Carrizo Oil & Gas (CRZO) Q3 2018 Results - Earnings Call Transcript

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Carrizo Oil & Gas, Inc. (NASDAQ:CRZO) Q3 2018 Earnings Call November 6, 2018 11:00 AM ET

Executives

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

David Pitts - Carrizo Oil & Gas, Inc.

John Bradley Fisher - Carrizo Oil & Gas, Inc.

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

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

Analysts

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Leo P. Mariani - NatAlliance Securities

Jeff Grampp - Northland Securities, Inc.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Eli Kantor - IFS Securities

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

Kashy Harrison - Simmons & Co. International Ltd.

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Third Quarter 2018 Earnings Conference Call. During the presentation, all participants will be in a listen-only mode. Afterwards, we'll conduct a question-and-answer session. As a reminder, this conference is being recorded, Tuesday, November 6, 2018.

I would now like to turn the conference over to Chip Johnson, President and Chief Executive Officer with Carrizo. Please go ahead.

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

Thank you, operator. This was another excellent quarter for Carrizo as we delivered record quarterly production and adjusted EBITDA. We also announced the acquisition of an attractively priced asset in the Delaware Basin that is a perfect fit within our existing Phantom position.

We've been hard at work since closing the transaction last month and expect to be able to deliver meaningful synergies from the acquisition. We also continue to make progress toward our longer term corporate goals.

At the end of the third quarter, our leverage metric fell below our target level of 2 times, and we expect it to move even lower next year. We also remain on track to reach a free cash flow positive inflection point during 2019, while still targeting long-term double-digit production growth.

Our total production during the third quarter was 64,627 Boe per day, which exceeded the high-end of our guidance range, as well as consensus expectation. Our crude oil production of 40,813 Bopd was up 8% versus the second quarter and accounted for 63% of our total production during the quarter.

We continued to deliver excellent cost control with total unit operating expenses declining 2% sequentially. Our adjusted EBITDA margin increased by 2% versus the second quarter to $35 per Boe as our Eagle Ford Shale production continue to benefit from strong LLS pricing.

This shielded us from the dramatic widening of differentials in the Permian Basin during the quarter. As a result of these items, we were again able to deliver adjusted EPS and EBITDA that exceeded the analysts' consensus estimates.

For 2018, we're maintaining our DC&I CapEx guidance of $800 million to $825 million, which should allow us to run an average of six rigs over the balance of the year. Our development plan had assumed a frac holiday in November and December. So, we're expecting a reduction in completion activity during quarter, resulting in our Q4 CapEx trending below the run rate of the prior three quarters.

Given the strong production we've seen from our assets, as well as the impact of the recent Delaware Basin acquisition, we are increasing our 2018 production guidance range to 60,200 Boe per day to 60,500 Boe per day from the previous 58,700 Boe per day to 60,100 Boe per day. This equates to approximately 12% production growth at the midpoint or more than 30% pro forma for our A&D activity. Crude oil is expected to account for 64% to 65% of our production during the year. For the fourth quarter, production is expected to increase to 67,700 Boe per day to 68,700 Boe per day.

In the Eagle Ford Shale, we are currently operating four drilling rigs. In the third quarter, we drilled 32 gross or 31 net operated wells and completed 25 gross or 24 net wells. Total production from the play was more than 39,000 Boe per day for the quarter, up 5% sequentially. As a result of crude oil production from the play, receiving LSS-based pricing, our operating margin expanded more than $50 per Boe during the quarter.

At the end of the quarter, we had 20 gross or 19 net operated Eagle Ford 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.

Our production in the Eagle Ford Shale has recently been impacted by an unusually higher rainfall in the region, which has caused a number of operational delays. This has resulted in production from new pads coming online later than we had planned. Additionally, DCP has been doing the maintenance work on its pipeline of gas plants in the area, which has resulted in temporarily restricted production from some of our wells tied into their gathering system. We expect the work to be completed shortly and should see production impact diminishing.

We now have eight months of production history from our multi-pad project at Brown Trust and believe this is the optimal development strategy for our remaining Eagle Ford position where it can be applied. Production results from the wells continue to meet expectations. And in addition, the development is also estimated to reduce long-term area downtime by 65% to 70% relative to our traditional four to six well pad developments.

By combining the multi-pad development with lower-fluid, hybrid frac designs, we believe we will minimize parent-child impact and improve stimulation efficiency. Based on this, we have elected to begin operations on two additional large scale multi-pad projects in the Eagle Ford, a 15-well project in our Pena Winfield area and a 23-well project in our RPG area. Production from these multi-pads is expected to be online late in the first quarter and should drive strong production growth from our Eagle Ford asset in 2019.

