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Good morning, and welcome to the Callon Petroleum Company Third Quarter 2019 Earnings and Operating Results Conference Call. [Operator Instructions] Please note this event is being recorded.
I would now like to turn the conference over to Mark Brewer, Director of Investor Relations. Please go ahead.
Thank you, Operator. Good morning and thank you for taking the time to join our conference call today. With me this morning are Joe Gatto, our President and Chief Executive Officer; Dr. Jeff Balmer, our Chief Operating Officer; and Jim Ulm, our Chief Financial Officer.
During our prepared remarks, we'd be referencing the earnings results presentation we posted yesterday afternoon to our website, so I encourage everyone to download the presentation if you haven't already. You can find the slides on our Events and Presentations page located within the Investors section of our website at www.callon.com.
Before we begin, I'd like to remind everyone to review our cautionary statements, disclaimers and important disclosures included on Slide 2 and 3 of today's presentation. We will make some forward-looking statements during today's call that refer to estimates and plans as well as reference our previously announced acquisition of Carrizo Oil & Gas, Inc. Actual results could differ materially due to the factors noted on these slides and in our periodic SEC filings.
We will also refer to some non-GAAP financial measures today, which we believe help to facilitate comparisons across periods and with our peers. For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the Appendix to the presentation slides and in our earnings press release, both of which are available on our website. We incorporate those by reference for today's call.
Following our prepared remarks, we will open the call for Q&A. Please note that the topic for this call is our quarterly results. So we appreciate directing any questions on this call to the company's current and previous quarterly results and operational performance. We continue to firmly believe the announced merger with Carrizo is the right strategic move for Callon. But we will defer answering questions relating to the status of the transaction at this time. We're engaging extensively with our shareholders ahead of the special meeting vote on the merger with Carrizo and we look forward to having the opportunity to discuss issues in greater depth and address any questions during those conversations.
With that, I would like to turn the call over to Joe Gatto.
Thanks Mark. And we appreciate everyone joining us today.
Yesterday afternoon we released our third quarter results which demonstrated the strength of our operations and progression towards highly efficient scale development that is producing tangible improvements and capital efficiency. We see a unique opportunity to make additional gains and capital efficiency with our pending acquisition of Carrizo which will accelerate our timeline for sustainable free cash flow, improved returns on capital, and further our efforts to strengthen Callon financial position. We are excited to hit the ground running on our integrated development plan and reap the benefits from the strategic combination of two talented teams and high quality asset basis.
I will start on Page 4 by visiting our introductory slide from our February outlook earlier this year. Entering 2019 our message was clear to investors. This year we would focus on harvesting asset value through increased pad development and cycle time reductions. We would seek to optimize margins and increase our operational flexibility.
Through thoughtful capital allocation, we would minimize outspend and moderate growth. And from a longer term perspective, we would seek to balance the preservation of longer term reinvestment opportunities with our near term return profile.
This approach would advance our goal to generate sustainable free cash flow from a model driven by leading capital efficiency coupled with differentiated cash margins and resilient growth profile supported by strong well productivity in a maturing decline profile.
As we look back at our activity and accomplishments during 2019, we have stuck exactly to that roadmap. Our shift to scale program development, while operating within reduce budget relative to 2018 has driven record levels of capital efficiency across the portfolio as we've expanded our deployment of larger projects from the Midland basin to the Delaware basin earlier this year.
Our margins remain among the strongest in the industry and have been furthered by our success in reducing costs on acquired properties in the Delaware basin and leveraging the infrastructure investments we've made in earlier years. In addition, the optimization of the portfolio through the sale of almost $300 million in assets year-to-date allowed for redemption of high cost preferred stock, reducing our cost of capital and simplifying our capital structure.
We firmly believe that the strategic combination of Callon and Carrizo will meaningfully increase the impact of these initiatives to an increased critical mass of development activity and infrastructure in the Delaware basin, operating and corporate cost reductions and expanded set of acid optimization and rationalization opportunities.
In sum, we will be a stronger company with an advantage cost of supply to improve our competitive position as the unconventional oil and gas business matures. We've honored our promises and delivered exceptional performance as a result.
As we look forward to 2020, the opportunities for shareholder value creation are expanded greatly as we continue to execute our strategy across a larger asset base and unlock the benefits of a thoughtful scaled operations.
I'm going to let Jeff start us off with the operational update for the third quarter. Jeff?
Thanks Joe.
