Nov 5, 2015
Executives
Eric Williams - Manager of Finance Fred Callon - Chairman and Chief Executive Officer Gary Newberry - Senior Vice President of Operations Joseph Gatto - Senior Vice President, Chief Financial Officer and Treasurer
Analysts
Neil Wiese - SunTrust Jeb Bachman - Scotia Howard Weil Ron Mills - Johnson Rice Gabe Daoud - J.P. Morgan Ipsit Mohanty - GMP Securities Stephane Aka - Seaport Global Chris Stevens - KeyBanc Irene Haas - Wunderlich Will Green - Stephens Kyle Rhodes - RBC Jeff Grampp - Northland Capital Markets John White - Roth Capital Joel Musante - Euro Pacific Capital
Operator
Welcome to the Callon Petroleum Company's Third Quarter Financial and Operating Results Conference Call. All participants will be in listen-only mode.
As a reminder, this call is being recorded. A replay of the call will be archived on the company's website for approximately one year.
I would now like to turn the call over to Eric Williams, Manager of Finance for opening remarks. Please go ahead, sir.
Eric Williams
Good morning, and thank you for taking time to join our third quarter 2015 results conference call. With me this morning are Fred Callon, Chairman and Chief Executive Officer; Gary Newberry, Senior Vice President of Operations; and Joe Gatto, Senior Vice President, Chief Financial Officer and Treasurer.
During our prepared remarks we will 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 website at www.callon.com.
To locate the slides, simply click the PDF icon located on the Events & Presentations page for today's conference call or, alternatively, click on the Current Presentations link included at the bottom of any page on our website. Before we begin, I would like to remind everyone joining this call that our comments today include forward-looking statements.
A variety of factors could cause Callon's actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements. For a complete discussion of these risks, we encourage you to read our filings with the SEC including our Form 10-K available on our website or the SEC's website.
Today's call will also contain discussions of certain non-GAAP financial measures. Please refer to the earnings press release we issued yesterday afternoon for important disclosures regarding such measures and the corresponding reconciliations.
You can obtain a copy of our press release in the news section of our website. Following our prepared remarks we will open the call for Q&A.
And with that, I would like to turn the call over to Fred Callon and direct the audience to slide 3 of the earnings presentation I previously mentioned. Fred?
Fred Callon
Thank you, Eric and thanks to everyone for joining us this morning. Looking back to our last earnings call from August 6, a lot has change for the commodity markets and for Callon.
Oil prices continued to declines through August ending down over 30% from levels in early July. We've seen a bit of stability in the $45 range but I'm uncertainly still weighs on our sector.
On our last earnings call we laid out a plan to move the company to self-funding status by mid 2016 based on oil prices moving back into the mid-50s next year. While we may get there on prices we can't plan our business that way.
Our goal of cash flow neutrality is a key guidepost for our business and we need to be prepared for a sub $50 world for the foreseeable future. With that in mind, we made a decision in August to further optimize our drilling program and move both of our rigs to our Central Midland fields focusing almost exclusively on the Lower Spraberry.
Our 2016 plans include reducing capital expenditures to $110 million while generating average daily production in the range of 11,500 barrels of oil equivalent per day which is approximately 20% higher than our 2015 estimate. It is this type of capital efficiency that will enable us to stay on our path living within our means and strengthening our financial position for future growth opportunities in a lower for longer world.
During the third quarter, we continued to deliver results in line with our expectations despite the broader operational plan changes the team were making real time. Daily production grew to 9,739 barrels of oil equivalent per day, a 72% increase over the third quarter of last year while both LOE and G&A came in at the low end of guidance.
Importantly our EBITDA margin per BOE remain strong at 70% with improvements in cash cost and realized prices per barrel of oil produced. This margin has matched the best across our coming peer group driven the highest percent of oil content in the group and the dramatic reductions we've achieved in LOE costs.
In terms of reaching our financial goals our internal cash margins are just one piece of the equation, equally important is our capital spending. On this front we recently increased our facilities expenditures to support our activity shift to the central area and set us up for efficient operations as approach 2016.
We've also continued to invest in larger completions and longer laterals which we believe will contribute to sustained capital efficiency. So while we increased our 2015 budget by 10% to account for these items the dollar per well spend as we focus on Lower Spraberry with pad development.
On our last call we talked about our normalized operational CapEx spend of $30 million to $35 million per quarter under our previous plan that was split between the southern and central properties. After our initial investments in infrastructure in the second half of this year we see this normalized rate decreasing 15% from our previous plan to a range of $25 million to $30 million while continuing to drive similar production growth of approximately 20% in 2016.
I'll now turn the call over to Gary Newberry, Senior Vice President of Operations to provide you with an update on our operational front.
Gary Newberry
Thanks Fred and good morning. I will start on slide 4 with a summary of our activity in the third quarter.
We placed seven wells on production in the quarter with five Wolfcamp B wells and two lower Spraberry wells spread across our southern and central areas. As Fred discussed our organization was focused on pivoting the business to the central area during the quarter while maintaining operational momentum and a high level of efficiency.
We recently brought on line a well in the southern area at the Garrison Draw field targeting the lower Wolfcamp B which satisfies all drilling obligations for this field. We had originally planned to Cline test from that pad with deferred that delineation well as we shifted the operational plan.
While our focus has transitioned to our central properties we are fortunate to have the derisked opportunity set in the southern area for future activity under an expanded capital program. As we stand here today we are now in full stride with our Central Midland Base in Lower Spraberry development program.
The mid quarter operational realignment demonstrates our ability to be flexible in this environment and was accomplished with minimal impact on our production expectations for the year. I'm very proud of our team for their efforts and look forward into 2016 to drive for added efficiencies and deliver strong returns through our focused development program.
While developing the Lower Spraberry zone will be our principle focus in 2016, our first Middle Spraberry well was placed on production in late October and is located in our Casselman field. Although the well continues to cleanup we are encouraged by better than expected oil volumes during flow back and an overall level of well performance that is similar to early time results from our Lower Spraberry wells.
