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Edited Transcript of CRZO earnings conference call or presentation 23-Feb-17 4:00pm GMT

Thomson Reuters StreetEvents

Q4 2016 Carrizo Oil & Gas Inc Earnings Call

Houston Feb 23, 2017 (Thomson StreetEvents) -- Edited Transcript of Carrizo Oil & Gas Inc earnings conference call or presentation Thursday, February 23, 2017 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Chip Johnson

Carrizo Oil & Gas, Inc. - President & CEO

* David Pitts

Carrizo Oil & Gas, Inc. - CFO

* Andy Agosto

Carrizo Oil & Gas, Inc. - VP of Business Development

* Brad Fisher

Carrizo Oil & Gas, Inc. - VP & COO

* Jeff Hayden

Carrizo Oil & Gas, Inc. - VP of IR

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Conference Call Participants

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* Neal Dingmann

SunTrust Robinson Humphrey - Analyst

* Will Green

Stephens Inc. - Analyst

* Jeff Grampp

Northland Capital Markets - Analyst

* Brian Corales

Scotia Howard Weil - Analyst

* Carlos Newall

Raymond James - Analyst

* Sean Sneeden

Oppenheimer & Co. - Analyst

* Marshall Carver

Heikkinen Energy Advisors - Analyst

* Chris Stevens

KeyBanc Capital Markets - Analyst

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Presentation

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Operator [1]

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Ladies and gentlemen, thank you for standing by. Welcome to the Carrizo Oil & Gas fourth quarter and year-end results conference call.

(Operator Instructions)

As a reminder, this conference is being recorded, Thursday, February 23, 2017. I would now like to turn the conference over to Chip Johnson, President and CEO. Please go ahead, sir.

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Chip Johnson, Carrizo Oil & Gas, Inc. - President & CEO [2]

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Thank you, operator. Let's get started. I will go over a brief introduction and then turn the presentation over to David Pitts, our CFO, to go over the financials. Then I will talk about operations and then we will open it up to Q&A. Our management team is pleased to report another outstanding quarter for the Company.

Our net oil production of 28,727 barrels of oil per day exceeded the high end of our guidance range and total production of 44,775 barrels of oil equivalent per day also exceeded the high end of our range. Despite the challenging commodity price environment we had in the first part of 2016, the fourth quarter capped off a record year production for Carrizo as Q4 oil production and full-year 2016 oil production were records for the Company. We also continue to report strong reserve growth as our proved reserves increased by 17% to more than 200 million Boe despite an SEC crude oil price deck that was approximately 15% below 2015 level.

David Pitts will discuss our proved reserves in more detail later. For 2017 we are announcing initial drilling and completion CapEx guidance of $530 million to $550 million as well as initial land CapEx guidance of $20 million. 2017 plan should allow us to run three rigs in the Eagle Ford as well as continued to develop our Delaware Basin position. Based on this level of activity, our initial 2017 crude oil production guidance is 31,400 to 31,900 BOPD, which equates to 23% production growth using the midpoint of the range.

Total production guidance for 2017 is approximately 48,500 to 50,000 Boe per day, over 16% year-over-year growth at the midpoint. For the first quarter of 2017, crude oil production is expected to dip to 27,700 to 28,100 BOPD due to a large amount of wells that have been shut in during the first quarter for offsetting fracs. The natural gas and NGLs first quarter production should range between 72 million and 76 million cubic feet per day and 4,700 to 4,900 barrels per day respectively.

We currently have a deep inventory of high return drilling locations, not only in the Eagle Ford where we have 1,200 net derisk locations, but in our other areas as well. Given this visibility, we're also announcing a three year plan that is designed to deliver a compound annual growth rate of more than 20% for our crude oil production while also reducing our leverage over the period. We expect to be able to deliver this growth rate by maintaining a three rig program in Eagle Ford and complementing this activity from other areas. Now I will turn it over to David talk about the financials.

