Carrizo Oil & Gas (CRZO) Q1 2017 Results - Earnings Call Transcript

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Carrizo Oil & Gas, Inc. (NASDAQ:CRZO) Q1 2017 Earnings Call May 9, 2017 11:00 AM ET

Executives

S.P. Johnson - Carrizo Oil & Gas, Inc.

David L. Pitts - Carrizo Oil & Gas, Inc.

Andrew R. Agosto - Carrizo Oil & Gas, Inc.

Brad Fisher - Carrizo Oil & Gas, Inc.

Jeff P. Hayden - Carrizo Oil & Gas, Inc.

Analysts

Brian Corales - Howard Weil

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Jeff Grampp - Northland Securities, Inc.

Geoff Jacques - IBERIA Capital Partners LLC

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Timothy A. Rezvan - Mizuho Securities USA, Inc.

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Carrizo Oil & Gas first quarter 2017 earnings call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question and answer session. As a reminder, this conference is being recorded Tuesday, May 9, 2017.

I'll now turn the conference over to Chip Johnson, President and CEO.

S.P. Johnson - Carrizo Oil & Gas, Inc.

Thank you, and thank you all for calling in for the first quarter 2017 earnings call.

Our management team is pleased to report another outstanding quarter for the company. Our net oil production of 28,844 barrels of oil per day exceeded the high end of our guidance range, and total production of 46,367 Boe per day also exceeded the high end of our range. While crude oil production during the first quarter was roughly flat with the prior quarter, this was the result of a significant number of planned shut-ins during the quarter for offset fracs. Underlying results remained strong, and we expect a material uplift in our oil production in the current quarter.

Given the increased activity in our industry since late 2016, we have begun to see some service cost inflation. However, our team has been able to more than offset the cost pressures with continued efficiency gains, allowing us to actually lower our estimate for a type curve well in the Eagle Ford by $100,000 to $4.0 million, even after factoring in an estimated double-digit increase in some components in frac prices.

The increased industry activity has also resulted in an increase in non-op activity we're seeing on our acreage in the Niobrara and Delaware Basin. As a result, we've increased our planned non-op budget for the year by approximately $30 million to approximately $45 million.

Efficiency gains on our operated assets have offset much of this incremental capital. But given the better-than-expected performance from our operated assets so far this year, we have also elected to reduce some operated completion activity. As a result, we're able to increase our crude oil production growth guidance for 2017 to 26% from 23% using the midpoint of the range, while maintaining our 2017 drilling and completion capital expenditure guidance of $530 million to $550 million. Our land and seismic CapEx guidance for the year rises to $45 million based on our outlook for additional acreage deals.

I'd like to talk briefly about our M&A strategy. While we're not going to discuss any specific deals that may be in the market, we can comment generally about how M&A fits into our corporate strategy. Our goal is to increase shareholder value, which we strive to do through maximizing the value of our existing assets as well as accretively acquiring new assets.

Given this, we typically evaluate every deal within our core areas. With that said, we are in the fortunate position of having a very deep inventory of high-return, low-breakeven-cost drilling locations. So we do not believe we need to do any deal in the market.

For us to pursue an acquisition, we have to believe it will increase long-term shareholder value after accounting for both the acquisition price and the cost of financing. If it can't clear this bar, it doesn't matter how good the acreage is; it's not the right thing for our shareholders.

Additionally, we have elected to test the market for our Appalachian assets, as they do not currently compete for capital with our three core oily plays. Monetization of these assets would leave Carrizo with a core position in three high-return, oil-weighted plays and should enhance our long-term production growth profile.

With that I'll turn it over to David Pitts to discuss the financials.

David L. Pitts - Carrizo Oil & Gas, Inc.

Thanks, Chip, and good morning, everyone.

As Chip mentioned, crude oil production for the quarter was 28,844 barrels per day, which was 12% higher than the first quarter 2016. Natural gas production for the quarter was 78 MMcf per day, and NGL production was 4,508 barrels per day. Our NGL production was lower than expected due to changes in our estimates of non-operated activity, as well as our production mix being oilier than originally forecasted.

In total, first quarter production exceeded the high end of guidance, primarily due to stronger-than-expected production from the company's Niobrara and Delaware Basin assets.

First quarter included revenues of $151 million, of which $128 million was attributable to crude oil. During the quarter, we realized 95% of NYMEX for crude oil, 73% of NYMEX for natural gas, and 35% of NYMEX for NGLs, all of which exceeded the high end of our guided realizations.

Operating costs and cash G&A for the quarter were $58.7 million or $14.07 per Boe, which was within our guidance range. Given the movement in our stock price during March, we elected to pay a larger percentage of 2016 annual bonuses in cash versus stock than we originally forecasted. This resulted in cash G&A of $19.7 million, towards the upper end of our guidance range. The flow through impact of this is what causes us to slightly increase the range of our full year cash G&A guidance.

