Callon Petroleum Co (CPE) 2016 Q2 法說會逐字稿

Good morning and welcome to the Callon Petroleum second quarter 2016 earnings and operating results conference call. After today's presentation, there will be an opportunity to ask questions. (Operator instructions). Please note, this event is being recorded. A replay of this event will be available on the company's website for one year. I would now like to turn the conference over to Eric Williams. Please if ahead.

Good morning. Thank you for taking time to join our conference call. With me this morning are Fred Callon, Chairman and Chief Executive Officer, Gary Newberry, Senior Vice President of Operations and Joe Gatto, Chief Financial Officer and Treasurer. We'll be referencing the earnings results we posted yesterday to our website. I encourage everyone to download the presentation if you haven't already. You can find the slides on our Events and Presentations page located in the Investors Section of our website at www.callon.com . 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 call Callon's actual results to differ materially from the anticipated results or expectations being expressed in these forward-looking statements.

For complete discussion of these risks we encourage you to read our filings. Today's call will also contain discussions of certain non-GAAP financial measures. Please refer to the earnings release we issued yesterday afternoon and to the appendix of the slide presentation being discussed for important disclosures regarding such measures and US GAAP. You can obtain a copy of the earnings release in the new section of our website. Following our prepared remarks, we will open the call for Q and A and with that I like to turn the call over to Fred Callon and direct the audience to slide 4 of the presentation.

Thank you, Eric. Again thank you to everyone for joining us this morning. As always we appreciate your interest. As we discussed in our press release, this was another important quarter for Callon on several fronts. We closed on two core acquisitions in the Midland Basin late in the second quarter which added substantially to our inventory and increased our surface footprint to approximately 35,000 net acres. Beyond those transactions we obtained the goal that we had been driving our activity for the last several quarters which was living within our means while delivering sequential production growth. It was important for us to prove our ability to pivot the business as necessary during periods of all price volatility which we expect will persist in a rebalancing oil market. This operational flexibility enhanced our financial strength ultimately positioning us to take an advantage of these two acquisitions in the quarter and stay on a front foot and continue to grow our business in the Permian Basin. The map on slide 4 shows our current acreage position comprised on the core Monarch and Wild Horse and Ranger operating areas.

As you know we have been focused primarily in the Monarch area since late 2015 but have now added a second rig that will add activity and focus in Howard County later this year. Page 5 outlines several key highlights from a busy last few months. On the strategic side in addition to the larger acquisitions I mentioned, we continue to pursue both own acquisitions in our core areas including recent purchase of additional 4% working interesting in CaBo area. Our production in second quarter was approximately 13,500 barrels of oil equivalent per day, representing a 8% increase over the first quarter. Importantly we continue drive down our cost structure with cash operating costs just under $11 per BOE in the quarter which translated into an adjusted EBITDA per BOE of approximately $30 per barrel to help fund our capital program. Our focus on blocking and tackling in a very challenged commodity price environment has clearly paid dividends. We have also been able to pursue incremental activity that will contribute to our long-term growth potential including density tests and Lower Spraberry as well as our first completion in Howard County in the Wolfcamp A

Silver City A-1H with a completed lateral length of 7,400 feet was placed on first production in early July and produced over 48,600 barrels of oil equivalent of which 90% was oil in the first 30 days. We're very encouraged with early time performance which supports our technical views of Howard County acreage. This area will be a key focal point for our second horizontal rig that was added back in service last week. Although we don't expect to see much production contribution from our second rig this year, we are increasing our production guidance to mid point of 15,000 barrels of to oil equivalent per day on the continued strength of our base program. We recognize the challenges that still face the oil markets but we believe the returns offer by Callon's deep well inventory combined with a solid financial position more than warrant an increase in activity in 2016 as well as a planned incremental increase early 2017 if we continue to see signs of rebalancing and stability in the oil market.

I'll now turn the call over to Gary Newberry, Senior Vice President of Operations.

