Carrizo Oil & Gas (CRZO) Q2 2018 Results - Earnings Call Transcript

Carrizo Oil & Gas, Inc. (NASDAQ:CRZO) Q2 2018 Earnings Call August 7, 2018 11:00 AM ET

Executives

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

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

David Pitts - Carrizo Oil & Gas, Inc.

John Bradley Fisher - Carrizo Oil & Gas, Inc.

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

Analysts

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Ronald E. Mills - Johnson Rice & Co. LLC

Leo P. Mariani - NatAlliance Securities

Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Noel Parks - Coker & Palmer, Inc.

Kashy Harrison - Simmons/Piper Jaffray & Co.

Michael Dugan Kelly - Seaport Global Securities LLC

John A. Freeman - Raymond James & Associates, Inc.

Daniel Eugene McSpirit - BMO Capital Markets (United States)

John Nelson - Goldman Sachs & Co. LLC

Operator

Ladies and gentlemen, thank you for standing by and welcome to the Carrizo Oil & Gas Second Quarter 2018 Earnings Call. As a reminder, this conference is being recorded today, Tuesday, August 7, 2018.

I would now like to turn the conference over to Mr. Jeff Hayden, Vice President of Investor Relations. Please go ahead, sir.

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

Thank you, operator, and thanks to everyone for joining us. Before we begin, I'd like to remind you that today's remarks include forward-looking statements, as well as non-GAAP measures. Please refer to yesterday's press release for the cautionary language about any forward-looking statements or reconciliations to the most directly comparable GAAP measure. We have posted slides to go along with the webcast today. The slides can be found on the Investor Relation section of our website at www.carrizo.com.

Joining me on the call this morning are Chip Johnson, President and CEO; David Pitts, Vice President and CFO; Brad Fisher, Vice President and COO; and other members of our senior management team.

And with that, I'll turn the call over to Chip.

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

Thanks, Jeff. This was another excellent quarter for Carrizo as we delivered results that exceeded expectations and reacted quickly to shift capital to our higher margin Eagle Ford asset, once it Permian Basin differentials were widening sooner and to a greater degree than we had originally expected. This shift is expected to enhance our overall financial metrics, as returns in the Eagle Ford Shale are currently significantly higher than returns in the Delaware Basin.

We believe our ability to quickly shift capital between our plays highlights the advantages of having complementary acreage positions. Our total production during the first quarter was 57,077 Boe per day, which exceeded the high end of our guidance range. Our crude oil production of 37,860 Bopd was up 11% versus the first quarter and accounted for 66% of our total production during the quarter. We also delivered excellent cost control with total unit operating expenses coming in below the guidance.

Our adjusted EBITDA margin increased by 17% versus the first quarter as our Eagle Ford Shale production continued to benefit from strong LLS pricing. As a result of these items, we were again able to deliver adjusted EPS and EBITDA that exceeded the analysts' consensus estimates.

Given the relative outlook for local oil prices in our two core plays, we have elected to shift capital from the Delaware Basin to the Eagle Ford Shale. We began to shift activity in the second quarter as we moved one of our four Delaware Basin rigs to the Eagle Ford. We recently added another rig to the play bringing our total to four. For the balance of the year, we currently expect to run an average of six rigs with four in the Eagle Ford Shale and two in the Delaware Basin. This compared to our prior plan, which had two rigs in Eagle Ford and three to four in the Delaware Basin.

Our current plan should allow us to build an inventory of more than 40 Eagle Ford DUCs by year-end setting us up for strong growth in the play in 2019. As I mentioned, we expect the capital shift to have a positive impact on our financial results. Based on current strip prices, our new plan should result to more than $100 million incremental EBITDA by year-end 2019, driving a further reduction in our leverage metrics and it should enhance our total returns leading to an approximate 2 percentage point increase in our return on capital employed relative to our prior plan from 14% to 16%.

As a result of the increased drilling activity, we are increasing our DC&I CapEx guidance to $800 million to $825 million, which should allow us to run an average of six rigs and two to three completion crews. We are adjusting our 2018 production guidance to 58,700 Boe per day to 60,100 Boe per day, which equates to more than 30% production growth at the midpoint pro forma for our A&D activity from last year.

Our new guidance range accounts for a 650 Boe per day to 700 Boe per day negative impact from non-op divestiture in the Delaware Basin, as well as the earlier expected payout at the Brown Trust multipad. Crude oil is still expected to account for 65% to 67% of our production during the year.

