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Carrizo Oil & Gas (CRZO) Q1 2019 Earnings Call Transcript

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Carrizo Oil & Gas (NASDAQ: CRZO)
Q1 2019 Earnings Call
May. 08, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Greetings and welcome to the Carrizo Oil & Gas first-quarter 2019 earnings call. [Operator instructions] As a reminder, this conference is being recorded Wednesday, May 8, 2019. I would now like to turn the conference over to Jeff Hayden, vice president of financial planning and analysis. Please go ahead.

Jeff Hayden -- Vice President of Financial Planning and Analysis

Thanks, operator, and thanks, 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 measures. We have posted slides to go along with the webcast today.

The slides can be found on the Events page under the Investor Relations section of our website at www.carrizo.com. Joining me on the call this morning are Chip Johnson, president and CEO; David Pitts, VP and CFO; Brad Fisher, VP and COO; and other members of Carrizo's senior management team. And with that, I'll turn the call over to Chip.

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Chip Johnson -- President and Chief Executive Officer

Thanks, Jeff. As Carrizo entered 2019, our goal was to execute on a capital program that generated prudent high-return production growth while achieving a free cash flow positive inflection point during the year. In addition to rightsizing our activity level for mid-$50 world, we also targeted various cost reductions and operational improvements and we're expected to enhance our capital efficiency. We set aggressive targets for our team and I'm happy to report that we are currently exceeding these in both of our plays.

One of the key drivers of our recent efficiency gains has been our shift to large-scale developments. Since late 2018, our primary operational focus has been on the development of several highly efficient multipad projects, the two in the Eagle Ford Shale and one in the Delaware Basin. We were able to complete each of these projects on time and within budget and they're all currently flowing to sales. While these large-scale projects are expected to result in improved project level economics, they also result in a more uneven production profile as the number of wells turned to sales, as well as average production downtime can vary significantly between quarters.

We saw this impact in the first quarter of the year as the limited number of wells brought online late in the fourth quarter and early in the first quarter combined with a higher level of planned downtime in the first quarter resulted in total production declining to 61,960 BOE per day in the first quarter. This was in line with our expectations as first-quarter production was near the high end of our guidance range. Crude oil production during the quarter was 40,727 BOPD accounting for 66% of our total production during the quarter and exceeding the high end of our guidance. Our adjusted EBITDA margin also remained strong during the quarter as our Eagle Ford Shale production continuing to benefit from its exposure to seaborne oil markets.

As a result, we were again able to deliver adjusted EPS and EBITDA results that exceeded the analysts' consensus estimates. While the first quarter saw a sequential dip in our production, our activity set the stage for what we expect to be strong growth for the remainder of the year. As a result, we are maintaining our 2019 production guidance of 66,800 BOE per day to 67,800 BOE per day, which equates to approximately 11% year-over-year growth. Crude oil is currently expected to account for 63% of our production during the year.

For the second quarter, we're expecting production to increase to 66,500 BOE per day and 67,500 BOE per day. We remain on track to meet our DC&I capex guidance of $525 million to $575 million. While we spent approximately 40% of our DC&I budget in the first quarter of the year, we also drilled and completed 44% and 46% of our planned 2019 activity respectively during the quarter. We remain committed to capital discipline and currently have no plans to increase our announced DC&I budget despite the increase in crude oil prices.

In the Eagle Ford Shale, we are currently operating one drilling rig. In the first quarter, we drilled 27 gross or 24 net operated wells and completed 32 gross and net wells. Total production from the play was more than 39,500 BOE per day for the quarter, up 2% versus prior quarter. Crude oil production from the play was more than 31,300 BOPD, up 2% sequentially.

As a result of crude oil production from the play receiving seaborne-based pricing, our operating margin remained strong at more than $39 per BOE during the quarter. At the end of the quarter, we had 41 gross or 38 net operated Eagle Ford Shale wells in progress or waiting on completion. We currently expect to drill 55 to 60 gross or 45 to 50 net operated wells and frac 75 to 80 gross or 70 to 75 net operated wells in the play during 2019. During the quarter, we began to bring on production from our most recent multipad projects in the play.

Production from the Pena project came online at the end of January while production from the RPG project began in March. I'm pleased with the early results we've seen from these projects, both from an operational efficiency standpoint, as well as the performance standpoint. The projects were completed on time and within budget, and gross crude oil production from the 33 wells is approximately 17,000 barrels a day from restricted chokes. As we've shifted our development to focus in the Eagle Ford to multipad projects, we've been able to further reduce cycle times.