Execution during the third quarter continue to exceed expectations with our capital efficiency benefiting from two significant large pad developments while on each of the Delaware and Midland basins. We saw a lower operating costs as the optimization project that we kicked off in the first quarter of this year was completed during the early portion of the third quarter.
We also saw additional benefits from the increased utilization of our recycling facilities and changes to our chemical treatment programs. Alongside these operational accomplishments, we continue to grow production per share and lower our lease operating expense per share versus the same period of 2018, while maintaining robust operating margins. At the bottom of this slide, you can see that cost reduction efforts in both the Delaware and Midland basins benefited significantly from the execution of larger pad development projects.
Flipping to Slide 6, we can take a closer look at the initial results of these larger pad developments and demonstrate how they've shown very positive early performance. Through the first 90 days or production, the Rag Run mega pad wells have averaged roughly 1000 barrels of oil per day equivalent with approximately an 80% oil cut.
We utilized a slightly more conservative choke methodology with this pad, which you can see in the upper right hand chart and this is something we expect to employ more broadly with future concepts of this size in the Delaware we believe that while it slightly reduces the peak IP rates, it better manages pressures and results in better productivity for the well of about six months through the end of the life of the well.
In the Midland basin, we recently placed on production a seven well pad in the Fairway asset area in Central Howard County. The project included three lower Spraberry wells, and four Wolfcamp A wells from two pads. These wells directly offset historical producers in the immediate vicinity and we're very pleased to say that they're tracking right alongside their previous vintage wells.
It's important to understand that much of what we've been able to accomplish this year has come from the transition through a more optimal development methodology that drives benefits from greater scale and continuous deployment of drilling and completion teams to more concentrated projects.
The efficiency gains have resulted in faster drilling cycle times and increased completion stages per day both of which save significant capital dollars. The less visible benefit to shareholders is the preservation of future drilling locations and approved project level returns as a result of optimal development timing, well design, and leveraging of our infrastructure investments that we've done for the past few years.
At this point in time, I'd like to hand over the call to Jim for the next few slides.
Thanks Jeff.
Slide 7 provides a quick overview of the current and future financial benefits our shareholders enjoy as a result of our focus on creating leading margins, which are on display in the bottom portion of this slide. Our methodical approach to hedging which we have consistently employed over time has allowed us to secure the great majority of our current oil production volumes in 2020 at very attractive prices with additional protection for our limited gas volumes as well.
With recent spikes in the commodity, we were able to act quickly and add some attractive positions in the fourth quarter of this year as well, which should come in handy given some of the market volatility as of late.
You can see in the table in the upper right portion of the slide that we have diversified our crude oil pricing through marketing and transport agreements that provide us the opportunity to better control physical movements and improve realizations in an increasingly complex oil market. We will continue to evaluate opportunities like these across the entire commodity portfolio.
Page on Slide 8, I think it's important to revisit the strategic financial objectives that we laid out for the market earlier this year. There were four key areas that we felt would advance value for shareholders as we saw progress in each relative area and those were fairly straightforward.
Number one, increase our cash flow return - excuse me, our cash return on invested capital. Number two, begin generating free cash flow. Three, reduce our leverage; and four, focus on long term sustainable returns. Each of these critical points is well supported by our strategic acquisition of Carrizo and ultimately results in a more investable, credit worthy and robust economic vehicle for shareholders of both companies.
We will benefit from the stronger field level economics available from a more capital efficient development plan from shedding non-core assets and unlocking additional value through other monetization along with accelerating absolute debt reduction, while still retaining the scale necessary to receive the credit market benefits, and lower our overall cost to capital for the company. We feel strongly that these benefits are what can make Callon a highly differentiated investment option amongst the current peer companies.
Turning to Slide 9, there's good reason to believe that our team can execute this strategy and create those financial outcomes. We have exhibited a history of acquiring assets and employing our operational expertise to reduce costs, improve well results, and create value for shareholders. With this particular transaction, we are already starting off with high quality assets in the Eagle Ford and Delaware, which is part of a broader program that will benefit from increased scale and can be optimized within a capital allocation program that utilizes timeouts consistently throughout the Delaware.
Data sharing and employing best practices will only further enhance well results, something that we have seen in the positive impact we have made on the acreage acquired in May of last year from a prior operator. We have already seen an uptick in well productivity as exhibited on the upper right hand graph but more importantly, we have utilized our field level practices and high quality infrastructure investments to drive down operating costs resulting in much improved EBITDAX margins versus the prior operator.