For the third quarter of 2018, production is expected to increase to 62,000 Boe per day to 63,000 Boe per day. In the Eagle Ford Shale, our operations continue to perform very well. In the second quarter, we drove 19 gross or 18 net operated wells and completed 18 gross or 16 net wells.

Total production from the play was more than 37,000 Boe per day for the quarter. As a result of lower unit operating expenses as well as crude oil production from the play receiving LLS-based pricing, our operating margin expanded to approximately $48 per Boe during the quarter.

At the end of the quarter, we have 15 gross or 14 net operated Eagle Ford Shale wells waiting on completion. We currently expect to drill 95 gross to 100 gross or 90 net to 95 net operated wells and frac 85 gross to 90 gross or 75 net to 80 net operated wells in the play during 2018.

Production from our first large-scale multipad development located in our Brown Trust project area continues to be strong. The multipad has been on production for more than 120 days and continues to produce more than 12,000 Bopd gross.

Based on the strong performance from the wells as well as strong commodity prices, we currently expect the wells in the project to payout in six to nine months. While this highlights just how strong the project's return is expected to be, it also accelerates the timing of the back in after payout that occurs in the Brown Trust area. The impact for year 2018 production of the payout moving from early 2019 into the second half 2018 is expected to be more than 200 Boe per day.

In the Delaware Basin the company's activity during the quarter was weighted towards the Wolfcamp A. During the second quarter, we drilled 9 gross or 8 net operated wells, completed 12 gross or 9 net operated wells. The total production from the play was approximately 19,800 Boe per day for the quarter, up 30% versus the prior quarter. We currently expect to drill 28 to 32 gross or 22 net to 26 net operated wells and frac 23 to 27 gross or 18 to 22 net operated wells in the play during 2018.

We continue to deliver strong well results in the play, bringing on a number of wells that achieved crude oil production rates of more than 1,000 Bopd. Among these were two over under stack tests, Zeman 11H and Dorothy 11H where we completed a Wolfcamp A well directly above an existing lower Wolfcamp B well.

In order to continue testing potential multi-zone of cube development concepts, the vertical separation between these new and existing wells was roughly 450 feet and we are very encouraged by the early results with little or no interference.

We also recently brought online a nice delineation well in an area where we haven't included many locations in our de-risked inventory count, the SRO 551 100H located on our Ward County acreage began production last month. While it has yet to record a peak 30-day rate, it recently achieved a 24-hour rate of more than 2,400 Boe per day on a restricted choke.

We continue to enhance our portfolio of midstream contracts in the Permian Basin since the first quarter. On the oil side, we recently signed a deal with a major crude purchaser who agreed to buy all of our crude oil production with no minimum volume commitments from us from September 2018 through July 2020 at Midland-based prices. This deal provides us with 100% certainty of flow for our crude oil production, while also maintaining our flexibility to shift capital between plays in order to maximize our returns.

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

David Pitts - Carrizo Oil & Gas, Inc.

Thanks, Chip, and good morning everyone. As Chip mentioned, oil production for the quarter was over 37,800 barrels per day. NGL production was over 9,300 barrels per day and natural gas production was over 59,000 Mcf per day, the total production exceeding the high end of our guidance range.

During the quarter, we realized 98% of NYMEX for oil, 37% of NYMEX for NGLs and 85% of NYMEX for natural gas. The realizations were either in the upper half or above the high end of our guided ranges. NGL realizations were higher than forecasted due to higher than expected ethane prices. Natural gas realizations were higher than forecasted due to higher than expected realizations in the Eagle Ford.

Operating costs and cash G&A for the quarter were $61 million or $11.74 per Boe, although the low end of our guidance range. For the second quarter, adjusted EBITDA was $178.9 million, with adjusted net income of $66.6 million or $0.79 per diluted share, exceeding consensus earnings estimates of $0.68 per diluted share.

With regard to dividends on preferred stock, during the second quarter, we elected to pay the $4.5 million dividends in cash. Quarterly dividends will continue to be $4.4 million to $4.5 million per quarter, with the quarterly non-cash expense related to the accretion of the discount of preferred stock expected to be $0.7 million to $0.8 million. We currently expect the dividends will continue to be paid in cash.

Drilling, completion, and infrastructure capital expenditures for the quarter were $218 million, in line with our expectations. Nearly 55% of the expenditures were in the Delaware Basin with the balance in the Eagle Ford. At the end of the second quarter, our net debt to adjusted EBITDA was 2.5 times as calculated under the terms of our credit agreement. We have $485 million drawn at the end of the quarter, with a total elected commitment of $900 million.