Net interest expense and interest capitalized for the first quarter were $20.6 million and $3.8 million, respectively, also within our guidance range.

For the first quarter, adjusted net income was $12.1 million or $0.18 per diluted share, which exceeded consensus earnings estimates of $0.12 per diluted share. Drilling and completion capital expenditures for the quarter were $128 million, over 85% of which was in the Eagle Ford, with the remainder weighted towards the Delaware Basin and Niobrara.

Included in the press release is our second quarter and updated full year 2017 guidance. For the second quarter, we expect to realize 94% to 96% of NYMEX for crude oil, 67% to 72% of NYMEX for natural gas, and 28% to 30% of NYMEX for NGLs. LOE guidance the quarter is $7.25 to $7.75 per Boe. The slight increase in LOE per Boe from the first quarter is driven by planned workovers, as well as lower forecasted Marcellus production.

Last quarter, I noted that the historical unit operating cost of the properties acquired from Sanchez were higher than nearby Carrizo-operated properties. We have continued to integrate those properties with our legacy operations, resulting in a significant level of workover activity in the first half of the year. We expect this activity to taper off in the second half of this year. DD&A guidance for the second quarter is $13.25 to $14.25 per Boe. We also estimate that net interest expense for the second quarter will be $21 million to $22 million, and interest capitalized will be $3.5 million to $4 million.

In early April, we added to our crude oil hedge position for the second half 2017 and full year 2018. We currently have hedges in place for one-third of our estimated crude oil production for the remainder of 2017. Our 2017 crude oil hedges consist of approximately 11,000 barrels per day of fixed price swaps at an average price of approximately $53 per barrel. For 2018, we also have three-way collars covering 6,000 barrels per day with $50 floors, $65 ceilings, and $40 sub-floors. Additionally, we have hedges in place for over a quarter of our estimated natural gas production for the remainder of 2017. These natural gas hedges consist of 20,000 MMBtu per day at fixed price swaps at $3.30 per MMBtu.

Based on strip prices as of yesterday, we expect our derivative settlements during the second quarter to range from $1.5 million of net cash receipts to $1.5 million of net cash payments. We plan to continue opportunistically adding additional hedges for the fourth quarter of 2017 and 2018 to further protect our cash flows. Details regarding our derivative contracts are included in the press release.

In connection with our recently completed spring borrowing base redetermination, our borrowing base was increased by 50% to $900 million, of which we elected a commitment amount of $800 million. In addition, our financial covenants were amended, eliminating the secured-debt-to-EBITDA and EBITDA-to-interest-expense ratios and adding a total-debt-to-EBITDA ratio not to exceed 4 times. Lastly, the maturity date of our current facility was extended to May 2022.

Now I'll turn the call back over to Chip for an update on operations.

S.P. Johnson - Carrizo Oil & Gas, Inc.

Thanks, David.

In the Eagle Ford we are producing from approximately 514 gross or 431 net wells, with three drilling rigs running and two 24/7 frac crews. During the first quarter we drilled 24 gross or 20.1 net operated wells and completed 29 gross or 28.7 net wells. 17 gross or 16.9 net operated wells were brought online during the quarter.

Net crude oil production from the play was more than 25,500 barrels per day for the quarter, up 2% versus the prior quarter. At the end of the quarter, we had 29 gross or 23.9 net operated Eagle Ford Shale wells in progress or waiting on completion, equating to net crude oil production potential of approximately 9,000 BOPD. We currently expect to drill approximately 106 gross or 91 net operated wells and frac 94 gross or 85 net operated wells in the play during 2017.

We continue to conduct multiples tests aimed at enhancing the value of our Eagle Ford Shale asset. We currently have five stagger-stack pilots underway across our acreage and expect to test additional pilots later this year.

We also plan to drill our initial infill well on the properties we recently acquired from Sanchez. We don't currently include any infill locations from this acreage in our de-risked inventory count. So a successful result should lead to upside for this number.

We also continue to test different completion techniques in order to enhance our well performance, including varying fluid type, proppant concentration, and stage spacing. On the latter, we continue to be pleased with the performance of our wells with 200-foot frac stage spacing, as they are currently showing an 18% uplift versus nearby wells spaced at 240-foot stage spacing. We currently have 13 wells online with 180-foot frac stage spacing that we hope provide a further uplift in well productivity.

In the Delaware Basin we recently completed our Thunderbolt State 1H well on the western side of our acreage position. We're testing a new completion design on the well, as we completed it with all slickwater and 100-mesh sand. The well is currently in early-stage flowback. We'll provide an update on it once we have more production history. For the year we plan to drill six gross or six net and complete five gross or five net operated wells in the Delaware Basin.

