Callon Petroleum Co (CPE) 2015 Q1 法說會逐字稿

Good morning and welcome to the Callon Petroleum first-quarter 2015 earnings conference call. All participants will be in listen-only mode. (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.

Thank you. Good morning and thank you for taking the 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 look at the slides, simply click on the PDF icon located on the Events & Presentations 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 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 Securities & Exchange Commission, 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 our earnings press release we issued yesterday afternoon for important disclosures regarding these measures and the related reconciliations to US 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 take your questions.

And with that, I would like to turn the call over to Fred Callon. Fred?

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 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 have been on the leading edge of well cost reductions. We've already achieved 20% wealth cost reductions, and we are on pace to drive those costs down another 10%. We anticipate that we will be drilling 7500 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 also worked hard on our cost structure with a 20% decrease for BOE and LOE from last quarter, and a recent corporate cost initiative is 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 for our own wells and then use offsetting well results to provide additional support for our EURs. We will begin a horizontal development. Over three 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 for the increasing set of 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 this growing body of work, our average Central Midland Basin type curve are now 640,000 barrels of oil equivalent for the Wolfcamp B, and there were $900,000 for the Lower Spraberry.

We 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 two to two and a half 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 into 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 two-rig program.

Looking out to 2016, 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 breakeven 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.

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, an increase of 97% BOE per day over our production level one 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 of 2014 weighed on our realized pricing before sold hedges.

Offsetting this decline to some degree was an improvement in Midland Basin differentials, which averaged approximately $2.00 per barrel versus approximate $5.80 per barrel last quarter.

In total, our unhedged oil price realizations were approximately 9% of average NYMEX prices during the quarter relative to 89% in the fourth quarter.

Going forward, we are 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 are already on takeaway pipe.

In addition, our realized natural gas prices per MCF also experienced a notable decline as NGL prices were under pressure in line with 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've seen some improvement realizations but expect that NGL pricing will continue to face headwinds in the coming quarters.

Our hedge position added support to our revenue stream with cash settlements related to our hedging program totaling $13.41 per BOE in the quarter. We continue 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 5000 barrels of oil per day under swap contracts for the remainder of 2015 and an additional 2000 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 excludes 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 appreciation.

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-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 forecasted 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. Non-cash unsettled losses of $5.1 million related to a mark-to-market of our hedging portfolio, a non-cash loss of $1.7 million related to the mark-to-market valuation of performance-based incentive compensation awards, a loss of $2.4 million for the early recognition of drilling rig payments that are anticipated to be made over the next eight months for the release of our rate in late March if that rig is not re-contracted by another party, and a loss of $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, regenerated $26.7 million of adjusted EBITDA in the first quarter and adjustments for the items I just mentioned, as well as other customary items.

Moving to page 7, in review of operational CapEx in the quarter, one can see that this was a busy quarter for us on the operations side under a three-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 three-rig program development as the quarter progressed.

Importantly, we did begin see the impact of the capital cost reductions we have 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 and 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 on 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 2.8 times. This adjusted EBITDA figure annualized the results for the last two 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 plan in this environment, we'll continue to focus on our cash margins, including the impact of corporate G&A expense or an additional data point beyond just low-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 saw average NYMEX oil prices of just under $50 per barrel. With our revised cost guidance for the year, we estimate that this adjusted EBITDA margin will 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.

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 three rigs. Our pace was a bit higher than expected as efficiencies were increasingly realized with the addition of the third rig in the fourth quarter, as well as the opportunity to participate in a nonoperated Lower Spraberry well in Midland County, which now brings our Lower Spraberry well count to five in the basin.

Outside of this well in our first two wells at the Pecan Acres, most of our activity was focused in the Southern Midland Basin where we began our horizontal operations three years ago and continue to see strong results. We brought a mix of six Upper and Lower Wolfcamp B wells online. These zones have been well-established over the last three years, but we continue to optimize our completions and evaluate additional derisked zones.