Thanks, Fred and good morning to everyone listening today. Moving to slide 6, from a high level, another successful quarter for Callon on the operations front with exceptional day-to-day execution on the Lower Spraberry drilling program in the Monarch area. Outside of the Monarch area our team was focused on positioning for the future with continued investments that will benefit our long-term capital efficiency and well productivity. This included initiatives to establish facilities in infrastructure that support program development. We also continue to dedicate substantial resources to evaluating enhanced completion techniques that will selectively test on upcoming wells. As Fred mentioned earlier, we will now be turning to efficient execution of the two rig program at Monarch and Wildhorse as well as getting prepared for the addition of a third rig in early 2017. In the second quarter we did experience unanticipated down time at our Carpe Diem field which is our largest producing area. While will we do factor in some down time in our forecast, this was a unique situation caused by two offsetting fracs close to our lease line over a short period of time. Several of our wells were watered out due to hydraulic interference which is typically mitigated by our artificial lift systems.

However, we experienced power outages at the same time as this interference which severely limited our ability to dewater the field during the month of the June. As a result, we estimate that we deferred approximately 425 barrels of oil equivalent per day of production for the quarter. Since the end of the quarter we have seen a strong rebound in production in July with a return to normal operations producing over 16,000 barrels of oil equivalent per day at the corporate level for the month. Turning to slide 7, I'll focus on recent activity in the three fields that comprise the Monarch area predominantly located in Midland County. We continue to see solid repeatable results from our Lower Spraberry wells as detailed here and in the recent -- and in the recent press release. With 30-day IPs that typically range from 135 barrels to 160 barrels of oil equivalent per day per 1,000 foot of lateral. In an effort to further enhance the returns from this highly productive area, we have had success extending lateral lengths which can be seen in the cross hatched acreage blocks of both Carpe Diem and Pecan Acres.

In addition we have just completed an agreement to drill 10,000 foot laterals northward from the western acreage block at Carpe Diem and are finalizing plans to do the same southward from the western block of Pecan Acres. We're looking to build on our success in this area with the addition of a new bench in the Wolf Camp A, with a 10,000 foot well that was spud last month at Pecan Acres. Given the large amount of oil in place in the Lower Spraberry, continued well density testing is very important to us, not only to ensure maximum recovery but also to avoid overcapitalizing the zone. As discussed previously we have moved to development on a 11 wells per section basis which would performed in line with expectations and are now looking to methodically increase our well density.

On that front, our 12 well per section test has not shown they degradation of performance after an extended period of time. This can be seen on page 8 in the top two charts showing production and intake pressure draw-down well could have been to a group of wells on basing. On our next step we're currently drilling a three-well pad using three wells per section density and expect in a pad to come online early in the fourth quarter of 2016. I will now turn to page 9 and a map of our position in Howard County which we calm the wild horse area. As I mentioned earlier, we've been busy developing the facilities and from to begin program development of this acreage position in the coming weeks with our second rig. We will begin with a focus on the Wolfcamp A and central Howard County moving from east to west on that position with two well pad development. In future quarters we look to broaden our program to include stacked development of additional zones in the Lower Spraberry and Wolfcamp B. We recently placed our first Wolfcamp A completion on production on July 3 and our sidewinder field which is in the northwest corner of Howard County.

In addition, we will continue our infrastructure build-out at wild horse and ranger and continue to seek acquisition and partnership well opportunities across our asset base to optimize development. With these initial investments, we will be well-positioned to increase our activity with a third rig as early as January, 2017 as we plan for success in the business. Which takes me to slide 11 and a snapshot of our portfolio of investment opportunities for the future. Following our recent acquisitions, we have increased our base of delineated potential locations concurrently producing zones to over 900 which translates into 18 years of drilling inventory assuming a three-rig base. More importantly, all of these delineated locations in our three focus areas are forecast to generate wellhead returns in excess of 25% at WTI prices under $55 per barrel.

With 700 locations meeting that hurdle at a benchmark oil price under $45 per barrel. This is a solid starting point that provide long-term visibility with production growth in a rebalancing global oil market. In addition, we will be working to expand this opportunity set through a well density test in the coming quarters and also pursue delineation of other perspective zones and acquisition opportunities. We have assembled an exceptional team that delivered from both a technical and cost perspective and we are looking forward to put in a team to work on a growing asset base with continued increases in drilling activity in the coming quarters.

I will now turn the call over to Joe to, our CFO who will pick up on slide 12 with the financial discussion.

Thanks, Gary. The quarter ended June 30, Callon reported adjusted net income per share of $0.05 which excludes the after tax effects of certain non-recurring items and non cash valuation adjustments including impairments and derivative losses.