Included in the press release and earnings presentation is our third quarter and full-year 2018 guidance. Chip has already discussed the guidance for production and capital expenditures, so I'll cover some of the other highlights. Given the LLS premium to WTI, we expect Eagle Ford realizations to be about 102% of NYMEX, resulting in total crude oil realizations of 95% to 97% of NYMEX for the third quarter. For natural gas, we expect third quarter realizations to be 80% to 82% of NYMEX. NGL realizations are expected to be 38% to 40% of NYMEX for the third quarter.

Our LOE guidance for the third quarter is $6.75 to $7.25 per Boe and we're lowering our full-year LOE guidance to $7.15 to $7.50 per Boe.

We expect production taxes as a percentage of revenues to be 4.75% to 5% for the third quarter and have narrowed our annual production tax guidance range to 4.7% to 4.9%. Regarding ad valorem taxes for the third quarter, moving forward, we will begin guiding this cost on a percent of revenue basis.

Cash G&A guidance for the year has been narrowed to $52.5 million to $53.5 million. For the third quarter, we expect cash G&A to be $10 million to $10.5 million.

DD&A guidance stays flat for the third quarter at $13.75 to $14.75 per Boe with guidance for the year now at $13.75 to $14.50 per Boe. Regarding guidance for interest, net interest expense in the third quarter is expected to be $15.8 million to $16.8 million, with interest capitalized expected to be $8 million to $8.5 million.

With respect to hedging, we've used basis swaps to help manage our exposure to crude oil price differentials. For the balance of 2018, we have Midland-Cushing basis swaps on 6,000 barrels per day locking in a discount to WTI of $0.10 per barrel. We also have LLS-Cushing basis swaps on 18,000 barrels a day locking in a premium to WTI of over $5 per barrel for the balance of 2018.

As Chip mentioned, we recently executed a deal that provides us with flow assurance on 100% of our Delaware Basin crude oil production at a market-based Midland price through mid-2020. Since signing this contract, we've added 5,000 barrels per day at Midland-Cushing basis swaps locking in a discount to WTI of $4 per barrel, and we're currently looking at adding additional basis production in 2020 as well.

This should provide us with price protection in case one or more of the planned Permian pipelines is delayed causing the differential to worsen as we shift activity back to the basin. Details regarding our derivatives contracts can be found in the press release. Based on strip prices as of yesterday, we expect our derivative settlements during the third quarter to result in cash payments of $24.5 million to $28.5 million.

Now, I'll turn the call back over to Chip.

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

Thanks, David. At this point, we'd like to start the Q&A. So let's go ahead with that.

Question-and-Answer Session

Operator

Thank you. And our first question comes from the line of Neal Dingmann with SunTrust. Please go ahead.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Good morning, Chip, the rest of the guys. Chip, Eagle Ford continues to look like you're having really nice success there. Can you just talk about space in a little bit more there? I know you've been able to down space a bit with the Brown Trust and others, but just any comments you could have around how you view the rest of your space and field?

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

I think generally we're sticking with 330-foot spacing in bulk of the acreage. There's still a couple of places we think 500 feet might be better on the Brown Trust. We did have some of the wells in 250 feet. And so far we haven't seen any interference or better or worse performance, but we're still in the early six-month period where everything is on restricted chokes and constrained rate. So it's hard to tell. I think we'd rather just say 330-foot is the easy answer and we'll keep trying to figure out ways to tighten that up.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. Thanks, Chip. And then secondly, Chip, there seemed to be a little confusion or maybe just talk a little bit about the Brown Trust accelerated payout. Is that sort of typical of what you're seeing on a lot of your plays? And again, I mean, frankly I was glad to see it, but I just – if you could talk maybe a bit more about that?

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

Well, I don't think we have back-ins after payout anywhere else in our inventory. We used to – we bought out some of those partners three or four years ago. But this was an arrangement we got into with a major where we had at least half the minerals, they own the other half, and we made a deal with them eight years ago where we could drill and they could either participate or they could back-in after payout. And sometimes they participate, sometimes they back in.

This time, they're going to back in. And this had been in the fourth quarter. We probably would have had to draw attention to it. But if it had just been in the middle of the year, it wouldn't have made much difference. But they have 1,000 barrel a day drop in production in the fourth quarter. We felt like we needed to point that out. Otherwise, we thought this would have happened in the first or second quarter of next year.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

And then, Chip, when that just balances, I guess that's just sort of a onetime item then, correct?