We are currently progressing three initiatives in the Southern area on this front. We are pumping higher property volumes with recent tests of 1,500 and 1,900 pounds per lateral foot, we are evaluating the Lower Spraberry zone in Upton County, and we are 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 profit at Bloxom and Garrison Draw are exhibiting higher flow back pressures and rates early time, which is encouraging us to increase property 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 Midland, 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 a larger pool of production data.

Before I get to that update, I want to discuss our progress on the well costs. 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 7500-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've made in recent weeks, we believe we will be writing AFEs in the low $5 million range for a 7500-foot lateral in the second half of 2015. This will 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 tight curves for the Central Midland Basin with an average of 639,000 barrels of oil equivalent for Wolfcamp B and over 900,000 barrels of oil equivalent for the Lower Spraberry for normalized 7500-foot wells. This shouldn't be much of surprise given the strong offsetting operator 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 uptick has been the performance at 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 D&C and flat $55 per barrel pricing. Average IRRs are strong in the range of 30% to 55%, but equally as important, our MPV per $1.00 of investment is 60% to 100%, and payback periods are between two and two and a half 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 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 tight 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 two key differences between Callon and some of our peers.

One, we are a two-stream reporting company which generally understates volumes by approximately 15% relative to three-stream reporters, and two, IP data can be misleading even on a 30-day basis depending on the method and timing of artificial lifts. 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 Central and Southern positions compare favorably to the peer group. Again, this shouldn't be much of a surprise given our Central Midland position, but the chart does a good job of highlighting the quality of our Southern position as well. It further illustrates the increased potential at 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 are 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 five wells in our original plan.

Our plans now also include the drilling of 27 net wells versus the previous 24 net wells, including nonoperated activity. Part of this increase is attributable to Callon stepping into the interest of small nonconsenting working interest partners and new horizontal wells, as well as a slightly quicker pace of development due to efficiencies we are 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 three net wells. This capital range is based on well cost reductions that we've achieved to date, but we are targeting additional reductions by the second half.

After decreasing activity for the first quarter's three 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 9000 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're targeting an exit rate of around 9500 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.

Thank you. Thank you, Gary and Joe. And, again, we appreciate everyone taking time to call in this morning, so we will now open the call to questions.

(Operator Instructions). Will Green, Stephens.

Good morning, everyone. So just looking at the slides, obviously some big numbers for Spraberry EURs in 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. It is a situation where the returns just don't compete with 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?

Again, we are 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 are 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 have at Bloxom, and we are pretty excited about it. But it's only one well.

So we are still a little slow, I guess, and trying to think of how we move that forward, but the results we are seeing at Garrison Draw and the B and the A are pretty spectacular results. It's helping us drive and achieve some of the significant production growth we have achieved quarter on quarter because a lot of the wells we have actually brought on were all in the Southern part of the basin.

And so we are excited about the A there. But, at this point in time, we just don't have enough data to jump in there and say we're just going to go ahead and rank it differently or much better than the B or even suggest it as good as the Lower Spraberry yet. We just don't have enough data.

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 to have still a stack with Spraberry, Wolfcamp A, Wolfcamp B, a number of those pretty tightly close in there together?

We do. And again, it's kind of our philosophy, especially in the Central part of the basin. We watch all that development quite closely. And we believe that potential exists, and at this price environment, we are really focused on just a little bit of derisking in some of the fields, but primarily focused on things we know will work and drive production and be developed at low FD costs 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.

Very well put. Thank you, guys.

Phillips Johnston, Capital One.

Thank you. Just a couple 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 so we should consider that more sort of a hydrated type curve?

Again, this type curve has moved up over time, primarily because of the way we've -- (inaudible) confident in the assets, and we 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 the Central Midland Basin, there is 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 are showing you are results from the wells we have. Those tight 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 and those basins, those parts of the basin.