We will discuss in more detail early next year. Slide 5 summarizes how we characterize our opportunity set as we develop our longer term plans.
As you can see in the chart we have an estimated 17 years of inventory that delivers a return of at least 20% in a $40 to $50 per barrel commodity price environment. These locations are in both our central and southern areas high graded to specific fields in current producing zones on our property base.
Given the volatility we've seen in recent months our operations are now pinned on the Central Lower Spraberry inventory that we see as offering acceptable returns even at $30 to $40 per barrel. That bar represents approximately five years of inventory at our current pace of 15 wells per year and we believe we could more than double that inventory with future well cost reductions and operational efficiencies achievable under those commodity price assumptions.
Moving back to the right side of the chart you can also see our estimated inventory increase to almost 30 years under a $50 to $60 per barrel assumption with additional contribution from our southern fields as well as the Cline and Jo Mill targets. Given our Lower Spraberry focus moving forward we've provided an updated view of well economics on page 5.
The left hand chart continues to track the strong results that we've seen from our initial wells relative to the normalized two-stream type curve double where 900,000 barrels oil equivalent. We will be revisiting this type curve later this year with extended well performance and the additional wells that have been placed on line in recent months.
Shown on the right hand chart, we estimate returns of 60 % at $50 flat and 35% at $40 flat using current well cost and the existing type curve. While returns are strong relative to other drilling opportunities we are equally as focused on the capital efficiency and cash flow profiles of these wells given our goal of living within our means.
Our type curves drives a cash out time of 1.6 years and a ratio of PV-10 to capital investment of over 100% with both measures pointing to exceptional capital efficiency to underpin our operational and financial planning. Slide 7 has been provided to give some guidance for modeling purposes.
The curve shown is for a 7,500 foot normalized well and our plans include drilling lateral lengths of 5,000 to 10,000 feet. Results from our Lower Spraberry wells and industry results offsetting our central acreage illustrate the strength and high quality of Callon's asset base.
On slide 8, we've also provided an update on our southern economics that will be an important component of our future development plan. While Central Lower Spraberry returns are ahead of our Wolfcamp B our recent initiatives to improve our completion designs in the southern area have yielded strong results with performance exceeding our type curve assumptions and generating returns of 30% under $50 flat WTI.
This opportunity sets us to attract significant capital today in many drilling budgets where we will defer these projects of maintaining a level drilling cadence targeting the outstanding returns of the Lower Spraberry while remain focused on achieving cash flow neutrality. I will now move to slide 9, and walk through the other important component of the capital efficiency equation and discuss our overall operational cost structure.
Our well costs continue to move over with recent AFP for 7,500 foot laterals at approximately $5.9 million including costs for flow lines and testing. This figure also includes a steadily increasing level of profit that is approaching 1,700 pounds per foot of lateral.
This level is above our original levels for planning purposes that we're seeing improved returns and recoveries with these designs. So, we believe this is a worthwhile investment to capture the resource in the most efficient manner.
As we look forward, we see additional areas for internal improvement beyond service provider cost reductions through the initiatives on the right side of the page. Slide 10 shows dramatic improvements in our LOE cost over the last several quarters with improvements in workover expense and realized benefit from investment and infrastructure.
We're pleased with the progress we have made over the last several quarters and we're also proud to be among the lowest cost operators in the Basin as shown on the right hand side. Turning to slide 11, I will take a couple of minutes to address how our capital spending plan has changed with the accelerated operational shift.
Starting on the left hand chart by year end, our quarterly operational CapEx is projected to be down over 15% from the fourth quarter of last year reflecting the strength of a high graded capital program that we believe will generate a sustainable production growth profile. For the third quarter spending was a bit high than expected due mostly to the accelerated timing of facilities investments needed to support the operational pivot to our central region focus.
You can expect to see spending decreases over 30% to the normalized $25 million to $30 million per quarter that I mentioned earlier. We also had a substantial increase in average lateral length which contributed to a higher level of drilling and completion.
Putting all this detail together slide 12 summarizes our updated 2015 operational capital plans and highlights the operational flexibility afforded by our current asset base. We've increased our 2015 capital budget by 10% to reflect the facilities investment and increased Lower Spraberry profit levels that are a product of our new operational plan.
These increased expenditures are in support of greater capital efficiency in the long term and will begin to show benefits in the next few quarters. I would note that this modest increase in CapEx has been offset in part by continued operational efficiencies and service cost reductions, with our operational CapEx per completed foot down approximately 40% since the beginning of the year.
As we look forward into an uncertain commodity price environment Callon is well positioned to deliver strong returns on invested capital. We are 100% held by production, with the flexibility to allocate capital to the most value added drilling opportunities.
Furthermore, our assets have no dept severed rights that prevent us from efficient development of multiple stack designs. This very high level of flexibility positions Callon to address emerging opportunities and challenges as well as any company in the Basin.
Joe Gatto our financial, Chief Financial Officer will pick up on slide 13 with the financial discussion.
Joseph Gatto
Thanks Gary. From a financial standpoint we had another stellar quarter summarized in the right hand chart with an adjusted EBITDA margin of almost $35 per BOE.
LOE and G&A were both at the low end of guidance and revenues benefited from a continued improved in our total pricing differential shown in the lower left corner. Our unhedged realized oil price of $38.30 was over 95% of the WTI benchmark as a result of an improved Mill and Cushing pricing differential and the early impacts of putting our Southern Midland fields on gathering systems.
East Bloxom was put on a gathered line in mid-July and Garrison Draw and Taylor Draw are expected to be on systems by year end which should drive continued reductions in our transportation differentials. We're also working towards having our last major producing field Carpe Diem on pipe in early 2016.
In the meantime, we've been seeing improvements in the cost of trucking our crude with continued infrastructure build out throughout the basin. We exited the quarter with a strong liquidity position which also benefited from a borrowing base increase of 20% that we received last month.