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

Yeah, on those wells. Next year when we bring on more wells in the Brown Trust, if that company has not participated, then it'll start another back-in after payout on those wells.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Very good. Thank you.

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

The good thing was we made that much more EBITDA this year than we expected to, because of the raise in the oil prices. So, we felt like it was a good thing.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

No, I would agree.

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

Hey Neal, this is Jeff. Easy way to think about it is whenever we're talking to you guys about acreage, we assume the company is going to come in and participate heads up, so if they don't, we just end up with a higher interest earlier on. And then after wells hit payouts, they back in. So, this doesn't really have any impact on any of the inventory numbers, net acre numbers, anything like that. It's just we get the benefit of some additional production upfront, if they elect to not participate heads up.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Good. Yeah. Good clarification. Thanks, Jeff. Thanks, Chip.

Operator

The next question comes from the line of Ron Mills with Johnson Rice. Please go ahead.

Ronald E. Mills - Johnson Rice & Co. LLC

Good morning. Chip, I just – I know we haven't talked about – you haven't talked about 2019. But as you shift those, the other two rigs to the Eagle Ford and you build your DUC locations from 15 to 40. You talked about that shift generating an incremental $100 million of EBITDA for a lower amount of CapEx. But the production impact clearly is felt in 2019. How would you want us to look at 2019 in terms of that cadence from those DUCs coming online?

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

Well, I guess to put all that back in perspective, we are saying we'll increase EBITDA over $100 million next year with the same amount of CapEx, and that the oil production ramp-up starts in the fourth quarter of this year from the shift. We don't get a lot of impact from the shift in the third quarter, and frankly, most of the wells we frac'd in the second quarter were in the Permian.

So as we start fracing more wells in the Eagle Ford, the production will start coming up in the Eagle Ford. Permian will decline more than we thought or more than we had planned. And so next year, we'll see – we're not trying to increase the Bopd, we're trying to increase the EBITDA. So, it's not as much based on the production increase as producing barrels with $50 margins instead of $22 margins.

So, we haven't worked out how all these pads are going to come on next year. In the Eagle Ford, everything is done on pads. The smallest pads we do are probably three-well pads and we've done 16-well pads. So, the production is lumpier. We haven't mapped all that out. But we know basically what we'll do for the year and that's how we can come up with the increasing EBITDA.

Ronald E. Mills - Johnson Rice & Co. LLC

Okay. Great. And then, as you think about the shifts back in the middle part of 2019, the – when you go back to four rigs in the Permian ahead of the capacity increases, how do you think that that program lays out given the recent activity was all focused in the A. Is it going to be more balanced between the A and B and any other zones potentially to be tested? Thanks.

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

Well, we're working on this cube concept, where we frac from the A to the bottom of the B and maybe into the C. Where we're trying, like everybody else, to figure out how to optimize the number of layers you can get; we thought we were going to get three layers in the A and the B. And based on these early tests and the lack of interference, we think maybe if we're careful we can increase that, maybe up to five layers. And we're working with (21:10) right now to try to figure out how to do that based on core work. But one good thing about the shift to the Eagle Ford is that now we'll have more time to analyze the spacing and stacking pilots that we're still going to go ahead and do in the Permian. And hopefully, have that figured out by late next year when we bring the rigs back, if the futures market is right on where the differentials are.

Ronald E. Mills - Johnson Rice & Co. LLC

Great. Thank you.

Operator

The next question comes from the line of Leo Mariani with NatAlliance. Please go ahead.

Leo P. Mariani - NatAlliance Securities

Hey, guys. Just wanted to follow up a little bit on what you'd said there on the Permian and, clearly, you guys were talking about lower activity as you work later this year. But I guess just from a high level, should we expect Permian to continue to grow in the third quarter and then also in the fourth quarter or do you start to see Permian flatten out or even decline a little late this year in terms of the production there? And then into the first half of 2019, just a similar question, does Permian grow? Does it flatten? Does it decline? How do you see that playing out with the activity shift?

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

Hey, Leo. It's Jeff. So, if you think about it, you just kind of add on a little bit in some of those questions about activity. What you probably see just given the drilling activity in Eagle Ford this year, and then in fact we're keeping four rigs there for the first half of next year, I think it's safe to assume that you probably see the completion activity weighted to the Eagle Ford in the first half of the year. And then it'll probably be weighted a little more towards Permian in the back half of the year.

