May 7, 2015
Executives
Eric Williams - Fred L. Callon - Chairman, Chief Executive Officer, President, Chief Executive Officer of Callon Petroleum Operating Company and President of Callon Petroleum Operating Company Joseph C.
Gatto - Chief Financial Officer, Senior Vice President and Treasurer Gary A. Newberry - Senior Vice President of Operations
Analysts
Will Green - Stephens Inc., Research Division Phillips Johnston - Capital One Securities, Inc., Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Joseph Bachmann - Scotia Howard Weil Incorporated, Research Division Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Mostafa Dahhane - Northland Capital Markets, Research Division
Operator
Good morning, and welcome to the Callon Petroleum First Quarter 2015 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded.
I would now like to turn the conference over to Eric Williams, Manager of Finance. Please go ahead.
Eric Williams
Thank you. Good morning, and thank you for taking time to join our First 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 you to download the presentation if you haven't already done so.
You can find the slides on our website at www.callon.com. To locate the slides, simply click on the PDF icon located on the Events and Presentation page for today's conference call or, alternatively, click on the Current Presentations link at the bottom of any page on our website.
Before we begin, I would like to remind everyone during 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 Securities and Exchange Commission, including our Form 10-K, available on our website or the SEC's website. Today's call will also contain discussion to certain non-GAAP financial measures.
Please refer to our earnings press release, we issued yesterday afternoon, for important disclosures regarding measures -- these measures and the related reconciliations to U.S. GAAP.
You can obtain a copy of our press release in the News section of our website. Following our prepared remarks, we will be happy to answer your questions.
And with that, I would like to turn the call over to Fred Callon. Fred?
Fred L. Callon
Thank you, Eric, and again, thank you, everyone, for joining us this morning on the call. Callon reported another quarter of strong sequential production growth, driven by new wells brought online in the southern Midland Basin as well as sustained performance of our initial Lower Spraberry wells.
While growth is important, we recognize that delivering production gains in the most capital-efficient manner is what most drives value creation for our shareholders. To this end, we've been on the leading edge of well cost reductions.
We've already achieved 20% well cost reductions, and we're on pace to drive those costs down another 10%. We anticipate that we will be drilling 7,500-foot lateral wells for just over $5 million in the next couple of months, which is down over 30% from last year's levels.
We've also worked hard on our cost structure, with a 20% decrease per BOE and LOE from last quarter and a recent corporate cost initiative that's expected to save $5 million a year in total G&A. We continue to see strong performance from our Wolfcamp B and Lower Spraberry wells in Central and Southern Midland Basin.
As you know, we have been measured in the pace of our type curve upgrades over time in order to capture longer-term performance data from our own wells and then use offsetting well results to provide additional support for our EURs. When we began our horizontal development over 3 years ago, the majority of our early drilling was focused at East Bloxom and Taylor Draw in Southern Midland Basin.
We've taken the opportunity to increase our EUR estimates in the Southern Basin a couple of times over that period, with an increase in sub wells and production data. Over the last year, we ramped up activity at our Garrison Draw field in Reagan County and kicked off development in our Central Midland Basin fields.
Based on the sprawling body of water, our average Central Midland Basin type curve are now 640,000 barrels of oil equivalent for the Wolfcamp B and over 900,000 for the Lower Spraberry. We've also upgraded our average Southern Midland Basin, Wolfcamp B type curves to 575,000 barrels of oil equivalent for both the Upper and Lower Wolfcamp B.
Putting these increased EUR assumptions together with the capital and operating cost reductions, we expect returns across our asset base of 30% to 35% for the Wolfcamp B and 55% for the Lower Spraberry in a $55 per barrel world, with associated payouts of roughly 2 to 2.5 years. As we and other operators have discussed, Lower Spraberry is delivering exceptional results in the Midland Basin, and we intend to allocate an increasing portion of our capital program to the Lower Spraberry development in the second half of 2015.
Given the flexibility provided by our largely HBP footprint, we were able to modify our plans relatively quickly and leverage this opportunity in the near term. Based on our revised operational plan that Gary will discuss in a few minutes, we now expect to have production growth of 30% from the fourth quarter of 2014 to the fourth quarter of 2015 under our 2-rig program.
