Carrizo Oil & Gas Inc (CRZO) Q4 2018 Earnings Conference Call Transcript
Carrizo Oil & Gas Inc (NASDAQ: CRZO)
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Q4 2018 Earnings Conference Call
Feb. 26, 2019, 11:00 a.m. ET
Contents:
Prepared Remarks
Questions and Answers
Call Participants
Prepared Remarks:
Operator
Ladies and gentlemen, thank you for standing by. Welcome to the Carrizo Fourth Quarter and Year End 2018 Earnings Conference Call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this call is being recorded Tuesday, February 26, 2019.
I would now like to turn the call over to Mr. Jeff Hayden, Vice President of Investor Relations. Please go ahead, sir.
Jeffrey Hayden -- Vice President of Investor Relations
Thanks, operator, and thank you everyone for joining us this morning. 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 most directly comparable GAAP measures. We have posted slides to go along with the webcast today. The slides can be found on 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, Vice President and CFO; Brad Fisher, Vice President and COO and other members of our senior management team.
With that, I'll turn the call over to Chip.
Sylvester Johnson -- President and Chief Executive Officer
Thanks, Jeff. As we mentioned in yesterday's release, the fourth quarter capped off another excellent year for Carrizo and help set the stage for us to achieve our longer-term targets, which I'll discuss shortly. Our total production during the fourth quarter was 68,328 Boe per day, in line with our guidance range and up 6% sequentially. Our crude oil production of 43,040 Bopd was up 5% sequentially and accounted for 63% of our total production during the quarter. Despite the downturn in crude oil prices during the quarter, our margins remained strong, thanks to the Eagle Ford Shale's exposure to premium seaborne-based crude oil markets.
We continued our trend of strong reserve growth during 2018 with total proved reserves increasing by 26% to 329 million Boe. For the year, we replaced more than 475% of our production at an attractive cost of $10.34 per Boe. Excluding acquisitions, we replaced more than 450% of our production at cost of about $8.50 per Boe. Proved developed reserves increased by 20% and accounted for 40% of our total reserves. Primary driver of our reserve growth during the year was the Delaware Basin where reserves nearly doubled. At year-end, our PV-10 value was $4.1 billion for the Company and our proved developed PV-10 value was $2.4 billion. This provides us with an excellent foundation of value considering their enterprise value is currently less than $3 billion.
As we set out to develop our multi-year plan, our goal was to design a capital program that facilitated prudent long-term, high return production growth within cash flow in a mid $50 price environment. As a result, we have elected to reduce our activity level from where we ended 2018 in order to better match our CapEx with our expected cash flows in the current price environment. While we are still running five rigs across our portfolio, today we expect to drop a couple of rigs by the end of the quarter and average three to four rigs for the balance of the year.
As a result of this, plus a combination of service cost reductions, efficiency gains, and changes to completion techniques, our 2019 DC&I CapEx program is expected to be between $525 million and $575 million, down approximately 35% versus last year. This plan should allow us to generate more than 10% production growth during the year while achieving a free cash flow positive inflection point during the third quarter and entering 2020 with positive operational momentum as fourth quarter '19 production should be above fourth quarter '18.
Our 2019 plan implies a material improvement in capital efficiency, key focus of our management team, and a direct result of the factors I just mentioned. As we expect to maintain these efficiencies in future years, while it's too early for us to give official 2020 guidance in the current price environment, our expectation would be to add a second rig back in the Eagle Ford Shale next year as Eagle Ford Shale well economics are quite attractive in the current commodity price levels, they are also competitive with our Permian Basin economics. This combined with the shorter cycle times into play should allow us to provide a balanced, predictable, and profitable (inaudible) of incremental production while we continue to optimize our development in the Delaware Basin, where our early expectations would be to maintain a three rig program. At this level of activity, we'd expect to generate continued production growth with a similar level of CapEx this year and generate positive free cash flow for the year.
In the Eagle Ford Shale, we are currently operating three drilling rigs and expect to reduce this to one by the end of the quarter. In the fourth quarter, we drilled 38 gross or 37 net operated wells and completed 18 gross or 16 net wells. Total production from the play was approximately 38,600 Boe per day for the quarter, roughly flat with prior quarter. Crude oil production from the play was more than 30,600 Bopd, up 2% sequentially.
As a result of crude oil production from the play receiving seaborne-based pricing, our operating margins remained strong at approximately $44 per Boe during the quarter. At the end of the quarter, we had 39 gross and net operated Eagle Ford Shale wells waiting on completion. We currently expect to drill 50 to 55 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.
As we mentioned in the press release, we have made a number of strategic and operational changes to our development plan in the Eagle Ford Shale in order to maximize our capital efficiency in a mid-$50 world. (ph) While we expect the net impact of these changes to be neutral to EURs going forward, we do expect them to result in a lower capital cost. This should yield a positive impact on our fieldwide profitability and corporate level returns.