The other process improvements we discussed in recent quarters, such as the return to hybrid gel completions, have also contributed to the efficiency gains we've seen so far in 2019. To quantify these, we've been able to reduce our average drilling days per well to eight from nine to 10 during 2018 and we've been able to increase our completion stages per day to nine from six to seven in 2018. The year-to-date improvements we've seen have exceeded our expectations, and as a result, we now expect a 6,600-foot lateral well in the Eagle Ford Shale to cost $3.9 million to $4.1 million, down from our prior expectation of $4.3 million. Our Eagle Ford development program should remain weighted to multipad developments for the balance of the year as we have three additional projects planned.

Combined, the projects include 36 wells in our Brown Trust, Irvin and Arnold project areas. In the Delaware Basin, we are operating two drilling rigs. During the first quarter, we drilled eight gross and net operated wells and completed 11 gross or nine net wells. Total production from the play was more than 22,400 BOE per day, down versus the fourth quarter due to a limited number of wells coming online late in the fourth quarter and early in the first quarter, as well as a higher level of planned downtime for offset fracs.

At the end of the quarter, we had nine gross or eight net operated Delaware Basin wells in progress or waiting on completion. We currently expect to drill 20 to 25 gross and net operated wells and frac 20 to 25 gross or 15 to 20 net operated wells in the play during 2019. In order to achieve this level of activity, we plan to have a third rig during the third quarter. However, given our focus on capital discipline, if we are able to maintain or improve upon the efficiency gains we have achieved to-date this year, we may delay the addition of the rig in order to stay within our budgeted spending lines.

During the first quarter, we completed our first cube test in the Wolfcamp A, B and C, which we refer to as The Six. The project consists of six wells on two pads, though we were able to complete all six wells in just one of the pads to be used for high-pressured lines in agreement. The project tested four separate landing zones within the section with the laterals drilled in a 330-foot wine-rack configuration or 660-foot spacing within the layers. Early microseismic results show that a multi-layer co-development could result in improved frac geometries and positive communication.

We also deployed 37 unique production tracers during the completion of the project wells, which should give us added insight into the performance of specific zones. The data we gained from this project will be used to further optimize completion design, three-dimensional well spacing and target landing points within a zone. We're very encouraged with the initial performance we've seen from The Six as the project has already achieved a rate of approximately 10,600 BOE per day with approximately 6,400 BOPD of oil. As expected, the strongest performance thus far has come from the Wolfcamp A wells, but the Wolfcamp B wells are also performing in line with expectations.

Of note, we are seeing strong performance from the projects Wolfcamp C well, which has recently been averaging more than 1,450 BOE per day. This is exceeding our early expectations and provides us with another strong Wolfcamp C result on our Phantom acreage position. While we have yet to include any Wolfcamp C locations in our estimate of net derisked inventory in the play, safe to say, we're pretty constructive on the potential of the Wolfcamp C as the target arises. We've recently commenced drilling on our next cube test.

The Dorothy-Sansom project is currently planning as a seven well, five layer co-development of the third Bone Spring through the Wolfcamp C. This test will include our first test in the third Bone Spring on the Phantom acreage. We're excited to test the potential of this zone especially with the recent 1,400 BOPD well that was just announced by an offset operator. We were able to significantly improve our capital efficiency in the Delaware Basin during the first quarter of the year.

During the quarter, our drilling activity was focused in our Ford West area where the shift to multi-well pads helped drive a 19% reduction in drilling cycle times, relative to their single-well counterparts in 2018. Combined with other process improvements and cost saving initiatives, this resulted in more than 35% sequential reduction in drilling cost per effective lateral foot. And on the completion side, we were able to decrease our cost per effective lateral foot in the quarter by approximately 25% versus the third quarter of 2018. As with the Eagle Ford, these efficiency gains have exceeded our expectations and we now expect the average costs of the 7,000-foot lateral well in the Delaware Basin to be $7.8 million to $8.2 million, down $8.5 million previously.

With that, I will turn it over to David Pitts to discuss the financials.