Looking up to '16, we expect additional growth of 10% compared to the fourth quarter of 2015. Using this forecast and current commodity price levels, we expect to achieve a cash flow break-even position by mid-2016, which provides us with additional financial flexibility to complement our strong capital and liquidity position to pursue drilling and acquisition opportunities in the future.
I'll now ask Joe Gatto, Senior Vice President and Chief Financial Officer, to discuss our financial results for the quarter.
Joseph C. Gatto
Thanks, Fred. I'll pick up on Page 4 with an overview of the key components of revenue in the quarter.
As Fred discussed, we achieved a sequential daily production volume increase of 18% over the fourth quarter of 2014 and an increase of 97% BOE per day over our production level 1 year ago. Total revenues in the quarter, excluding settled hedges, were $30.4 million or approximately $39.42 realized per BOE of production relative to $57.44 per BOE last quarter.
Given our production profile is heavily weighted to oil, the approximate 40% decrease in NYMEX WTI prices from fourth quarter '14 weighed on our realized pricing before settled hedges. Offsetting this decline to some degree was an improvement in Midland Basin's differentials, which averaged approximately $2 per barrel versus approximately $5.80 per barrel last quarter.
In total, our unhedged oil price realizations were approximately 90% of average NYMEX prices during the quarter relative to 89% in the fourth quarter. Going forward, we're in the process of connecting our Southern Basin fields to crude transport lines in the third quarter, which should benefit realized pricing, similar to what we see at our Central Midland fields that are already on takeaway pipes.
In addition, our realized natural gas prices per Mcf also experienced a notable decline as NGL prices were under pressure in line with the oil prices, and also reflected the impacts of ongoing ethane rejection by big gas processors. As a result, our combined natural gas stream, including the Btu uplift from NGL content received only a premium of $0.20 or 7% per Mcf relative to NYMEX Henry Hub prices this quarter.
Since the end of the quarter, we have seen some improvement in realizations but expect that NGL pricing will continue to face headwinds in the coming quarters. Our hedged position added support to our revenue stream with cash settlements related to our hedging program totaling $13.41 per BOE in the quarter.
We've continued to add to our oil hedges over the past few weeks to provide cash flow protection in an uncertain environment and now have an average of almost 5,000 barrels of oil per day under swap contracts for the remainder of 2015, and an additional 2,000 barrels of oil per day hedged in 2016. On Page 5, we have provided an overview of our key operating expenses and trends over the last 12 months.
While we can't do much about the direction of commodity prices, we have made significant strides in reducing the cost portion of our cash margins. LOE, including workovers, was $9.03 per BOE for the quarter, representing a quarterly decrease of 20%.
This reduction reflects both increased leverage of our fixed cost components across a growing production profile and a lower overall workover expense. Adjusted G&A expense, which exclude the impact of mark-to-market valuation items and nonrecurring items, was $4.7 million in the first quarter of 2015, which was slightly higher than the fourth quarter of 2014 but in line on a BOE basis at $6.15.
Of this amount, 87% or $5.37 per BOE was cash, excluding stock-based compensation and corporate depreciation. During the first quarter, we initiated a cost reduction program, which reduced our employee base by approximately 20% and resulted in early retirement expenses of $4.7 million in the quarter.
This reduction is expected to result in a total G&A savings of approximately $5 million per year, relative to a one cash -- one-time cash cost of $7.1 million in the quarter, which included the cash payout of equity incentive awards. As a result, our expectations for both G&A expense and capitalized G&A are forecast to decrease going forward on an absolute basis and somewhat more on a BOE basis with growing production.
Moving to DD&A, on the lower left corner of the page. We reported a 13% decrease on a BOE basis, reflective of lower forecast of future development costs as well as continued proved reserve additions during the quarter from both net revisions and drill-bit adds.
Slide 6 summarizes our bottom line results for the quarter with reported net loss on a GAAP presentation of $12.2 million or $0.21 per diluted share. This figure included the impact of the following items on an after-tax basis: noncash unsettled losses of $5.1 million related to a mark to market of our hedging portfolio; a noncash loss of $1.7 million related to the mark-to-market valuation performance-based incentive compensation awards; also $2.4 million for the early recognition of drilling rig payments that are anticipated to be made over the next 8 months for the release of our rig in late March, if that rig is not recontracted by another party; and also $3 million for the early retirements described earlier.