At this time, I'm going to turn the call back over to Joe.
Thanks Jim.
In our previous presentations regarding the Carrizo acquisition, we outlined many of the statistics on Page 10. But I wanted to take the opportunity to reiterate just how differentiate our future is after the combination of these two companies.
The doubling of the core Delaware footprint and combined total Permian inventory of high quality locations that are well suited for our mega pad development model, provide an enviable runway of opportunity for any Permian operator. We will also more than double our production base while preserving a high oil content and a leading cash margin profile.
In addition to supporting immediate free cash flow generation in 2020, this cash flow base will enable us to overlay large scale development in a more meaningful way, especially in the Delaware basin, and benefit from the undeniable capital efficiencies that accompany repeated activities and economies of scale and manufacturing mode.
Sustained scale development will build upon itself over time and lead to a steadily improving free cash flow profile, driving a step change in our ability to drive shareholder value from near term leverage reduction, and other opportunities for capital returns in the future. And looking at the aggregation of these metrics and what it means for Callon as a commodity producer, our corporate breakeven is reduced from $55 on a standalone basis to $50 in 2020, with further improvement into 2021 as our development model matures.
To put it simply, this will provide investor greater clarity regarding corporate durability through commodity market fluctuations. The structural shift also enhances what's truly important to our shareholders, that being returns on capital that are competitive with our industries.
I've talked to several benefits of our pending transaction and wanted to summarize how these are manifest in terms of real dollars and ultimately improved free cash flow generation. We've clearly identified $100 million to $130 million of annual run rate cash synergies from two primary buckets, cash G&A, which accounts for approximately one-third of that total amount, and the efficiencies generated from increased large project development with simultaneous operations in the Permian Basin, which comprise the balance.
The cash G&A synergies alone represent over 25% of our current equity value, providing a solid base for immediate per share accretion. On top of that, we have demonstrated capital efficiencies from larger projects sizes combined with reduced cycle times, starting with our Delaware program in 2020 and expanding to the broader Permian over time. This is an incremental $400 million of MPV does not dependent on improvements and well productivity or the ability to lengthened laterals on the combined footprint.
These opportunities are real as we have proven in prior acquisitions as our benefits from shared water infrastructure and refinancing savings but these aren't captured in our primary synergy buckets and provide upside to our estimates.
Slide 12 breaks out the operational synergies in more detail. The key takeaways here are clear. Our base level synergies are not about direct acreage overlap. While you do need contiguous footprints to overlay scale development and leverage centralized infrastructure which both of our companies possess and the combined Delaware business, we're unlocking incremental value from an expanded capital program that reaches the critical mass to run multiple rigs and frac crews on a sustained repeatable basis.
After similar projects in the Midland Basin over the last several quarters, we demonstrated the D&C capital savings component in our recent Rag Run project in the Delaware basin that developed six wells using two frac crews and simultaneous operation, a decrease of over 15% per lateral foot from where we started the year. This is relative to the 5% to 8% level we needed to hit our target operational synergies for this bucket of savings.
Another key benefit is reduced production downtime. With more wells drilled as parents and larger project sizes, future production disruptions from offsetting children frac operations are eliminated and revenue isn't deferred. Key to our future and that of our industry is developing organizations that have the operational flexibility and financial strength to manage commodity price volatility and generate consistent results over time.
Our pending combination with Carrizo more than doubles our proved reserves and production base and provide a tremendous amount of operational flexibility on a footprint of 200,000 net acres and two premier shale plays.
On Slide 13, we’ve highlighted the elements of our resulting financial strength. The clear advantage of being a larger, strong entity have already been recognized by the credit agencies in their recent comments. We’ve also provided some competitive credit statistics in the appendix that illustrate the improvements in our credit profile. We have combining entities with similar leverage metrics as we stand here today and clearing a path from meaningful pro forma improvement on that front through absolute debt reduction driven by dramatically improved free cash flow profile.
With this improved credit outlook, we will have the ability to improve our cost of capital through opportunistic refinancings. As we've already announced, we are also progressing asset monetization opportunities from multiple sources that will create additional near term debt reduction opportunities and further advance our leverage target below two times.
I'll finish up by turning to Slide 14. To summarize, we've continued to execute the plan we provided to investors at the outset of the year. Callon has evolved over the past few years from a prudent a crier of top tier acreage positions to a capital efficient operator that can effectively turn those top tier assets into cash flow and corporate level returns.