Last quarter, we spoke about one of these design changes reverting to hybrid water gel completions from 100% slickwater completions. Since then, we have completed more than 10 pads with a hybrid design and have seen a material improvement in average production downtime. The parent well is exhibiting more than 50% improvement in production recovery time following offsets to frac hits.
While we're further along the learning curve in the Eagle Ford than we are in the Delaware Basin, our team continues to deliver efficiency gains. We recently drilled two of our longest well to-date in the Eagle Ford with average effective laterals of about 13,600 feet. These wells were drilled four to six days faster than our previous record well despite 5% to 10% longer laterals.
On the completion side, improved processes, coupled with adjustments to our completion techniques have helped drive more than a 25% increase in the number of stages we've been completing per day relative to our 2018 average.
In the Delaware Basin, we are operating two rigs. We currently expect to add a third during the second half of the year and during the fourth quarter, we drilled five gross and four net operated wells. We didn't have any completion activity planned during the quarter. Total production from the play was approximately 29,700 Boe per day for the quarter, up 16% sequentially. At the end of the quarter, we have a 11 gross and 9 net operated Delaware Basin wells waiting on completion. We currently expect to drill 25 to 38 gross or 20 to 25 net operated wells and frac 20 to 25 gross or 15 to 20 net operated wells in the play during 2019. Our current operational focus in the play is testing multi-layer of cube concepts as we believe co-development on various zones will result in the optimum development of our acreage.
In our Phantom area, we are currently completing the area's first large-scale co-development test of the Wolfcamp A, B and C. Test is comprised of six wells across four target layers with average horizontal spacing of 660 feet within the layers and vertical spacing of 150 to 250 feet between the layers. We've posted a video to our website to look at the sequencing, the completion test which are being monitored with microseismic and 37 unique production tracers. As you'd be able see in the video, the wells have been completed with different frac sequences in order to test the various Wolfcamp layers with and without being bounded by either underlying or overlying offset fracs. Results from this project will be incorporated with ongoing field study efforts and other data in order to further optimize completion design, three dimensional well spacing and target landing points within a zone. The six well cube is currently planned to begin production during the second quarter.
In late 2018, we began delineating additional zones on our acreage. In the Phantom area where we had previously derisked the Wolfcamp A and B, we currently have our first two Wolfcamp C tests online. The Woodson well test came online last quarter and has achieved a peak 90-day rate of more than 1,500 Boe per day while our Zeman test came on earlier this quarter. While this well has achieved peak 30-day rate yet, it has recorded a peak 24-hour rate of more than 1,900 Boe per day.
In the Ford West area, where we have previously derisked the Wolfcamp A, we brought our initial Wolfcamp B tests online during 2018 as part of a multi-layer test. The well achieved a peak 60-day rate of approximately 2,100 Boe per day. We are encouraged by the early results from these wells and have additional tests at these target layers in progress across our acreage.
Recently, we shifted about half of our sand supply for the Delaware Basin to local mines. This combined with logistical improvements and service cost reductions have helped reduce our well costs in the region by more than 10%. And we see opportunities for further cost improvements due to operational efficiencies. As an example, we recently drilled a well in our Phantom area in under 20 days, approximately 33 faster than our average budgeted drilling curve.
With that, I'll turn it over to David to discuss the financials.
David Pitts -- Vice President and Chief Financial Officer
Thanks, Chip. To build on what Chip has already highlighted, our goal for 2019 was to target a development program that would deliver sustainable free cash flow and prudent long-term production growth in the current environment. With this in mind, we prioritize sustainable free cash flow generation and view production growth as more of an input in determining the optimal capital program. In addition to generating sustainable free cash flow, we are also cognizant of project level economics, corporate returns, leverage metrics and liquidity, as these things are also key components of long-term value creation.
As Chip has already discussed, production growth and operational efficiencies, I'll go over some of the other components that contribute to our plan. Improving our balance sheet remains a high priority for the Company. As we begin to generate free cash flow later this year, we plan to allocate a 100% to debt reduction. And if prices move higher than the level at which we budgeted, we expect to allocate the incremental free cash flow to further debt reduction. We currently have no plans to add activity in 2019 based solely on improvements in commodity prices. We believe reducing our outstanding debt and leverage improves our long-term competitive position in the market and will allow us to capitalize on value added opportunities regardless of where we are in commodity price cycle.
We are currently planning to hold our spring borrowing base redetermination next month at which time we'd expect an increase to our borrowing base limit. While the banks have revised their price decks down since fall redetermination, we did not elect to utilize our full borrowing base at that time. That cushion plus strong PDP growth is what we expect to drive the increase despite the lower bank debt pricing.