Excluding these items and the related statutory income tax rate of 35% for the quarter, our adjusted net income was $100,000 or $0.00 per diluted share based on our average diluted share count at 57.5 million shares. Looking at the EBITDA line, we generated $26.7 million of adjusted EBITDA on the first quarter after adjustments for the items, I just mentioned, as well as other customary items.
Moving to Page 7, in review of our operational CapEx in the quarter, one can see that this was a busy quarter for us on the operation side under the 3-rig program, with 7.8 net drilled wells and 8.1 net completed wells, primarily in the southern portion of the basin. This level of operational CapEx was a little higher than expected due to reduced drilling and completion cycle times from operational efficiencies we gained in our 3-rig program development as the quarter progressed.
Importantly, we did begin to see the impact of the capital cost reductions we've been discussing in the right-hand chart. Comparing the fourth quarter of 2014 to this past quarter, we both drilled and completed a higher number of wells at a lower overall cost relative to the fourth quarter of 2014.
Gary will discuss this more, but I will note that we are forecasting a significant decrease in operational capital levels into the third quarter following the release of the drilling rig in late March and continued progress in well cost reductions. Turning to Slide 8.
You'll see that from a leverage and long-term capital perspective, total debt to adjusted EBITDA stood at 2.8x. This adjusted EBITDA figure annualizes the results for the last 2 quarters similar to our credit agreements, and captures the impact of our Central Basin acquisition that was closed early in the fourth quarter of 2014.
From a liquidity perspective, our position remains strong following our recent borrowing base redetermination at an unchanged level of $250 million, leaving us with $215 million of cash and credit availability to complement our internal cash flow generation shown on the right-hand chart. As we monitor our drilling plans in this environment, we'll continue to focus on our cash margins including the impact of corporate G&A expense with an additional data point beyond just raw-level economics.
While revenues per BOE, including hedges, have decreased by just over 35% since the first quarter of 2014 with the decline in commodity prices, our cash operating cost per BOE produced has decreased 33% over that period as well, resulting in an adjusted EBITDA margin of over $35 per BOE in a quarter that's average NYMEX oil prices were just under $50 per barrel. With our revised cost guidance for the year, we estimate that this adjusted EBITDA margin would be in excess of $40 per BOE of production for the remainder of the year based on recent strip pricing.
Gary Newberry will pick up on Slide 9 with an operational update.
Gary A. Newberry
Thank you, Joe, and good morning to everybody. With 10 gross wells drilled and 11 gross wells completed in the quarter, it was an active quarter for our team while running 3 rigs.
Our pace was a bit higher than expected as efficiencies were increasingly realized from the addition of the third rig in the fourth quarter, as well as the opportunity to participate in a non-operated Lower Spraberry well in Midland County, which now brings our Lower Spraberry well count to 5 in the basin. Outside of this well and our first 2 wells at Pecan Acres, most of our activity was focusing the Southern Midland Basin where we began our horizontal operations 3 years ago and continue to see strong results.
We brought a mix of 6 upper and lower Wolfcamp B wells online. These zones have been well established over the last 3 years, but we continue to optimize our completions and evaluate additional derisked zones.
We are currently progressing 3 initiatives in the southern area on this front. We are pumping higher proppant volumes with recent test of to 1,500 and 1,900 pounds per lateral foot.
We're evaluating the Lower Spraberry zone in Upton County and we're extending the delineation of the Wolfcamp A further east in Reagan County. We are encouraged with the early time performance of the Lower Spraberry at Bloxom and the Wolfcamp A at Garrison Draw.
Furthermore, the wells with increased proppant at Bloxom and Garrison Draw are exhibiting higher flowback pressures and rates early time, which is encouraging us to increase profit volumes across the Midland Basin. The exception seems to be Taylor Draw where the increased volumes have not performed any better than previous wells.
