreage?

Sylvester P. Johnson

No, we have A bench and B bench, and that's the area where we're drilling. And Whiting and Noble are both testing it. Noble has a really elaborate 28 wells and 2 section tests planned that we're going to be in because we have acreage in those units. And it tests A, B, C, different parts of the ABC in different spacing. So we know the C has as much oil and plays as the B. It's just spread out over a thicker interval and probably going to be harder to drain. But the exciting upside, it could double our potential in that area.

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 in the Utica, how much of your acreage is amenable to longer laterals?

Jim Pritts

This is Jim Pritts, and in the Utica, our position is pretty blocky in the majority of our acreage position. And I'd say upwards of 70%, 75% is amenable to longer laterals. And we're in the process of doing similar things as we did in the Marcellus with respect to acreage trades to further block that up, and we've had some success to date with doing the acreage trades. So we would expect that percentage to grow over time.

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

Okay, great. And then is there any update on your midstream plans in the area?

Jim Pritts

Right now, as we continue to block our positions, there's 2 midstream providers that have significant infrastructure that transects the core of our acreage. That would be Blue Racer and MarkWest. So while we haven't landed on a final solution with respect to a midstream provider, we're in discussions.

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

Okay. And then the Pearsall test, does that result change you guys view on the play at all, I mean, I guess relative to the Eagle Ford?

Sylvester P. Johnson

It hasn't changed it yet because our initial results aren't that different than some of the other competitors in the play. We feel like the condensate/gas ratio is the key factor. And so we need some time and some production history to decide whether this is going to be economic. If it just turns into an extensive wet gas play, then it doesn't work. You've got to have that high condensate ratio, and some of the other peers in the area have seen that drop off at times. So that's what we're concerned about.

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Just in the Eagle Ford, could you talk about how many completions you all did in the first half versus what's planned in the second half, or roughly?

Sylvester P. Johnson

Give us a minute.

Brian M. Corales - Howard Weil Incorporated, Research Division

And then maybe while you're looking for that, with the potential sale of the Barnett, can we assume that you'll probably start accelerating a little faster in the Eagle Ford, maybe bring in another rig? Or is step #1 maybe bring down that waiting on completion wells?

Sylvester P. Johnson

No, right now, we plan to stay at our current pace. I mean, that still gives us 45% year-over-year oil growth. So we're not planning to accelerate or expand anything at this point. Yes, Brian, for the year, our plan in the Eagle Ford is to complete 46 wells, 46 gross wells. And that's going to be a little heavier weighted to the first half, on the order of 26 wells in the first half.

Operator

Our next question comes from the line of Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Chip, I'm just looking for a little bit more color on the outperformance of the Eagle Ford. You guys put out updated guidance for the second quarter oil production in the middle of June. And with the results put out this morning, you came in well above what you put out there on June 17. Just looking for some color on that. What's the main driver of that performance?

Sylvester P. Johnson

Yes, I think our numbers were spot on. We had some higher outside operator production, both in the Niobrara and from El Paso in the Eagle Ford. That was a part of it. And then we also had some prior-period adjustments, I think mostly in the Niobrara, where we had underestimated our working interest on the wells.

Operator

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

Marshall Carver

Yes, in the Marcellus, you talked about seeing volatile pricing. I mean, what sort of pricing are you seeing right now? And at what price would you increase production?

Sylvester P. Johnson

Generally, if we can get $2 or $2.30 or $2.40 at the least, we'll sell the gas. But we've seen prices some time in the last 2 weeks drop down to $1.25 at the least. So we think this is a short-term problem caused by weather and the lack of gas demand in the Northeast right now. So we and our marketers feel like October, November, this problem will go away. And there's no point in selling gas right now for $1 to $1.50 less than you're going to get in 2 months.

Marshall Carver

So the guidance assumes that you have lower production in 3Q and then you ramp it back up in 4Q, is that fair to say?

Sylvester P. Johnson

That's right. And so actually, I think we even deemed October a little bit, too. So November and December back to normal.