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David Pitts, Carrizo Oil & Gas, Inc. - CFO [3]

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Thanks, Chip, and good morning, everyone. Today I will provide a brief review of our fourth quarter results and year-end reserves and then discuss some highlights of our 2017 guidance. As Chip mentioned, oil production for the quarter was a record 28,727 barrels per day, 17% higher than the third quarter of 2016. Gas production for the quarter was 66 MMcf per day and NGL production was 5,048 barrels per day.

Fourth quarter production exceeded the high end of guidance primarily due to stronger-than-expected performance from our Eagle Ford and Delaware Basin assets. Fourth quarter included revenues of approximately $144 million, of which hundred $123 million was attributable to crude oil. During the quarter we realized 95% of NYMEX oil which was at the high end of our guided realization range. We also realize 68% of NYMEX for gas -- also above the range of our guide realization due to better-than-expected differentials in the Marcellus.

We also realized 32% NYMEX for NGLs, also above the range of our guided realization. Operating costs and cash G&A for the quarter were $46.3 million, or $11.23 per Boe, which was within our guidance range. Net interest expense and interest capitalized for the fourth quarter were $20.5 million and $3.6 million respectively, also within the range of guidance.

EBITDA for the quarter was $118.1 million, a 30% increase from the $91 million reported for the third quarter of 2016. For the fourth quarter adjusted net income was $28.4 million, or $0.44 per diluted share, exceeding consensus earnings estimates of $0.32 per diluted share. Drilling and completion CapEx for the quarter was $92 million, more than 85% of which was in the Eagle Ford with the remainder weighted towards the Delaware Basin and Niobrara.

With respect to our proved reserves, which are included in our press release, for the year we delivered a 291% reserve replacement at an F&D cost of $13.65 per Boe. Our year-end proved reserves were approximately 200 MMBOE, an increase of 17% versus 2015 despite negative price related revisions of 6.7 million barrels of oil equivalent. Excluding the impact of those revisions, our drill bit reserve replacement was 295% at an F&D cost of $9.01 per Boe.

Included in the press release for the first quarter and full-year 2017 guidance, since Chip has already covered the CapEx and production guidance, I'll focus on some other key highlights. For the first quarter expect to realize 93% to 95% in NYMEX for oil, 68% to 73% of NYMEX for gas and 31% to 33% of NYMEX for NGLs. LOE guidance for the quarter is $6.75 to $7.25 per Boe.

As you may recall, last quarter I noted the historical unit operating costs of the properties acquired from Sanchez were higher than nearby Carrizo operating properties. Since taking over as operator of the properties that we acquired in December, we continued to integrate those with our legacy operations and expect to realize some level of operating efficiencies going forward. Our ongoing work-over plan on the acquired assets, along with those higher unit operating costs, is expected to result in an increase of approximately $0.50 per Boe to our first quarter LOE.

We expect to drive these costs down over time and bring them more in line with the LOE of our legacy operated properties. Cash G&A guidance is $47 million to $51 million for the year and $16.5 million to $20.5 million for the first quarter. The increase in cash G&A is due to an increase in headcount associated with the Sanchez acquisition as well as our decision to pay annual bonuses this year with a combination of cash and stock versus 2016 when we paid bonuses with 100% stock.

DD&A guidance for the first quarter is $12.75 to $13.75 per Boe. We estimate that net interest expense for the first quarter will be 20.5% to 21.5% and interest capitalized will be $3.5 million to $4 million. Our 2017 crude oil hedges consist of approximately 8,200 barrels per day of fixed-price swaps at an average price of $51 per barrel. Additionally, we have fixed-price swaps covering 20,000 MMBtu a day for the year at $3.30 per MMBtu.

Based on strip prices as of yesterday, we expect to receive $0 to $2 million from derivative settlements during the first quarter of 2017. We plan to opportunistically add additional hedges to the second half of 2017 and 2018 to protect our cash flows. Details regarding our derivative contracts are included in the press release. At year end, our net debt to adjusted EBITDA was 3.2 times.

We had $87 million drawn on our revolver with the total borrowing base of $600 million. Based on the latest bank price deck, we expect our spring redetermination will result in a significant increase of our borrowing base and will provide us with more than adequate liquidity to execute our business plan. Now I'll turn it back over to Chip for an operations update.