We understand that to compete with other investible opportunities both within and outside our sector, we must create durable returns that exceed our cost of capital. To that end, we have taken action to optimize our capital structure, protect our cash flows from commodity fluctuations and continue to proactively align our executive compensation programs with investor focus areas as our company matures.
We have been clear in our strategy and our focus as evidenced by several examples on this page. They've also been clear over the last two years the consolidation was coming and we are going to evaluate our options from a position of strength to maximize shareholder value.
Our board and management team firmly believes that our pending acquisition advances all of our stated objectives and positions Callon as a stronger company for the future. We also believe that shareholders recognize that the Carrizo transaction represents a unique opportunity to unlock additional value from our Permian asset base and improve our all-in cost of supply as a commodity producer.
Despite a challenge equity market sentiment, this cast a negative shadow on our industry, we ask all of you and our shareholders to acknowledge the compelling strategic logic of this transaction and vote your support in the coming days.
That's going to conclude our prepared remarks. I'm going to turn the call back over to Mark here briefly.
Thanks Joe.
At this time we're going to go ahead and move forward with Q&A and open the line for questions. Please remember that the topic for this call is the company's current quarterly results and as such we'll ask that all questions on this call be directed, counts, current and previous, quarterly financial and operational performance.
Thank you. Operator, would you please open the line for Q&A.
[Operator Instructions] The first question comes from Neal Dingmann with SunTrust. Please go ahead.
Joe, just looking at that Slide 6, particularly the bottom right, there it shows the middle and large pad outperformance. You know, given the continued outperformance you're seeing, I see that Wolfcamp 7, well pad as well as the 5. You know, really what's interesting is that the outperformance versus the parent child offset. Could you talk about maybe multi-zone pads and kind of what size pads you're targeting there?
Actually, I'll let Jeff start off on that.
Yes. The point of the nice things about that is that was a multi-zone pad. So, there was a three-well development kind of on the left hand side of the section with a four-well development on the right hand of the section, each bucket of those, the three and the four had an existing well drilled back in 2015 if memory serves me correctly.
And those parent wells are in though the primary zone of the Wolfcamp A. So we offset two Wells off of that primary zone and then also went above it to the lower Spraberry. And so you see a multi-zone stack development program that's more efficient. It eliminates the use or the creation of future child wells.
We did do a little bit of a different completion design on them, where the interior wells were a little softer in their design, a little bit less water, so we would negatively affect the existing parent well and then kind of got after the wells on the outside.
So that's a good example of a thoughtful application of design changes. And acknowledging that some depletion would have occurred on the existing Wells and it's a modest blueprint for what we plan on doing going forward. Anytime that we do have a situation where we want to do stack development in an area that has existing parent wells.
Great details. Then just one last follow up, can you just talk, what you're thinking sort of early next year for just further cost reductions particularly I'm curious on LOE as you get more in development mode. Thank you.
Sure. The main thing that we're trying to do is just maintain focus. I really do like the progress that the team has made throughout 2019. There is a whole number of things that have contributed to our performance and I think these are - without going into specific detail on any of them, the things that we’ve done very well, we can continue to do better.
So whether it is - we mentioned the chemical program with getting improvements on the ASP run time submersible pumps, the longer that they are in the wells and the better that they perform, the lower the cost is from having to go in and pull those.
We've had pure workovers on our historic vertical wells, which are tend to be the lower producers, but are still reasonably costly to go in and work over and pull the tubing. We performed items on power reliability with the two substations that we put in play. One in the Delaware basin and then one in Howard County that gives us repeatable cheap power especially when there's fluctuations due to weather or from the overall service company that's providing that.
So those are the focus areas for us going forward to continue to hit the high ticket items. And we continue to see opportunities while I'm still very proud of what we've accomplished so far this year.
The next question is from Gabe Daoud with Cowen. Please go ahead.
I guess starting with the rig cadence on count legacy footprint. You're at four rigs today and I think for '20 you’re anticipating picking up a couple of - could you maybe just talk about a timing on those rig additions and if you know, depending on when you add them and just the cadence today, if that's enough to grow volumes sequentially in 1Q 2020.
Yes. We've provided some guidance Gabe around our combined 2020 profile that is still stands out there in terms of targeted production growth over the next couple of years, what that means for free cash flow. So while we had previously provided some guidance around Callon on a standalone basis early in the year, we obviously have an integrated plan that we'll be putting in place towards the end of this year. So it's not really an apples-to-apples discussion.