A disciplined hedging program is another key part of our financial strategy as it helps mitigate price risk and allows us to make longer term operational decisions. Typically, we've targeted hedging 50% to 75% of our crude oil production over the next 12 months as you see on Slide 14 of our earnings presentation, right in that range with hedges in place for approximately 64% of our 2019 oil production. As we consider our hedging strategy going forward, we view our target hedging level as having an inverse correlation to our leverage. As we use free cash flow to further reduce debt, our tolerance for price risk increases are offering our shareholders more potential upside in the event of material improvements in commodity prices.
Given this, we will be targeting the hedge level in 2020 closer to 50% of our oil production. For 2020, we currently have hedges covering 9,000 barrels per day, 3,000 barrels per day of fixed price swaps at $55 and 6,000 barrels per day of three-way collars with $55 floor, $65 ceilings, and $45 sub-floors. We'll continue to layer on additional hedges for 2020 as the opportunity arises.
In this quarter's press release, we reiterated our full year 2019 production guidance of 66,800 to 67,800 Boe per day. We also provided cost guidance for the year as well as production and cost guidance for the first quarter. Given the limited number of wells turned to sales in the fourth quarter and the early part of the first quarter, we're expecting first quarter production to range from 61,100 Boe per day to 62,100 Boe per day. As our large multi-pad projects continue to come online, we expect a significant uplift in production during the second quarter with a further increase in the second half of the year.
From a CapEx standpoint, we expect our CapEx to be more heavily weighted toward the first half of the year given the heavier completion activity during this period. For our expense guidance, you'll notice that we expect LOE to increase slightly in the first quarter. One of the main drivers of this is the added workover activity required on the Delaware Basin assets we acquired late last year. We currently expect a significant reduction in LOE over the balance of the year as cost savings identified by our operating and procurement teams are realized. With respect to severance and ad valorem taxes beginning with 2019, we are guiding those expenses on a combined basis as a percentage of total revenues rather than individually.
With that, I'll turn the call back over to Chip.
Sylvester 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. As David mentioned, the initial use for our free cash flow will be earmarked for debt reduction. 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 and Answers:
Operator
Certainly. (Operator Instructions) And our first question comes from the line of Neal Dingmann with SunTrust. Your line is open. Please go ahead.
Neal Dingmann -- SunTrust Robinson Humphries -- Analyst
Good morning, guys. Chip, my first question is on operational flexibility. I'm just wondering, given the large number of rigs that each of your Eagle Ford rigs can drill, how do you -- how does this sort of factor in when you think about bringing back another rig? I think you mentioned either maybe early next year, late this year, depending on what commodity price is doing. I'm just trying to get a sense of, I guess, timing or how quickly you see the results versus what we often see in the Permian.
Sylvester Johnson -- President and Chief Executive Officer
Well, I mean, we can shift back and forth quickly. I think we've talked to that before that we can move rigs back and forth in six to eight hours between the plays. The Eagle Ford economics are pretty well understood, so that's what we would use as kind of a safety valve while we're still studying the Permian and trying to get the co-development right. So that is pretty easy to do that. The Eagle Ford is nearly all HBP-ed now, all the facilities are in, so shifting capital to the Eagle Ford can happen very quickly.
Neal Dingmann -- SunTrust Robinson Humphries -- Analyst
Okay. And then sticking with Eagle Ford for my second question, how do you all -- and you all touched upon this, how do you all think about the upside of the slickwater versus lot of those hybrid completions?
Brad Fisher -- Chief Operating Officer and Vice President
Hi, Neal, this is Brad Fisher. Just to address the hybrid versus slickwater, I just want to make sure everybody understands that a hybrid job as we pump in is actually 76% slickwater. So, what our job looks like is, we pump slickwater with sand, then we follow it with a hybrid fluid which is a light gel to kind of pack sand in at the end of the job. The big upside for us is switching from the slickwater back to the hybrid, which, by the way, we pumped over 400 hybrid jobs, that's what we started with back in 2011.
The big advantage is that we use 57% less water. The performance of the slickwater frac versus a hybrid on the child is very similar, OK, from an EUR standpoint. The advantage for us comes as we kind of do this gap management and we're dealing with parent wells is the amount of fluid that's involved in slickwater job is having a negative impact on the parent. The return to pre-frac rate productions are extended whereas with the hybrid job, we're able to control that much better with less fluid and we're seeing return to pre-frac rates in less than two months versus the slickwater where we are seeing four to six month turnaround. So that's going to help us with our downtime or production downtime.
Neal Dingmann -- SunTrust Robinson Humphries -- Analyst
Fantastic details. Thank you, all.
Operator
Our next question comes from the line of Brad Heffern with RBC Capital Markets. Your line is open. Please go ahead.
Brad Heffern -- RBC Capital Markets -- Analyst
Hey, good morning, everyone. I guess, for the Wolfcamp C tests in Phantom and the Wolfcamp B tests in Ford West, can we talk a little bit about how the economics compare to the higher benches? I obviously understand it's early, but any initial thoughts?