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Chip Johnson, Carrizo Oil & Gas, Inc. - President & CEO [4]

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Thanks, David. In the Eagle Ford we're producing from approximately 490 gross or 425 net wells with three drilling rigs running and two 24/7 frac crews. During the fourth quarter we drilled 23 gross or 22.9 net operated wells and completed 14 gross or 13.3 net wells. Crude oil production from the play was approximately 25,100 barrels per day for the quarter, up 16% from the prior quarter.

At the end of the quarter we had 35 gross or 33.4 net operated Eagle Ford Shale wells waiting on completion, equating to net crude oil production potential of more than 12,500 BOPD. We currently expect to drill approximately 107 gross or 92 net operated wells and frac 99 gross or 87 net operating wells in the play during 2017. The 2017 program is expected to be weighted toward longer lateral wells. Given our choke management practices, the benefit of longer lateral wells is not expected to materially impact 2017 oil production.

As I mentioned earlier in the call, we expect Eagle Ford production in the first quarter to be impacted by well shut-ins for offset fracs. As of today we had 25 net wells shut-in, representing approximately 1,900 BOPD of net production. Our spacing initiatives in the Eagle Ford continue to bear fruit. At the RPG project area we have four stagger stack pilots testing 250 foot effective lateral spacing that have five to eight months production history. Results thus far have been very encouraging with cumulative production meeting or exceeding production to the nearby 330 foot space wells.

At Irvin Ranch we have three pilots testing 200 feet to 285 feet effective lateral spacing. These pilots have 10 to 14 month production history. While the early dated Irvin Ranch was not conclusive, performance from these pilots has continued to improve and we now believe the stagger stack development will be profitable in this part of the Irvin Ranch. As the lease covers approximately 10,000 acres, we plan to conduct additional pilots on the untested portion of Irvin Ranch.

We also had success from our initial infield test in the Eagle Ford which was located on the Irvin Ranch as well. The Irvin 1H was drill between a pair of five year old producing wells and has approved -- produced approximately 75 MBO 14 months from a short lateral. We also saw a positive production response from the parent wells which produced approximately 15 MBO of an incremental oil following the Irvin 1H completion. As a result of the spacing initiatives we increased our estimate of net derisk drilling inventory in the Eagle Ford by more than 10% over 1,200 net locations.

We currently have five additional pilots across our acreage positions that are being drilled or completed or have limited production history. We will provide further updates as we got more data on these tests. We also continue to see positive results from tighter frac stage spacing in our Eagle Ford wells. We currently have 28 wells online with 200 foot stage spacing and they appear to be out-performing the wells with wider stage spacing by approximately 10%.

We also see less frac interference from offsetting parent wells when use the tighter stage spacing. Given these results, we plan to test even tighter stage spacing in future wells testing 175 feet to 180 feet stage spacing. I'll also note that while we believe that tighter stage spacing will result in higher EURs, this impact has not been factored into our year-end proved reserves or our production guidance.

In the Delaware Basin we drilled two new operated wells during the quarter that were [odder] state 1H and the [Thunderbolt] state 1H, both of which are located on the western side of our acreage position. We expect to complete both wells as part of our 2017 program which currently includes drilling approximately six gross or four net operated wells and completing six gross or five net operated wells. We expect our 27 program to manage our leasehold obligation in the basin as well as further delineate our acreage position. With that, we'd like to turn it over to Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions)

Neal Dingmann, SunTrust.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [2]

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Chip, could you talk about just looking at that slide -- I guess it's slide 7 -- you talked about the success in your press release about the stagger stacks and about potentially going to more areas. Can you talk about where in the near-term you're thinking about going and is there additional areas you could also apply that later on?