In the Delaware Basin, where we are currently operating two rigs, our activity during the quarter was spread across our Phantom and Ford West positions. During the third quarter, we drilled 7 gross or 5 net operated wells, and completed 10 gross or 9 net operated wells.

Total production from the play was approximately 25,600 Boe per day for the quarter, up almost 30% versus the prior quarter. We currently expect to drill 28 gross to 32 gross or 22 net to 26 net operated wells, and frac approximately 25 gross or 20 net operated wells in the play during 2018.

We continued to deliver strong well results from the play during the quarter. In our Ford West area, we brought on in Mustang State 20H, the Wolfcamp A test located approximately 3,000 feet from our initial Mustang State test. The well incorporated previous technical and operational learnings from our drilling in the area and recorded a peak 30-day rate of more than 1,600 Boe per day.

In our Phantom area, highlights from the quarter include the Davis 10H and Lovelace State 11H, the Wolfcamp A and B tests, respectively, that both achieved rates of more than 2,000 Boe per day. Also, in the Phantom area, are Sandhu State 12H well, a delineation test on the far western side of our acreage in the area produced nearly 2,000 Boe per day. We continue to be pleased with the strong results we see from our Phantom block.

As I mentioned, we recently closed on our previously-announced bolt-on acquisition from Devon, which added approximately 10,000 net acres to our core asset in the play. We have identified numerous potential synergies from the acquisition, including reducing operating costs, by shifting disposal of produced water from third-party sites to company-owned wells, and increasing production through optimizing artificial lift.

Additionally, we recently reprocessed 3D seismic over the area and now believe that more than 1,000 additional net acres, where we initially included no development locations in our valuation appear to be prospective. While we will need to test this acreage to be certain, this does imply upside potential to our early estimate of de-risk drilling locations.

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 40,800 barrels per day, NGL production was over 11,400 barrels per day, and natural gas production was over 74,000 Mcf per day, with total production exceeding the high end of our guidance range. During the quarter, we realized 98% NYMEX for oil, 46% NYMEX for NGLs and 77% of NYMEX for natural gas, with oil and NGL realizations exceeding the high end of our guided ranges.

Operating costs and cash G&A for the quarter were $11.46 per Boe, below the low end of our guidance range on a per unit basis. For the third quarter, adjusted EBITDA was $209 million, with adjusted net income of $84.1 million or $0.94 per diluted share, exceeding consensus earnings estimates of $0.79 per diluted share.

With regard to dividends on preferred stock, during the third quarter, we elected to pay the $4.5 million of 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 on preferred stock expected to be $0.7 million to $0.8 million. We currently expect dividends will continue to be paid in cash.

Drilling, completion, and infrastructure capital expenditures for the quarter were $241 million, in line with our expectations. Approximately 62% of these expenditures were in the Eagle Ford with the balance in the Delaware Basin.

At the end of the third quarter, our net debt to adjusted EBITDA was 1.95 times, as calculated by the terms of our credit agreement. We had $310 million drawn on our revolver as of September 30, with the borrowing base of $1 billion and an elected commitment of $900 million.

As a result of our recently completed fall borrowing base redetermination, our borrowing base was increased to $1.3 billion and our elected commitment was increased to $1.1 billion. In addition, our margin to LIBOR was reduced by 25 basis points to 1.25% to 2.25%, based on the level of outstanding borrowings. We plan to use the increased liquidity under our revolver to redeem the remaining $130 million of our 7.5% senior notes we have outstanding.

Included in the press release and earnings presentation is our fourth 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 the Eagle Ford realizations to be about 107% of NYMEX, resulting in total company accrual realizations of 99% to 101% for the fourth quarter. For NGLs, we expect fourth quarter realizations to be 38% to 40% on NYMEX and natural gas realizations are expected to be 75% to 77% on NYMEX for the fourth quarter.

Our LOE guidance for the fourth quarter is $7 to $7.50 per Boe and we expect production taxes to be 4.75% to 5% of revenues. And ad valorem taxes to be 0.5% to 0.75% of revenues.

Our cash G&A guidance for the fourth quarter is $10.6 million to $11.1 million and our DD&A is expected to be $13.50 per Boe to $14.50 per Boe.