In the Central Midlands, we began horizontal development at our Pecan Acres area, with a stack test at the Lower Spraberry and Wolfcamp B. Again, we are still early time with these wells, but we are seeing strong performance in line with neighboring wells in the area.
Overall, we continue to be focused on efficient development of derisked zones, albeit at a slower pace for the time being. For now, we are producing over 60 -- from 60 operated horizontal wells, which has given us another opportunity to revisit our type curves with a larger pool of production data.
Before I get to that update, I want to discuss our progress on the well cost. Page 10 shows our achieved cost reductions and further targeted reductions, as we continue to work directly with our preferred service providers.
We are writing AFEs for $6 million for 7,500-foot drilled wells, which is a decrease of 20% relative to the fourth quarter of 2014. We started our discussion on this front with our key service providers on the drilling rig and pressure pumping side and have now expanded this dialogue with other components of the well.
With the progress we have made in recent weeks, we believe we will be writing AFEs in the low $5 million range for a 7,500-foot lateral in the second half of 2015. This would be a decrease of 30% from last year's levels, and a testament to the relationships we have built with our service partners in the Midland Basin.
Moving to Page 11. The cost reductions are critical to our near-term economics, but I also want to highlight the resource potential of our asset base that will provide the opportunity for longer-term value-added growth.
The left-hand chart shows our range of type curves for the Central Midland Basin, with an average of 639,000 barrels of oil equivalent for the Wolfcamp B and over 900,000 barrels oil equivalent for the Lower Spraberry for normalized 7,500-foot wells. This shouldn't be much of a surprise given the strong offsetting operating results, but it was important for us to see the results in our own wells over the past 12 months.
You can also see that we are still showing ranges for these zones and expect to see these converge to a tighter band with additional wells and extended well performance. The chart to the right shows our EUR ranges for the Southern Midland Basin, which continue to increase with time and have converged within a fairly tight band based on repeatable results.
A key driver to this subject has been the performance of our Garrison Draw field in Reagan County, and has also been helped by our increasing use of gas lift at our well-established East Bloxom development in Upton County. We've also laid out the economics of our drilling program and actual drill-bit lengths, assuming our targeted P&C and flat $55 per barrel pricing.
Average IRRs are strong in the range of 30% to 55%, but equally as important, our NPV per dollar of investment is 60% to 100% and payback periods of between 2 and 2.5 years on average. Our Lower Spraberry results are clearly at the higher end of the economic ranges.
And with this type of performance, we will be shifting additional capital to this part of the portfolio in the coming months as we're refocusing on -- as we focus on adding to our asset value and growing our reserve base at a relatively low F&D cost per well. The next slide compares our current type curves to some of our Midland Basin peers that publicly disclosed comparable EUR data.
The chart is a summary of oil-only EURs on a barrel of oil per drilled lateral foot basis. This presentation adjusts for 2 key differences between Callon and some of our peers.
One, we are a 2-stream reporting company which generally understates volume by approximately 15% relative 2 -- 3-stream reporters. And two, IP data can be misleading even on a 30-day basis depending on the method and timing of artificial lift.
We have been moving to gas lift in our more established areas, which typically has lower early time rates, but longer-term shallower declines. Based on this data, both of Callon's central and southern positions compared favorably to the peer group.
Again, this shouldn't be much of a surprise given our Central Midland position, but this chart does a good job of highlighting the quality of our southern position as well. It further illustrates the increased potential of the Lower Spraberry, which is driving our development realignment and focus for the remainder of 2015 and 2016.
Page 13 provides an update on operational plans for 2015 and some early insight into our capital allocation for 2016. With a very flexible drilling plan that isn't driven by obligation wells, we're able to react quickly to opportunities that arise.
Clearly, the Lower Spraberry is one of those opportunities, and we are now planning to drill 14 gross Lower Spraberry wells in 2015, relative to 5 wells in our original plan. Our plans now also include the drilling of 27 net wells versus a previous 24 net wells, including non-operated activity.
Part of this increase is attributable to Callon stepping into the interest of small non-consenting working interest partners in new horizontal wells as well as a slightly quicker pace of development due to efficiencies we're realizing on both drilling and completion. In total, we now plan for operational capital, which includes drilling and completion and facilities of $160 million to $165 million, which is in with the range of previous guidance, despite the addition of 3 net wells.