In the Niobrara Formation we continue to participate in a number of non-op wells, while we evaluate resuming operated development activity. As other operators in our area have highlighted, newer vintage completion techniques continue to deliver significant outperformance versus prior type curves for the area. So we are very optimistic about the additional upside from these techniques and are interested in testing these concepts on both the Niobrara and Codell formations on our operated acreage.

While we were sad to hear about the explosion in Firestone, Colorado, near another operator's well, we do not currently expect to see a material impact on our operations in the state, as our assets are located primarily in sparsely populated rural areas. And we do not have a material number of legacy vertical wellbores that have not already been P&A-ed.

With that I'd like to open it up for questions.

Question-and-Answer Session

Operator

Certainly. Our first question comes from the line of Brian Corales with Howard Weil. Please go ahead.

Brian Corales - Howard Weil

Good morning, guys. Just a couple for you. The increased lay-in budget, was that partly due to, I guess, the Eagle Ford acreage you added in the quarter? And what acreage, I guess, are you targeting? It sounds like you have something pinpointed now.

S.P. Johnson - Carrizo Oil & Gas, Inc.

We have acquired acreage in the Eagle Ford and the Permian. Generally it's bolt-on acreage to the acreage we already have. Nearly all of it adjoins something we're already operating.

Brian Corales - Howard Weil

Okay. And in Appalachia, I'm assuming you're looking to sell both assets. And is there a data room open, or is this kind of see what's out there?

S.P. Johnson - Carrizo Oil & Gas, Inc.

We have engaged bankers on both of them and are doing teasers followed by data rooms.

Brian Corales - Howard Weil

And any kind of rough estimate in terms of timing or – ?

S.P. Johnson - Carrizo Oil & Gas, Inc.

The Marcellus is further along. We've had some data room visits on that. The Utica, data rooms are being scheduled.

Brian Corales - Howard Weil

All right. Thanks, guys.

Operator

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

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Good morning, Chip. Just two quick ones. One on your – when you look at your Delaware acreage, how much of this, at this time, do you think you've now de-risked most of it, between what you all have drilled yourselves and the peer activity around you all?

S.P. Johnson - Carrizo Oil & Gas, Inc.

I guess we feel like we understand the assets very well now in the northern part of the play, kind of in our core area. I think we understand how the different layers perform and where the faulting is, and we've looked at enough 3-D to know now how we would develop the asset.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. And then just one last one, moving over to the Eagle Ford. I forget when the last slides were out, but looking you guys always put out those estimated IRRs and NPVs. Does that incorporate – you had some even recent more upside with the enhanced completions. Does that fully bake that in, or is there even potential upside when you all look at estimates for your economics of those wells here recently?

Andrew R. Agosto - Carrizo Oil & Gas, Inc.

Hey, Neal. This is Andy Agosto. No, those numbers do not yet include any uplift from the different completion techniques Chip referred to earlier.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Got it. And is that something, Andy, you think you would do to update type curves, or not enough well data yet to do that?

Andrew R. Agosto - Carrizo Oil & Gas, Inc.

I think we'd like to see some more well data. We have taken the shorter-stage spacing much wider across the play on some of our more recent wells. So I think here we would like some more data, but I think you'll see something later this year on that.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Perfect. Thanks so much.

Operator

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

Jeff Grampp - Northland Securities, Inc.

Morning, guys. Circling back to the Appalachian processes you guys are looking at, can you maybe just kind of walk us through the thought process? Was this kind of an opportunistic time in your minds to market these types of assets? Or is it a good time to generate some liquidity for potential M&A or acceleration? Or just kind of maybe give us a little bit of insight as to why now maybe making the move to look more aggressively on that.

S.P. Johnson - Carrizo Oil & Gas, Inc.

I think we felt like in the Marcellus particularly, there was a run-up in gas prices here that we thought would be opportunistic. And I think those prices are probably going to hold through the year. So we thought that was good timing. And we just weren't drilling any more wells. The IRRs in those wells weren't competing with our Eagle Ford wells and Niobrara and Delaware wells.

Utica was the same way. We have some wells teed up to drill, but the IRRs just aren't quite as good. So we felt like now was the time to test the market. We know there are some other people that are aggressive in that market, and we thought we should test it.

Jeff Grampp - Northland Securities, Inc.

Okay. Very helpful. And then just a follow-up on the Delaware side of things. Can you guys just remind us on this Thunderbolt well with the slickwater and the 100-mesh, can you remind us what was kind of the base completion in your prior wells?

Brad Fisher - Carrizo Oil & Gas, Inc.

Yeah, Jeff. This is Brad Fisher. We've utilized pretty much the same completion in the last several wells we've pumped. And we initially started with more of an Eagle Ford hybrid frac type. And we've moved to 2,000 pounds per foot and all slickwater in this. So we'll have a good test on this relative to the last three or four wells that we fracked.

