Q3 2019 Earnings Call
Good morning, and welcome to the Cowen Petroleum Company third quarter, 2019 earnings and operating results Conference call.
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I would now let's turn the conference over to Mark <unk> Director of Investor Relations. Please go ahead.
Thank you operator, good morning, everyone and thank you for taking the time to join our conference call today.
With me. This morning are Joe Gatto, President and Chief Executive Officer, Dr. jump Palmer, our Chief operating Officer, Jim Walmart Chief Financial Officer during our prepared remarks will be referencing the earning results presentation, we posted yesterday afternoon to our website.
Kurt you're going 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 Dot Cowen Dot com.
Before we begin I'd like to remind everyone to review our cautionary statements disclaimers important disclosure is included on slide two and three of today's presentation. We will make some forward looking statements during today's call. The refer to estimate some plans as well as referenced our previously announced acquisition of curries oil and gas Inc. actual results could differ materially due to factors noted on.
These slides 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. Bernie 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 way.
Website, we incorporate those by reference for today's call.
Following our prepared remarks, we will open the call for QNX.
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 would create though is the right strategic move per gallon.
We will differ answering questions relating to the status of the transaction at this time.
We are engaging extensively with our shareholders ahead of the special meeting vote on the merger with creeps up and we look forward to having the opportunity to discussion issues in greater depth and address any questions during those conversations.
With that we'd like to turn call over to Joe got it.
Thanks, Mark and we appreciate everyone joining us today [laughter] yesterday afternoon, we released our third quarter results, which demonstrated the strength of our operations and progression towards highly efficient scaled development is producing tangible improvements in capital efficiency.
We see unique opportunity to make additional gains in capital efficiency with our pending acquisition of credo, which will accelerate our timeline for sustainable free cash flow improve returns on capital and further our efforts to strengthen cowens financial position.
We are excited hit the ground running on our integrated development plan and reap the benefits from a strategic combination of two talented teams and high quality asset basis.
I'll start on page four by visiting our introductory slide from our February outlook earlier. This year entering 2019 or message was clear to investors. This year and focus on harvesting asset value through increased pad development in cycle time reductions, we would seek to optimize margins increased our operational flexibility.
Through thoughtful capital allocation, we would minimize outspend in moderate growth.
And from the 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 and 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, well operating within reduced budget relative 2018 has driven a 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 I've 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 the redemption of high cost preferred stock, reducing our cost of capital and simplifying our capital structure.
We firmly believe that the strategic combination of Cowen Accredo will meaningfully increase the impact of these initiatives through an increase critical mass of development activity and infrastructure in the Delaware Basin.
Operating a corporate cost reductions expanded set of asset optimization and rationalization opportunities.
And some will be a stronger company with an advantage cost to supply to improve our competitive position as the unconventional oil and gas business matures.
We have honored our promises and delivered exceptional performance as a result.
As we look forward to 2020, the opportunities for shareholder value creation, our expanded greatly as we continue to execute our strategy across a larger asset base.
Block the benefits of thoughtful scaled operations.
I'll, let Jeff start us off with the operational update for the third quarter Jeff.
Thanks, Joe.
Execution during the third quarter continued to exceed expectations with our capital efficiency benefiting from two significant large pad development.
One each in the Delaware and Midland basins.
We saw 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 can 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 six we can take a closer look at the initial results of these larger pad development and demonstrate how they've shown very positive early performance.
Through the first 90 days or production the Rag, Ron Mega pad wells have averaged roughly 1000 barrels 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.
This is something we expect to employ more broadly with future concepts of this size in the Delaware, We believe that while it's slightly reduces the peak IP rates better manages pressures and results in better productivity for the wells from about six months through the end of the life of the well.
In the Midland Basin, we recently placed on production of seven well pad and the fairway asset area in Central Howard County.
The project included three lower Spraberry wells and for 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 the 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 to a more optimal development methodology that drives the 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, an increased completion stages per day, both of which saves significant capital dollars.
The less visible benefit to shareholders as the preservation of future drilling locations and improved 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 slots.
Thanks, Jeff.
Slide seven 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 the we have diversified our crude oil pricing through marketing and transport agreements that provide us the opportunity to better control physical movements and improved realizations in an increasingly complex oil market. We will continue to have.
Valuate opportunities like these across the entire commodity portfolio.
Page on slide eight 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 or excuse me our cash return on invested capital number to begin generating free cash flow three reduce our leverage and for focus on long term sustainable returns.
Each of these critical points as well supported by our strategic acquisition of Korea, though 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 monetizations, along with accelerating absolute debt reduction, while still retaining the scale necessary to receive the credit market benefits and lower our overall costs to cap.