That makes sense. And then just I guess you talked about the three important wells that you had sort of the progress in the South, the Lower Spraberry at East Bloxom, the Wolfcamp A test and the Wolfcamp B I think it was testing the design of 1900 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?

It's probably too early to talk about the specific performance of those wells. We are very encouraged with certainly the Lower Spraberry and Bloxom. That well is doing quite well. It's very steady. It's just like we are being gentle with it. We have a small sub pump in that well, 400 foot easy, and rates are very steady, pressures are good, water rates are still dropping while oil rates are still increasing, and on the A at Garrison Draw, that is a pretty strong well as well. And we are encouraged with that. And those wells will pump a little bit more sand.

Now you asked 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 admit 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 had been previously pumping closer to around 1,300 pounds per foot. So we had two well tests there, and both are producing similar to the previous wells.

Great. Thanks very much.

Neal Dingmann, SunTrust.

I'm just wondering, are you limited on lease lines by how long lateral 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.

We are certainly optimizing lateral lengths where we can. Again, where Garrison Draw is a good example, we kind of -- we've got three strong Wolfcamp B wells there, five from Wolfcamp B wells there that have been flowing back for a long period of time. We've got three 7,500 foot laterals have been drawn back for nearly five months now. And gosh, we just keep opening the choke and under natural flow back, they are just performing phenomenally well. The two wells we recently brought on in this quarter were 10,000 (technical difficulty) 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 7500-foot wells. So we are doing this the way we can, extending our lateral lengths. But honestly in some places, we are limited. Even though we are very excited about the Lower Spraberry results at Pecan Acres and Casselman-Bohannon, those wells, the lateral lengths for the two wells we have in that area, are close to around 4400 completed lateral lengths.

So because of geography, we are a bit limited on lateral length where we can. We see the wells going forward at Casselman-Bohannon. We have all these surface locations secure now. So those lateral lengths will be extended by about 10% to get up to about 5000 completed lateral length, which we are encouraged with that opportunity.

And then at Carpe Diem, we are certainly on the east side of Carpe Diem where we have three sections north-south. We've optimized our lateral length by putting the surface locations in the center, so on average 7500 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.

Thank you, guys.

Gabe Dowd, JPMorgan. Jeb Bachmann, Scotia Howard Weil.

Good morning, guys. Just a question for you on the IRRs. Are those fully loaded IRRs, or are those just at the well?

They are wellhead economics.

If you were to fully load those, what would those look like?

I would probably have to discuss what kind of parameters you want to run that on in terms of G&A or overall corporate costs -- (multiple speakers) beyond that.

I was just meant mostly with (technical difficulty) infrastructure, that kind of stuff associated with (multiple speakers).

Infrastructure, what we do per well, we spend $150,000, $200,000 per well. But outside of that, we've spent a lot on infrastructure already. We're going to program development for three years, so there's not a lot of incremental infrastructure going in to support those well economics, certainly for the fields outside of cabo. 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 that are shown there is going to be pretty limited.

Gary, you want to address that any differently?

No, again, it's just really getting hooked up to our existing facility. So it would be a little limited for now. Cabo, as we drilled out those sections, we will upgrade some of the reserves there because facilities there are just meant for the vertical development that's already existing. So we will have to expand that as we go, but that will be measured over time.

Okay. And I guess just to follow on that, Gary, with the cost reductions, you guys have a breakout between efficiency and just the service vendors bringing down cost in this environment?

Efficiencies are coming little by little, little chunks. 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 those are just little small parts that we know we we are gaining on overtime. Drill curves are slightly moving to the left on depth versus days curves.

So I don't know the breakdown of that in comparison to what we actually achieved on service providers. Most of it is service providers have stepped up big time. For us, as you know, over 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 are getting calls on a weekly basis from vendors saying they've built tremendous capacity, and they want to put it to work.

So there's still an 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.

Last one from me is for Fred on M&A. You had some announcements this morning. Just wondering kind if you guys are still in that market and the size -- the size of deal you guys would be comfortable with at this point?