Regarding guidance for interest, net interest expense in the fourth quarter is expected to be $14.8 million to $15.8 million, with interest capitalized expected to be $8.5 million to $9 million. We've also updated the full-year 2018 guidance based on these fourth quarter guidance ranges.

With respect to hedging, since our last earnings call, we've entered into additional crude oil hedge positions, primarily consisting of 12,000 barrels per day at three-way collars for 2019 with $52.50 floors, $42.50 sub-floors and $87 ceilings.

Also we've entered into 13,000 barrels per day of Midland-Cushing basis swaps for 2020, locking in a discount to WTI of $1.27 per barrel and 6,000 barrels per day at Midland-Cushing basis swaps for 2021, locking in a premium to WTI of $3 per barrel.

The details of all of our derivative contracts can be found in the press release. Based on strip prices as of yesterday, we expect our derivative settlements during the fourth quarter to result in cash payments of $32.5 million to $36.5 million.

I'll turn the call back over to Chip.

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

Thanks, David. In closing, we believe our portfolio has us well positioned to continue to execute at the current environment. We are positioned to scale in two world-class basins that provide us with a long runway of high-return inventory. As we've mentioned before, we view these assets as highly complementary as their proximity and operational similarities provide us with options to mitigate the many macro risks that can impact our industry, thus helping to maximize our long-term corporate returns.

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

Question-and-Answer Session

Operator

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

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Morning, Chip and team. Chip, my question will be, I guess, for either you or Brad. You mentioned in the press release talking about doing some either testing and delineation, why you've sort of have more focus today in the Eagle Ford, doing some of that in the Delaware Basin. Just wondering how much of that or could you give a little more details as far as how much of that you'd like to do and what you'd really like to accomplish from that before you really start aggressively increasing activity next year in that area?

John Bradley Fisher - Carrizo Oil & Gas, Inc.

Hey, Neal. This is Brad Fisher. Probably, the biggest test that we have in the Permian right now is our co-development project, which we call The Six. It's something we're going to look at, a spacing test for the Wolfcamp A, the Wolfcamp B, the Wolfcamp B Lower and the Wolfcamp C. And so, what we want to learn from that is: one, what the parent-child relationship is going to be or the inter-well relationships are going to be there; and two, probably more importantly is we're planning to run a significant amount of micro-seismic, as we're doing the zipper fracking out there. And we're looking for the interaction vertically between the wells to see what all these carbonate stringers that are present in the Wolfcamp interval, how they're going to impact fracs both now and in the future.

So, I think like anything, that data once we get that test completed, we're just about done drilling. We'll be finished in a week here drilling that test. We'll frac it early next year. It's going to take us six months, just like it does in Eagle Ford, it's going to take six more months to kid of digest that data and understand what is telling us and what impact that has on future development. So, we'd like to get that finished before we kind of go full scale into kind of the development mode out there.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Very good. And then just one follow-up in the Eagle Ford, maybe again for you Brad or if Chip wants to jump in. Just in your comment, I know talking to Jeff didn't sound like it has anything to do with – and it certainly doesn't appear to have anything to do with the down spacing. Could you talk about the impact? You mentioned here just from the downtime in the parent wells, but maybe more specifically about the upside you're seeing from doing some of these slickwater completions?

John Bradley Fisher - Carrizo Oil & Gas, Inc.

So, the slickwater completion is – the primary driver in going to slickwater completions was cost. Slickwater and (16:38) sand was cheaper than the hybrid job that we have been using. The down side that we found with the slickwater fracs, is we have to use about 25% more water in a slickwater frac to get the equivalent sand away.

The impact that that's having on the parent wells is kind of two-fold. One, we're putting a lot of water into the system when we do these mega pads. And what we're finding is a lot of that water is escaping the system. So, if it's escaping kind of the targeted frac area and getting into the parent wells, we don't think that that water is being used efficiently in the fracture process – fractionation process.

And when we get to the parent wells, we're kind of at the second stage of our official lift in most of these parent wells where we're offsetting with these mega fracs. So, we're on broad pump. We're moving that volume of water over to those parent wells, they do come back, it's just taking longer to get the fluid off the wells with broad pumps, it really doesn't make sense to convert them back to gas lift just to get that fluid off. So, we're experiencing longer downtimes than we had previously estimated.

To fix that problem, we're going to go back to our hybrid stage or hybrid design, which uses considerably less water and we can still get the sand away. We think we're still going to get the same stimulation efficiency, but will have a lower impact on our parent wells.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Great. Thanks so much, guys.