This capital range is based on well cost reductions that we have achieved to date, where we are targeting additional reductions by the second half. After decreasing activity for the first quarter's 3-rig activity levels, we expect our normalized operational capital spend to be $30 million to $35 million per quarter in the second half of the year based on current costs.
On the lower right-hand chart, you can see that we will be drilling an increasing proportion of Lower Spraberry wells as the year progresses, which will continue into our 2016 plans as we reallocate capital within the portfolio. Finally, I will turn to Slide 14, which summarizes our updated production and cost guidance for the year, and introduces similar guidance for the second quarter.
Based largely on our type curve increases, we now see total production for 2015 at just over 9,000 barrels of oil equivalent per day at the midpoint. We also expect our second quarter production to increase approximately 500 barrels of oil equivalent per day over the first quarter, and we are targeting an exit rate of around 9,500 barrels of oil equivalent per day this year.
In addition to these improvements in capital efficiency and resulting production growth, we forecast continued reductions in our per-unit production cost both at the field and corporate levels. I will now turn the call back to Fred for some final comments.
Fred L. Callon
Thank you. Excuse me -- thank you, Gary and Joe.
And again, we appreciate everyone taking the time to call in this morning. So we'll now open the call to questions.
Operator
[Operator Instructions] The first question comes from Will Green of Stephens.
Will Green - Stephens Inc., Research Division
So just looking at the slides, obviously some big numbers for Spraberry EURs and returns even at these levels. It looks like at this stage, you guys are planning on drilling more of those wells.
It looks like at the expense of some of the Wolfcamp B and Wolfcamp A. I wonder if you could just talk about how the Wolfcamp A stacks up versus the Wolfcamp B.
Is it a situation where the returns just don't compete with the Spraberry? Is it a situation where you don't feel like you can stack those as well?
I wonder if you could just elaborate on how you guys feel about the Wolfcamp A, and how that develops longer term?
Fred L. Callon
Yes. Well, again, we're very excited with the Lower Spraberry.
It's obvious, the results are pretty stellar. We've done most of our work on the Wolfcamp A in the southern part of the basin.
And as we compare the A to the B, it's slightly less than the B at Bloxom, but we're pretty encouraged with the A at Garrison Draw. So it's a little different.
The Garrison Draw well is a lot stronger than the well that we had at Bloxom, and we're pretty excited about it, but it's only 1 well. So we're still a little slow, I guess, in trying to think of how we move that forward.
But the results we're seeing in Garrison Draw in the B and the A are pretty spectacular results. It's helping us drive and achieve some of the significant production we've achieved -- production growth we've achieved quarter-on-quarter, because a lot of the wells we've actually drawn on were all in the southern part of the basin.
And so, we're all excited about the A there. But at this point in time, we just don't have enough data to jump in there to and say, we're just going to go ahead and rank it differently or it's much better than the B, or even suggest it's as good as the Lower Spraberry yet.
We just don't have enough data.
Will Green - Stephens Inc., Research Division
Got you. And at this point, do you guys have any -- do you feel like that column is thick enough to potentially at some point in the future have still a stack with Spraberry, Wolfcamp A, Wolfcamp B, a number of those pretty tightly close in there together?
Gary A. Newberry
We do. And again, it's kind of our philosophy, especially in the central part of the basin.
We watch all that development very closely, and we believe that potential exists. And in this price environment, we're really focused on just a little bit of de-risking in some of the fields, but primarily focused on things we know will work and drive production, and we developed a low F&D cost and really add value.
So we'll still be watching our partners intently as they further delineate those zones for us. It's kind of a nice position to be in to be surrounded by some great partners.
Operator
The next question is from Phillips Johnston of Capital One.
Phillips Johnston - Capital One Securities, Inc., Research Division
Just a couple of questions for Gary. On the increase in the type curves, would the new figures apply to all of the drilling locations in your total inventory?
Or would they just apply to the locations that you expect to drill this year and next, so we should consider that more sort of a high-graded type curve?