Capital for the company, we feel strongly that these benefits are what can make cowen a highly differentiated investment option amongst the current peer companies.
Turning to slide nine 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 improved well results.
And create value for shareholders.
With this particular transaction, we're already starting off with high quality assets in the Eagle Ford in 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 seim us 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 prior operator, we've already seen an uptick in well productivity as exhibited on the upper.
All right hand graph.
But more importantly, we've 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 point Im going to turn the call back over to Joe.
Thanks, Jim and our previous presentations regarding Accredo acquisition, we outline many of the statistics on page 10, but I wanted to take the opportunity to reiterate just how differentiated 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 in 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.
Sustain 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 calendar is a commodity producer.
Our corporate breakeven is reduced from $55 on a standalone basis to $50 in 2020 with for further improvement into 2021 as our development model matures.
Put simply this will provide investors 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 our competitive with other industries.
I've talked to several benefits of our pending transaction I wanted to summarize how these are manifest in terms of real dollars and ultimately improve free cash flow generation.
We've clearly identified 100 $230 million of annual run rate cash synergies from two primary buckets cash DNA, which accounts for approximately one third of that total amount.
And efficiencies generated from increased large project development was simultaneous operations in the Permian basin, which can be comprised the balance.
The cash DNA synergies alone represent over 25% of our current equity value, providing a solid base for immediate per share accretion.
On top of that we've demonstrated capital we have demonstrated capital efficiencies from larger projects sizes combined with reduced cycle times, starting with our dealer program in 2020 and expanding to the broader Permian overtime.
This is an incremental $400 million of MTV does not dependent on improvements in well productivity or the ability to lengthen laterals on the combined footprint.
These opportunities are real as we have proven and 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 company's possess and the combined Delaware business, we're locking incremental value from an expanded capital program that reaches the critical mass to run multiple rigs in frac crews honest.
Sustained repeatable basis.
After similar projects in the Midland Basin over the last several quarters.
We demonstrate the DNC capital savings component in our recent rag around project in the Delaware Basin that develop six wells using two frac crews and simultaneous operation.
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 has 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.
Q2, 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 carries on more than doubles, our proved reserves and production base and provides a tremendous amount of operational flexibility on a footprint of 200000 net acres and two premier shale plays.
On slide 13, we've highlighted the elements of our resulting financial strength.
The clear advantages of being a larger stronger entity have already been recognized by the credit agencies and their recent comments. We've also provided some comparative credit statistics in the appendix the illustrate the improvements in our credit profile.
We're combining entities with similar leverage metrics as we stand here today and clearing a path for meaningful pro forma improvement on that front through absolute debt reduction driven by a dramatically improved free cash flow profile.
With this improved credit outlook, we will have the ability to improve our cost of capital through opportune net opportunistic refinancings.
As we've already announced we're 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 acquirer of top tier acreage positions to a capital efficient operator, they can effectively turned 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.
We've also been clear over the last two years that consolidation was coming and we're going to evaluate our options for our position of strength to maximize shareholder value.
Our board management team firmly believes that our pending acquisition advances all of our stated objectives and positions count as a stronger company for the future.
We also believe that shareholders recognize the decrease of 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 challenging 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 turn call back over to Mark here briefly.
Thanks, Joe.
At this time, we're going to go ahead and move forward with Q in a and open the line for questions. Please remember that the topic for this call's companies current quarterly results and as such will add it all questions. On this call will be directed gallons current and previous quarterly financial operational operational performance. Thank you operator would you. Please open the lines acuity.
We will now begin the question and answer session.
To ask a question you May Press Star then one on your Touchtone phone.
If you are using a speakerphone. Please pick up your handset before pressing the keys to withdraw your question. Please press Star then two.
Please limit your questions to one with a single follow up at this time, we will pause momentarily to assemble a roster.
The first question comes from Neal Dingmann with Suntrust. Please go ahead.
Only on good color.
Joe just looking at slide six, particularly the bottom right there that shows the Midland large pad outperformance.
Given the continued outperformance you're seeing I see that Wolfcamp seven.
Well pad as well as the five.
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 are targeting there.
Your next I'll, let Jeff start off on that yes, one of the nice things about that is that was a multi zone pads. 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 handed the section each.
Bucket of those the three in the four had an existing well.
Drilled back in 2015, if memory serves me correctly.
And and those.
Parent wells are in though the primary zone of the Wolfcamp a so we offset two wells off of the 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.
For 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 thats 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 situation, where we wanted you stack development in an area that has existing parent wells.
Great details on just one last follow up can you just talk what you're thinking sort of.