Operator

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

Leo P. Mariani - NatAlliance Securities

Hey, guys. I wanted to focus a little bit on the statement you guys made around being free cash flow positive at some point in 2019 as a key goal. Is that something you think that you might attain for the full-year or is it more of sort of a point in time, kind of a second half type of event? And I guess when you guys do hit the free cash flow positive inflection point, what are the plans for that free cash flow?

David Pitts - Carrizo Oil & Gas, Inc.

Thanks, Leo. I guess what we modeled out is that we get to about free cash flow midyear. And then, by the end of the year, the total for the year is still positive. And right now, the plans for that extra cash flow are all about the balance sheet that even though we're going to have debt to EBITDA under two times, we'll keep trying to reduce that and that will be the initial focus.

Leo P. Mariani - NatAlliance Securities

Okay. That's helpful. And I guess just with respect to moving over to more of these mega pads in Eagle Ford. And obviously, you guys have got some two rather large pads, I guess, you said they're coming on kind of late in the first quarter here. It sounds like that's probably going to make your production maybe a little more lumpy. What can you kind of tell us about the next couple of quarters of production? Obviously, you've got your fourth quarter guidance, but are we going to be a little more flat in the first quarter and then up a ton in the second quarter and then I guess you start to see Permian layered in, in the second half. What can you just sort of tell us directionally about how that's going to play out?

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

Well, we haven't given out any guidance on that, but based on a frac holiday towards the end of the fourth quarter and then the lumpiness of these multi-pads, we'll have to be very specific quarter-by-quarter about what we think we're going to be able to do.

Leo P. Mariani - NatAlliance Securities

Okay. Understood. And I guess obviously you guys did a pretty good-sized acquisition recently. What is Carrizo's appetite for more deals of that ilk, and I guess, is there available liquidity for you guys to do things like that going forward?

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

Well, we look at every deal in our basins. And no, we don't have the balance sheet to jump into a really big deal, but we keep looking for bolt-ons because we can add meaningful inventory in the Permian, if we just do deals like the Devon deal.

Leo P. Mariani - NatAlliance Securities

Okay. Thanks, guys.

Operator

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

Jeff Grampp - Northland Securities, Inc.

Morning, guys. I was curious on the cube test that you're doing in the Delaware. If you could tell us kind of maybe what spacing per zone or wells per section type of density is being tested on those. And is the hope or expectation that you have enough results on those cubes to be able to make that kind of a more normalized development pattern as you ramp up activity into next year?

John Bradley Fisher - Carrizo Oil & Gas, Inc.

Hey, Jeff. This is Brad Fisher. So, what we have is, we have two wells in A, which are 660 feet part. We have a B Upper, which is spaced 330 feet between those two, so dead center.

And then in the Wolfcamp B Lower, we have two wells spaced at 660 feet. So, if you look at that panel right there, it looks like a five on a dice, okay. The pit was called The Five at one time. We decided to add a Wolfcamp C, tested that and it's 330 feet centered up, but be below the Wolfcamp B Lowers.

Jeff Grampp - Northland Securities, Inc.

Okay. Got it. That's helpful. And then as we think about the multi-pads in the Eagle Ford and you guys kind of, I guess going from four-rigs to two-rigs in the back half of next year, is the expectation that you guys can continue to incorporate those multi-pads at only a two-rig pace or will be the multi-pads get smaller relative to these bigger ones or just kind of wondering, I guess, how the multi-pads fit in as you go from four-rigs to two-rigs next year.

John Bradley Fisher - Carrizo Oil & Gas, Inc.

Hey, Jeff, basically, the answer is yes. We can continue with the larger pads of two rigs, because of the efficiency of the Eagle Ford. I mean we're drilling three wells per rig per month. So, we can still do big pads with two rigs in there. This is going to vary by where we have the spaces, right? We're going to have different-sized gaps. And right now, we're kind of focused on the gap management. We're filling in some of these very, very large gaps in there, some smaller gaps that we'll fill in with the two-rig program and we'll probably finish part of the year drilling some large pads. So, it's going to be a mixed bag.

Jeff Grampp - Northland Securities, Inc.

Okay. Great. Understood. That's helpful. I appreciate the time, guys.

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. You've completed a lot of wells in the Eagle Ford in the third quarter, but I'm not sure how many of those went to sales. Could you give me the net wells to sales for third quarter and plan for Q4?