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Andy Agosto, Carrizo Oil & Gas, Inc. - VP of Business Development [3]

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Hi, Neal, it's Andy Agosto. Going forward, in 2017 I think generally anywhere where we've got fairly large multi-well pads we're going to be adding some stagger stack tests. So we've actually have got a couple of the ones that Chip mentioned in his comments -- we are in our [Panea-Jasik] area and then a couple more that are at Irvin Ranch right now. But going forward, in 2017 I think we're going to continue to do it wherever we have enough wells to justify it.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [4]

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Okay. And then just one last one. Chip, you mentioned about adding the rig. Can you talk about are you able to lock in cost? Some of your peers are talking about that. If you could just give some color on, for the remainder the year, if you're able to lock anything in. Thank you.

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Brad Fisher, Carrizo Oil & Gas, Inc. - VP & COO [5]

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Neal, this is Brad Fisher. We did pick up another rig in the Eagle Ford. It was an H&P. We're going to call that a gen three rig. It's equipped with 7,500 psi equipment plus three pumps.

So it's a bit of an upgrade for us. As far as locking in cost, we have been able to lock in some cost. We have locked in some frac cost through Q2 with a couple of our vendors. Of course, all this price locking is going to be subject to any significant move in sand cost and stuff like that, particularly on the frac side. But we buy our pipe typically six months out in advance so we have been able to locked down some prices here.

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Operator [6]

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Will Green, Stephens.

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Will Green, Stephens Inc. - Analyst [7]

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Let's follow on on that last point. Obviously lift in prices -- you guys are looking at locking in some of the costs that you guys foresee. Are you guys thinking about any change in hedging strategy going forward given that we may be entering an environment of maybe some service cost inflation? How are you guys thinking about the hedge strategy going forward? Is there any shift in that?

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Chip Johnson, Carrizo Oil & Gas, Inc. - President & CEO [8]

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I guess one thing we've started looking at that we hadn't for a long time, in light of what you just said on service cost but also the [backward] dated oil curve, is looking at some collars. And we have been pricing collars that are generally $50 to $70 and then looking at selling a foot somewhere below that to help pay for that. So we haven't done that yet. We have been pricing those. But we would like to get some price protection on oil but not give up the upside if service costs go up.

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Will Green, Stephens Inc. - Analyst [9]

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Sure. That's helpful. And then I wonder if -- looking forward, obviously the meat of the budget and the meat of the go-forward plan is in Eagle Ford. You guys talked about this growth ramp that you guys have focused on oil that's mainly focused on the Eagle Ford. But there's also been a lot of industry focus out in the Wattenberg as of late, in the Delaware as of late.

And specifically in the Delaware, you guys are noting IRRs that are actually comparing pretty favorably to where you guys are in the Eagle Ford. So I guess my question is what's the scenario where we actually see the Delaware commanding two or three dedicated rig program. Is it just more scale out there, better repeatability, better takeaway, more visibility on the service landscape? What factors go into ultimately seeing that Delaware ramp take place for you guys?

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Chip Johnson, Carrizo Oil & Gas, Inc. - President & CEO [10]

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You make a good point. One thing we have seen as we model all this out is that we can grow our oil production a lot faster within the same budget in the Eagle Ford and the Niobrara. Everything just takes longer in the Delaware. Ultimately the profitability is good.

A lot of that is driven by gas and NGLs. But you just can't drill as many wells as fast as you can in Eagle Ford and the Niobrara. So that's -- while we don't have to do that yet in the Delaware, we are still building out infrastructure and adding water disposal, working through the pipeline commitments -- it just makes a lot more sense right now to focus on the Eagle Ford or what we will probably call just an Eagle Ford-type oil return for a dollar spent, which right now is Eagle Ford and Niobrara.

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Will Green, Stephens Inc. - Analyst [11]

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Great. I appreciate the color, guys.

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Operator [12]

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Jeff Grampp of Northland Capital Markets.

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Jeff Grampp, Northland Capital Markets - Analyst [13]

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First question on the stagger stack -- I though it was an interesting comment in the release that you guys are actually seeing some improving performance on some of the recent tests. Can you talk a bit about what you all are seeing there as far as what in particular could be driving that improved performance?

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Andy Agosto, Carrizo Oil & Gas, Inc. - VP of Business Development [14]

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This is Andy Agosto again. I guess maybe on stagger stack step back a little bit. We have been pretty consistent in the past talking about the program, the objectives of the program being maximizing [NPV] and reserves from the Eagle Ford asset. But to do this and maintain really attractive rates of return, to reach a project area, the well spacing and commodity prices are going to dictate what the best -- what effect the well spacing gets you there.