David Pitts -- Vice President and Chief Financial Officer

Thanks, Chip. As Chip mentioned, we remain committed to capital discipline and delivering on a development program that can generate sustainable free cash flow and prudent long-term production growth with crude oil prices in the mid-50s. When we announced our plan earlier this year, we also stated that improving our balance sheet by using free cash flow that we expected to generate in the second half of the year for debt reduction was a high priority. While crude oil prices have increased since we announced our plan, we remain committed to the capital program we laid out earlier this year.

Our current strip prices imply a higher level of free cash flow than we initially forecasted. We plan to use the incremental cash flows from higher-than-budgeted commodity prices for debt production. We continue to believe this strategy will lower our cost of capital and put us in a stronger competitive position in the future. We recently completed our spring borrowing base redetermination, which resulted in an increase in our borrowing base from $1.3 billion to $1.35 billion.

This is despite a decrease in bank debt pricing. We elected to increase the commitment amount from $1.1 billion to $1.25 billion, which we believe gives us sufficient liquidity to execute our plan. We plan to use the free cash flow we expect to generate later this year to reduce the outstanding balance on our revolver. At the end of the first quarter, net debt to adjusted EBITDA, calculated in accordance with our credit agreement, was 2.4 times, and we continue to target reducing our leverage below two times.

For the first quarter, we reported DC&I capital expenditures of $215 million. As Chip mentioned, this was about 40% of our DC&I guidance for the year, despite first-quarter activity accounting for about 45% of our full-year plan. As you may recall, we started the year with four rigs running in the Eagle Ford and with the multi-pads we completed during the first quarter, we expected it to be the heaviest capex quarter. We're now down to one rig in the Eagle Ford and we remain on track with our capex target for the year.

While we don't normally provide capex spending by quarter, given the intense focus on those right now, we've elected to provide our quarterly capex expectations for the balance of 2019. For the second quarter, we expect capex to be approximately $130 million to $150 million with the remainder split fairly evenly between the third and fourth quarters. A disciplined hedging program remains a key part of our financing strategy. For 2019, our goal has been to target hedging 50% to 75% of our crude oil production.

While we had already achieved the targeted range as of our fourth-quarter release, we have remained opportunistic recently adding approximately 4,500 barrels per day of swaps at $65 for the remainder of the year. After the recent hedging activity, we now have hedges in place for more than 70% of our estimated crude oil production for the remainder of the year. While we don't typically spend much time talking about natural gas hedges since gas production only accounts for a small portion of our revenue stream, our marketing team did a great job highlighting some of the potential natural gas supply demand issues in the Permian Basin. As a result, we elected to add WAHA basis swaps back in March in order to mitigate the risk of extreme regional price differentials like we saw last month.

We currently have an average of 14,700 MMBtu per day locking in a differential of minus $1.58 for the remainder of 2019. You can find more details on our current hedge positions in the press release. Chip already discussed our production guidance, so I'll cover the expense guidance. In general, we're seeing a positive trend in our expenses and are either reducing or maintaining our annual guidance for each item of cost and expenses.

For LOE, as previously mentioned, we expected the first quarter to be the high watermark during the year as a result of lower production and higher workover activity. As these items reverse and we begin to realize the cost savings identified by our operating and procurement teams, we expect LOE to trend down to $7 to $7.50 per BOE in the second quarter and below $7 in the back half of the year. With that, I'll turn the call back to Chip.

Chip Johnson -- President and Chief Executive Officer

Thanks, David. In closing, we continue to believe our dual basin portfolio has us well-positioned to execute in the current environment. Our portfolio generates some of the highest margins in our industry, which puts us in a strong position to generate profitable growth within cash flow in the current commodity price environment. And as we mentioned, the initial use of our free cash flow will be for debt reduction, but down the road, we also plan to evaluate other ways to return excess cash flow to shareholders.

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

Questions & Answers:


Operator

[Operator instructions] Our first question comes from the line of Gabe Daoud of Cowen & Company.

Gabe Daoud -- Cowen and Company -- Analyst

I guess, just given the focus on the topic of efficiency gains and just overall improved operations continuing to put pressure and pull forward spend, how much further would you guys slow down, I guess, in the second half? To live within budget, you mentioned perhaps not adding the third rig, but would you think about dropping crews or does some of the cost savings you guys highlight offset all of that? And just generally, how do we think about that especially in the context of preparing for 2020?