This level of liquidity is almost two times the preliminary 2016 capital budgets that I'll discuss in a few minutes. Slide 14 shows our sequential production growth throughout the year with an expected midpoint production rate of 10,450 BOE per day in the fourth quarter, this level represents a 7% increase over the third quarter and a 43% increase compared to the fourth quarter of 2014.
As Gary discussed, a large amount of our third quarter new producing well activity occurred in the last half of the quarter with over 80% of our combined lateral length completed in the last half of the quarter. The contribution from these levels will provide strong operational momentum into the first quarter in 2016 as our new drilling plant get full stride.
I'll finish upon slide 15 with a review of how our new focus impacts our outlook for 2016. We presented the similar view in August but as we noted a lot of change starting with an increase in the proportion of Lower Spraberry wells planned.
While in the aggregate we're now planning for the fewer net wells in 2016. The capital efficiency of the optimize Lower Spraberry program results in a 17% operational CapEx reduction from our previous plan combined with a less than 2% reduction in anticipated production.
We believe this program will enable us to achieve cash flow neutrality under various commodity price and associated service cost scenarios. Our estimated 2016 average production rate of 11,500 BOE per day under this program would be a 20% increase over our anticipated 2015 volumes with an associated oil mix that remains at the top of our peer group.
While this growth is attractive is a byproduct of the pursuit of our top goals of living within our means and generating capital efficient growth from disciplined investment in high return projects. The chart on the lower right hand corner provides some context on this point comparing the efficiency of our expected liquids growth to that of our peer's based on recent street estimates.
While we're not quite at the top of each of these measures looking into 2016, we are squarely in a mix with these other strong operators and will continue to move upwards on debt adjusted production growth as we progress to cash neutrality. I will now turn the call back to Fred for some final comments.
Fred Callon
Thank you, Joe. In summary let me say I am extremely proud of our employees in the way they have adapted to a very difficult commodity price environment.
We continue to improve our operating cost structure and capital efficiency in the current environment which further advances our goal of funding our drilling problem with internally generate cash flows by mid-2016. Since clear focus will now be on the Lower Spraberry that as you would expect we'll continue to monitor the surround peer activity and well performance in the Wolfcamp A and Middle Spraberry.
Fortunately we have a strong balance sheet, high quality assets being managed by one of the best operating chains in the Permian Basin. I think combine these will provide a solid foundation that will allow us to continue to grow and create value for our shareholders even if oil prices are lower for longer.
Now I would like to open the call for questions.
Operator
[Operator Instructions] And our first question will come from Neil Wiese from SunTrust. Please go ahead with your question.
Neil Wiese
Good morning, guys, Gary for either Fred or to Joe, just wondering with the new plan you have obviously looks like going but up in the north in the core and you talked about spend within cash for next year, are they different, can you walk through maybe some different sensitivity is depending on again what oil might do, where you would think about either potentially happen to either drop a rig or potentially adding a rig?
Fred Callon
You want to start on that Gary or.
Gary Newberry
Gosh, I guess sensitivity is for us Neil, I am really going to hand you on our ability to meet our top financial goal of living within our means. So, if prices move down further, we may have to adjust depending on the types of results that we're getting from our wells.
The response we get from service providers to that further downward with moment in commodity prices and if prices move up, we'll get there sooner and potentially consider accelerating activity sooner than what we're currently thinking about.
Fred Callon
And Neil to round that, I mean it's, obviously it's the question we field quite a bit but it really is predicated on what our views on the cost structure right, you know the oil price could do a lot of different things but we have to do our job and keep an eye on what does our cost structure do under those scenario. So, we did see a move to the low 40s and staying there, we do think that there are additional well cost reductions that we can achieve and so in a world that we're focused on cash margins and capital efficiency we'd probably still be running two rigs and under this high graded program and similarly if we see things move up into the mid 50s that we did earlier this year, we're going to be patient about adding rates because we would expect that the Permian Basin is going to be ground zero for additional drilling activity and you'll see service cost move up so we just want to understand what that cost structure is going to be before we make a commitment like that.
Neil Wiese
No, that makes sense. And just my last follow up.
Gary when you go, when you are drilling this new plan, thoughts about multi-stack laterals and as far as multi-well pads just how are you going to tackle this for 2016? Thanks.
Gary Newberry
Yeah Neil thanks. All of our pads will be at least two or three well pads.
All of our locations will be like that. They will currently we're myopically focused on the Lower Spraberry.
But I got to tell you we're very encouraged with the early results of the Middle Spraberry and we've seen that the exceptional results that have been reported by our peer group on that horizon. So we will stay very focused on the Lower Spraberry until we get more time and effort and experience with the Middle Spraberry but if it's acting like the Lower you could see us do two wells stack pads but we'll stay very focused on the Lower Spraberry.
Well we won't vary from that because we have got to be very good at what we do. In this environment every company that does that will do very well with the asset base that we have.
Neil Wiese
Thanks.
Operator
Our next question will come from Jeb Bachman from Scotia Howard Weil. Please go ahead.
Jeb Bachman
Good morning guys and I appreciate all the info in the presentation. Gary just on that Middle Spraberry well, can you tell us what the lateral length is of that well and did you guys use 1,700 pounds in that completion?
Fred Callon
Yeah, Jeb, that's an off lease location, so that's actually going to be a 5,000 foot completed lateral length. So, we're happy with that and yes, we used the higher sand concentrations in all three of those wells on that pads with Lower Spraberry and the Middle Spraberry and we're happy with the way that sand went away.
Jeb Bachman
Okay, great. And then looking at the program for 2016 and I apologize if I missed this but Joe you're going to be running two rigs in 2016 and does that assume that if you keep that Cactus rig at the rate you have it today?