Given that, what you're probably going to looking at in the Permian is kind of a flattening. I don't know if you'll necessarily see a decline, but maybe a flattening of production over the next several quarters. And then as you get kind of later next year, you probably see the Permian start to incline a lot more as we start increasing the completion activity out there. In the meantime, I think, between now and then you're going to see a lot of production growth likely in the Eagle Ford Shale as we kind of shift our activity over there.

Leo P. Mariani - NatAlliance Securities

Okay that's helpful. And I guess is it safe to assume that the changes you guys have made, a shift in capital to Permian that basically all your Permian acreage as you're looking to protect will get held over the next year here?

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

Yeah. We've got a drilling schedule in the Permian that takes care of our acreage. That's still something. That's the most critical thing we have to do at this point.

Leo P. Mariani - NatAlliance Securities

Okay. Now that makes sense for sure. And I guess just lastly on the asset sale that you guys had just mentioned here. Just trying to get a sense in terms of magnitude, if you guys could let us know what the proceeds are and is this a one-off deal or might you guys monetize other little bits and pieces of the Permian going forward?

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

Well, I guess in the past we've actually sold some little bits and pieces. This one, especially because it was non-op and the new owner, the new operator of these assets looked pretty aggressive about capital spending. We felt like this could reduce our non-op CapEx budget significantly over the next two years and we felt like we got a good price for it. Part of our CapEx increase this year has been non-op. We have some other non-op partners who ramped up their activity in different parts of the core of the Delaware Basin and so we've had to increase our CapEx for that. But we felt like this was a good chance to maybe get out of some non-op at a good price and reduce that exposure to somebody else's capital footprint.

Leo P. Mariani - NatAlliance Securities

All right. Thanks.

Operator

The next question comes from the line of Mike Scialla with Stifel. Please go ahead.

Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.

Yes. Hi. Good morning, guys. I wanted to see if I could get any more color on your decision to build the DUC count in the Eagle Ford. What kind of savings do you think you're seeing over there versus just completing those wells right away or is that just a function of going to these multi-well pads?

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

Well, I think we talked about this on the last call. There's some easy math you can do on interference with parent wells and the amount of delays in production you can get from fracing in other wells and the amount of sand you have to clean out later. And that can easily be $1 million per pad that you do, the bigger pad you do over smaller pad. But what we're more excited about is the results on the Brown Trust wells, and we don't have enough data yet to say that this multipad raises EURs. But ultimately, that's what we're hoping is that by fracing all these wells at once, you get the desired frac interference with each other more with pressure walls and rubblizing more rock, and if that works, then you should get higher EURs. But at this point, it's too early to say.

Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.

I think you've got a mix of lateral lengths on the Brown Trust, but can you give an idea on what the well costs were there?

John Bradley Fisher - Carrizo Oil & Gas, Inc.

Well costs, hold on a second, Mike. This is Brad Fisher. We'll look that up real quick. Mike, yes, those are about 8,000 to 10,000-foot laterals. They're probably, the 10,000-foot laterals are probably completed, $7 million, probably in that range. 8,500-foot average? So, the average out there across all the pads is 8,500, which my guess is we're going to be somewhere in the $6.5 million to $7 million range. But our base cost in the Eagle Ford has actually gone down. But we typically report on a 6,200 foot average lateral length well. And we've been kind of talking about a $4.5 million well. We're down to about a $4.3 million well. So, we've picked up some efficiencies out there and as well as the use of local sand has driven down our costs. So, the guys are doing a really good job on bringing costs down in the Eagle Ford.

Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.

Great. Thank you.

Operator

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

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Yes. Thank you. You gave the number of wells completed, but what were the number of wells, net wells to sales in the quarter in the Eagle Ford and Delaware?

David Pitts - Carrizo Oil & Gas, Inc.

Hang on, Marshall, let me get that for you here.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

And I guess while Jeff's looking that up, on the building of DUCs in the Eagle Ford, it seems like things are going well now and you're getting very good rates of return on those wells. I guess what's the point in saving the DUCs for next year or was there an operational issue with the desire to not increase CapEx further or what was the logic behind saving the DUCs?

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

I think the main point is to stay within our CapEx guidelines. We're in this to focus on profits and returns and we're not just trying to grow oil production. We're just trying to shift capital to more profitable oil production. So, the second point of that is that we have the capacity to bring on as much Eagle Ford production as we want. But the pads are bigger. So, as we build up DUCs, a lot of those are going to go to big pads and it just takes a while to get those built up.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Okay. Thank you.

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

It's not like we're not fracing in the Eagle Ford from now till then.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Right.

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

We have a lot of drilling going on. And the drilling is very fast in the Eagle Ford.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Thank you. And the wells on sale. Go ahead. Yes?