Gary A. Newberry
Again, this type curve has moved up over time, primarily because of the way we've gotten a lot more confident in the assets, and we've improved upon some of the completion techniques. And we feel confident that certainly in the Southern Midland Basin, on the B certainly, that type curve works pretty well.
And Central Midland Basin, there's still a pretty wide range there, especially on the Lower Spraberry. We hope to continue to move that average up to the upper end of that range.
But what we're showing are results from the wells we have. Those type curves are wells we have, delivered and wells we intend to deliver going forward.
So I wouldn't suggest it covers all of our inventory, but certainly the inventory that we have focused on those specific zones in those basins, those parts of the basin.
Phillips Johnston - Capital One Securities, Inc., Research Division
Okay. And then just the -- I guess you've talked about the 3 important wells that you had sort of in progress in the south, Lower Spraberry at East Bloxom, the Wolfcamp A test and the Wolfcamp B.
I think that was testing a design of 1,900 pounds, I think, of sand per lateral foot. Is it too early to talk about IP rates or 30-day rates on any of those wells at this point?
Gary A. Newberry
Yes, it's probably too early to talk about the specific performance of those wells. We're very encouraged with certainly the Lower Spraberry at Bloxom.
That well is doing quite well, it's very steady. It's just like we're being gentle with it.
We have a small sub pump in that well, pulling it pretty easy. And our rates are very steady.
Pressures are good. Water rates are still dropping while our oil rates are still increasing.
And on the A at Garrison Draw, that's a pretty strong well as well, and we're encouraged with that. And those wells were pumped with a little bit more sand, okay?
Now if you ask me about the 1,900 pounds per foot of sand, and we actually did that at Taylor Draw, and that was a bit of a disappointment. I'll just submit that, that didn't work.
Maybe it didn't work because Taylor Draw is a little shallower, it's a little bit lower pressure. But that didn't work any better than what we've been previously pumping closer to around 1,300 pounds per foot.
So we had 2 wells test there and both are producing similar to the previous wells.
Operator
The next question is from Neal Dingmann of SunTrust.
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division
Gary, just wondering, are you limited on the lease lines by how long laterals you can do? And it doesn't appear to me that you are.
And if not, just your thoughts on even taking these laterals out even further?
Gary A. Newberry
Neal, we're certainly optimizing lateral lengths where we can. Again, at -- Garrison Draw is a good example.
We kind of -- we've got 3 strong Wolfcamp B wells there -- 5 strong Wolfcamp B wells there, that have been flowing back for a long period of time. We've got 3 7,500-foot laterals that have been flowing back for nearly 5 months now.
And we just keep opening up choke and under natural flowback, they're just performing phenomenally well. The 2 wells we've recently brought on in this quarter were 10,000-foot laterals at Garrison Draw.
So we saw the opportunity to extend the lateral lengths to, again, minimize our cost to access the resource. And those wells are flowing back at even higher pressures and higher rates early time than the 7,500-foot wells.
So we're doing where we can extending our lateral lengths, but honestly, in some places we're limited. Even though we're very excited about the Lower Spraberry results at Pecan Acres, and Casselman-Bohannon, those wells -- the lateral lengths for the 2 wells we have in that area are close to around 4,400-feet completed lateral lengths.
So because of geography, we are a bit limited on lateral lengths where we can. Fortunately the wells going forward at Casselman-Bohannon, we have off-lease surface locations secured now.
So those lateral lengths will be extended by about 10%. We get up to about 5,000 completed lateral length, which we're encouraged with that opportunity.
And then at Carpe Diem, where -- certainly on the East side of Carpe Diem where we have 3 sections north and south, we've optimized our lateral length by putting the surface locations in the center. So on average, 7,500 feet north-south.
So we work hard on every asset that we have to maximize our lateral length and minimize our cost of development, and the capital necessary to access the resource the best that we know how.
Operator
The next question is from Jeb Bachman of Scotia Howard Weil.
Joseph Bachmann - Scotia Howard Weil Incorporated, Research Division
Joe, just a question for you on the IRRs. Are those fully loaded IRRs or are those just at the well?
Joseph C. Gatto
They're wellhead economics, Jeb.