Fred Callon
That's correct, yeah, there is two horizontal rigs running both Cactus rigs and both the rates that we've talked about previously 15,000 a day. On that operational capital outlook page you'll see that the net wells go down that's really a function of in the central part of the basin we have a lower working interest than the southern but so it's not a reduction in the gross well activity, it's really a net reduction on two rigs.
Gary Newberry
Yeah, and Jeb just as far as the rig rate, we have no indication that that rig is going to change. I think the market is finally catching up to where we've been I've heard other company say they're finally getting to the rate that we've been most of the year.
So, Cactus has been a great partner for us throughout this entire year.
Jeb Bachman
Okay and last one from me Joe on the transportation, is that interruptible or is that from contracts on those pipelines?
Joseph Gatto
We've dedicated production to those gathering system. So, these are small diameter pipes not necessarily Bridge Tex type of a pipeline that you're committed to firm tera.
These are negotiated with people like claims and some of the gathering folks out there that we've dedicated production to them for a period of time at a locked in tariff.
Gary Newberry
You know, common carrier system that they have so any interruptions or curtailment will end up [indiscernible] curtailed quality. So, but certainly we look to have plenty of capacity for what we have plan for next year.
Jeb Bachman
Yeah. I appreciate it guys.
Gary Newberry
Sure.
Operator
Our next question will come from Ron Mills from Johnson Rice. Please go ahead.
Ron Mills
Good morning, guys. Just alone the couple of the recent Lower Spraberry completions that were at 9,000 foot laterals that really drove your third quarter average lateral length up, is that going to be more of an aberration, it looks like the returns more into a 6,500 foot level in the fourth quarter or as we look to 2016 is there the opportunity to do more of the 8,000 and 9,000 foot type laterals?
Gary Newberry
Yeah. Ron that's a good question but you're right our average lateral length in the fourth quarter will go down simply because we drilled some really long laterals at Carpe Diem and Garrison Draw in the third quarter that drilled that up but Carpe Diem as well as the East side of Pecan Acres provides the opportunity to drill 9,000 and 10,000 foot lateral length wells and as we stay focus on our Central Basin asset we'll be moving in and out of those areas as well as in and out of our west side of Pecan Acres reason into our Casselman, and Bohannon Area.
So, in total our average lateral length will be likely more in line with what we're headed to in the fourth quarter but we'll still have the opportunity to drill several long laterals throughout the year.
Ron Mills
And then given the way that Casselman, Bohannon is a little bit more checker boarded than Pecan Acres and Carpe Diem, when you look at those, those two rigs, any senses to how the schedule progresses in terms of how much of the year they're going to spend in CaBo versus Carpe Diem versus Pecan Acres because that will drive the lateral length?
Gary Newberry
Yeah I think the way you should think about that Ron is we'll have one rig fully dedicated to Casselman, Bohannon and the other rig that'll be moving in and out of Carpe Diem and Pecan Acres. That kind of sets us up to make certain that all of our facilities and our resources are all lined up to quickly and effectively bring those wells on completion once we get them drilled but that's the way I think about it.
Ron Mills
Okay. In which both rigs now up in the Central Midland Basin is the $6 million of accelerated facility cost has that all been done and are those facilities ready now for you to start focusing your completions on that Lower Spraberry?
Gary Newberry
Yeah, again we're still doing some additional work for the section that we're drilling and I'll just go right back to your statement about the checkerboard area for Casselman and Bohannon that's where we drive in a lot of our capital work related to facilities because we have to build new facilities on each one of those sections. And so that's the driver.
We'll still have more of that to do in 2016, that's the reason the capital that we've kind of targeted has some capital work to do with it. But once we get that built out in early 2016 then we will be very efficient with adding wells with minimal capital after 2016.
Ron Mills
Okay, and then Joe one for you, the realized oil prices and differentials had a big improvement in the third quarter, is that 96%, 97 % of the WTI, is that about what we should expect going forward or is there still some potential improvement via lower transportation costs to get you in terms of the differential in transport costs continue move that down a little bit?
Gary Newberry
There are going to be two key pieces of that Rob, obviously that the Mid-Cush differential being a pretty big contributor in the third quarter moving from a couple of dollars below Cushing in the second quarter and was running about $0.70, $0.80 above Cushing in the third quarter that's starting to come back a little bit. We would expect that Midland Cushing differential to normalize longer term just based on physical crude pipelines and tariffs and flow of crude that normalize in the $0.75 to $1 is sort of how we planned for that longer term.
So that's one piece of it. Then on the transport side on average we're about $2.75 in the quarter.
We are just starting to see the impacts of moving to the gathering systems we talked about so we would expect to pick up on average $1 versus that $2.75, $3 going forward so all in we're looking about minus $3.25 I would say as a reasonable estimate going into next year is all in differential versus TI?
Ron Mills
Great, let me get back in line. Thank you, guys.
Operator
Our next question will come from Gabe Daoud from J.P. Morgan.
Please go ahead.
Gabe Daoud
Hey, good morning, everyone. Just wondering if you could provide some comments on the current A&D environment in the basin and what you're seeing out there and your I guess appetites remain opportunistic throughout 2016?
Fred Callon
Yeah, Gabe, thanks, so, this is Fred. As we've said before, we continue to actually look at, we look for opportunities, we've seen I would say a good amount of deal flow, haven't seeing a much sort of fuel cleared by market.
So, we remain active looking certainly for bolt-on opportunities like we've done in the past and continue to be active there. We think perhaps there are some larger opportunities that we look into 2016 we think we'll see more looks like there is going to be continue to be good deal flow.
So, we'll continue to remain active looking.
Gabe Daoud
Thanks, Fred. And then, maybe just reading a bit into this too much but I guess given longer laterals from $0.19 and continue type curve outperformance by the Lower Spraberry, I guess maybe would have expected to see a bump on full year production guidance, any thoughts there?
Fred Callon
Yeah, certainly we have a bit of momentum going into the back half of the year. I'd say one thing that's dialed into that in the fourth quarter where some issues around off take at our Bloxom field, there was an issue with the gas plant that curtailed us on gas and oil for a decent amount of October right Gary that influences it so that is something that we've incorporated in this number a bit and we think that's all resolved at this point, but that was something that probably would have led you to a different answer than otherwise.