Brad Fisher -- Vice President and Chief Operating Officer

Gabe, this is Brad Fisher. So the biggest efficiency gains that we're seeing are really on the Permian side and going into the year, we planned our drilling budget around two rigs going to three in the back half of the year to meet the current budget. The efficiencies that we're seeing, the effect of that is basically all we're doing is pushing that third rig out or we may just push out the year completely. So our intent is to drill the number of wells that we scheduled and we have flexibility in our schedule to account for efficiency improvements by pushing that third rig out.

Gabe Daoud -- Cowen and Company -- Analyst

And then I guess just a follow-up, on the cost savings that you guys did highlight in both areas, could you maybe quantify how much is structural versus maybe pricing oriented, if any? And then if these savings continue, could we actually see a decrease in the overall budget, or maybe just like a tightening of the range? Just any thoughts on that.

Brad Fisher -- Vice President and Chief Operating Officer

Gabe, this is Brad Fisher again. Yes, from an efficiency standpoint, a lot of it is really on the frac side. So in the Permian Basin, we've gone from 165-foot stage spacing to 200-foot stage spacing. So that's driving efficiency, costs really.

And then in the Permian, we've changed our frac program to hybrid, which has increased our frac efficiency, which reduced our cost. We've also changed the profit concentration there from -- kind of looking at the year, going in at 2,000 pounds per foot across the board to a 2,000 pound per foot and 1,600 pound per foot, 2,000 pounds per foot outside the well, 1,600 pounds per foot on the inside wells. As far as kind of taking down the range, I mean, what we're looking at right now in the Permian, that's really going to be the driver of the overall drill cost increase. Our last pad that we drilled out there was a three-well pad, our Tomahawk pad.

We dropped our drill times by 19% out there and cut our overall cost by 35%. If you look at historically what we've done in the Permian, 70% of the wells we've drilled in the Permian have been single-well pads. So we are heavily weighted this year -- for the balance of the year, completely weighted to three to four well pads, actually two to four well pads going forward. So we think that our kind of 27 day well that we have now is probably going to go into the 23, 24 days by the end of the year.

So we're going to pick up some additional cost efficiency on that. So we're really focused on staying within the budget that we outlined and we're putting pressure on that budget to try to drive it down.

Chip Johnson -- President and Chief Executive Officer

Gabe, it would be great to narrow the range around the capex budget, but it's only been one quarter and we always worry about service cost increases more than we worry about decreasing.

Operator

Our next question comes from the line of Neal Dingmann of SunTrust.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Obviously, you guys have got an active program that's front-end loaded this year. I guess being mindful that you don't have the 2020 guidance out like most, could you just speak in broad terms to how you anticipate finishing the year in term of DUCs or growth trajectory, anything you can say around just sort of how you envision the year end?

Jeff Hayden -- Vice President of Financial Planning and Analysis

Neal, it's Jeff. If you remember when we kind of gave the guidance, one of the comments we talked about was that we expected fourth-quarter 2019 production to be higher than fourth quarter of 2018 production, yes, that's still the case. I mean, while we only talk to you guys kind of one year at a time, our 2019 program is part of multi-year plan. As part of that multi-year plan, we do expect to continue to be able to deliver prudent growth.

So, everything was set up, not just with an eye on 2019, but also 2020, 2021, etc. So, if you kind of look at how we're exiting the year again, I'd expect to exit the year with again kind of year-over-year growth Q4 '19 versus kind of Q4 '18. And from kind of a DUC standpoint, Eagle Ford should be somewhere probably, I guess, 20, 25 DUCs. So, ample to support one kind of 24/7 frac crew in that basin.

And then in the Permian, it's probably somewhere in the mid-teens. So I think end of the year, we'll be in a very good spot from a PUD standpoint to execute on our capital efficiency program in 2020 as well.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Great points, Jeff. And then just secondly turning over to Slide 9, maybe for Brad or Chip just looking at, just wondering if you believe now -- you've obviously done a lot of microseismic work and other work there. So I'm just wondering if you believe you've got enough results and data from either what you've done or offset operators to determine how to optimize your cube design in term of multi-zone spacing going forward? It looks like you've certainly made a lot of advancements there. So just anything you can talk about on how you see that on a go forward?

Brad Fisher -- Vice President and Chief Operating Officer

Yes, Neal. So I would say the tests that we did on The Six is probably as comprehensive as anybody has done in the basin. The amount of data that we acquired out there, the way we set the pads up out there to acquire the data, the amount of production tracers that we had, we've got a lot of studying to do there, but the quality of the data that came out of there was fantastic. We were able to disseminate which carbonate beds that separate some of the layers in the various intervals in the Wolfcamp are effective frac barriers, which ones aren't.