Joseph Bachmann - Scotia Howard Weil Incorporated, Research Division
So if you were to fully load those, what would those look like?
Joseph C. Gatto
Probably have to discuss what kind of parameters in terms of G&A or overall corporate costs, and factors beyond that.
Joseph Bachmann - Scotia Howard Weil Incorporated, Research Division
So I just meant mostly with infrastructure that kind of stuff associated with that program.
Joseph C. Gatto
Oh, the infrastructure, we do -- per well -- we spend about $150,000, $200,000 per well. But outside that, we spend a lot on infrastructure already.
We've been in program development for 3 years, so there's not a lot of incremental infrastructure going into support those well economics, certainly for the fields outside of Ca-Bo. We are spending a little bit more to upgrade the infrastructure we bought with that acquisition for horizontal development.
But overall, our infrastructure spend on the assets there that are shown there is going to be pretty limited. I don't know, Gary, do you want to address that any differently?
Gary A. Newberry
Again, it's usually getting hooked up to our existing facility, so it would be a little limited for now. Ca-Bo, as we drill out those section, we'll upgrade the facilities that are there because the facilities there are just meant for the vertical development that's already existing.
So we'll have to expand that as we go, but that will be measured over time.
Joseph Bachmann - Scotia Howard Weil Incorporated, Research Division
Okay. And I guess just to follow on that, Gary.
With the cost reductions, do you guys have a breakout between efficiency and just the service vendors bringing down cost in this environment?
Gary A. Newberry
No. Again, efficiencies are coming little by little, little chunks.
I mean, our team is focused on every aspect of the well, from drilling it, to moving rigs, to efficiently setting up the site, to minimizing the length of time necessary to get it fracture stimulated. So there is -- those are just little small parts that we know we were gaining on over time.
Drill curves are slightly moving to the left on depth versus days curves. So I don't know the breakdown of that, and the comparison that what we've actually achieved on service providers.
Most of it is service providers that stepped up big time for us, as you know, early time the drilling rigs came down, the frac services came down. There's tremendous competition in the basin now, especially around frac services, pumping services.
We're getting calls on a weekly basis from vendors saying they built tremendous capacity and they want to put it to work. So there's still opportunity in every aspect of what we do to construct and complete, and produce a well that is allowing us to anticipate and drive for additional cost reductions over what we've already achieved.
Joseph Bachmann - Scotia Howard Weil Incorporated, Research Division
Okay. And the last one for me, maybe this is for Fred.
On M&A, had some announcements this morning. This morning, kind of you guys are still in that market, in the size, the size of the deal you guys will be comfortable with at this point?
Fred L. Callon
Yes, Jeff, the answer is, yes, we certainly are. We're in the market, but at the same time we're certainly not competing in that size range.
As we've talked before, I think part of the reason we did additional equity here earlier this year is to provide some additional capital to opportunistic with acquisitions during the year. As you know, we are focused we think on a core of the Midland Basin.
So we recognize things are not going to come cheap, but we continue to think we're -- again, there are opportunities out there, they're smaller. But we think we'll be successful this year, continuing to add to our acreage position, starting the bolt-on acquisitions that we've talked about.
Operator
[Operator Instructions] The next question comes from Ron Mills of Johnson Rice.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
A couple of questions, left. When you look at the increased proportion of Lower Spraberry, Gary, did you say in terms of gross wells that, that well count is on the Lower Spraberry this year is going from 5 to 14?
Gary A. Newberry
Yes, sir, I did. And when we started seeing those results on our wells up in the central part of the basin, we got a well at the current acreage.
We got a well at Casselman-Bohannon. We've now got 2 wells there at Carpe Diem given our own well and the non-operated well.
And so, we're very excited about those results. We're seeing it and we're seeing the steady nature of how those wells are performing.
And so, what we have heard and what we now see in the Lower Spraberry is real. And we're quickly adjusting our planned Wolfcamp B wells to Lower Spraberry wells in those same fields.
So that was a very easy adjustment for us, because we already had planned the pads, we already had planned wells. We had already worked out facility plans that were already in our scope.