David Pitts - Carrizo Oil & Gas, Inc.

On those numbers, as far as well to sales in the quarter, net, it was probably something a little over 25 in the Eagle Ford, of which the majority of those are Brown Trust. All of those wells technically were turned to sales in the quarter. And then it was at probably around 9-ish in the Permian Basin. Yes. The Permian Basin.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

And are those net or growth?

David Pitts - Carrizo Oil & Gas, Inc.

What?

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Are those net or growth numbers?

David Pitts - Carrizo Oil & Gas, Inc.

Those are net.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Okay. Thank you.

John Bradley Fisher - Carrizo Oil & Gas, Inc.

Hey, Marshall. This is Brad Fisher. Just to add some – a little bit more color to the DUCs, just to give you an idea on kind of inventory hold, right? So, if we're doing a mega-pad, we have three separate pads and we have two rigs working on it. It's really not frac-able as a mega-pad until all three pads are done.

So, from an inventory standpoint, as we exit this year, we've got several of these large mega-pads that are in progress. So, from a holding time, we've got one with 15 wells that we're holding for a month before we actually frac it. So, it'll be ready to frac in December, and we're starting at the end of December, ready to start early December. We're fracing into December, into 2019.

So, that's more of the case here and just having our whole bunch of one-off five well pads that we're holding off, we're building very large positions for these mega-pads because once again pointing to the Brown Trust and the efficiencies we have as far as not interfering with the parent wells is bad. And then the overall efficiencies we think we're going to get from stimulating these large volumes, these large areas at once. So, it sounds like a big number, but really from a pure inventory hold standpoint, we're not holding an inventory very long.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Okay. Thank you.

Operator

Our next question comes from the line of Noel Parks with Coker & Palmer. Please proceed.

Noel Parks - Coker & Palmer, Inc.

Good morning. I had a question about the Eagle Ford. Just in general, are you – I'm aware of some packages that have been for sale in the region? And I just wondered if you had looked at those and what you thought of peoples' pricing expectations, and I guess about consolidation in the region, overall.

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

I think in general, we try to stay aware and look at all the packages in our core areas, especially the bolt-ons, but we don't talk about any individual deals.

Noel Parks - Coker & Palmer, Inc.

Okay. My impression I got there is that in general, expectations, I guess maybe with oil being stronger, have gotten sort of out of whack with value. So that was just sort of direction I was heading. I also heard rumblings of service equipment finding its way out of the Permian back into the Eagle Ford. And I wondered if you're aware of those trends and if that figured any of your thinking about what the cost environment is going to look like heading into next year?

John Bradley Fisher - Carrizo Oil & Gas, Inc.

So, this is Brad Fisher.

Noel Parks - Coker & Palmer, Inc.

Yeah.

John Bradley Fisher - Carrizo Oil & Gas, Inc.

I think service companies are just like we are. They're going to put their assets in the place that they can keep them working. And I think you've heard several companies announced that they're going to maybe pare down Eagle Ford operations a little bit. So, the Permian activity down a little a bit, so assets moving from the Permian to the Eagle Ford makes perfect sense.

From a cost standpoint, the more assets we get competing to work in a basin, that tends to drive costs down, not up. So, I think just like I talked about a minute ago, we've actually moved our Eagle Ford well costs down a couple hundred thousand dollars when we had talked about last quarter. Hard to predict that trend going forward, but I like service companies moving equipment from one basin to the others that typically is more competition. So, that tends to put downward pressure on pricing.

Noel Parks - Coker & Palmer, Inc.

Okay. Great. And just my last one. It's been a while since we've talked much about other targets in the Eagle Ford. And I just wondered if you could just refresh my memory on sort of Upper versus Lower Eagle Ford potential in your core areas and any thought or work's been done on that recently?

John Bradley Fisher - Carrizo Oil & Gas, Inc.

All right. I think what we have said before is that about a third of our Eagle Ford acreage has Upper Eagle Ford potential, we drilled one well that's profitable, but right now it just doesn't compete with the wells we're drilling in the Lower Eagle Ford. So, we hold all that acreage by drilling the Lower Eagle Ford, so we don't have to do anything there. And maybe technology will find a way to get that production out of there and increase the rate of return in the future.

Noel Parks - Coker & Palmer, Inc.

Great. Thanks. That's all I had.

Operator

Our next question comes from the line of Kashy Harrison with Simmons Piper Jaffray. Please proceed.

Kashy Harrison - Simmons/Piper Jaffray & Co.