Is that fair Gary?
Gary Newberry
Yeah, that's very fair, you know West Texas gas and plants there that we send our gas to had a [indiscernible] on September 21st and it was resolved about the third week of October, so we were significantly curtailed at Bloxom throughout that time period. And without that we may have been talking about comp but we are back to where we are full up and running and feeling good about where we are.
Gabe Daoud
Thank you guys. And then just may be one final one from me obviously, impressive cost reductions thus far, I know 7,500 for lateral, how much low do you think you could go at this point if you assume commodity price markets stay where they are, just mainly based on your continued efficiency gains in the basins, how low you think that could ultimately get?
Fred Callon
Again, that's always a moving target, but the one thing we've been impressed about is the amount of interest that people have been doing work for us. We have a lot of service providers who have capacity in their schedules that are continuing turning to us and they can do better and cheaper.
We will be testing some of those in 2016 some of it comes around our pumping services. We've been incredibly impressed with the service and quality of work that petrol group has done and we intend to continue with that group, but frankly there are some significant cost savings being offered by several other pumping services providers that could lower that cost considerably.
So we're going go ahead and schedule that in the first quarter of 2016. Everybody already knows about it, so we wish the services providers know about it, I don't want to talk about who they are at this point in time.
But that as well as we're seeing a significant reductions finally in tubular costs coming through now. We have a significant effort, internal effort and having very detailed discussions with all of service providers still at this lower price environment and having that relationship positions us well if it goes lower and it even positions them well if it goes higher because we're working as a team not as just a contractor operator relationship, we're truly working for the benefit of all parties.
Gabe Daoud
That's fair, that's all I had. Thanks everyone.
Fred Callon
Thanks Gabe.
Operator
Our next question comes from Ipsit Mohanty from GMP Securities. Please go ahead.
Ipsit Mohanty
Hey, good morning guys. You talked about average lateral length in 2016 [indiscernible] your fourth quarter [indiscernible].
Would you be able to provide an average working interest as you can now move back and forth between regions in the Central Midland?
Fred Callon
Yeah, that information is provided actually on slide 6. We didn't really focus on it, but if you look at average lateral length plan for 2016 you know we've got about 6,540 feet and the average working interest looks to be around 65%.
That's assuming, hey, that everyone continues to participate as they have and again so far look our partners are happy with the cost savings we've had, happy with the returns we all expect to deliver and so far everyone is trying to participating. So, we're happy to have them with us.
Ipsit Mohanty
Sure. Now it seems like a bunch of your guidance is hinged on your sort of reliability on the Lowest Spraberry results.
When I look at slide 15 and you have that 1.3 well in Upper Wolfcamp B, is that still in Central Midland or is some of it kind of left over from a Southern Midland?
Fred Callon
No that's entirely in Central Midland that's some joint wells and some exceptional either Wolfcamp A or Wolfcamp B wells as we work through a pattern with our Pecan Acres field and our joint venture relationship with RSP Permian.
Ipsit Mohanty
Got you. And then coming back to Lower Spraberry a bunch of your peers have actually guided even higher going towards to 1 million MM BOE EUR so in that case do you see your EUR estimates sort of trending up toward that or you're happy where you are?
Fred Callon
No. We'll, again as we're blessed to have great operators around us and operators that are delivering exceptional results and we're delivering similar results.
So, on a 7,500 foot type curve you can see the types of results we're delivering that curve was likely going to move up. We just wanted to get a more statistically significant number in our own working system before we did but clearly everyone seems to be outperforming that type curve and as we are.
So, yes we would expect that to move up some time next year.
Ipsit Mohanty
All right, great. Thank you, guys.
Good quarter.
Operator
Our next question comes from Stephane Aka from Seaport Global. Please go ahead.
Stephane Aka
Hi, guys, good morning.
Fred Callon
Good morning.
Stephane Aka
I was hoping to revisit the Middle Spraberry a little bit, I know you start showing it earlier but just wondering if you could kind of frame for us in the context of how you think this may ultimately kind of compare versus what you have in the lower? And then, in addition if you could give us some color in terms of any other zones you think that are getting better in your eyes?
Thanks.
Fred Callon
Yeah, we're, again this is our first Middle Spraberry well but again RSP, Permian and Diamondback have done exceptional work in proving this zone up and really getting exceptional results that are equal to or even better than some of the Lower Spraberry wells. We were interested in really with the Lower Spraberry being a little shallower on how well it will take sand and we were interested in whether or not it would be difficult to drill out given it was a little shallower and a little bit lower pressure.
And then we were very interested in how long it would take to get first oil because those are the indicators that we were looking for in comparison to what we've heard and seen from the other off site operators. They took sand that's equal to the Lower Spraberry, it drilled out exactly the same.
We had no issues with drilling it out and we had good oil on flow back and we've got increasing oil even four or five days after putting it on top. So right now it's acting exactly like the Lower Spraberry.
Now this is only one day to point but we're pretty excited about.
Stephane Aka
Thank you.
Operator
Our next question will come from Chris Stevens from KeyBanc. Please go ahead.
Chris Stevens
Hey guys just wanted to get your view on the Lower Spraberry down spacing, what spacing are you planning to develop your acre on in 2016 and since most of your focus is on the Lower Spraberry near terms do you see a need to go out there and catch tighter spacing earlier rather than later?
Fred Callon
Again we are at the benefit of learning significantly from our peers. They have published a lot of data.
They shared a lot of data with us especially around the way we intend to jointly develop the activity around the Pecan Acres. We are about to go complete two wells at Carpe Diem, they were drilled on a similar spacing that's been published by both RSP and Diamondback about 10 wells per section and they even testing a little bit tighter spacing.
