Callon Petroleum Co (CPE) 2015 Q3 法說會逐字稿

Welcome to 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 1 year.

I would now like to turn the call over to Eric Williams, Manager of Finance, for opening remarks. Please go ahead, sir.

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'll 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 and 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 call today includes comments that are forward-looking. 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 a discussion of certain non-GAAP financial measures. Please refer to the earnings release we issued yesterday afternoon for important discussions regarding such measures and the corresponding reconciliation. 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-and-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?

Thank you, Erik, and thanks to everyone for joining us this morning. Looking back at our last earnings call on August 6, a lot has changed for the commodity markets and for Callon. Oil prices continued to decline through August, ending down with 30% from levels in early July. We've seen a bit of stability in the $45 range, but uncertainty 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 oil 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.

This is the type of capital efficiency that will enable us to stay on our path of living within our means and restricting 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 teams 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 the LOE and G&A came in at the low end of guidance.

Importantly, our EBITDA margin per BOE remained strong at 70%, with improvements in both cash costs and realized prices per barrel of oil produced. This margin [just marks] the best across our Permian peer group, driven by the highest percent 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 we 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 dollars are well spent as we focus on the Lower Spraberry with pad development.

On our last call, we talked about a 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.

Thanks, Fred, and good morning. I will start on slide 4 with a summary of our activity in the third quarter. We placed 7 wells on production in the quarter, with 5 Wolfcamp B wells and 2 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 online 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 decline tests from that pad, but 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 Basin 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 a focused development program.

While developing the Lower Spraberry zone will be our principal 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 clean up, we are encouraged by better than expected oil volumes during flowback 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 and 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 5 years of inventory at our current pace of 15 wells per rig 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 increased almost 30 years under a $50 to $60 per barrel assumption with additional contribution from our Southern fields as well as decline in Jo Mill targets.

Given our Lower Spraberry focus moving forward, we've provided an updated view of well economics on page 6. 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 of over 900,000 barrels of oil equivalent. We will be revisiting this type curve later this year with extended well performance and the additional wells that have been placed online 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 the returns are strong relative to other drilling opportunities, we're 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 payout 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 own 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 plans. While the Central Lower Spraberry returns are ahead of our Wolfcamp B program, 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 set would attract significant capital today in many drilling budgets, but we will defer these projects in favor of maintaining a level drilling cadence targeting the outstanding returns of the Lower Spraberry, while we 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 lower with recent AFBs 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, but we are 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 costs over the last several quarters with improvements in workover expense and realized benefits from investment in infrastructure. We are pleased with the progress we have made over the last several quarters and are also proud to be among the lowest-cost operations in the basin, as shown on the right-hand chart.

Turning to slide 11, I'll 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 50% 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.

While the third quarter spending was a bit higher 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.

Pulling 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' investments in 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 new 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 depth-severed rights that prevent us from efficient development of multiple stacked zones. This very high level of flexibility positons Callon to address emerging opportunities and challenges as well as any company in the basin.

Joe Gatto, our Chief Financial Officer, will pick up on slide 13 with a financial discussion.

Thanks, Gary. From a financial standpoint, we had another solid 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 improvement 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 Midland Cushing pricing differential and the early impact of putting our Southern Midland fields on gathering systems. East Bloxom was put on a gathering 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 are also working toward having our last major producing field, Carpe Diem, on a pipe in early 2016. In the meantime, we've been seeing improvements in the cost of trucking our crude with continued infrastructure buildout 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 2 times the preliminary 2016 capital budget that I will 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 wells will provide a strong operational momentum into the fourth quarter in 2016 as the new drilling plan hits full stride.

I'll finish up on slide 15 with a review of how our new focus impacts our outlook for 2016. We presented a similar view in August, but as we noted, a lot has changed, starting with an increase in the proportion of Lower Spraberry wells planned.

While in the aggregate, we are now planning for fewer net wells in 2016, the capital efficiency of the optimized 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 that 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 will 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, it is a byproduct of the pursuit of our top goals of living within our means and generating capital efficient growth from disciplined investment and high-return projects.

The chart in the lower right-hand corner provides some context on this point, comparing the efficiency of our expected liquids growth to that of our peers 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 the 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.