We can see some structural things like how stress shadowing and three-dimensions is going to allow us to impact frac geometries. So from a kind of well interaction, I think we've got a lot of good data. It's going to take us a while to figure all this out and apply it going forward. But I think we have a really strong base to set up our co-development program going forward.

Operator

Our next question comes from the line of Brad Heffern of RBC Capital Markets.

Brad Heffern -- RBC Capital Markets -- Analyst

I was wondering if you could give any color on the remaining three Eagle Ford multi-pad projects that you highlighted, approximately when those are planned to come online?

Brad Fisher -- Vice President and Chief Operating Officer

Brad, this is Brad. So the three that we have for the balance of the year, I've got some very catchy names for them. There's 13 wells in the Brown Trust, so we call that the Brown Trust 13. We're currently fracking that.

We have two crews on that. We anticipate that coming on in June. There's 14 wells at Irvin, we call that Irvin 14, that's going to come on in July. And then we have the Arnold 9, which is a series of extremely long wells, are all over 10,000 feet, we anticipate that will come on late October, early November this year.

Brad Heffern -- RBC Capital Markets -- Analyst

And then, I remember back with prior Brown Trust pad there was that the working interest decline when it reached payout. I was wondering if either the Pena or the other pad that came on recently, any of these pads could face a similar situation like that?

Jeff Hayden -- Vice President of Financial Planning and Analysis

Brad, it's Jeff. I'd just tell you that we factored all that stuff into the guidance we provided to you guys and we don't typically give you all kind of working interest on specific wells. But just understand that the average working interest we tell you guys to run with and we tell you all, assume kind of 85% to 90% accounts for all of that stuff. So it's always accounted for in the guidance we provide you guys and if any of that ever exist, it's existed since we've been active in the Barnett Shale -- since we've been active in the Eagle Ford, sorry.

Operator

Our next question comes from the line of Michael Scialla with Stifel Financial.

Michael Scialla -- Stifel Financial Corp. -- Analyst

Just want to follow up on the cube test. Based on what you've seen there, is that configuration what you are anticipating to use going forward or do you need to do more experimentation there with the geometries?

Brad Fisher -- Vice President and Chief Operating Officer

Michael, this is Brad Fisher here. Right now, yes, that is the type of configuration that we're going to go forward with. We are in the process of drilling a seven-well pad at our Dorothy-Sansom area. The only change on that from The Six in configuration will be, that will be a five-layer test, we'll be adding a Bone Springs to that as well.

Michael Scialla -- Stifel Financial Corp. -- Analyst

OK. And on the Eagle Ford, these large multi-pad projects, you've experimented with a number of different sizes there. Can you just talk about -- I know it's early still, but what you've learned, what you may do differently, have you zeroed in on what may be an optimal size multi-pad project, anything to that. Thanks.

Brad Fisher -- Vice President and Chief Operating Officer

I don't think that there is necessarily an optimal size. This is more for us about gap management. So we structured our development program the way drilling obligations worked out. And when we left gaps between wells, we tried to leave very large gaps to minimize this parent-child relationship.

So what our mega pads are doing now rather than going and drilling three five-well pads one at a time to kind of finish out a gap we just drill them all at once. It's proven to be very effective from a parent-child standpoint and from a reserve recovery. Our Brown Trust mega pad that we did last year, we did 16 wells and kind of finished out an area. If I look at equivalent areas that we stimulated versus kind of single-well pads for the same area, we're getting about 7% more reserves out of there.

So, it's really just -- it's more about gap management than it's about number of wells. The fact that we can drill wells in eight days, the timing really doesn't become a big factor in the development decision.

Michael Scialla -- Stifel Financial Corp. -- Analyst

Anything you want to know that you would do differently based on the what you've seen so far?

Brad Fisher -- Vice President and Chief Operating Officer

Well, we did make the change back to hybrid, and I think that's the optimal way to go. Our hybrid is 75% slickwater, 25% cross-linked fluid. That has been very effective. It has helped our parent-child relationship again.

Our parents now, looking at my Brown Trust pad, mega pad, it was -- it took nine months for the offset parent to completely recover. The last mega pad that we just finished up, the Pena mega pad, the offset parents from the time they were shut in for frac to the time they reach full production was two months. So that has been a significant impact on downtime for us. And then on the sand production problem, getting away from the slickwater has eliminated a lot of our sand production problem.