And then just to follow up, I guess it's back to the Howard County, two coal development projects. Can you just remind us of both the seven and the five well projects are spaced at 10 wells per section in the A. And then overall how you think about spacing in Howard amongst the three zones, the Wolfcamp A, the B and the lower Spraberry?
Sure. The well spacing was a little tighter than 660 on these, but not in full development, which is a little unusual in that, in my mind you'd kind of start with 660 and tend to be a little bit wider than that going forward, especially when you have an existing parent well.
This is good rock and good geology and I think in rare instances you can close in and go a little bit tighter in certain circumstances. We took advantage of this, and I think you can see it in the early well results.
However, in normal practice, when you're in a situation where you have parent wells in place and you're trying to optimize the development program, that's probably a little tighter than you would want to go, but a lot of it depends on the density of the well system that you're putting in. So every well matters.
If you're in a stack development program, you'll want to be thoughtful about that, but if you have great geology and you're really only targeting one zone, and you're doing it all at first in a kind of Virgin rock to maximize the recovery and the value of the wells, you would contemplate going a little bit tighter.
The next question is from Derrick Whitfield with Stifel. Please go ahead.
Perhaps for Jeff, from a bigger picture perspective, I know you have experienced with large scale development based on your time at [indiscernible]. I recall correctly the rag runner represents one of the first set of Callon miles was controlled for that. Do you have a view on the potential EUR uplift associated with control flow back in general and separately is this a concept that would apply in the Midland basin?
Yes, good that's a great question - I do believe - there is a lot of things that roll into the EUR the question in there. Generally speaking, what our data would suggest is you get a crossover at about six months. So the slower back or more conservative choke methodology, while by the way, it also decreases the erosion of degradation of sand cutting through your facility. So there's some operating expense and facilities maintenance benefits from a slightly more conservative choke methodology.
It does provide an opportunity for greater EUR post kind of the six months, what that number is I don't have a clear vision of that it's fairly substantial the data would suggest as you go through time but I don't want to apply a percentage to it at this point in time. There are applications within the Midland basin, it tends to be lower pressure, and water effects have a little bit more of a strong effect on the preliminary flow back.
So within the Midland basin, for instance if you put a lot of water into the system, generally speaking, you're going to want to try to remove that a little more quickly than you would in the Delaware which already has a lot of water in it. So - there definitely could be some benefits within the Midland basin, it really depends on the fluid system that you're in. How much depletion and voyage has already occurred within that system from the existing parent wells, and then what your design is. If you put a lot of water into a system, you want to roughly speaking, remove it a little more quickly because it's a lower pressure system.
That makes sense and then staying with you Jeff, for my follow-up referencing Slide 9. Could you comment on the design tweaks that have led to your 10% improvement in well performance versus the previous operator?
I'm just catching up with you - there is a number of things to think about it. From a design change perspective what we're trying to do is, is look at the - what we think is going to give us the best well for the least amount of money and when we can go in and make changes to the design profile, whether it's our stage link, the number of perf clusters per stage, the type of sand we're using, the volumes of how much water we're putting down on our barrels per minute standpoint.
All of that utilizing some data analytics and modeling. We have a proprietary predictive model that's allowed us to have well performance that's, amongst the best in the basin. I don't want to share too many of the specific details of it because it kind of be given away the farm a little bit. But we do recognize that we've made some significant improvements within the overall design and the outcomes are pretty evident and what we've been able to do from a production standpoint.
[Operator Instructions] The next question is from Brian Downey with Citigroup. Please go ahead.
One for perhaps Jeff or Joe looking back at Slide 5 clearly impressive reductions in well cost per foot as you transition to larger pads. I'm just wondering how should we think about further runway into 2020 on the well cost, whether that's on well design and efficiency or maybe if there is anything to capture on the surface pressing side?
Yes, both of those are opportunities I think. When you look at the specific well cost components of it, we are relentless in our efficiency - our quest for efficiencies, whether that's from drilling the perfect well to making our crews more efficient on the completion side. As you've seen, we had mentioned and highlighted the Midland basin system where we had record setting performance on the number of stages per day.
And part of that is processors, part of that is consistent crews which is again a benefit of having a larger operation with the Callon increase. So, merger gives us the opportunity to have both of those. But there is also some opportunity from - on the side of working with people who you get win-win situations with from a contractual, standpoint where if we're more efficient and as a partnership we both, benefit from that.