Thank you, Joe. In summary, let me say I'm extremely proud of our employees and the way they've adapted to a very difficult commodity price environment. We continue with our operating cost structure and capital efficiency in the current environment, which further advances our goal of funding our drilling program with internally generated cash flows by mid-2016.

It's clear our focus will now be on the Lower Spraberry, though as you would expect, we'll continue to monitor surrounding peer activity and well performance in the Wolfcamp A and Lower Spraberry.

Fortunately, we have a strong balance sheet, high-quality assets being managed by one of the best operating teams in the Permian Basin. And I think combining these will provide a solid foundation that'll allow us to continue to grow and create value for our shareholders, even if oil prices are lower for longer.

I'd now like to open the call for questions.

We will now begin the question-and-answer session. (Operator Instructions) Neal Dingmann, SunTrust.

Gary, for you or Fred or Joe, just wondering, the new plan you have obviously looks like going up in the north in the core. And you talked about [spending] cash for next year. Are there different -- can you walk through maybe some different sensitivities depending on again, what oil might do, where you would think about either potentially having to either drop a rig or potentially adding a rig?

Do you want to start on that, Gary or --

Gosh, I guess sensitivities for us, Neal, are really going to hinge 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 movement 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.

Yes, and Neal, around that, obviously, it's a question we field quite a bit, but it really is predicated on what our views are on the cost structure, right? Because 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 scenarios. 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 rigs because we would expect that the Permian Basin is going to be ground zero for additional drilling activity and you'll see service costs move up. So we just want to understand what that cost structure is going to be before we make a commitment like that.

No, that makes sense. And just my follow-up, Gary, when you go -- when you're drilling this newer plan, thoughts about multi-stack laterals and as far as multi-well pads, just how you're going to tackle this for 2016? Thanks.

Yes, Neal, 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 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 well stack pads, but we'll stay very focused on the Lower Spraberry. But 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.

Thanks.

Jeb Bachman, Scotia Howard Weil.

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?

Yes, 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 pad, the two Lower Spraberry and the Middle Spraberry. And we're happy with the way that sand went away.

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?

That's correct. Yes, there's two horizontal rigs running, both Cactus rigs and both at 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. It's really a function of, in the Central part of the basin, we have a lower working interest in the Southern but -- so it's not a reduction in gross well activity. It's really a net reduction on two rigs.

And Jeb, just as far as the rig rate, we have no indication that that rate is going to change. I think the market is finally catching up to where we've been. I've heard other companies 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.

Okay. And last one for me, Joe, on the transportation. Is that interruptible or is that firm contracts on those pipelines?

We have dedicated production to those gathering systems. So these are smaller diameter pipes, not necessarily the Bridge Tex type of a pipeline that you're committed to a firm tariff. These are negotiated with people like Plains 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.

Yes, a common carrier system that -- if there are any interruptions or curtailment, the whole industry will be curtailed equally so -- but certainly, look to have plenty of capacity for what we have planned for next year.

All right. I appreciate it, guys.

Ron Mills, Johnson Rice.

Just along the -- a 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 it 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-foot and 9,000-foot type laterals?

Yes, 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 drove that up, but Carpe Diem, as well as the east side of Pecan Acres, provides the option to drill 9,000-foot and 10,000-foot lateral length wells.

And as we stay focused on our Central Basin asset, we'll be moving in and out of those areas, as well as moving in and out of our -- the west side of Pecan Acres and into our Casselman and Bohannon area. So in total, our average lateral length will likely be 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.

And then given the way that Casselman and Bohannon is a little bit more checker-boarded than Pecan Acres and Carpe Diem, when you look at those two rigs, any sense as 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.

Yes, I think the way you should think about that, Ron, is we'll have one rig fully dedicated to Casselman and 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 sure 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.

Okay. And with both rigs now up in the Central Midland Basin, are the -- 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?

Yes, again, we're still doing some additional work for the sections that we're drilling. And I'll just go right back to your statement about the checkerboard area for Casselman and Bohannon. That's really driving 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 some more of that to do in 2016, thus the reason that 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.