So I think we implemented the changes we like and we'll tweak things a little bit going forward. We're pretty happy with what we're doing.

Operator

Our next question comes from the line of Jeff Grampp of Northland Capital Markets.

Jeff Grampp -- Northland Capital Markets -- Analyst

I was curious if you could touch on, you mentioned in the release a couple of times here, some of the carbonates that run through Delaware and it may act as a frac barrier for you. Do you have any sense at this point of how pervasive that might be across your acreage footprint?

Jeff Hayden -- Vice President of Financial Planning and Analysis

Jeff, you were breaking up a little bit there. I think your question was, could we comment some more on some of the carbonates we referenced in the Delaware Basin and how pervasive that could be, what kind of impact that could have, is that correct?

Operator

Mr. Grampp, your line might be muted.

Brad Fisher -- Vice President and Chief Operating Officer

Jeff, I'm going to go ahead, this is Brad. I'm going to go ahead and answer that, the question that Jeff just gave me. Yes, so across the acreage, we do have some areas particularly in the northern part of our Phantom acreage where there's a pretty significant carbonate beds, in the southern part of the acreage we have some carbonate beds. They're going to be impactful and the fact that these development cubes -- one of the issues with the development cubes is the number of wells in the vertical section that we're trying to simulate at any given time.

The presence of these carbonate beds if we can develop around these things will allow us to kind of split the cube. We can do kind of over and under a carbonate bed, which will be more efficient in the long-term for us.

Jeff Grampp -- Northland Capital Markets -- Analyst

Can you guys hear me OK?

Brad Fisher -- Vice President and Chief Operating Officer

Still little distant.

Jeff Grampp -- Northland Capital Markets -- Analyst

Sorry about that. That was exactly my question. I'll let someone else hop on.

Operator

Our next question comes from the line of Kashy Harrison of Simmons Energy.

Kashy Harrison -- Simmons Energy -- Analyst

So first of all -- sorry, first off, great work just driving costs down across the portfolio and improving drilling returns. As you -- just focusing on the free cash flow specifically, can you talk about how much free cash flow you expect to generate at the forward strip or your preferred price deck during the second half of the year? And then can you help us think through where -- under your mid-cycle price deck that you guys use or your medium-term price deck, can you help us think through where you would like optimal leverage before you transition to returning cash to shareholders directly with dividends or buybacks?

David Pitts -- Vice President and Chief Financial Officer

Kashy, this is David Pitts. We have not provided any guidance in terms of level of free cash flow we expect to generate in the second half of the year. And I don't think we want to start doing that at this point. All we say, it is at a higher level than we originally forecast.

We laid out our original plan for you guys back in February. In terms of what's the level of leverage at which we need to be to -- before we start returning -- evaluate returning cash to shareholders, right now, our target is to get below two times. And I would say, in evaluating returning cash to shareholders, we need to be well inside of two times, such that whatever returning cash to shareholders that we might employ needs to be sustainable on a long-term basis such that we can achieve and maintain leverage below our two times target.

Kashy Harrison -- Simmons Energy -- Analyst

Gotcha. And just to clarify that's two times at the 55 deck you guys use right?

David Pitts -- Vice President and Chief Financial Officer

That is the plan that we've set out for 2019. I think even last year, we were talking about two times being our -- getting leverage below two times being our target. And that was in a different price environment. I don't know that we've changed our -- that our target change is based on different price environments, it just impacts how quickly we get there.

Kashy Harrison -- Simmons Energy -- Analyst

Gotcha. And then maybe switching gears a little bit, I know that LOE may not necessarily be the sexiest topic in the world. But can you talk about what's driving LOE lower heading into 2Q? And then can you talk about where you expect to end the year on LOE and how we should think about the sustainability of those costs into -- of those levels into 2020 just taking the evolving mix of Delaware, Eagle Ford production into future?

Brad Fisher -- Vice President and Chief Operating Officer

Kashy, this is Brad Fisher. So just to kind of give you a waterfall going from Q1 kind of really to where we expect to end the year, we've got a big supply chain movement going on here. And one of the things that we're really targeting is production chemicals, I think in Eagle Ford for us, our biggest spend item. We think we're going to see some very substantial reduction in our production chemical usage and cost.