Early next year for just further cost reductions particular, I'm curious on Ela, we as you get more into development mode. Thank you.
Sure.
We that 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's 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 that chemical program with.
Getting improvements on.
SP runtime, so our submersible pumps the longer that they're in the wells in 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 workover and pull the tubing.
We performed items on power reliability with the two substation. So we put in play one in the.
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.
We continue to see opportunities, while I'm still very proud of what we've accomplished so far this year.
Great detail. Thanks again.
Thank you.
The next question is from Gabe Daoud with Cowen. Please go ahead.
Hey, good morning, everyone.
Starting with.
The rig cadence on Oaktown legacy footprint, you referenced today, and I think for 20 or anticipating picking up a couple of could you maybe just talk about.
Timing on those rig additions and then.
Depending on when you add them and just became today, if thats enough to grow volumes sequentially and once you 20.
Yes, we've provided some guidance gave around our combined 2020 profile that you know it's still stands out there.
In terms of target 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 will be putting in place.
We ended this year, so it's not really an apples to apples discussion.
Okay got it Joe Thanks.
And then just a follow up I guess is back to the Howard County.
To call development project can you just remind us of both the seven in the five all projects are space at 10 wells per section in the a and then overall, how you think about spacing and 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 kind of start with 660 and tend to be a little bit wider than that going forward, especially when you have.
In existing parent well.
We 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.
Situation, where you have parent wells in place and.
And you're trying to optimize the development program.
That's that's probably a little tighter than you would want to go on.
But a lot of it depends on the density of the well system that you're putting in so every well matters. If youre in a stack development program you want to be thoughtful about that.
But if you have great geology in a really only targeting one zone.
Doing it all at first in a in a kind of Virgin rock.
To maximize the recovery in the value of the wells, you would contemplate going a little bit tighter.
Got it thanks, Jeff Thanks, everyone.
Thank you thanks.
The next question is from Derrick Whitfield with Stifel. Please go ahead.
Hi, good morning on congrats on a strong ops update.
Thanks, Eric Thank you.
Perhaps for Jeff from a bigger picture perspective, I know you have experienced with large scale development based on your time at Cana.
Recall correctly, the red runoff represents one of the first set of Cowen wells with controlled flowback.
Do you have a view on the potential.
Uplift associated with control flip back in general and separately is this the concept that would apply in the Midland Basin.
Yes, good that's a great question that I do believe that Theres, a lot of things that roll into the that you are.
The question in there.
Generally speaking what our data would suggest as you get a crossover at about six months. So the the slower back or more conservative choke methodology, well while by the way. It also decrease the.
Erosional degradation of sand cutting through your facilities, so theres some.
Operating expense and facilities maintenance benefits from a slightly more conservative joke methodology.
It does provide an opportunity for greater you are.
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 your water effects have a little bit more.
Have a have 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 whether they are definitely could be some benefits with.
In 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 Stanley few Jeff for my follow up referencing slide nine.
Could you comment on the design tweaks that have led to your 10% improvement overall performance versus the previous operator.
I am just catching up with the that the.
There is that Theres, a number of things to think about it.
From a design change perspective, what we're trying to do is.
Is look at.
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 too.
The the design profile whether its.
Our stage length.
The number of perf clusters per stage the type of sand we're using.
The the volumes of how much.
Water, we're putting down on a barrels per minute standpoint.
All of that.
Using utilizing some data analytics and modeling we have a proprietary predictive model that's allowed us to have well performance. That's no amongst the best in the basin I don't want to share to many of the specific details of it because it kind of be giving away the farm a little bit.
But we do recognize that we've made some significant improvements within the overall design and outcomes or are pretty evident in what we've been able to do from a production standpoint.
Understood. It's very helpful. Thanks for your time.
Thank you Mr.
Again, if you have a question. Please press Star then one.
The next question is from Brian Downey with Citigroup. Please go ahead.
Good morning, Thanks for taking my questions one for perhaps Jeff for Joe looking back at slide five clearly impressive reductions on well costs per foot as you transition a larger pads Im just wondering how should we think about further runway and into 2020 on the well costs, whether that's on well design inefficiency or maybe if there's anything to capture on the on the service.
Pricing side.
Yes, both of those are opportunities I think.
When you look at the the specific well cost components of it where we are really Atlas and our efficiency.
Our quest for efficiencies, whether thats from drilling the perfect well to making our crews more efficient on the completion side.
As you've seen and we had mentioned in highlighted a Midland basin system, where we had record setting performance on the number of stages per day and part of that is processes part of that is consistent crews, which is again a benefit of having a larger operation with the Callon inquiry. So.