Good morning, everyone, and thanks for taking my question. So, just a quick follow-up to an earlier comment. Chip, I think you mentioned that you're seeing positive indications on the Eagle Ford Brown Trust, on the potentials or revisions to an EUR eventually maybe. And I was just wondering how much data do you think – how many month of data do you think you would need to make a call on whether the EURs should be moving up or not? Do you think that's something you might have by year-end reserves this year? Or do you think maybe that's more of a year-end reserves process for next year?

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

I hope we have an update by, say, January for Ryder Scott to look at it and have a good answer. I mean, If we're still choked back on some of the wells, then it's going to be hard to come up with the final EUR.

Kashy Harrison - Simmons/Piper Jaffray & Co.

Okay. That was it for me. Thanks for taking my question.

Operator

Thank you. Our next question comes from the line of Mike Kelly with Seaport Global. Please proceed. Mike Kelly's line is now open and interactive. Please go ahead with your questions, sir.

Michael Dugan Kelly - Seaport Global Securities LLC

Appreciate that. Thanks. Chip, I wanted to go back to your comments on seeing the $100 million of incremental EBITDA from reallocating to the Eagle Ford from the Permian. And maybe I'm mischaracterizing this and correct me if I'm wrong. But, yes, it sounds like most of this is coming on the margin front, if not, on the oil volume front. And I guess it was a little bit surprising that given that you're drilling these wells much faster in the Eagle Ford, and they're more oilier. So, just hoping you could kind of reconcile that and just help me understand that a little bit more. Thanks.

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

Well, I mean, you're probably right. I probably should have said it's not coming on the Boe front, but it is oilier in the Eagle Ford than the Permian. So, oil as a percent of production will go up. But really, the oil rates are the driving factor versus the oil declines in the Permian that makes sense. It's just the margins are more than twice as good and that's what drives the increase.

We're not a whole lot different than we were in January when oil hit $70, and it looked like the Permian and Eagle Ford would have good margins for the next two years. And then the Permian margins got whacked by the differentials. And so, we were able to adjust to that. But we're kind of getting back to where we were if oil had just stayed at $70 and everybody had great margins from the beginning. There just aren't very many companies that can get back to where they were in January because of the differentials that we get for basins.

Michael Dugan Kelly - Seaport Global Securities LLC

Got it. Maybe ask just a little bit of a different way too, if you kind of have the model right now predicated on old guidance versus new guidance here, I mean, do you see an increase in the absolute oil number in 2019 under this new approach, or is it relatively similar but just a higher percentage of oil in the total volume?

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

Hey, Mike. It's Jeff. We're not commenting on 2019 numbers at this point. So, I mean we've talked to you guys a lot about what some of the impacts are in Eagle Ford profile versus a Permian Basin profile. But at this point we're just not going to talk about hard numbers in 2019.

Michael Dugan Kelly - Seaport Global Securities LLC

Fair enough. The incremental $100 million seems good enough. Thanks, guys.

Operator

Our next question comes from the line of John Freeman with Raymond James. Please go ahead.

John A. Freeman - Raymond James & Associates, Inc.

Hey, guys.

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

Hi, John.

John A. Freeman - Raymond James & Associates, Inc.

The first question I had, just sort of following up on, I understand kind of the timing and the lumpy nature of the Eagle Ford driving the big DUC build. But on, unlike an annualized basis, is like a two to one ratio of frac crews to rigs still the right way to think about it in the Eagle Ford?

John Bradley Fisher - Carrizo Oil & Gas, Inc.

Yes, John. This is Brad Fisher. Yes, I would say that's pretty close. It's obviously a function of lateral length and stage length, but two to one is probably not bad. It may inch up towards 2.25. So, we're getting pretty efficient with the number of stages we can pump today.

John A. Freeman - Raymond James & Associates, Inc.

Okay. And then just the follow-up question along those lines, when I think about the Permian where you're still primarily doing kind of the single-well tests. Should we assume that for most of 2019, that still remains the case and then as you move back in in late 2019 and then I guess really more 2020 is when the Delaware would start to transition to more of the multi-well sort of pad development?

John Bradley Fisher - Carrizo Oil & Gas, Inc.

Yeah. In general, that's right. I mean, we do have a cube test we're going to do next year that where we'll frac up to five wells at the same time. But in general, it'll be one-off wells or maybe two-well pads. But then hopefully in 2020, we'll have this figured out and we'll be doing nearly everything with multi-well pads.

John A. Freeman - Raymond James & Associates, Inc.