So I think going forward we continue to look for opportunities to leverage both the physical operations and then contractual partnerships that we have with folks.
And if you think about 2020 and - actually we put out some directional guidance on that on a combined basis that was relatively a flat CapEx guide adding together our 2019 programs. So it doesn’t reflect any deflation in the market. It does not reflect continued improvement that Jeff had said.
It does reflect obviously a structural change in our development that we benefit from a capital efficiency standpoint, but there are going to be more opportunities for us to drive down costs here as we move forward. We've shown it in this quarter and Carrizo's announcement last night you should have seen that they highlighted that as well.
So you take a lot of momentum from the combined companies, put them together you have best practices. And then overlay a larger development model to even get incremental savings it's pretty powerful, and that's excluding any of the potential deflation.
And then as my follow up, you touched on the spacing on the larger pads, but just curious has anything changed on your go forward approach on co-development from a flow unit selection itself over time, particularly in the Delaware is it still A's and B's for now or anything else you plan on adding to that stack?
Yes, that's the primary bread and butter. That's exactly right.
The next question is from Will Thompson with Barclays. Please go ahead.
Joe or Jeff as it's been noted the Rag Run D&C efficiencies are head of pro forma expectations despite this being your first Delaware mega pad to-date. What specifically drove your performance, how repeatable is that and how much the benefit came from cost deflation, which has been a consistent theme so far this earning season?
So the cost deflation really wasn't a large component of it. Anytime that we can do the same thing for a better deal, we're certainly going to take advantage of it but really the well performance on the larger pads and this one specific, it was a combination of having a repeatable crews, applying learnigns both the joining and completion side, making design changes to the completion crews to make them more efficient working process improvements.
So the physical movement of our operations on location are well coordinated with consistent crews and once you get running in that setup, it just build on it. On the day before everybody wants to do a little bit better and, and really the group got in a wonderful groove regarding that.
As I mentioned, we did some modest design changes. So we modified some of the interior wells and reflection of the value of decreasing some of the initial capital investments while still maintaining a very robust production profile. And if you added that altogether, what it created was a terrific outcome on the cost side.
Outside just the D&C cost per foot and we pick up the benefits of cycle times right to do a six wheel pad with one frac crew as a water cash conversion cycle. So that's a benefit outside of the incremental CapEx you can pick up, but certainly the cycle times and that impact on returns and that what we have highlighted on Page 12 also in terms of the production profile, deploying more of the mega pad concept is going to reduce or eliminate the amount of children that you have to come back and frac and not good parent wells offline.
And then it was mentioned the redemption the counts preferred stock reducing cost of capital and plans for opportunistic refinancing. Remind me, is it fair to assume that the priority would be to redeem Carrizo preferred shares. Would you like to use the revolver [indiscernible] any color there will be helpful? Thank you.
Sure, I think we've said from the beginning that the current intention is a voting agreement. And that to the extent of we're unable to get a voting agreement we have plenty of capacity underneath, a newly completed RBL. There is obviously cost of capital savings when you're using a little over 3% debt relative to the [indiscernible] of the preferred. But, we've not changed our thinking in terms of where we stand on that right now.
Ultimately, I think that is one of the first places we would look. They also - we will have in the maturities deck in eight and a quarter, security that's $250 million that is pretty logical place to get further cost of capital benefits as well. But no real update there beyond the remarks I've just made.
The next question is from Dun McIntosh with Johnson Rice. Please go ahead.
On Slide 9, you highlighted about pretty strong improvement on the Howard County acquisition. I was wondering if you could - are those co-developed wells and kind of what's, been a lot of the driver to that up with particularly on those assets? Is it targeting, is it more on the engineering standpoint. Any color there would be good.
Yes. This is on the top right hand side.
Yes.
Yes Dun some of those are standalone. Some of those are co-developed.
Jeff we had addressed some of this a little earlier in terms of - there has been a lot of things that we've done differently. We have changed them completion designs, refined some targeting. The data set is represented by the previous operator average I think is about 9 wells, over 4 or 5 years.
So there was some tweaking going on. We were in a position given that the warnings we had stepping into the Delaware 2017 to overlay what we’ve been - what we were learning because we are very focused on that area. So out of the box we are over - able to overlay some learnings and then enhance that with some completion design tweaks. We've done some subsurface modeling that helped with some of the performance as well.
This concludes our question-and-answer session and the conference has also now concluded. Thank you for attending today's presentation. You may now disconnect.