So we're getting just a little bit shallower this year and get significantly better performance. That's what we're doing.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And so -- and maybe I can get this from Joe off line, the 5 gross -- the 9.1 net is up from how many net wells? And then when you look at '16, at least preliminarily, you show 15.6 net wells out of your 21.8 being Lower Spraberry, so almost 3/4.
Similar questions on gross to net there.
Gary A. Newberry
Yes, from our original plan, Ron, if that's a question. I think we had 3 net Lower Spraberry wells in the plan, and now we're going to 9.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
To 9. And then when I look at '16, you've 3/4 of your wells, at least your preliminary plan here being towards the Lower Spraberry.
Are the -- is your average working interest relatively constant '15 to '16?
Gary A. Newberry
The answer would be yes for the wells that are targeted this year and next year, because most of those wells are targeted in our Central Midland Basin. We'll have both rigs operating out there in the Lower Spraberry.
So it's comparable.
Joseph C. Gatto
Maybe a little bit lower in '16, Ron, just because the first quarter of this year with the activity in the Southern Basin. Directionally, we're going to have a higher working interest there versus the 2016 plan, we'll have probably a bit more Central Basin activity, which is a lower working interest.
Gary A. Newberry
Yes. My reference was just to the Lower Spraberry.
Our Lower Spraberry would be comparable.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And then when I look at your Lower Spraberry, at least as of last update, you had about 170, 175 Lower Spraberry wells in inventory. With -- given the results you've had and increased industry activity to that zone, any opportunity for more of your acreage to have Lower Spraberry?
Or are you still comfortable with that inventory count?
Gary A. Newberry
Again, we've been paying attention to what certainly Diamondback and RSP have been saying about that zone. We've got 8 wells per section in our inventory.
And so, it's -- you get to those numbers, we've got about 120 locations in the Central and closer to 40 or 50 locations in the Southern. We're very focused on the Central this time until we see more data and get more encouraged with the well that we just brought on at Bloxom.
So, yes, that inventory count could go up based on down-spacing. We've got companies out there talking about 10, 12 wells per section.
We're not quite there yet, but it could go up.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
That 10 to 12 compares to 8 for you?
Gary A. Newberry
That's correct.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And then, Joe, on the 10% growth in terms of, I'm assuming that's fourth quarter to fourth quarter '16 versus '15. Is that assuming that 2-rig program, does that mean that you're thinking about CapEx run rate of $30 million to $35 million a quarter throughout '16 as well?
Joseph C. Gatto
That's correct, Ron.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And just one clarification, the -- for Gary, on Page 11, we have your EUR ranges. What's the difference between the yellow portion of the curves and the red portion?
Because I'm just curious what the delta is? It looks like you've had some recent wells there in terms of normalized EURs over 1.2 million, 1.3 million barrels.
What's going on? And what's causing that wide range?
Gary A. Newberry
The wide range is clearly -- what that data represents is the real range of wells that we've delivered from the lowest part to the best part. And then the range, of course, is driven by a small data set, and it's just a few number of wells.
So it's a fairly wide range. As we get more data, we would expect that as -- at least I expect that the average will go up and we will be moving closer toward the upper side.
But I can't narrow that range yet until I get a bigger data set.
Joseph C. Gatto
Yes, Ron. The colors are just -- the top end just being high, bottom being low in the midpoint.
So it just -- there's no meaning to the colors other than showing you the top end of the range.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
The range versus the average.
Joseph C. Gatto
Yes, yes.
Operator
The next question is from Mo Dahhane of Northland Securities.
Mostafa Dahhane - Northland Capital Markets, Research Division
Just a quick question. Just curious if you guys have any plans to test the Middle Spraberry in the Central Midland maybe in sometime in 2016?
Fred L. Callon
That's not in our plans yet, but we can always squeeze a well in. We sometimes think about that as we start seeing more and more data from our offset operators, RSP's done most of the work in the Middle Spraberry.
They're pretty excited about it. I think 1/4 of their activity levels has been in the Middle Spraberry.
And so we'll keep looking at that data. But at the present time, it's an exciting part of our inventory.
Operator
There are no other questions at this time. The conference has now concluded.
Thank you for attending today's presentation. You may now disconnect.