Operator

Our next question comes from the line of Matthew Portillo with Tudor Pickering Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just a couple quick questions for me. In terms of the Eagle Ford, if you have success in the downspacing on your test case here, and it seems like, as you said, the industry is moving towards that drilling program already, how do you think about the acceleration potential? And then I guess just a second follow-on question to that. Given the initial results in the Utica from some offset operators, your encouraging results in the Niobrara and then your potential results in the Eagle Ford, how do you think kind of bigger picture over the next years about accelerating drilling and financing, a bigger drilling program versus continuing to lease and build acreage?

Sylvester P. Johnson

I think right now, our drilling complete budget is about 4x or 5x what our -- 4x what our land budget is. We also feel like some of the land opportunities are gone. There just aren't that many more of them out there that we can see. Our overall plan is just to grow with keeping our debt to EBITDA somewhere around 2x to 2.5x. And so we're already growing at one of the -- or growing our oil production at one of the highest rates in the industry. So I think we're going fast enough there. We really don't need to accelerate that much.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And so from that comment, you would expect, as we move into 2014, unless some really exceptional opportunities come up, that you'll significantly reduce your leasing CapEx, and that we could see more capital flow into the drilling budget?

Sylvester P. Johnson

That could happen. I mean, I just don't think the -- next year, the opportunities will be there for leasing. And so that capital could be directed into drill and complete.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then just a second follow-up question. You mentioned the Marcellus, decelerating that program as I think you get through some of your core acreage in Susquehanna and potentially shifting that rig to the Utica. I was just wondering if you have any color on the timing of that. And then secondly, as you look at the Utica play itself, how should we think about kind of the medium-term drilling cadence that you could have in the play?

Sylvester P. Johnson

In the Marcellus, we will probably have all of our acreage drilled out in about February or March, although we are going to test the upper Marcellus in 2 or 3 spots, which could completely change that program going forward. But those results won't be in until probably right around the end of the year or early next year. Utica, I think we can plan on ramping that up starting at about April next year for the rig to work there. Right now, we have a 50% working interest, so the capital is not that much different than the Marcellus. And I think that's a fast enough pace until we know more about the play and more infrastructure and I've seen takeaways.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

My final question here, just to dovetail into the last point there, could you talk a little bit about FA marketing for the basin and how you view the potential to strip and move that thing?

Sylvester P. Johnson

I guess if we look at the 2 midstream carriers' plans, and they both seem valid, once the Apex line is on, that's going to help a lot. Once all the new MarkWest plants are ready, that should help a lot. So I think this is going to kind of come together around the end of the year, first half next year, when things sort of stabilize. And then it will be a lot clearer. Down the road, I don't know where -- I think we're finding a lot of ways to move ethane out of the basin. I just don't know if there's enough demand in the right places to absorb it all. I know a lot of people are working on that now.

Operator

Our next question comes from the line of Will Green from Stephens.

Will Green - Stephens Inc., Research Division

On these Eagle Ford downspace tests, I assume you guys are maybe running some microseismic or something like that. And the other point I wanted to ask on is, is there any completion difference that you guys are making to ensure that these don't interfere with each other? Or is it just a pretty standard frac?

J. Bradley Fisher

This is Brad Fisher. No, we're not changing anything. The microseismic that we've run previously in other wells would indicate that we didn't need to change our frac design for the downspace. We are running some microseismic here to see what kind of interference we could potentially have.

Will Green - Stephens Inc., Research Division

Got you. And then just a point of clarity on the 17.5 net wells in the Eagle Ford that are waiting on completion. Is that 6,600 barrels a day a 30-day rate or is that gross, net? Just a point of clarity on that.

Sylvester P. Johnson

That's a 30-day rate.

Will Green - Stephens Inc., Research Division

Okay. All right. And then the last one I have is, in the Utica, you guys have your first tests coming up. If that comes in well, would you guys look to buy out Avista's kind of side of that working interest? Or is it just too early even to think about that?