So as Chip mentioned, at Irvin Ranch when we looked at that after six to eight months of production history on the last call, it was inconclusive. But with three additional months of data, those wells have -- production has kind of flattened out. And so it appears that at current prices where we have tested is profitable. And so that's why we've added some inventory there.

I think at Brown Trust and RPG -- we talked about Brown Trust on the last call and RPG on this one -- we saw conclusive result a lot sooner and so we were able to add inventory a lot quicker. But I think overall, it does underscore -- Irvin Ranch underscores the need to really adequately test each individual area.

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Chip Johnson, Carrizo Oil & Gas, Inc. - President & CEO [15]

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And to answer your question on the in-fills, we saw the same thing sometimes in the Barnett Shale where fracking in between wells would interfere with them initially but then they come back at a higher rate and have higher EURs. And it's hard to explain that. But we have seen it before and I think what it does is mean you might have a great target for refracs down the road on some of these old wells. So I know some people have been experimenting with that in the Eagle Ford and eventually we will too.

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Jeff Grampp, Northland Capital Markets - Analyst [16]

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Okay. That's helpful color. And for a follow-up, I got the bigger picture question -- as we look out in 2017, certainly guys highlighted plenty of liquidity on the line to fund the program. Is that kind of the base expectation that we should be thinking about? Or are you guys thinking about potentially, from the portfolio management standpoint, whether it's the Niobrara or Marcellus Northeast -- are any of those types of things on the dock for potential divestitures? Or how are you guys thinking about bigger picture funding the program?

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Chip Johnson, Carrizo Oil & Gas, Inc. - President & CEO [17]

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I guess that base case is that we can do it with the revolver. We typically haven't used equity to just fund drilling programs. But we do have inbound offers all the time for the Appalachian assets and we haven't seen a price we like but we are in discussions with bankers about what they think the market is and whether we should sell some of those assets that would help fund the program. It doesn't have much of an impact on EBITDA.

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Jeff Grampp, Northland Capital Markets - Analyst [18]

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Okay. Great. Helpful color. I'll have back into the queue. Thanks, guys

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Operator [19]

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Brian Corales with Howard Weil.

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Brian Corales, Scotia Howard Weil - Analyst [20]

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Just two quick questions. One, the 20% growth I guess on the out years you all discussed on the oil side, does that just assume the same rig count or is that an acceleration?

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Brad Fisher, Carrizo Oil & Gas, Inc. - VP & COO [21]

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No, that's three rigs in the Eagle Ford or something that has the same oil-to-dollars spent look as the Eagle Ford does

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Brian Corales, Scotia Howard Weil - Analyst [22]

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Okay.

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Jeff Hayden, Carrizo Oil & Gas, Inc. - VP of IR [23]

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Brian, sorry. It's Jeff. And then on top of that, it does assume there's some other activity in the basins outside of the Eagle Ford -- probably equivalent to about one rig year. And, honestly, we've got a lot of flexibility, whether that rig year is in the Delaware Basin, in the Niobrara, you can still hit those numbers.

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Brian Corales, Scotia Howard Weil - Analyst [24]

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Okay. Thanks. And then we saw at least a big transaction on the further -- on the western side of the Eagle Ford. I guess that was earlier this year. Are you all looking to step out of your core area in LaSalle or is that not in the cards?

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Brad Fisher, Carrizo Oil & Gas, Inc. - VP & COO [25]

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We look at every Eagle Ford deal. We're focused on volatile oil window and on assets in the volatile oil window that haven't been drilled up. So that's what ruled out that deal for us essentially and a couple other deals. But we are in data rooms now and have offers on the table for bolt-on Eagle Ford deals.

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Brian Corales, Scotia Howard Weil - Analyst [26]

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Okay. So has -- more willing sellers than we have seen maybe the past year or two?