On top of that, from a workover expense standpoint, we took on these Devon wells as part of the Permian acquisition and we had to kind of go through round one to get those wells up to our specs. And so we spent those dollars. And then this conversion in the Eagle Ford to hybrid fracs is really going to take down our workover cost for sand production problems. We have much less sand production issues associated with the hybrid frac.

Then in the Eagle Ford also we've a big electrification project that, particularly out in our RPG property where we will be able to release a lot of generators. We're running a lot of the properties on generators. So those three items are really what are going to point us down to kind of the $7 per BOE range in Q4 that we're guiding to.

Chip Johnson -- President and Chief Executive Officer

And actually, I'm going to also add to that I mean, for the year, you saw we reduced the range. I mean, our expectation is it will hopefully be below $7 a BOE, LOE in both plays kind of in the back half of this year and that's kind of a run rate we can maintain.

Kashy Harrison -- Simmons Energy -- Analyst

That makes sense. And then if I could just sneak one more in there and maybe one for Chip. You know you have 600-plus net locations in the Eagle Ford and you have 400 derisked or over 400 derisked locations in the Delaware. It seems like that's biased higher between your Wolfcamp C between what you're seeing from offset operators.

And so just as you think about your portfolio today, how do you think about optimal years of inventory life? Just how many years of inventory life would you like to have on an optimal basis?

Chip Johnson -- President and Chief Executive Officer

Well, we'd like to have unlimited, but I think the way we're going to manage our spreading capital is to be efficient about how we drill up the Permian because there are so many questions to answer there in terms of spacing and multi-layer development. And so, one of the good things for us with the Eagle Ford is that we can drill that to maintain our cash flow and growth targets. The IRRs are almost the same between the two plays. So it just gives us some breathing room while we test these cubes.

And those things, you can't figure those out in a couple of months. You need six months to a year to really look at all the tracer data, the production data. So we're in a pretty good spot where we can keep allocating capital to the Eagle Ford. And at the rate we're going, I think we have about a 8 to 10 year life, so we're just not drilling at that fast and we'd like it to be more of a -- there's not a lot of real high-quality acreage available around us.

Operator

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

Marshall Carver -- Heikkinnen Energy Advisors -- Analyst

How do you think management teams and boards should best address the recent activist activity in the sector, in particular on your stock?

Chip Johnson -- President and Chief Executive Officer

I guess, anybody who has an activist needs to get some advisors that are used to dealing with activists, and we have to engage the activists because they are our shareholders, and they often have good ideas, and that's not all we can say about it.

Marshall Carver -- Heikkinnen Energy Advisors -- Analyst

OK. And a housekeeping question, how many wells were put to sales in the quarter?

Jeff Hayden -- Vice President of Financial Planning and Analysis

Marshall, it's Jeff. Let me get that number for you. See, on an operated basis, 19 wells in the Eagle Ford, four wells in the Permian were brought online in the first quarter, gross.

Operator

Our next question comes from the line of Leo Mariani of KeyBanc.

Leo Mariani -- Keybanc Capital Markets -- Analyst

Hey, guys. I certainly noticed that your Permian gas production was down a fair bit in the first quarter of 2019 versus 4Q. Just wanted to get a sense, was there any flaring sort of going on there and to talk about any issues you might think may pop-up in response to getting gas to market? I know there has been some negative prices out there lately.

Jeff Hayden -- Vice President of Financial Planning and Analysis

Hey, Leo, it's Jeff. One of the big things that kind of impacted production in the quarter in the Permian basin was a very heightened level of planned downtime due to offset activity. In particular, over in the Ford West area, we had an offset operator basically fracked a well, which offset three very recent producers. There were some pretty strong producers as you know over in that area that is kind of the gassier part of our acreage position.

I believe that operator had some issues with that well, which required it take a long time. We had to keep our wells down for that entire period of time. So as a result of that, you did see an impact on kind of gas production in the basin. What I think is important is the stuff like this always happens, it happens to every operator, but despite things like that we were still able to deliver production guidance which came in near the high-end of our range and our crude oil production exceeded the high-end of our range.

Leo Mariani -- Keybanc Capital Markets -- Analyst

OK. And I guess just wanted to follow up a little bit on the Eagle Ford. You guys sort of talked about kind of filling the gaps a little bit with these very large pads. What type of spacing have you guys migrated to these days in the Eagle Ford? Just want to get a sense of what kind of the average well spacing is on your acreage here in terms of how you're developing? And then when you talk about gaps, what sort of the spacing there -- those areas where there's just very little well density, maybe you can help us out with the density in terms of when you say, hey we needed to go back in there and go back out.