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

Yeah. Hang on, Marshall, it's Jeff. Let me grab that for you. These are going to be gross wells that I'm going to give you here. All right. So, in the Eagle Ford in the third quarter, you're looking about 27 gross wells that came online that probably drops down to about 17 gross wells in the fourth quarter. Permian Basin was about 12 gross wells in third quarter and almost nothing in the fourth quarter. You might get a well.

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Okay. And as a follow-up, in terms of the frac holiday for Q4, how quickly do you plan on starting back up in 2019? You all sort of be phasing in completions? Or are you going to hit the ground running?

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

Basically...

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

How should we think about that?

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

...they were back completing wells again one, basically. I mean...

Marshall Hampton Carver - Heikkinen Energy Advisors LLC

Okay. Okay. Thank you.

Operator

Our next question comes from the line of Eli Kantor with IFS Securities. Please go ahead.

Eli Kantor - IFS Securities

Hey. Good morning, guys.

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

Morning.

Eli Kantor - IFS Securities

As you look to forecast future production growth, what level of interference or communication between the wells do you assume, if any, as it move from single-well development to some of these multi-well pad?

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

Well, Eli, this is Andy Agosto. Obviously, as Brad mentioned earlier, we're going to have a mixed bag of exactly how many multi-pad wells we're going to drill and where. So, it's going to be a function of the maturity of the parent wells, the more mature, the lower the pressure, the higher the potential impact. And then, just the number of child wells we drill as a total fluid, we're putting back into the system.

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

Essentially, in the Eagle Ford, there are no more single-wells. Everything is at least a small pad. And hopefully, we can do more and more multi-pads to get rid of the interference.

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

Eli, if you look at the Brown Trust multi-pad, there were 9 offset wells to the 16 that we drilled that had some amount of downtime. So, you can contrast that to a typical four-well to six-well pad.

Eli Kantor - IFS Securities

And is the preliminary expectation to see the same kind of reaction or interference in the Delaware?

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

Hey, Eli. Let me back up a sec. Are you talking about interference or frac hits? Are you asking about downtime in the areas?

Eli Kantor - IFS Securities

No. I'm asking about well productivity as you move from single-well development to infilling some of these leases that you have.

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

Yeah. Eli, it's Andy again. I think if anything, because of the number of wells and how we're fracking this, we may increase that. We're actually increasing frac complexity between wells with the number of wells we have here.

Eli Kantor - IFS Securities

Okay. Excellent. As you think about Carrizo's future spending level, what are you seeing on service costs inflation and deflation front relative to early this year? And what changes, if any, do you expect to see over the next 12 months to 24 months?

John Bradley Fisher - Carrizo Oil & Gas, Inc.

Eli, this is Brad Fisher. So, that's a bit of a long look, but I can address the kind of the shorter term stuff here and kind of how we think about longer term. Short-term coming into Q4, there's – actually, we're seeing some downward pressure on things. We're actually seeing some service companies talk about incentives to stay busy in Q4, because there's a lot of companies that are doing the same thing. We are taking frac holidays into Q4 just kind of the budgets are up.

Going into next year, basically what I'm hearing from the service providers is prices are going to be pretty flat. We're not seeing a lot of pressure, I mean the anticipation is that the Permian won't get kicked back off until later the year. When the Permian does get kick back off, they'll probably be a little bit of upward strain on prices, but I don't think a lot of things, you're going to have the market share re-grab, go on again, and things will stay pretty competitive.

Going out in past 2019, it's going to be a function of where product prices are. I mean product prices are going to drive where the service companies think they can set their price point at.

Eli Kantor - IFS Securities

Makes sense. Thanks for the color. Nice quarter.

Operator

Okay. Our next question comes the line of Michael Scialla with Stifel. Please go ahead.

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

Yeah. Hi guys, can you talk about what you learned from that well that the recent Mustang well in Eagle Ford – in the Ford West area in the Delaware. It looks like you made some improvements over what you'd done there previously. And do you have any more plans to drill in that area this year or next or was that more of just an acreage saving type well?

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

No. I think we learned a lot from the first couple of wells we drilled up in that area, mostly based on fault avoidance and how far to stay away from big faults that could either add water production or gas. So, I think we figured that out. Now we have a pretty good handle on how we would develop that whole Western Ford West area that has the most complexity.

We will see drilling there. Some will be acreage holding. Those wells are a little shallower, but the rates are a little lower. So, the IRRs are still a little lower than we would see in the Phantom area. But, we'll keep drilling there, and we'll also try to prove up some other layers there now that we've sort of conquered the Wolfcamp A.