But we are planning on moving forward with the 10 well per section development so that we don't leave anything behind and continue to learn from our own work as well as the work of our peer group.
Chris Stevens
Okay, is that going to be a stagger stack sort of pattern or is that all on the lower portion of the Lower Spraberry >
Fred Callon
Our plan is staggered stacked but again based on some recent results published by those guys they are getting exceptional results with even same level of tight density spacing. So we'll continue to pay attention and learn as a group because we'll share our results with them and hopefully we will continue to see their results as they continued to move that forward.
Chris Stevens
Okay, great. And are you able to quantify any of the uplift in well performance that you are seeing from the increased proppant loadings up to 1700 pounds per foot levels more recently?
Fred Callon
I guess to quantify generally and thing that as we get more sand in the ground, whether it Wolfcamp B at Garrison Draw recently or whether it's even the Spraberry wells that are coming back now the early indications are pressure, the early indications are first oil, the ability to flow on its own, or to put it on pump and get good withdrawals even higher withdrawals even though we kind of operate our sub pumps at fairly low rates, higher withdrawals even those lower early times production times. But again we don't have an update over time to tell you how long that's going to - how to quantify other than is more encouraging early time that we see.
In both the Wolfcamp B and Lower Spraberry so it's difficult to say it's an uplift of certain number of barrels for certain incremental costs simply because the data set is too small.
Chris Stevens
Right, okay, and then I guess your 2016 production guidance at this point does it reflect any of the improvements that you've seen even over the past couple of quarters, as you've been optimizing your design overall?
Fred Callon
Our 2016 plan is based entirely on the type curve that we published, so no, the type curve has moved up a little bit as you know from quarter-to-quarter but we think it will likely move plus more.
Chris Stevens
Okay, great. Thank you.
Operator
Our next question comes from Irene Haas from Wunderlich. Please go ahead.
Irene Haas
Hi. My question has to do with, you know, throughout this whole time downturn Callon has just been working very, very diligently on improvement, efficiency gain as such.
So, would be able to give me some color say in the last 12 months certainly on an apples-to-apples basis what has been happening to your drilling days from spud to release. And my second question has to do with the weather, are you guys seeing any annual impact in the Permian this quarter?
Fred Callon
Yes. As far as the operational efficiency from drilling days, we've been doing pad drilling since 2012 or since the end of 2012 and early 2013.
So, we've been incrementally moving forward with better pit selection, better tools, different lead systems, different types of ways to reduced drill times by hours and hours on each pad. So, just recently we drilled a long lateral in 15 days from spud to TD and we were very happy with that.
So, the drilling team continues to work at it, they keep at least tempering my expectations a little bit by saying they are awfully good now and they are but we're never going to give up on taking another half a day out of that schedule. Importantly, we're very quick as well to be ready to move on and bring that production online because of our relationship with our pumping services company and the team out in middle that works diligently to be ready to frac that well just a couple of weeks after that rigs moves off which I think that's steady schedule, that rhythm or that rhythm that we're in continues to get better whether it's just hours or days that continues to get better.
And so I think added efficiencies are still going to be a big part of cost savings going forward. And those efficiencies are even not just ours, they're coming from companies that we're talking to about what we ought to be doing in the future.
Whether it be smaller footprint, less cost per location, using dual fuel pump systems, lot of different things that are being ventured around by our partnership that we have with all of our service providers that make a difference. Now your second question was?
Irene Haas
Weather.
Fred Callon
Weather, we have seen significant weather so far this year, it's all been and a good thing in form of rain, a lot of rain. And there's been all of the flooding that occurs in major metropolitan areas but we've had our share of challenges in continuing to move things forward efficiently with a lot of wet weather in midland.
The team has done very well to work safely and efficiently around those issues to look out for each other but the last thing I guess they have rain in midland we won't be complaining about that.
Irene Haas
Okay. Great.
Thank you.
Operator
Our next question comes from Will Green from Stephens. Please go ahead.
Will Green
Good morning everyone.
Fred Callon
Hi Will.
Gary Newberry
Good morning Will.
Will Green
So you guys have obviously talked a lot about the capital efficiency side and it sounds like drilling times are still coming down, tubulars are getting better. Gary you just mentioned a few things that you guys are doing with your completions guys they're trying to get these cost down as well and you also listed a number of things on slide 9 on the cost initiative side that are you guys are tried about.
I wonder if you can maybe talk for one or two of those points on slide 9, you know on the cost, you know on the cost initiatives and maybe give us some color around which one you're most excited about or which to you are most excited about and what you ultimately hope that it yields in terms of a cost or drill time or something like that?
Gary Newberry
Yeah, well thanks for that opportunity. I guess probably bundling services whether it be on the drilling side or whether it be on the completion side provides significant advantages to us.
And many companies are trying to bring more and more that bundled services to us, so that way it reduces our need to have various vendors and the coordination of that, and it even streamlines our accounting processes in total. That all helps but probably the one thing on here that's made the bigger difference is even transitioning at even ProPetro request the 24 hour pumping services mostly we're doing for 16 hours would be more stages done in a day now and we shorten that cycle time for completions and we bring that fluid on that, that rate on quicker and we reduce other rentals that are out there that used to be out there for longer periods of time for that.
The biggest opportunity is still is on the sheet and that is the, the biggest thing we see on the horizon now based on pumping services is opportunities to leverage integrated companies with sand sources all the way through to pumping services. And the discounts that we've been offered are mostly from companies they have their own sand supplies.
And really pass them those through maybe at cost or more minimum margins, but there is significant opportunity there up to really hundreds of thousands of dollars per well. So, that's what we're anxious to test in February or March of next year with another provider.
They don't need a bit at this point in time but it's something that we're excited about and just the myopic focus we have on cost and the discussion we have with all of our service providers continues to bring in additional savings small that it might be from each provider it all adds up. We recently got a significant reduction in tubular cost simply like going out and testing to market it's pretty hard.