Andy Agosto -- Vice President of Business Development
Well, this is Andy Agosto, Brad. We are really early in the production life of these wells. I think we have between three and four months on one of the wells and less than a month on the other. I believe right now we're seeing results which are similar to Wolfcamp B, but again it's early and I don't think we can really comment much more than that at this point.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay. And then I know you guys have the big cube test coming up in Phantom, but any thoughts about your expectations going into that as far as how co-development would look? Do you currently think that the three benches in that area need to be developed together or where are the frac barriers and so on?
Brad Fisher -- Chief Operating Officer and Vice President
Hey, Brad, this is Brad, a little Brad test here. Yes, the whole purpose for the co-development test for us is to understand the vertical interaction. The one thing that we've learned from the Eagle Ford in just two dimensions is that parent child relationships matter, OK. They're going to be compounded in a three dimensional cube here. So an early understanding of how stress shadowing controls frac growth in both height and width is going to really guide us to how we're going to develop this in the future. I mean, we are convinced that the cube is the way to go. For us, right now, it's just all about how we sequence fracs and how we ultimately space the wells and we think that the data that we're going to get out of this six-well, four-layer test, which I think -- which as far as we know, it's one of the first in the basin. I think it's really going to give us a lot of data, which is going to point us in the direction that we need to go to develop that asset.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay. Appreciate it.
Operator
Our next question comes from the line of Leo Mariani from KeyBanc. Your line is open. Please go ahead.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Hi, guys, wanted to dig in a little further on this Permian Basin well cost. I think you guys referenced your $8.5 million on the protocol on the press release, and I guess in the release that kind of talked about a projected well cost. Is that kind of supposed to be a 2019 average and have you got that $8.5 million today? Have you seen some benefit from service cost reductions as well to kind of get there? What can you kind of tell me, a little bit more granularity around that $8.5 million number?
Brad Fisher -- Chief Operating Officer and Vice President
Yeah, Leo, this is Brad Fisher again. So, no, the answer is, we're there today. So the cost reduction which is basically about $1 million, right now we're going to split it about 60% into the completion side, a big component of that 45% is our switch -- complete switch to local 100 mesh sand there and the other portion of that is really is a service cost reduction. We've seen about 55% of that savings in the completion side is from an erosion of what we like to call the Permian premium. We've been paying -- as everyone else has, been paying a premium to pumps jobs, frac jobs in the Permian. We're seeing those prices come more in line with what we're paying in the Eagle Ford. So that's a big part of it.
On the drilling side, the guys have been successful in kind of reducing our average days from mid-30s to kind of high 20s in the basin, so that's made a big difference out of $60,000 to $70,000 spread rate on a rig. Six, seven days is a significant reduction. So we're there with that. The hope is that we'll continue to improve in that just like we did in the Eagle Ford, but right now we're thrilled with -- very comfortable with the $8.5 million range.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Okay, that's great color. In terms of your comment around the hope to improving, what are some of those things that you hope to materialize here in 2019 to get that well cost to move lower?
Brad Fisher -- Chief Operating Officer and Vice President
The biggest thing for us going into 2019 is our switch from primarily single well development to pad development. So everything we've got moving forward in 2019 and in 2020 quite honestly is pad development in the Permian. So we see, just like we did in the Eagle Ford, there is great efficiencies in that and so we're going to build off of that, being able to batch drill surface, batch drill intermediate, batch drill TD, that all -- that's starting to pay off for us.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Okay. That's great color. And I guess, just wanted to follow up on your comment about potentially bringing another rig in 2020 into the Eagle Ford if prices hold. Obviously, you guys have moved around a little bit between the basins. Just wanted to kind of get your thoughts sort of behind capital in the Eagle Ford versus capital in the Delaware today now that a good portion of the price differentials have sort of gone away with much better (inaudible) price and I realize there's still a pretty big gap between LLS and WTI. But how do you think about the comparative economics in the two basins today in kind of the decision is to kind of where to spend capital on those two areas?
Sylvester Johnson -- President and Chief Executive Officer
Well, I think, we still believe that the economics of the Eagle Ford are as good as the Permian and a little safer because of the basin differentials that even though the Midland Cushing differential is low now, there still could be some more problems. So we don't have to go back for the Eagle Ford later in the year, but that's kind of a simple thing to do for us once we're past getting cash flow neutral. The other thing we want to do is just have a lot of time to understand the Permian downspacing and layers. And so there's plenty of data out there by industry that shows that parent child interference can be serious and we want to get this right before we start. And I'd just go out there and drill a bunch of Wolfcamp A parent (inaudible) a lot of our acreage in the Wolfcamp B. So we have the luxury of having time in the Permian to get it right and because we have the Eagle Ford where we can deploy capital very quickly and very profitably which is probably the highest margins in the business right now.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Okay, great color. Thank you.
Operator
Our next question comes from the line of Michael Scialla with Stifel. Your line is open. Please go ahead.