Sylvester P. Johnson

I guess we'd look at buying them out. I mean, I think they're willing to sell sometimes. So we probably won't have that data, though, until November, December. And I think we're confident enough in the play to be buying more acreage up there. That's just a bigger number that we'd have to look at.

Operator

Our next question comes from the line of Graham Tanaka with Tanaka Capital.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

I'm just wondering, the different areas where you're looking at changing downspacing, what might that do to the IRRs and basically the percentage that -- of the hydrocarbons that you'd be able to drain from the resource? Is there much change in that, or is it just really kind of moving up in time? And what does it do to those metrics?

Andrew R. Agosto

Yes, Graham, this is Andy Agosto again. That's part of the reason that I guess we'd characterize these as tests. We've looked at all available industry data from competitors. Obviously, in the Eagle Ford, there's been a lot of activity on the spacing that we're testing now, 400 to 500 feet between laterals in the Karnes, the Gonzales areas. And EOG has also given some data on very slight degradations in IRR but significant increases in overall recovery efficiency. So those are the kind of results we're anticipating. But again, that's part and parcel for why we're running these as tests.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

And what was your increase in overall recoveries? And what are the characteristics that are maybe different in where you are?

Andrew R. Agosto

Well, if you look at our well results compared to industry, I mean, we're definitely in the top quartile on just -- on pretty much every metric except maybe IPs. And that's just a function of how we elect to produce the wells early on. I'm not intimately familiar with the EOG data. I do know that, again, they had similar EURs at tighter spacing with, obviously, a higher number of wells per section.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

I mean, is your -- I guess your -- what would this do? And just wondering, in terms of the IRRs, why wouldn't there be an improvement? Are we talking about the cost of capital being higher because you're putting more in the unit or what? I just don't understand why the IRRs wouldn't change.

Andrew R. Agosto

I think that the best way to characterize it is you'll have similar IRRs and similar EURs. Again, I can only comment on what EOG has talked about publicly, and that's, I think, the theme of what they've stated.

Operator

Our next question comes from the line of Subash Chandra with Jefferies.

Subash Chandra - Jefferies LLC, Research Division

I guess you don't want to talk to Barnett. I was just curious if you can talk about maybe the free cash flow per quarter it's currently generating? Or annual or...

Paul F. Boling

Yes, annual, that was supposed to be about $30 million of free cash flow. So second half is going to be less than $15 million.

Subash Chandra - Jefferies LLC, Research Division

Okay. And I'm trying to -- when you talk about the transition to Utica and the Marcellus about the same time the Marcellus maturing, is there a desire here, then, to monetize Marcellus? Is there a need or a desire to do that next year?

Sylvester P. Johnson

I don't think we need to do that next year. I think we -- we're still developing it now. I think most of these gas plays really are best marketed after all the initial declines have happened and they kind of get on a flat, low declines of the fields' [ph] MLPs. So I think that's some time out. And we need to test the upper Marcellus. That zone is as thick as the lower Marcellus. It's just -- it's spread out over more total thickness. And we might be draining some of it now. So that's sort of the intrigue of that part of the play.

Subash Chandra - Jefferies LLC, Research Division

Okay. And a final one for me. Niobrara wells are 44 gross. It just superficially seems to me that you can do a better pace than that. Is that accurate? Or do you think that's kind of what you have budgeted, is what you're going to do?

Sylvester P. Johnson

That's essentially the plan. I mean, we're just -- everything we do is controlled by the budget, not by logistics or what we could do. We could go faster in every play we have.

Operator

[Operator Instructions] I'm showing no further questions at this time.

Sylvester P. Johnson

Okay. Well, then we'll wrap it up. Again, thanks to our staff for such a great execution of our strategy in the second quarter. The results are also proving out the quality of our assets and validate our net asset value, which we described in our company presentation. We have some exciting, imminent catalysts with downspacing tests in the Eagle Ford and the Niobrara and additional potential upside later in the year from the Pearsall and the Utica. Thanks again for your support of Carrizo.

Operator

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

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