Great. Thanks. Appreciate it.

Operator

Thank you. Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please go ahead.

Daniel Eugene McSpirit - BMO Capital Markets (United States)

Thank you, folks. Good morning. Related to Mr. Kelly's earlier question, what differential or realized price do you need to see in the Permian Basin, maybe to pivot back to West Texas, and what's the equivalent price or margin in the Eagle Ford? Just asking in an effort to get a better sense of what's parity and kind of the economic sensitivity, if you will, in this decision really asking maybe most honestly here in an effort to get some help on the arithmetic.

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

Well, we've been trying to figure that out, too, Dan. I mean, the answer is really easy right now with $14 to $15 differentials and the bump in LLS prices over WTI. But as we look out into 2019, if the curves hold, we're not exactly sure where we're going to make that shift back. That's why we just said mid 2019 to late 2019. I mean, the difference in margins starts getting closer, but the profitability of the wells also matters. And at some point, the IRRs of the investments start coming back closer to each other.

Daniel Eugene McSpirit - BMO Capital Markets (United States)

Understood. Thanks again and have a great day.

Operator

Thank you. And our next question comes from the line of John Nelson with Goldman Sachs. Please go ahead.

John Nelson - Goldman Sachs & Co. LLC

Good morning. Thank you for taking my questions. I wanted to circle back to just the comments on still being able to retain all of your leasehold in the Permian. And just wanted to clarify that, I think if I go back to the K, there's something like 10,000 net acres that would expire in 2020. And so, can you just maybe put in context, is there a bigger step-up in the activity that would need to happen in 2020 to still kind of retain all that? Or have you been shooting above just what lease retention would be in kind of 2018 and 2019 and it won't necessarily cause a big shift in the plan?

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

Well, I think we don't have an issue until 2020. And most of that acreage, I believe, is in Alpine High. So, we'll have a year-and-a-half to look at Apache's results out there to see what kind of activity we want. Or whether we want to go ahead and extend some of those leases. But at this point, that's not a very pressing issue compared with drilling wells that hold the acreage in the Phantom area.

John Nelson - Goldman Sachs & Co. LLC

Okay. That's a really helpful clarification. And I was just curious, sorry if I missed this. Was there a proceeds number for the Eagle Ford West – or the Ford West divesture rather?

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

We haven't disclosed the proceeds number on that, John.

John Nelson - Goldman Sachs & Co. LLC

Okay. And then just a last one for me. I think you guys still have 35 or 40 kind of Eagle Ford turn to sales over the back half. I guess just trying to get clarity on some of the comments about the pad size that have kind of come out. Should we expect those to be more 4Q weighted because kind of they are larger pads or is it pretty evenly kind of mix between the two? Just any help on kind of the timing of Eagle Ford turned to sales over the back half.

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

John, this is Andy Agosto. It's kind of the relatively similar between quarters, probably a few more in Q3 and in Q4.

John Nelson - Goldman Sachs & Co. LLC

Okay. That's all I had. Thanks, guys.

Operator

Mr. Hayden, Mr. Johnson, there are no further questions at this time. So, I will turn the call back to you.

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

Okay. Well, thank you, all, for calling in. We felt like we had a great quarter and we were able to raise the midpoint of guidance that we had – at our property sale, we would have been able to raise the high end also. Our LOE was better than we thought. Our water system in the Permian is performing well. Those costs have come down. We've been very pleased with drilling and completion costs. They've basically been flat. And one of the catalysts we think going forward for the rest of the year might be reductions in well costs both due to efficiencies and, hopefully, pricing pressures that we're able to put on people.

I think our biggest catalyst is that we want to see the increase in our financial performance relative to our peers due to the shift to the Eagle Ford and the much higher margins. Again, our goal is not to increase our production, it's to increase our profitability, and by going to we're $50 margins than $25 margins, that's going to have great outcomes.

We're also excited about the development strategy in the Permian, and the early results we've seen on these over under stack tests, that's leading us to some more experiments with things we can do to possibly increase the number of layers and understand the lateral spacing at the same time. That can go on now, while we're shifting capital to the Eagle Ford to drive the EBITDA growth.

So, we believe our current portfolio has us well-positioned to continue to execute in the current environment. We are positioned to scale two world-class basins that provide us with a long runway of high-return inventory. We view these assets as highly complementary as their proximity and operational similarities provide us with options to mitigate the many macro risks that have impacted our industry helping to maximize our long-term corporate returns, which is our focus. So, thank you for your interest, and we'll talk again in the quarter.

Operator

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