The answer is yes, we certainly are. We are in the market, but at the same time, we are certainly not competing in that size range as we talked before. I think part of the reason we did official equity here earlier this year is to provide some additional capital to be opportunistic in acquisitions during the year.

As you know, we're focused we think on the kind of core of the Midland Basin, so we recognize things are not going to come cheap. But we continue to think there are opportunities out there, they are smaller, but we think we will be successful this year and continue to add to our acreage position sort of on the bolt-on acquisitions that we talked about.

I appreciate it, guys.

(Operator Instructions). Ron Mills, Johnson Rice.

Good morning. A couple questions left. When we look at the increased proportion of Lower Spraberry, Gary, did you say in terms of gross wells that that well count is on Spraberry this year is going from five to 14?

Yes, I did. And when we started seeing those results on our wells up in the central part of the basin, we've got a well at Pecan Acres, we've got a well at Casselman-Bohannon, and we've now got two wells there at Carpe Diem, given our own well and the nonoperated well. And so we are very excited about those results. We are seeing it, and we are 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 are 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 pads. We already had planned wells. We had already worked out facility plans that were already in our scope. So we can just drill a little bit shallower this year and get a significantly better performance to what we're doing.

So maybe I can get this from Joe offline, the [5] gross -- the [9.1] net is up from how many net wells, and when you look at 2016, at least preliminarily, you show 15.6 net wells out of your 21.8 being Lower Spraberry, it's almost three-quarters. A similar question is on gross to net there.

From our original plan, if that's a question, I think we have three net Lower Spraberry wells in the plan. Now we're going to nine.

And when I look at 2016, you have three-quarters of your wells, at least your preliminary plan here, being towards the Lower Spraberry. Are they -- is your average working interest relatively constant 2015 to 2016?

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 area. We will have both rigs operating out there in the Lower Spraberry, so it's comparable.

It will be a little bit lower in 2016, Ron, just because the first quarter of this year with the activity in the Southern Basin directionally we're going to have higher working interest there versus the 2016 plan. We will have probably a little bit more Central Basin activity, which is a lower working interest.

My reference was just to the Lower Spraberry.

That was very comparable.

Yes.

And then when I look at your Lower Spraberry, at least as of the last update, you had about 170, 175 Lower Spraberry wells in inventory. With -- given the results you 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?

Again, we've been paying attention to what certainly done (inaudible) have been saying about that zone. We've got eight 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 are very focused on the Central this time until we've seen more data and get more encouraged with the well that we just brought on at Bloxom.

So that inventory count could go up based on down spacing. We've got companies out there talking about 10, 12 wells per section. We are not quite there yet, but it could go up.

That 10 to 12 compares to eight for you?

That's correct.

And then Joe, on the 10% growth in terms of -- I'm assuming that's fourth quarter to fourth quarter 2016 versus 2015, is that assuming that two-rig program, does that mean that you're thinking about a CapEx run rate of $30 million to $35 million a quarter throughout 2016 as well?

Correct, Ron.

And just one clarification. Forgive me. 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 have had some recent wells there in terms of normalized EURs over 1.2 million barrels, 1.3 million barrels. What's going on and what's causing that wide range?

The wide range -- 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. It's just a few number of wells.

So it's a fairly wide range. As we get more data, we would expect as -- 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.

The colors are just -- top end being high, bottom being low and the midpoint, so there's no meaning to the colors other than showing you the top end of the Range. (multiple speakers) yes.

Perfect. I'm going to let someone else jump. Thanks.

Mo Dahhane, Northland Securities.

Good morning, congrats on a good quarter, and impressive EUR uplift. Just a quick question. Just curious if you guys have any plans to test the Middle Spraberry in that Central Midland maybe sometime in 2016?

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. Our RSP has done most of the work in the Middle Spraberry. They are pretty excited about it. I think a fourth 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.

Thank you.

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