Michael Scialla -- Stifel Nicolaus -- Analyst
Yeah, good morning, everybody. Wanted to follow on to Leo's last question there. So you do go to two rigs in the Eagle Ford next year. Just want to get a sense of, is that a realized -- you are doing these large projects now so the production quarter-to-quarter is going to be really lumpy, but would that be enough to generate growth out of the Eagle Ford or should we think about that being kind of flat year-over-year and the growth is going to come from the Permian?
Jeffrey Hayden -- Vice President of Investor Relations
Hey, Mike, it's Jeff. Two-rig program in the Eagle Ford, I'd probably characterize that as flattish growth and generating a -- or two flattish production. I guess would be a better way to put that and generating a lot of free cash flow.
Michael Scialla -- Stifel Nicolaus -- Analyst
Okay. And with that, I mean, say, based on strip prices, so you're thinking that two to three rigs would stay in the Permian under that scenario and that would be where the growth would come from?
Jeffrey Hayden -- Vice President of Investor Relations
Well, I think, what we -- what Chip kind of mentioned in his remarks was that we kind of exited this year with three rigs in the Permian. So if you were just to assume we maintain that level of activity in the Permian, that we should be able to do that and kind of a similar level of CapEx is what we're expecting to spend this year and we would expect to see year-over-year production growth companywide.
Michael Scialla -- Stifel Nicolaus -- Analyst
Got it. Thanks. And then you laid out, obviously, your -- and talked a lot about your six-well test in the Phantom area. I was curious on the spacing that three well test you did in Ford West. Is that the same sort of 660 foot spacing within zone, between those two Wolfcamp A wells, with the Wolfcamp B staggered between or was that a different dimension and curious to why one of those Wolfcamp A wells look quite a bit better than the other? Any color around that?
Andy Agosto -- Vice President of Business Development
Yeah. Mike, this is Andy. I believe we were -- I don't have the exact number there, but I think we were close to 600 feet within the layer, maybe a little bit wider. I'm looking at my production guys right now. In terms of why they're different, one of the A wells was about 11,000 feet long. The other was more of a single section well, I think 4,500 to 5,000 effective feet lateral. Performance-wise, right now they are still actually relatively similar, but, yeah, I mean, that would be the only difference between those two wells.
Michael Scialla -- Stifel Nicolaus -- Analyst
Okay, I thought I had -- well, I probably miscalculated. I thought I saw difference on a per foot basis, but I'll be wrong there. This last one for me on your --
Andy Agosto -- Vice President of Business Development
Mike.
Michael Scialla -- Stifel Nicolaus -- Analyst
Yeah.
Andy Agosto -- Vice President of Business Development
Mike, it's Andy again. Yeah, on a per foot basis, the 22H is higher, because it's a shorter lateral and we're producing it at similar rates to the...
Michael Scialla -- Stifel Nicolaus -- Analyst
That makes sense. Got you. Okay. Then wanted to ask, just lastly, on your Slide 10, the frac sequencing design diagram there, can you explain what you have shown us there?
Jim Pritts -- Vice President, Technology and New Business Development
Hi, Michael, this is Jim Pritts. What we're showing there is kind of the stages of each frac in each well. The colors are -- and each dot is an individual stage along the well and what it does is, if you look at some of it, the colors are bounded versus unbounded. If we look at the 12H well, in the center on the slide, where you see Wolfcamp B upper bounded, that would be because it had a Wolfcamp B lower underneath it. And if you look at the video on the website, it shows the sequencing and progression of the fracking as we jump around from well to well and whether we have a offset frac above laterally or below the particular well. So there's 303 stages in total and we're about -- have monitored about 132 to-date. We are going to ultimately monitor 180 of these stages.
Michael Scialla -- Stifel Nicolaus -- Analyst
Okay, great. Thank you.
Operator
(Operator Instructions) Our next question comes from the line of Noel Parks from Coker Palmer Institutional. Your line is open. Please go ahead.
Noel Parks -- Coker Palmer Institutional -- Analyst
Good morning. I was looking to just get some clarity on what you have left drilled at HBP in the Delaware for 2019-2020 and kind of where you are in the pace of being on top of those lease expirations?
Andy Agosto -- Vice President of Business Development
Yeah, this is Andy Agosto. We really don't have that many wells in our program that are focused solely on lease management. As Brad and Chip both alluded to, we're trying in every case to drill multiple wells and just get out of the single well business. That said, we had a couple of wells that we drilled last year that we're going to complete early this year that were obligation wells. The bigger challenge in the Delaware, as you're probably aware, is a lot of these leases have depth restrictions. And so while we may aerially hold 640 acreage units, there may be leases within that 640 acres that have a depth severance. And so it's a pretty complicated business of trying to make sure all the depths and all the right leases are held. But again, that's another advantage of our multi-well pads as we're able to kind of go top to bottom, hold all the acreage in that particular block of the acreage.