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 WTI, is that about what we should expect going forward or is there still some potential improvement via lower transportation cost to get you in terms of the differential and transport costs, continue to move that down a little bit?

Yes, I think there's going to be two key pieces of that, Ron. Obviously, 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. It'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 we plan 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're 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 at about minus $3, $3.25, I'd say, as a reasonable estimate going into next year as all-in differential versus TI.

Great. Let me get back in line. Thank you, guys.

Gabe Daoud, J.P. Morgan.

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, appetite to remain opportunistic throughout 2016?

Yes, Gabe, thanks. This is Fred. As we've said before, we continue to actively look at -- look for opportunities. We've seen, I'd say, a good amount of deal flow. Haven't seen as much [sort of] clear the market, so but 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 as we look into 2016, we think we'll see more. It looks like it's going to be -- continue to be good deal flow. So we'll continue to remain active looking.

Thanks, Fred. And then maybe just reading a bit into this too much, but I guess given the longer laterals and non-consents and continued type curve out-performance by the Lower Spraberry, I guess maybe I would've expected to see a bump on full year production guidance. Any thoughts there?

Yes, so certainly, we have a bit of momentum going into the back half of the year. Say, one thing that's dialed into that in the fourth quarter were some issues around offtake in our Bloxom Field, that there was an issue with the gas plant that curtailed us on gas and oil for a decent amount of October -- right Gary -- that influenced 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've led you to a different answer than otherwise. Is that fair, Gary?

Yes, that's very fair even though West Texas gas and plants there that we send our gas to had an incident in -- on September the 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 [a buck]. But we're back to where we're full up and running and feeling good about where we are.

Thanks, guys. And then just maybe one final one from me. Obviously, impressive cost reductions thus far in the 7,500-foot lateral. How much lower 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 do you think that could ultimately get?

Again, that's always a moving target, but one thing we've been impressed about is the amount of interest that people have in doing work for us. We have a lot of service providers who have capacity in their schedules that are continually coming to us saying they can do it 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 our [ProPetro] Group has done. And we intend to continue with that group. But frankly, there's some significant cost savings being offered by several other pumping services providers that could lower that cost considerably.

So we're going to go ahead and schedule that in in the first quarter of 2016. Everybody already knows about it, so at least the service providers know about them. Everyone talks about who they are at this point in time, but that as well as we're seeing significant reductions finally in tubular costs coming through now.

We have a significant effort, internal effort, and having very detailed discussions with all of our service providers still at this lower price environment. And having that relationship positons 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.

Thanks, Gary. That's all I had. Thanks, everyone.

Ipsit Mohanty, JMP Securities.

You talked about average lateral length in 2016 [concerning] your fourth quarter. Would you be able to provide an average working interest as you kind of move back and forth between regions in the Central Midland?

Yes, that information is provided actually on slide 6, but we didn't really focus on it. But if you look at average lateral length planned for 2016, 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, all of 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 kind of participating. So we're happy to have them with us.

Sure. Now, it seems like a bunch of your guidance has hinged on your sort of reliability on the Lower Spraberry results. When I look at slide 15, you have the 1.3 wells in Upper Wolfcamp, Wolfcamp B. Is that still in Central Midland or is some of it kind of left over from the Southern Midland?

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.

Got you. And then coming back to Lower Spraberry, a bunch of your peers have actually guided even higher going towards the 1 million MMBOE EUR. So in that case, do you see your EUR estimates sort of trending up toward that or you're happy where you are?

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. And that curve is likely going to move up. We just wanted to get a more statistically significantly number in our own working system before we did, but clearly, everyone seems to be out-performing that type curve and as we are. So yes, we would expect that to move up sometime next year.

All right, great. Thank you, guys, good quarter.

Stephane Aka, Seaport Global.

I was hoping to revisit the Middle Spraberry a little bit. I know you touched on it earlier, but just wondering if you could kind of frame it for us in the context of how you think this would -- 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.

Yes, 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 would 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 offside operators.

It took sand equal to the Lower Spraberry. It drilled out exactly the same. We had no issues with drilling it out. And we had drilled oil on flowback and we've got good increasing oil even 4 or 5 days after putting it on top. So right now, it's acting exactly like the Lower Spraberry. Now, this is only one data point, but we're pretty excited about it.