And I think others are starting to see reductions in tubular cost come through which we're excited about, that's a significant portion of our wells. But what we're most excited about right now going early 2016 test that this issue of whether or not these companies that have access to sand or a larger access to sand and leverage that access to the benefit of the industry is real.
Will Green
Great. I appreciate the color there.
And then, the other one I had was I don't recall or I don't know have in the front of me what the exact breakdown the PUDs was from the last reserve report but obviously you guys did have a kind of favorable borrowing base redetermination in the fall, looking into the spring just how we should think about any kind of PUDs that need to come out of the system this year or is that completely offset by the PDP guys who are adding given that the PUDs that might need to come off may not have been contributing that much by the PV-10 anyway, just how do we think that equation as you guys move forward?
Gary Newberry
Well, that's a good question. And we looked hard at that but if you - I can remind you at the end of the year we were clearly like in our one-to-one PDP ratio somewhere around that we had less than a two year inventory of PUDs on the books, we are not challenged at all with any capital SEC five year rule.
We've done SEC testing for the PUDs we have, there might be one or two that might come off but that will more than offset. They will be more than offset by the PDPs that we have added, I mean the additional PUDs that are around those exceptional wells.
So we feel pretty good about where we stand right now. We are in the middle our yearend, middle, tell me, October, we started it you know our reserves - third party reserves coordinators Gory or Macnotun and they have got our database, they are looking at it, we will have preliminary numbers in mid-December and final report in early January but we feel pretty good about where we stand.
Will Green
That's great to hear. Thanks for all the color guys.
Gary Newberry
Thanks.
Operator
Next question comes from Kyle Rhodes from RBC. Please go ahead.
Kyle Rhodes
Hey guys, good morning and I appreciate all the color so far. I was hoping you could provide some additional color on the partnership opportunities on expiring acreage you referenced.
Are you guys looking at farm outs there or is there any detail on the zip code or size of deals you are looking at?
Gary Newberry
Yeah Kyle. As Fred mentioned there is a lot of activity out in the basin at this point and whether that's in the form of outright sales which Fred mentioned, what a deal flow, a lot of things just haven't cleared is the infamous bid spread is still a little bit wide on some things but seems to be narrowing a bit and probably set up pretty well going into 2016.
But outright sale was one option but there are potentially some opportunities to come in and satisfy drilling commitments that others might have and they might not have the operational team ramped up, whether it be a private equity outfit that is set up to sort of capital resource that may be not as well set up to develop the resource, so given that we have extremely flexible operational phase that we don't have any drilling commitments, so if we did see opportunities like that we could come in and do a drill to earn and something like that we could peel off some activity from our existing operations and go satisfy those drilling obligations and earn our way into acreage or wells that way. But the trip to all that it's got to complete pretty well for capital in terms of what we are doing today.
We don't want to put a big drag on our cash flows and our ultimate goal of getting to cash neutrality but it's just another option that's out there. Again we're in various dialogue on various different structures at any one time, so that's just one of them.
Kyle Rhodes
And that's helpful, Joe, thanks. And I guess, may be for Gary, is there any update on the acreage swap front may be specifically CaBo and then if you could just remind us how long you can take those laterals there now at CaBo?
Gary Newberry
Yeah, I think what we are doing now is what we ought to plan for, you know, again we've worked hard with what the offset operators asking they are certainly interested in our results, but at the end of the day they are not ready to join us, so I think what we are doing is what we obviously plan for those wells are exceptional, even though there are off lease locations they will be 5,000 foot completed lateral lengths and if they are on lease locations that will be closer to 4,500, but those wells are very good wells. They come in at a lower cost side and that Pecan Acres as well that's right next to it is an 800 MBOE well, so and it's a short lateral.
So, we're happy with the asset base that we have.
Kyle Rhodes
Great, guys. Appreciate it.
Operator
Our next question will come from Jeff Grampp from Northland Capital Markets. Please go ahead.
Jeff Grampp
Good morning, guys. Share maybe a couple of quicker one from the cost side, just wondering looking at 2016 guidance and then $110 million CapEx or so under current well cost, do you guys think maybe that there's some conservatism built in there, obviously you guys have a great track record of incrementally moving the cost downward or with partners.
Maybe you think that maybe there is some downward bias to the extent you guys can move cost incrementally lower?
Gary Newberry
We certainly hope so. We are just not ready to talk about it yet but we got plans to move cost down considerably and we're getting good indications from our providers that opportunity might be there but frankly from a capital perspective, I expect to get big, better and go faster and potentially even do more.
So, that is just the guidance we're going to give you for now.
Fred Callon
We'll come back Jeff and early 2016 with the formalized budgets been approved by the board, this is the preliminary one that we're working with and are planning towards but we should have some more data on cost reduction that we're comfortable with in terms of baking in and we might have some insight to the extent that some of our non-operating working interest partners have budget constraints next year and we think that they're going to do some non-consensus that we can be at dead end a little bit more as we get closer to that point but right now one ten using current well cost gives us a little bit of leeway to handle anything like that more refresh it in January, February but things pretty good number with hopefully as Gary said a little conservatism will take some of that just give us some flexibility.
Jeff Grampp
Okay. I appreciate the color on that.
And then the last one for me on the LOE front, just kind of wondering how you guys are thinking that plays out moving into next year and given that you guys are really focusing in on a really concentrated area in the Central there, do you think maybe there is some efficiencies you guys can capture, investing in this infrastructure and really just focusing on this one area?
Fred Callon
Yeah, I think again we'll be tied into some pretty good capacity for water disposal that will drive some of those costs down. As we look at continued work with all of our service providers they are showing, they can continue to move some of the daily service fees down a little bit more.
But beyond that, the bigger impact is really the associated production growth related to controlling cost as we continue to drill on good assets.
Jeff Grampp
Okay, great. Thanks for the color guys.
Operator
Our next question will come from John White from Roth Capital. Please go ahead.
John White
Good morning and congratulations on another quarter of solid achievements?