Noel Parks -- Coker Palmer Institutional -- Analyst
Great. And if memory serves me, the amount of acreage for 2020 was somewhat larger as far as lease explorations in the 2019 list and so will the drilling in '19 take a significant chunk out of what you have obligated for 2020?
Jeffrey Hayden -- Vice President of Investor Relations
Noel, it's Jeff. As far as 2020, a lot of that was a function of Alpine High. I mean, that's where you kind of look out over the next couple of years, a lot of those lease expirations are. So, when you look at our core acreage, it's very easily manageable.
Noel Parks -- Coker Palmer Institutional -- Analyst
Got you. Thanks. And just one thing I just wanted to clarify on. You were talking earlier in the Phantom Wolfcamp A, B, C tests that I guess you had just a handful of wells with production history there. As far as offset operators, just curious like how much of a data set you have for the production of the different or I guess the -- yeah, the productivity of the different zones, that individual wells?
Andy Agosto -- Vice President of Business Development
Noel, this is Andy Agosto. We keep track of everything going on, on the other side of the fence from us and generally, go wider than that. I would say anywhere where we see geology that's similar, we are looking at whatever data is available. We have a team and a group now that's focused on taking that data, analyzing that data and I think in the Permian, in particular, we've done a really good job of staying on top of that.
Noel Parks -- Coker Palmer Institutional -- Analyst
And I'm sorry, so would you say, I mean, do you have any like -- do you have two year data on wells in each of the target at this point across the industry or...?
Andy Agosto -- Vice President of Business Development
Well, we have -- whatever data is available publicly, we have them, whether it's a month or five years. In terms of data that's not public, we do trades and things like that with offset operators to enlarge our database.
Noel Parks -- Coker Palmer Institutional -- Analyst
Okay, thanks a lot.
Andy Agosto -- Vice President of Business Development
Thanks, Noel.
Operator
Our next question comes from the line of Ron Mills with Johnson Rice. Your line is open. Please go ahead.
Ron Mills -- Johnson Rice & Company -- Analyst
Good morning, guys. Just to go back to the Eagle Ford completion design. Moving a little bit against the green (ph) versus where have people moved for the past 18 months or so, are you also seeing or talking to other operators or is the move back to hybrids starting to happen more and more, or are you kind of leading edge on this?
Brad Fisher -- Chief Operating Officer and Vice President
Ron, this is Brad Fisher. Leading hedge, I don't know if we are leading hedge as we've been doing this since 2011, that we kind of diverged from hybrid to test the slickwater concept not from slick -- not from -- not the other way around. So our completion design here really is not driven by the fact that the slickwater frac is not performing relative to the hybrid frac. What we're seeing is that the slickwater frac is causing unintended consequences in our parent wells as we kind of fill out, do gap management and fill out between the (inaudible) pads. That's the primary reason for us changing and we've seen immediate results with that change. I do know that other operators who are pumping slickwater fracs are having sand production problems. We don't have sand production problems when we pump the hybrid frac.
Ron Mills -- Johnson Rice & Company -- Analyst
Okay, great. And then you also referenced moving away from diverters as part of the recent changes in the Eagle Ford. What were you seeing on the diverter side or was it just a cost benefit analysis you weren't seeing enough uplift for incremental cost?
Brad Fisher -- Chief Operating Officer and Vice President
Ron, you nailed it. I mean that's the exact reason. We've gone through and looked at everything we're doing on the completion side and weighed the cost benefit analysis in this price environment. The particular side of the diverters was the diverters once again would intend to expand jobs because as you pump diverter, occasionally we get a complete bridge off of the perforation, sometimes you have to go in and get flow it back to get -- to reinjecting the job, you end up using more fluid which -- the unintended consequence of that again is the impact on the parent with more fluid. Sometimes we have to clean them out with coil tubing. By getting away from the diverter, the job, the sequencing is very quick, in fact and we've had some jobs here recently where we are pumping 12 to 13 stages a day versus our average last year of six to eight. So from an efficiency standpoint, it's better from a production standpoint, the hybrid job is better and then the diverter that -- drop net off the well has improved our economics as well.
Ron Mills -- Johnson Rice & Company -- Analyst
Okay, great. Thanks. And then in terms of the delineation of the B over in Ford West and the C and Phantom, I know you haven't booked any of those -- either of those formations in those areas. Just curious from your initial look at your acreage and analysis of data, do you think it's pretty -- those zones are pretty consistent over those acreage blocks? I guess, I'm trying to get to a sense as to, if the early results are replicated over time, how much that inventory can be augmented with those zones?