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Brad Fisher, Carrizo Oil & Gas, Inc. - VP & COO [27]

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I guess we have seen a lot more activity in the gassy assets. They seem to all be up for sale but not that much activity in the oily assets.

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Brian Corales, Scotia Howard Weil - Analyst [28]

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Okay. All right, guys. Thank you.

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Operator [29]

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Carlos Newall with Raymond James.

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Carlos Newall, Raymond James - Analyst [30]

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Quick question on -- you mentioned you're using larger pads on a go forward basis. Just curious, how big are the pads now? How big do you expect them to be? And how does that effect spud-to-sale per pad on a go-forward basis?

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Andy Agosto, Carrizo Oil & Gas, Inc. - VP of Business Development [31]

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I think -- this is Andy again -- historically we have generally been in the three to six wells per pad. And what we are moving to is actually a single pattern, maybe even two pads side-by-side where we drill eight, sometimes as many as 10 wells. I don't have the exact data spud to first production. It is going to add some time. I think you are right on with that. But maybe Jeff you can follow up on that.

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Jeff Hayden, Carrizo Oil & Gas, Inc. - VP of IR [32]

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Yes, I just think about some of the numbers -- we are probably drilling those wells right now and --

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Brad Fisher, Carrizo Oil & Gas, Inc. - VP & COO [33]

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Carlos, this is Brad Fisher. Just to chime in there -- so part of the strategy in going to these bigger pads is to implement two frac crews as well. So the actual spud to first production time is not really going to change. So when we drill these bigger pads, we will maybe we move two rigs in a single area, drill side-by-side, then we'll move two frac crews in. So we are really not going to see a significant change on a pad level basis.

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Carlos Newall, Raymond James - Analyst [34]

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That's really helpful. Thanks, guys.

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Operator [35]

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Sean Sneeden with Oppenheimer.

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Sean Sneeden, Oppenheimer & Co. - Analyst [36]

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Thank you for taking my questions. Chip, I appreciate the three year overview you guys gave. If you don't mind, just give me a little bit more granularity. One, can you give us a sense of how we should think about exit to exit as we go from 2017 to 2018?

And then one of the other questions was asking about free cash flow deficit. But is the general expectation that as you start going into 2018 that you are running roughly a free cash flow neutral profile -- kind of assume the three rig Eagle Ford program?

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Chip Johnson, Carrizo Oil & Gas, Inc. - President & CEO [37]

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I don't know if we're going to go out with specific guidance on that. But as far as exit to exit, I guess I just use 20% to model. The quarters are going to be lumpy because of the big pads we are fracking like they were last year in the third and fourth quarter.

Third was kind of down and then forth made up for it. But as far as out spending cash flow, with the current strip it looks like we are pretty close to neutral in 2018. And then in 2019, EBITDA should exceed our drill and complete budget with the current plan.

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Sean Sneeden, Oppenheimer & Co. - Analyst [38]

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Okay. That's helpful. And then just on the balance sheet, obviously the 7.5 are currently callable. And I think that call price dipped down in September. How are you guys thinking about trying to refinance that and push out the maturity at this point? Are you comfortable waiting until September or how do you guys think about that?

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David Pitts, Carrizo Oil & Gas, Inc. - CFO [39]

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This is David Pitts. Yes, we have been looking at that ever since they became callable last September. Given that we are roughly six months away from the point at which the call price drops by $11 million -- and if we refinanced today we could probably save $900,000 to $1 million a month -- it seems to make sense to us that we are going to wait until September to refinance those 7.5% notes.

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Sean Sneeden, Oppenheimer & Co. - Analyst [40]

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Okay. That's helpful. And then just maybe one housekeeping question. I know you guys have highlighted the drop in SEC price deck. Have you guys looked at what reserves in the associated value might be under more of a strip case?

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David Pitts, Carrizo Oil & Gas, Inc. - CFO [41]

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We have not done that yet. We are in the process of updating our reserves at the bank price stack, which is reasonably close to strip pricing, which should have a significant impact on the reserves and the PD9 in the bank case. But we have not run that yet.