Gary Newberry
Thank you.
John White
I wanted get back to the topic of spacing patterns for the Lower Spraberry at Carpe Diem. Are you drilling now any Lower Spraberry wells on a 500 foot pattern?
Gary Newberry
On the staggered pattern we are, that's essentially what the wells we just drilled.
John White
Okay.
Gary Newberry
That's correct, but that's not at the same vertical level.
John White
Okay, so that's what RSP Permian refers to as the Chevron pattern.
Gary Newberry
That is correct.
John White
And did you mention you're contemplating even tighter than 500 foot spacing to the Lower Spraberry?
Gary Newberry
Only no, we're not, we are not, we just wanted to test that there primarily to see if it impacted we could squeeze in another well to go from 10 to 11, because it makes sense to us but the pattern that both - the patterns that both our SP Permian and Diamondback speak about that if you think about the exceptional results that they're getting and their discussion about even a potentially tighter patterns we're very encouraged and excited about that opportunity. And so the pattern we're testing is really an 11-well pattern but it's stacked and staggered not one level like both of those companies are now talking about.
John White
Okay. Well that's pretty ambitious and when might an 11-well program, I mean that would like latest 2016 right?
Gary Newberry
Oh absolutely, yeah these two wells that we're going to fracture stimulate right now in another week, even the way they stimulate might tell us something but certainly in the way they flow back will tell us even more. So it'll be well after the first quarter before we can really talk about extending it beyond the 10-well pattern and people are kind of focused on.
John White
Thank you. And thanks again for such a nice presentation.
Gary Newberry
Thank you.
Fred Callon
Thanks John.
Joseph Gatto
Thanks John.
Operator
Our next question is a follow-up from Ron Mills from Johnson Rice. Please go ahead.
Ron Mills
Hey just on the acquisition front Kyle asked one of the questions in terms of in addition to just out right acquisitions it sounds like you were talking about the deep well, [indiscernible] et cetera but in terms of timing I know the acquisition market is always fluid but are there particular packages or versus things that are out there that are expected to potentially get done by year-end or is this something that will likely progress over in the next three to six months?
Gary Newberry
Ron, again larger packages, yeah, we've been actively looking at opportunities and I'm sure you know it's just difficult to tell at what point, as Joe said that you might close that gap and all of a sudden, so was expectations kind of come in line with ours. So, I can tell you we're actively looking and making offers, it's just very difficult to tell on the larger opportunities.
I will say though on smaller bolt-on type opportunities more in and out what we're doing, those I think we're continuing to make some progress there and I think that's an area where I think we can make some progress certainly in the short-term. Larger opportunities are just - it's just difficult to predict.
We're certainly looking at things that could come up in the short-term but certainly, we're seeing a lot gearing up for 2016. We'll continue to be on there looking, it's just difficult to predict.
Ron Mills
Geographically, would you say you're still more focused in the Permian or I know in the past you mentioned the Delaware as a possible area as well?
Gary Newberry
Yeah, certainly we're - our focus has been in the Midland basin historically but we've been actively looking at the Delaware for the past year. So, we feel very comfortable, we take our skill set and apply it in the Delaware if the right opportunity came along but, we are certainly looking at the Delaware as well.
Ron Mills
Okay great, thank you guys.
Operator
Our next question will come from Joel Musante from Euro Pacific Capital. Please go ahead.
Joel Musante
Good morning everybody. I just have a couple of quick questions for you.
On your production guidance, what's baked into that in terms of you know your assumptions on Lower Spraberry, is it just kind of your EURs?
Gary Newberry
Yes Joel, it's the EURs that we show on that one slide and then the lateral length and working interest ownership on the other slide that we've referenced already. That's what's baked into that forecast.
Joel Musante
Okay, all right. And it looks like there might be some upside there from at least on the EUR number, so is there something that's going to get, you are going to talk to your reserve engineer about or do you think you need more data, maybe some more drilling results there before you make that leap?
Gary Newberry
All the way I get that same question from my CEO all the time and the way I see it, Joel is I don't want to have a good hit at that curve. So I always want to get my own data set.
I have got two wells slowing back, two additional wells being fracked right now. I got two wells going to be fracked next week.
I will have twice as much data than that I have got on my own wells in at about three quarters and at that point in time, I will consider movement of that but it's to me is more proving it to myself, and proving it you guys on my own dataset versus looking at the very exciting data and the exceptional results being delivered by companies like RSP and [indiscernible] I mean those guys are doing exceptional work in the same area that we're working at.
Joel Musante
Okay. And how repeatable do you think I mean those - the EURs for some of the PUD results were pretty spectacular, so I mean do you feel comfortable to say you can do that from area to area or there might be some local geology issues?
Gary Newberry
I mean, I've heard people talk depressurization from vertical wells although Diamondback they didn't think that was a big problem.
Fred Callon
There is a lot of oil in place in these sections, Joel and we don't see that 40 acre development being a big issue as well. But because the results we're delivering are in vertically developed areas so our forecast is based on new results in those areas and we are a highly technically driven company and so we do a lot of work on a petro-physical viewpoint on understanding our asset base from the zone techniques, zone quality, consistency, any heterogeneity that might be expected from area to area and I can tell you that for what we're focused on right now, the Lower and Middle Spraberry look very consistent across our asset base.
So, I would expect some minor range of variation but certainly on a longer term consistent repeatable results.
Joel Musante
Okay, great. Nice quarter and that's all I had thanks.
Fred Callon
Thank you.
Gary Newberry
Thanks, Joel.
Operator
This concludes our question-and-answer session. I would like to turn the conference back over to Mr.
Callon for any closing remarks.
Fred Callon
Again thanks everyone for taking time this morning to dial in. We appreciate all the questions and opportunity to give you some color around what we're doing here so in the meantime anyone has any questions, please don't hesitate to give us a call.
Thank you.
Operator
The conference has now concluded. Thank you for attending today's presentation.
You may now disconnect.