Andy Agosto -- Vice President of Business Development
Yeah, this is Andrew again. We purposely have drilled C tests pretty much from end to end on the Phantom acreage. What we see on the well logs indicates we have -- what looks like pretty good rock consistently from top to bottom there but of course we want well data to confirm that and on the C so far we're very encouraged by what we've seen, but I think as we -- as Chip, Brad commented, and I think we had an earlier question, it's still pretty early there. Obviously, if we did out of a C layer, that's going to have a nice impact on inventory and as you correctly stated, none of that is built in right now. In terms of the B over in Ford West, we're real excited about the well we've just drilled. We've seen offset operator production in the B that looks very encouraging, so again not something we have in our inventory right now, but clearly an upside for us.
Ron Mills -- Johnson Rice & Company -- Analyst
Okay. And are you seeing dramatic differences in terms of commodity mix as you move deeper in the formation or nothing that you wouldn't have expected?
Andy Agosto -- Vice President of Business Development
We're seeing what we expected and we know as -- particularly in Ford West, that the B is going to be more gassy and it is, but we still -- I don't have the number off the top of my head, we still have a very attractive oil cut there.
Ron Mills -- Johnson Rice & Company -- Analyst
Okay. And then one last one, just I know you sold some of your Eagle Ford a year plus ago or so. How are you -- what are you seeing in the A&D market in either the Permian and the Eagle Ford and do you continue to plan to kind of prune areas that aren't going to get capital in the near term or how do you -- what's your approach to asset sales and/or acquisitions? Thanks.
Sylvester Johnson -- President and Chief Executive Officer
I guess that we normally don't talk in detail about any A&D. There aren't a lot of packages in the Eagle Ford that are in the core area for sale. Most of the activity has been in the downdip gassy areas where the -- very far updip areas. In the Permian, there doesn't seem to be a lot going on. The private companies who still have big acreage positions aren't willing to sell those at something that reflects a $50 oil world, so there's just not lot going on right now.
Ron Mills -- Johnson Rice & Company -- Analyst
Thank you.
Operator
Our next question comes from the line of Eli Kantor with IFS Securities. Your line is open. Please go ahead.
Eli Kantor -- IFS Securities -- Analyst
Hey, good morning guys. Can you talk about what kind of average cycle times you'd expect in the Eagle Ford this year, and how the cycle times are going to impact your 2019 quarterly production trend?
Jeffrey Hayden -- Vice President of Investor Relations
Hey, Eli, it's Jeff. Are you asking about cycle times or you trying to understand more like completion cadence?
Eli Kantor -- IFS Securities -- Analyst
I guess both. Just about the sales stance (ph) as well as what kind of completions we should expect each quarter?
Jeffrey Hayden -- Vice President of Investor Relations
Without giving specific on kind of every single quarter kind of what those numbers are going to be, if we just look at things from an operating standpoint, Eagle Ford activity is going to be weighted to the first half of the year because obviously we've got the two big multi-pads. We talked about the Pena wells came online recently, so that's in the first quarter. The RPG well will come online in second quarter. And then as you look at kind of the balance of the year, I'd say you'd probably see a little more activity in the third quarter than the fourth quarter because we do usually take a frac holiday late in the year. On the Permian, you probably see activity in the first half of the year weighted to Q1 because we're fracking that six-well cube. And then if you look into kind of the balance, second half of the year from an operating standpoint, probably pretty evenly spread throughout the remainder of the year. So hopefully that kind of gives you what you need.
Eli Kantor -- IFS Securities -- Analyst
It does. Thanks for the color. And then as far as your inventory goes, do you have a year end '18 undeveloped location count for the Eagle Ford and Permian?
Andy Agosto -- Vice President of Business Development
This is Andy Agosto. In the Eagle Ford, I think we're going to be a little north of 600 net locations. In the Permian, looks like we will be between Ford West and Phantom in the 500 range, maybe a little above just...
Eli Kantor -- IFS Securities -- Analyst
And that 500 number, can you just remind me, which zones you include in that?
Andy Agosto -- Vice President of Business Development
That number is going to be primarily A and B in the Phantom area and primarily A in kind of the Ford West area. Although we'll probably add -- we'll probably put a conservative number of B locations in the Ford West area just given the strength of our well results as well as what we've seen from offset operators.
Eli Kantor -- IFS Securities -- Analyst
All right. Thanks for the color, guys.
Operator
Our next question comes from the line of Marshall Carver with Heikkinen Energy Advisors. Your line is open. Please go ahead.
Marshall Carver -- Heikkinen Energy Advisors -- Analyst
Yes. Do you have a specific number of Wolfcamp C wells that you're going to be targeting this year or how would you -- the Permian wells, how would you spread them between A, B and C?
Andy Agosto -- Vice President of Business Development
Marshall, it's Andy Agosto. We have four Wolfcamp C tests that are in various stages of production and completion.
Marshall Carver -- Heikkinen Energy Advisors -- Analyst
And anymore specifically planned?
Andy Agosto -- Vice President of Business Development
Yes, wherever we drill a multi-pad and as I think Brad mentioned earlier, our plans as we move through 2019 and end of 2020 are to be drilling multi-pads. We will be including Wolfcamp C in those tests. We're also going to test the third Bone Spring.