Thank you.

Chris Stevens, KeyBanc.

Just wanted to get your view on the Lower Spraberry down-spacing. What spacing are you planning to develop your acreage on in 2016? And since most of your focus is on the Lower Spraberry near term, do you see a need to go out there and test tighter spacing earlier, rather than later?

Again, we had the benefit of learning significantly from our peers. They've published a lot of data; they've shared a lot of data with us, especially around the way we intend to jointly develop the activity around 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 session. And they're even testing a little bit tighter spacing, but we're 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.

Okay. Is that going to be a stagger stacked sort of pattern or is that on the lower portion of the Lower Spraberry?

Our plan is stagger stacked, but again, based on some recent results published by those guys, they're getting exceptional results with even the same level piped into the spacing. So we'll continue to pay attention to learn as a group because we'll share our results with them. And hopefully, we'll continue to see their results as they continue to move that forward.

Okay, great. And are you able to quantify any of the uplift in well performance that you're seeing from the increased proppant loadings up to 1,700 pounds per foot level more recently?

I guess I can quantify it generally in that as we get more sand in the ground, whether it be Wolfcamp B at Garrison Draw recently, or whether it's even the Spraberry wells that are coming back now. The early indicators are -- indications are pressure. The early indications are first oil, the ability to flow in a zone 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 at those lower early-time production times.

But again, we don't have enough data over time to tell you how long that's going to help how to quantify it other than it's more encouraging early-time that we see in both the Wolfcamp B and the Lower Spraberry. So it's difficult to say it's an uplift of a certain number of barrels for a certain incremental cost simply because the data set is too small.

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?

Our 2016 plan is based entirely on the type curve that we published, so no. And that type curve has moved up a little bit, as you know, from quarter to quarter. But we think it'll likely move up some more.

Okay, great. Thank you.

Irene Haas, Wunderlich.

My question has to do with throughout this whole downturn, Callon has just been working very, very diligently on improvement in the efficiency gain and such. So would you be able to give me some color, say, in the last 12 months sort of on an apples-to-apples basis, what has been happening to your drilling days from spud to release? Then my second question has to do with the weather. Are you guys seeing any el nino impact in the Permian this quarter?

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 bit selection, better tools, different mud systems, different types of ways to reduce 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 and they keep at least tempering my expectations a little bit by saying they're 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 Midland that works diligently to be ready to frac that well just a couple of weeks after that rigs moves on, which I think that steady schedule, that rhythm or that rhythm that we're in, continues to get better. Whether it's just hours or days, it continues to get better.

And so I think that 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, a lot of different things that are being bantered around by our partnership that we have with all of our service providers that make a difference.

Your second question was --

Unidentified Company Representative: Weather.

Weather. We have seen significant weather so far this year. It's all been -- and a good thing in the form of rain, a lot of rain. And there's been all 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 it's a blessing, I guess, to have rain in Midland. So we won't be complaining about that.

Okay, great. Thank you.

Will Green, Stephens.

So you guys have obviously talked a lot about the capital efficiency side. And it sounds like drilling times are still coming down and particulars are getting better. Gary, you just mentioned a few things that you guys are doing with your completions guys to try and get these costs down as well. And you also listed a number of things on slide 9 on the cost initiative side that you guys are excited about.

I wonder if you could maybe talk for one or two of those points on slide 9 on the cost initiatives? And maybe give us some color around which one you're most excited about or which two you're most excited about? And what you ultimately hope that yields in terms of a cost or drill time or something like that.

Yes, well, thanks for the opportunity. I guess certainly 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 of that bundled services to us. 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's] request, to 24-hour pumping services from what we were doing for 16 hours, we're getting more stages done in a day now. And we shortened that cycle time for completions and we bring that fluid on, that rate on quicker. And we reduce other rentals that are out there, that used to be out there for longer periods of time of time for that.

The biggest opportunity still isn't on this sheet, and that is 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 that have their own sand supplies and really passing those through maybe at cost or more minimal margins.