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Sean Sneeden, Oppenheimer & Co. - Analyst [42]

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Okay. Fair enough. Thank you very much.

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Operator [43]

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(Operator Instructions)

Marshall Carver with Heikkinen Energy Advisors.

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Marshall Carver, Heikkinen Energy Advisors - Analyst [44]

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Tighter stage spacing -- you said that it wasn't factored into reserves. But did you say if it was factored into guidance and what percentage of your 2017 wells will be using that tighter stage spacing?

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Andy Agosto, Carrizo Oil & Gas, Inc. - VP of Business Development [45]

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We are going to be using it in everything going forward, Marshall. This is Andy again. We did not factor it into production guidance or year-end reserves.

I think it's just a little bit early in terms of the overall data set we have in various areas. So we're really right now just implementing this in individual project areas generally for the first time. As we get more data going into 2017, I think we will be able to much more accurately make that assessment.

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Marshall Carver, Heikkinen Energy Advisors - Analyst [46]

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Okay. That's it for me. Thank you very much.

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Operator [47]

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Chris Stevens with KeyBanc.

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Chris Stevens, KeyBanc Capital Markets - Analyst [48]

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Is there any change to the average lateral line for your program in 2017 or 2018 out in Eagle Ford relative to 2016?

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Chip Johnson, Carrizo Oil & Gas, Inc. - President & CEO [49]

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Yes, we are going to on average longer laterals in 2017 and 2018. And I think we have come up with a number about 20% more frac stages in 2017 than we would have planned for. So that's a big part of why our CapEx went up. But we think we will get the reserves for that also. Production might not go up as fast because we tend to use choke management -- at least it won't go up in the near-term but it will probably be a little higher in the midterm than it would have been.

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Chris Stevens, KeyBanc Capital Markets - Analyst [50]

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Okay. And then in terms of the Eagle Ford DUCs, it looks like you're probably going to exit 2017 with roughly 43 out there. Is that the right number going forward for three rigs through 2019? Or do you start to work some of those down maybe in 2018 and maybe keep it constant?

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Andy Agosto, Carrizo Oil & Gas, Inc. - VP of Business Development [51]

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This is Andy again. That's a little bit high. We will be around the upper 30s we think at the end of 2017 -- mid to upper 30s.

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Chris Stevens, KeyBanc Capital Markets - Analyst [52]

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Okay. And then just in regard to the comment in the press release about testing a little bit further west over in Culberson County, do you plan to do the same sort of thing over there, same zone, same completion design or anything different? I know there are some offset operators testing the Bone Spring to the southwest of you.

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Andy Agosto, Carrizo Oil & Gas, Inc. - VP of Business Development [53]

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We don't have a bone spring test planned yet. We are watching theirs. Right now all of our plans are still Wolfcamp A. We are looking at shorter stage links, more and more water, different sand loadings -- everything everybody else is looking at. So it's kind of an ongoing improvement. But right now everything we are looking at is Wolfcamp A.

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Jeff Hayden, Carrizo Oil & Gas, Inc. - VP of IR [54]

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Chris, it's Jeff. I think the comment that we had in the press release was that the two wells we drilled in the fourth quarter were on the western side of our acreage. In fact, if you look at where those wells are, one of those is on the far western side of our acreage. So we don't really have anything further west than that.

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Chris Stevens, KeyBanc Capital Markets - Analyst [55]

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Okay. Appreciate the color. Thank you.

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Operator [56]

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Mr. Johnson, there are no further questions at this time. I will now turn the call back to you. Please continue with your presentation or closing remarks.

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Chip Johnson, Carrizo Oil & Gas, Inc. - President & CEO [57]

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Okay. Well thank you all for calling in and a lot of good questions. Thanks to our staff or another great quarter. We are excited by the improving performance on frac design, infill drilling and stagger stacks in the Eagle Ford.

The last three producers in the Delaware Basin show how fast we came up the learning curve in drilling and fracking. It validated the profitability of our entire position. And our Niobrara economics have improved dramatically from both price net backs and well performance, bringing that asset back into the conversation. So thanks again and we will talk after the next earnings.

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Operator [58]

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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.