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

Sounds good. And I guess on the other side of the play, last quarter, you talked about that well you drilled in Ward County. Any update on that and how you're thinking about that acreage?

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

I think we feel like we understand Ward County now especially with the reprocessed 3D. That SRO well is still an excellent well, and that kind of gives us a leg up on the competition on knowing how to drill Wolfcamp A over that area. We had a Wolfcamp B well we drilled there last year. That was good, but it wasn't as good as the Wolfcamp A, and so we need to follow that up with what we've learned with the new data and see if that layer will be just as good.

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

Thanks. And then last one from me; Brad, you mentioned in an answer to a prior question that, in the Brown Trust you may actually be seeing some improvement in EUR with the complexity of the fracs. Have you started to see a decline from those wells now to where you can do some sort of decline curve analysis with the pressures? Or is it still pretty flat?

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

Mike. This is Andy. It was actually – I'm the one who actually answered that question. I think that that...

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

Sorry about that, Andy.

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

...answer was relative to a – the single-well question that one of the caller had asked about earlier. So, that was just complexity from multiple wells versus just a couple. In terms of how those wells are performing, they're meeting expectation, meeting our type curve. Yeah. I mean they've started to decline as they've seen boundary effects from the other wells. But again, right in line with our expectations.

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

Very good. Sorry again about that, Andy. Thanks.

Operator

Our next question comes from the line of Kashy Harrison with Simmons Energy. Please go ahead.

Kashy Harrison - Simmons & Co. International Ltd.

Good morning and thanks for taking my questions. So first one for me, not sure if you all have run this analysis or not. But I was just wondering, do you guys have a sense of what your maintenance CapEx would be to hold the current rate of production, flattish on a go-forward basis?

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

Yeah. I mean, Kashy, it's always a tough question to answer, because so much of it is where are you putting the capital. And whether you put it in the Eagle Ford versus the Permian, that's going to imply slightly different capital efficiency. But – I mean ballparkey probably, maybe somewhere around, give or take, 60%-ish of this year's spending level.

Kashy Harrison - Simmons & Co. International Ltd.

Okay. That's helpful, Jeff. Thanks for that. And then I was just wondering, switching gears a little bit for some infrastructure stuff. I was just wondering, if you could provide some color on what agreements you guys have in place on the NGL side of the equation, specifically around fractionation? We've seen constraints across most spaces. And so just trying to get a better sense of how you're positioned on the NGL side of the infrastructure equation?

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

Yeah. Kashy, this is Andy Agosto again. On the NGL side in the Eagle Ford, we're fine. We have not seen any constraints there whatsoever. In the Permian, it's probably a good time to talk about our big gatherer processor there, Caprock, they – or just bought out by EagleClaw, which we view as a net positive there, because – EagleClaw has some additional scale. They have some additional NGL takeaway. We were a little tight in August, September on NGLs. We're back to normal levels in November. And again, given that transaction with EagleClaw coming in, we don't see any constraints on the NGL side going forward.

Kashy Harrison - Simmons & Co. International Ltd.

Got it. And so as you think about bringing the rigs back to – from the Eagle Ford to the Delaware, you all should be fine on the infrastructure side? No issues at all with NGLs?

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

None with NGL. As we talked about on the last call on oil, we have 100% flow assurance at Midland pricing, which we've backed up with some differential hedges that David talked about. So, yeah, we're in good shape.

Kashy Harrison - Simmons & Co. International Ltd.

Excellent. That's it for me. Thanks for taking my questions.

Operator

And we have no further questions at this time.

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

Great. Well, thank you all for calling in. It was a great quarter. I'd like to thank the staff and the management for dealing with a lot of the issues we had between the weather and some of the gas plants, which required a lot of juggling of things and also the staff for integrating the Devon assets, which are going to be real plus.

Catalyst to look for in the near future will be the 6-well Wolfcamp test, where we're testing the vertical and horizontal spacing in the A, B and C which will probably lead to a lot of decisions about our future development. We also have the large multi-pads in the Eagle Ford, which should add a lot of production in the first half of next year.

We will also have continued improvement to the balance sheet. Our debt to EBITDA using the current quarter annualized was down to 1.6 times. We think with the – using the strip in our current projections on Eagle Ford pricing and margins that we'll keep adding a lot of improvement on debt to EBITDA, and it will still have relative outperformance to our peers due to the higher oil prices and margins in the Eagle Ford. So, that's what we're looking for.

Thanks for calling in, and we'll talk again in the quarter.

Operator

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

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