Brad Fisher -- Vice President and Chief Operating Officer

Leo, this is Brad Fisher. So a lot of different answers here. So to address the spacing issues, so the spacing will vary by area kind of in line with what we've been guiding you guys to, for example, the Brown Trust 13 that we're fracking right now that's on 330-foot spacing, Irvin 14 is on 350-foot spacing, Pena 12 was on about 375-foot, RBG was 350-foot to 425 foot depending on well length. So they vary a little bit, but in line with what we've been guiding you guys to by different areas.

As far as you're talking about the size of the gaps, I mean they vary. For example, Brown Trust, the kind of entire south eastern half of the acreage track is on drill, we purposely drilled it all to kind of the Northwest and went to south part alone. So we're kind of progressing across that at 14 to 15 wells at a time. Irvin is same way, the Irvin 14 has filled in a rather large gap kind of on the northern side of our acreage.

So we did this intentional. If you kind of look at some of the guys around us, the way they develop their units, they do a little bit differently. In my opinion, they kind of got themselves the ability to really do a good job at gap management and minimize parent-child. We recognized the parent-child issue and led these larger gaps.

We'll put a 500-foot spacing in between existing wells and then we'll start the mega pad and we found that to be the most effective way to develop those.

Leo Mariani -- Keybanc Capital Markets -- Analyst

OK. That's very good color for sure. I think, just lastly here, I know Carrizo had a pretty big shift in terms of strategy moving to lower growth with free cash flow here in 2019. So certainly in contrast to kind of what we've seen with some higher growth in sort of years passed here.

I mean, I guess at this point, we really haven't seen, I guess the benefit to that, in terms of share price appreciation. So I guess, are there any other things that Carrizo thinks about in trying to maybe resolve the gap between where you guys are trading versus maybe where some of the other small to mid cap peers are trading?

Chip Johnson -- President and Chief Executive Officer

Well, I think we want to get to cash flow neutrality. We need to prove that first, I think, then that will show up in our stock price. But we haven't done yet. Hopefully it would still be in the third quarter, and we can talk about that at that point when we start throwing off some cash that we can delever with, I think will all be positive, and that's what we would be looking for.

And we are down to a two basic company. We are in two of the highest IRR oil plays of the three in the country. All of our activity has been tested. So we have almost no political exposure that other plays have.

We're in pretty good shape, I think operationally, you've heard of all of our efficiencies and cost flowing down everywhere, IRR is going up. So we're in good shape. I think, once we can start dragging about the cash flow neutrality then we'll see the corresponding increase in share price.

Operator

We have no further questions at this time.

Chip Johnson -- President and Chief Executive Officer

Thank you all for calling in. It was obviously a very good quarter for us. The operations guys especially in cutting cost and improving efficiencies have really changed the math for us going forward. I think in terms of catalyst in the next couple of quarters, one will be getting the cash flow neutrality in the third quarter, also the results of these additional multi-well pads in the Eagle Ford with the hybrid gel fracs.

Our next cube test in the Delaware will be really important because we'll be adding the third Bone Springs, which could have an entire layer to us. Right now, we have a successful Bone Springs test on east and west of us, so we're pretty confident. But until we prove that, we're not going to add that to our inventory. So I think that's what we're going to be looking for.

Also we'll have more results on the crater test on The Six, which will show us if we got the desired vertical frac containment in the constructed interference in a layer that we were looking for with this basin. So with that, we'll talk again in 90 days.

Operator

[Operator signoff]

Duration: 49 minutes

Call participants:

Jeff Hayden -- Vice President of Financial Planning and Analysis

Chip Johnson -- President and Chief Executive Officer

David Pitts -- Vice President and Chief Financial Officer

Gabe Daoud -- Cowen and Company -- Analyst

Brad Fisher -- Vice President and Chief Operating Officer

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Brad Heffern -- RBC Capital Markets -- Analyst

Michael Scialla -- Stifel Financial Corp. -- Analyst

Jeff Grampp -- Northland Capital Markets -- Analyst

Kashy Harrison -- Simmons Energy -- Analyst

Marshall Carver -- Heikkinnen Energy Advisors -- Analyst

Leo Mariani -- Keybanc Capital Markets -- Analyst

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