Jeff Grampp - Northland Securities, Inc.

Okay, perfect. I'll let someone else hop on. Thanks.

Operator

Our next question comes from the line of Geoff Jacques with IBERIA Capital Partners. Please proceed with your question.

Geoff Jacques - IBERIA Capital Partners LLC

Good morning, guys. Thanks for taking my questions. Could you guys elaborate a little bit on the timing of those Delaware wells or the five Delaware wells that are coming on by year-end?

S.P. Johnson - Carrizo Oil & Gas, Inc.

I think they're scattered across the year. Some are drilled as a result of a farm-out we did a couple years ago. Others are testing other parts of our acreage block. So there's nothing in terms of we're going to drill – or frac all five of them together. They'll be spread out over the year.

Geoff Jacques - IBERIA Capital Partners LLC

Got you. Okay, great. And then I guess one more on the Eagle Ford. Could you guys maybe talk a little bit about the completion design, that infill pilot on the Sanchez acreage?

Brad Fisher - Carrizo Oil & Gas, Inc.

Yeah. This is Brad Fisher. We're going to use a slickwater design on that. We've been testing slickwater and 2,000 pounds per foot on a few wells here recently. And that's what we're going to go with on the infill well there at Sanchez.

Geoff Jacques - IBERIA Capital Partners LLC

Great. Thanks, guys.

Operator

Our next question comes from the line of Chris Stevens with KeyBanc. Please proceed with your question.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Hey. Good morning, guys. Did I hear correctly that the 180-foot stage spaced wells in the Eagle Ford are outperforming the 200-foot by 18%? And can you just remind us what the stage spacing is currently for the Eagle Ford EUR that you have out there right now?

Andrew R. Agosto - Carrizo Oil & Gas, Inc.

This is Andy Agosto. What's in the corporate presentation would still tie back to 240 feet. The comment Chip made relative to 18% was the uplift we're seeing between the 200- and 240-foot on the first nine-well pilot that we looked at.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Okay. Got it. And then are any of those shorter staged space completions incorporated on your downspacing pilots at this point? And are you seeing any difference on those wells?

Andrew R. Agosto - Carrizo Oil & Gas, Inc.

Yeah. We've moved to shorter stage spacing generally everywhere that we drill and complete, and that would include the areas where we're continuing to test the stagger stack. None of those are mature enough yet to talk about, but we will have more data on those later in the year.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Okay, great. Thanks a lot.

Operator

Our next question comes from the line of Tim Rezvan with Mizuho. Please go ahead.

Timothy A. Rezvan - Mizuho Securities USA, Inc.

Hi. Good morning, folks. I'm just trying to understand the moving parts in your production guidance. I guess the natural gas update, maybe that just reflects sort of 1Q actuals. But as far as NGL guidance changing, can you talk about kind of what has changed quarter over quarter to revise the guidance across three streams?

Jeff P. Hayden - Carrizo Oil & Gas, Inc.

Hey, Tim, it's Jeff. So a couple things kind of going on. I mean, one, there are always kind of moving parts. But I'd say on the NGLs really two things kind of driving it. So, one, the mix just came out a little oilier, so that was part of it. The other aspect on the NGL side was for one operator in particular in the Delaware Basin, we've got some non-op wells. We were basically putting those in guidance on a three-stream basis. That operator only records revenue on a two-stream basis. So that's how we have to account for it. So essentially all those NGL volumes were removed from NGLs and put into gas.

Timothy A. Rezvan - Mizuho Securities USA, Inc.

Okay. That's pretty straightforward, thanks. And then I guess a second one, on the Eagle Ford you're hearing a lot more chatter from operators adding more capital, putting rigs back in the play to test new completions. How has that sort of changed the marketplace, given you all have been successful at making bolt-ons? Is the market tightening up a little bit, or does that new activity kind of make more opportunities available for you?

S.P. Johnson - Carrizo Oil & Gas, Inc.

I guess there have been several sales packages in the Eagle Ford. Most have been fairly gassy and small, but that could change the economics going forward. We'll be looking at that to see if there's a way to add more inventory and have higher EURs because we're using shorter stage spacing and the wells interfere less with each other laterally and possibly vertically.

Timothy A. Rezvan - Mizuho Securities USA, Inc.

Okay. Thank you.

Operator

There are no further questions at this time.

S.P. Johnson - Carrizo Oil & Gas, Inc.

Okay. Well, we thank you all for your questions, and thanks again to our staff for an outstanding quarter. Beating on production targets and raising guidance while keeping CapEx flat during rising service costs is not an easy thing to do. The catalyst going forward should include the Eagle Ford downspacing tests and more completion optimizations with results from the 180-foot stage spacing, the Delaware Basin well test results, and new completion results in the Niobrara with different well completions. So thank you for your interest in Carrizo.

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.

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