But there is significantly opportunity there out to really hundreds of thousands of dollars per well. So that's what we're anxious to test in February and March of next year with another provider. It's only a [bit] at this point in time, but it's something that we're excited about.

And 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 from each provider, it all adds up. We recently got a significant reduction in tubular cost simply by going out and testing the market 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 on early 2016 test is this issue of whether or not these companies that have access to sand or a larger access to sand, and potentially leverage that access to the benefit of the industry, is real.

Great, I appreciate the color there. And then the other one I had was -- I don't recall or I don't have it in front of me -- what the exact breakdown of 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 should we think about any kind of PUDs that need to come out of the system this year? Or is that completely offset by the PDP you guys are adding, given that the PUDs that might need to come off may not have been contributing that much to the PV-10 anyway? Just how do we think about that equation as you guys move forward?

Well, that's a good question and we've looked hard at that, but if I can remind you, at the end of the year, we were like at a 1-to-1 PUD PDP ratio. Somewhere around that, we had less than a 2-year inventory of PUDs on the books. We're not challenged at all with any SEC 5-year rule. We've done SEC testing for the PUDs we have. There might be one or two that might come off, but they've been more than offset -- they'll be more than offset by the PDPs that we've added and the additional PUDs that are around those exceptional wells.

So we feel pretty good about where we stand right now. We're in the middle of our year-end [or] middle. Even though it's only October, we started it, our reserves, third-party reserves coordinators, DeGolyer and McNaughton. And they've done our database; they're looking at it and we'll have preliminary number s in mid-December and a final report in early January. But we feel pretty good about where we stand.

That's great to hear. Thanks for all the color, guys.

Kyle Rhodes, RBC.

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 any details on the zip code or size of deals you're looking at?

Yes, Kyle. As Fred mentioned, there's a lot of activity out in the basin at this point and whether that's in the form of outright sales, which as Fred mentioned, a lot of deal flow. A lot of things just haven't cleared as the infamous bid-ask spread is still a little bit wide on some things. But it seems to be narrowing a bit and probably set up pretty well going into 2016.

But outright sale is 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 -- they're set up to sort of capture resource, but maybe not as well set up to develop the resource. So given that we have extremely flexible operational base that we don't have any drilling commitments.

So if we did see opportunities like that, that we could come in and do a drill to earn or 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 trick to all that has got to be -- it's got to compete pretty well for capital in terms of what we're 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 dialogs on various different structures at any one time, so that's just one of them.

And that's helpful, Joe, thanks. And I guess maybe for Gary, is there any update on the acreage swap front, maybe specifically at CaBo? And then if you could sort of minus how long you can take those laterals that are now at CaBo?

No, I think what we're doing now is what we ought to plan for. Again, we worked hard with the offset operators asking. They're certainly interested in our results, but at the end of the day, they're not ready to join us. So I think what we're doing is what we should plan for.

Those wells are exceptional, even though they're -- if they're off-lease locations, they'll be 5,000-foot lateral lengths and if they're on-lease locations, they'll be closer to 4,500. But those wells are very good wells. They come in at the lower cost side and that Pecan Acres 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.

Great, guys. Appreciate it.

Jeff Grampp, Northland Capital Markets.

A shot at maybe a couple of quick ones on the cost side. I'm just wondering, looking at 2016 guidance, and the $110 million CapEx or so under current well cost, do you guys think maybe that's -- there's some conservatism built in there? Obviously, you guys had a great track record of incrementally moving the cost downward and with partners. Maybe you think that maybe there's some downward bias to the extent you guys can move cost incrementally lower?

We certainly hope so. We're just not ready to talk about it yet, but we have plans to move costs down considerably. And we're getting good indications from our providers that 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 this is the guidance we're going to give you for now.

Yes, we'll come back, Jeff, in early 2016 with a formalized budget that's 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 reductions 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-consents, that we can bake that in a little bit more as we get closer to that point.

But right now, $110 million, using current well costs, give us a little bit of leeway to handle anything like that. And we'll refresh it in January or February, but think it's a pretty good number. But hopefully, as Gary said, a little conservatism will take some of that just to give us some flexibility.

Okay. I appreciate the color on that. And then last one for me on the LOE front -- I'm 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's some efficiencies you guys can capture, investing in this infrastructure and really just focusing on this one area?