Merger gives us the opportunity to have both of those.
But there's also some some opportunity from.
On the side of.
Working with people, who you get when when situations with from a contractual standpoint, where if were 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 2021.
So we put out some directional.
Guidance on that on a combined basis that was relatively flat Capex guide, adding together, our 2019 programs there that it doesn't reflect.
Any.
Deflation in the market does not reflect continued improvement that Jeff had said.
It does reflect obviously structural change in our development that we benefit from from a capital efficiency standpoint, but they're they're going to be more opportunities for us to to drive down.
Cost here as we move forward, we've shown it and this quarter inquiries those announcement last night as you've seen the they highlighted that as well. So you take a lot of momentum from the combined companies put them together you have best practices of an overlay a larger development model to even get incremental.
Savings, it's pretty powerful and that's excluding any of the.
Potential deflation.
Got it that's helpful. And then my follow up you touched on on the spacing on a 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 a in the Delaware is it still A's and B's for now or anything else you plan on adding to that SEC.
Yes, that's the primary bread and butter, that's exactly right.
Okay Thats helpful et cetera.
Thanks.
The next question is from World Thompson with Barclays. Please go ahead.
Hey, good morning, Joe or Jeff as has been noted Regwan DNC efficiencies are ahead of pro forma expectations. Despite this being your first Delaware Megapath today.
What specifically drove the outperformance how repeatable is that and how much of the benefit came from cost deflation, which has been a consistent theme. So far this earning season.
Sure the cost deflation really wasn't a large component of it.
Anytime that we can do the same thing for for a better deal. We're sure. We're certainly going to take advantage of it but really the the well performance on the larger this the larger pads and this one specific it was it was a combination of having the repeatable cruise applying learnings both from the drilling and completion side, making does.
Zine changes to the completion crews to make them more efficient working process improvements. So the physical movement of our operations on location, we're well coordinated with consistent crews and and once you get running in that.
That said.
And just builds on on the day before everybody wants to do a little bit better and.
And really the group got into a wonderful groove regarding that as I mentioned, we did some modest design changes. So we modified some of the interior wells and and reflection of.
The value of decreasing some of the initial capital investments bottles, while still maintaining a very robust production profile.
And if you added that all together what it created was a terrific outcome on the cost side.
And you know outside of just the DNC cost per foot, we pick up the benefits of cycle times right to do a six well pad with with one frac crews a water cash conversion cycle, so thats a benefit outside of the.
Incremental capex, you can pick up but certainly the cycle times and that impact on returns and that will you've highlighted on page 12 also in terms of the production profile deploying more of the Megapath concept is going to reduce or eliminate.
The amount of children that you have to come back and Frac and not good parent wells off line.
Thats helpful color. Thank you and then it was mentioned the redemption, the Cowen preferred stock reducing cost of capital and plans for opportunistic refinancing.
To remind me did it fair to assume that the priority would be to redeem creases preferred shares how would that you would you look to use the the revolver to refinance those to any color there would be helpful. Thank you.
Sure I.
I think we've said from the beginning at the current intention is a voting agreement.
And that.
To the extent of were unable to get a voting agreement, we have plenty of capacity underneath and newly completed RBL.
Theres, obviously cost of capital savings when you're using a little over 3% debt relative to.
The agent seven eight 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 and eight and a quarter.
Security, that's 250 million thats pretty logical place to to get further cost to capital benefits as well, but.
No no real update there beyond the remarks I just made.
Alright, thank you.
The next question is from done Mackintosh with Johnson Rice. Please go ahead.
Hey, good morning, Joe.
On slide nine you highlight.
Pretty strong improvement on the Ward County acquisition.
So wondering if you could are those co developed wells and kind of what's what's been a lot of the driver to that up with particularly on those assets targeting a bit more on the engineering standpoint, any color there would be good.
Yes. This is on on the top right hand side, yes, yes, yes, yes. It does some of those are standalone. Some of those are co developed.
Okay, and I think Jeff at address some of this a little earlier in terms of Theres been a lot of things that we've done differently, we've changed some completion designs.
Refine some some targeting.
The data set that is represented by the previous operator average I think is about nine wells.
Over four or five year so.
There was some tweaking going on.
We were in a position given that the learnings that we had stepping into the Delaware in 2017 overlay what we've been what we're learning because we were very focused on that area.
So out of the box, we're over able to overlay some learnings and then.
Enhance that with some completion design tweaks, we've done some sub surface modeling that helped with.
Some of the performance as well.
Hi, good that's it for me thank you.
This concludes our question and answer session at the conference has also now concluded. Thank you for attending today's presentation. You may now disconnect.
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