Marshall Carver -- Heikkinen Energy Advisors -- Analyst
Okay, thank you. And how many net wells to sales did you have in the fourth quarter? I saw you had a completed number and a drilled number, but not a wells to sales.
Andy Agosto -- Vice President of Business Development
Hang on, Marshall. Let me get that number for you here. In the fourth quarter of the year, in the Eagle Ford, it was little over 20 gross weighted early in the quarter and then in the Permian, one.
Marshall Carver -- Heikkinen Energy Advisors -- Analyst
All right, thank you.
Operator
Our next question comes from the line of Kashy Harrison with Simmons Energy. Your line is open. Please go ahead.
Kashy Harrison -- Simmons Energy -- Analyst
Good morning, everyone, and thank you for taking my questions. So, apologies if I missed this earlier, but it looked like there might have been a revision to oil reserves that was unrelated to changes in the development plan. I was just wondering if you could shed some additional color on the driver of the revision?
Andy Agosto -- Vice President of Business Development
Yeah, Kashy, this is Andy Agosto. As you just mentioned, I mean, this was a fairly complicated year from a reserve standpoint. We did transition to a more Permian-heavy program from last year where it was dominated by the Eagle Ford. And generally what we try and do there is get consistent with our projected budget activity going forward. So that resulted in taking some Eagle Ford out and essentially replacing that with Permian. In terms of performance revisions, we have a wide range of things that happened there, year-end '17 to year-end '18. We've talked quite a bit about parent-child impacts and that did translate into the reserve report, in terms of reserve revisions and we've had some type curve revisions, a lot of what I would characterize as just normal performance revisions, and then some mechanical issues and changes in lateral length.
Kashy Harrison -- Simmons Energy -- Analyst
And were those performance revisions more levered to either the Eagle Ford or the Delaware or were they just kind of a mix of both?
Andy Agosto -- Vice President of Business Development
They were more levered to the Eagle Ford.
Kashy Harrison -- Simmons Energy -- Analyst
Okay, got you. And then the second one for me, maybe a question for Jeff. What's the anticipated field level operating cash flow for the Eagle Ford and the Delaware at -- just pick your price factor in 2019. Just trying to get a sense of field level cash flow prior to G&A.
Jeffrey Hayden -- Vice President of Investor Relations
Yeah, I'm looking up something here for you Kashy, see what I can give you.
Brad Fisher -- Chief Operating Officer and Vice President
Jeff's looking. He just didn't have what exactly what you wanted.
Jeffrey Hayden -- Vice President of Investor Relations
Hey, Kashy, let me -- I mean, let me get offline with you there as far as that. I mean, we typically don't talk about field level cash flow estimates. So I'm going to hold off on providing those specific numbers, but I can walk you through how to think about the various guidance numbers that we put out there and how you can kind of get to your own number based on the public guidance we have available.
Kashy Harrison -- Simmons Energy -- Analyst
All right. Works for me. Thanks.
Operator
And we appear to have no further questions queued up over the phone lines at this time.
Sylvester Johnson -- President and Chief Executive Officer
All right. Well, thank you, moderator, and thank you all for calling in. It was a good wrap up to a very good year for us. We have a lot of catalysts going forward, and we hope people will be paying attention to. Results of the mega pads and the Eagle Ford are going to be significant. I think that will make a big difference in how we produce and drill going forward. It's obviously going to have a big impact on our production in the second quarter.
The hybrid frac design we think is going to be a game changer for us in terms of the parent child relationship problems that we're seeing more and more of, so those results would be impactful. In the Permian, the cube is the thing we're most focused on right now in trying to prove up whether we can get these four layers from the top of the A to the top of the C and get the spacing right between the layers and do better than what industry has done with parent-child problems in the Permian. And then we also want to keep testing the Wolfcamp C in the Bone Springs, which could add markedly to our inventory in the Permian.
So thank you again for calling in.
Operator
Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines.
Duration: 54 minutes
Call participants:
Jeffrey Hayden -- Vice President of Investor Relations
Sylvester Johnson -- President and Chief Executive Officer
David Pitts -- Vice President and Chief Financial Officer
Neal Dingmann -- SunTrust Robinson Humphries -- Analyst
Brad Fisher -- Chief Operating Officer and Vice President
Brad Heffern -- RBC Capital Markets -- Analyst
Andy Agosto -- Vice President of Business Development
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Michael Scialla -- Stifel Nicolaus -- Analyst
Jim Pritts -- Vice President, Technology and New Business Development
Noel Parks -- Coker Palmer Institutional -- Analyst
Ron Mills -- Johnson Rice & Company -- Analyst
Eli Kantor -- IFS Securities -- Analyst
Marshall Carver -- Heikkinen Energy Advisors -- Analyst
Kashy Harrison -- Simmons Energy -- Analyst
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