Yes, I think that -- again, we'll be tied into some pretty good capacity for water disposal that'll drive some of those costs down. As we look at continued work with all of our service providers, they're showing that 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.

Okay, great. Thanks for the color, guys.

John White, Roth Capital.

I wanted to 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?

On the staggered pattern, we are. That's essentially what the wells we just drilled that (inaudible), that's correct.

Okay. And that's the --

But it's not at the same vertical level.

Okay. So that's what RSP Permian refers to as the chevron pattern?

That is correct.

And did you mention you're contemplating even tighter than 500-foot spacing for the Lower Spraberry?

On these, no, we're not; we are not. We just wanted to test that there primarily to see if, in fact, we could squeeze in another well and to go from 10 to 11 because it makes sense to us that the patterns that both RSP Permian and Diamondback speak about, if you think about the exceptional results that they're getting, and their discussion about even a potentially tighter pattern, 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.

Okay. Well, that's pretty ambitious. And when might an 11 well program -- that would be like later 2016, right?

Oh, absolutely, yes, yes. 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 will be well after the first quarter before we can really talk about extending it beyond the 10-well pattern that people have kind of focused on.

Thank you and thanks again for such a nice presentation.

Ron Mills, Johnson Rice.

Hey, Joe, just on the acquisition front, Kyle asked one of the questions in terms of -- in addition to just outright acquisitions, it sounds like you're talking about drilling a [deep well], drilled earnings, etc. But in terms of timing, I know the acquisition market is always fluid, but are there particular packages or of course things that are out there that are expected to potentially get done by year-end? Or is this something that will likely progress over the next 3 to 6 months?

Ron, the -- again, larger packages, we've been actively looking at opportunities and as 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, [someone's] expectations kind of come in line with ours. So I can tell you, we're actively looking and making offers, but it's just very difficult to tell on the larger opportunities.

I will say on the smaller bolt-on type opportunities, more [into] what we're doing, those I think we're continuing to make some progress there. 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've seen a lot gearing up for 2016. And we'll continue to be in there looking, but it's just difficult to predict.

And geographically, would you say you're still more focused in the Permian or -- in the past, you've mentioned the Delaware as a possible area as well.

Yes, certainly, we're -- yes, 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'd take our skill set and apply it in the Delaware if the right opportunity came along, but we're certainly looking at the Delaware as well.

Okay, great. Thank you, guys.

Joel Musante, Euro Pacific Capital.

I just have a couple of quick questions for you. On your production guidance, what's baked into that in terms of your assumptions on Lower Spraberry? Is that kind of your EURs, your [type curve flip]?

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.

Okay. All right. And it looks like there might be some upside there from at least on the EUR number. So is this something that's going to get -- you're 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?

Well, the way I -- I get that same question from my CEO all the time. And the way I see it, Joel, is -- I don't want to [get ahead] of that curve, so I always want to get my own data set. I've got two wells flowing back, two additional wells being fracked right now. I got two wells going to be fracked next week. I'll have twice as much data than I've got on my own wells in about three quarters and at that point in time, I'll consider moving it up.

But to me, it's more of proving it to myself and proving it to you guys on my own data set versus looking at the very exciting data and the exceptional results being delivered by companies like RSP and (inaudible). Those guys are doing exceptional work in the same area that we're working in.

Okay. And how repeatable do you think the -- those EURs or some of the PUD results were pretty spectacular. So do you feel comfortable to say you can do that from area to area? Or there might be some local [geology] issues or -- I've heard people talk about depressurization from vertical wells, although Diamondback didn't think that that was a big problem.

Well, there's 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 real results in those areas. And we are a highly technically driven company, and so we do a lot of work from a petro-physical viewpoint on understanding our asset base from the zone thickness, 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 longer term consistent, repeatable results.

Okay, great. Nice quarter and that's all I had, thanks.

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Callon for any closing remarks.

Again, thanks, everyone, for taking time this morning to dial in. We appreciate all the questions and the opportunity to give you some more color around what we're doing here. So in the meantime, if anyone has any questions, please don't hesitate to give us a call. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.