We also reported adjusted EBITDA of 36.2 million a sequential increase of 41% from the first quarter. Both of these non-GAAP measures are reconciled in our press release. Moving to a breakdown of revenues, we grew production by 8% over the first quarter of 2016 while we only placed 3.4 net wells on production in the quarter, and experienced a downtime that Gary discussed, we benefited from just over a month of production from our Howard County acquisition and solid longer term performance from our Lower Spraberry program.

Our percentage of oil volumes was down 1% to 77% in the quarter which was partially impacted by a new initiative to reduce back pressure on our horizontal wells. This optimization has had a positive impact on oil production but also results in an increased flow of natural gas volumes under Lower pressure conditions. Overall, revenues excluding hedges grew 47% sequentially to 45.1 million. Driven by the increase in production in an uptick in oil, natural gas and NGL realizations resulting from improved benchmark pricing as well as a positive impact of reduced transportation costs.

Turning to slide 13, we've detailed our continued progress on reducing operating costs. We are proud of the team's continued efforts on the LOE front which have reduced LOE by over 20% year-over-year combined with a Lower cash G&A per BOE from an increasing production profile, we've achieved a 27% reduction in cash operating costs compared to just six months ago in the fourth quarter of 2015. Deducting the $10.90 per BOE of operating and G&A costs shown in the bottom left chart from unhedged price realizations, we generated over $26 per BOE of cash margin. This is excluding the impact of hedges to give a clear a picture for our capacity for sustained cash flow generation. This operating cost structure Has consistently provided the flexibility to absorb fluctuations in commodity pricing over the last two years and is critical to our ability to accelerate activity in the third quarter. On slide 14, we have highlighted a few important elements of our current financial position including liquidity of $345 million including the impact of an increase in our borrowing base to $385 million in July

In leverage of 2.3 times debt to EBITDA that aligns with our stated goals of obtaining this ratio under 2.5 times. Equally as important on the slide is the chart on the top right corner which illustrates the achievement of our stated goal of living within our means. In the second quarter, discretionary cash flow exceeded our cash capital expenditures by nearly $5 million. Clearly highlighting both the capital efficiency of our drilling program and our lean operating cost structure. Combining this firm foundation of cash flow with an ample liquidity position, we are well-positioned to responsibly fund our growth plans that we will detail on the next two slides. Starting on page 15, we provided the details of our new 2016 capital budget including the return of our second rig this week. Increase includes approximately $25 million for an incremental $6.5 net wells drilled and 6.7 net additional completions resulting from the addition of a drilling rig and also an improved pace of our base 1 rig program.

Included in the updated budget is an incremental $15 million for infrastructure, seismic and land to represent investments that is will benefit the efficiency of our near-term acceleration as well as our ability to increase activity in the future. A look at our plans for this future is presented on slide 16. We've outlined the impact of a three-rig program starting in the first half the 2017 and continuing at that pace through 2018. This level of activity would deliver compounded annual production growth of approximately 20% underpinned with a focus on the Monarch and Wildhorse areas, in addition to modest activity in the Ranger area. While the growth estimates are attractive, the underlying capital efficiency and cash on cash returns for our investments are evidenced in the improving leverage profile at an assumed oil price of $50 per barrel and below. As we refine these plans, living close to our means and minimizing requirements for outside capital will continue to be an important consideration. This plan honors that view generating a free cash flow neutral position at approximately $50 per barrel WTI in 2018. Assuming our current tight curves and well costs.

I will now turn this call back to Fred for some final comments.

Thank you, Joe. Again I'm sure you can understand why despite the current commodity price environment we're excited about the opportunities ahead and look forward to continuing to visit with you on that. So with that I'll open the call to questions.

We will now begin the question-and-answer session. (Operator instructions). The first question comes from Will Green of Stephens. Please go ahead.

Hi, guys. Very good results on that Silver City well. Congrats on that. I wonder if you can maybe talk about the reasons that well may have yielded in such a better 30-day rate than some of the other wells in that area. Do you think, you know, is this a pretty similar stock completion with just maybe hitting a pocket of some geologic favorability?

Did you guys try something new? I wonder if you guys could just add some color on what may have worked better there?

Will, this is Gary. We are very excited about the well. It's really one of the most northern Wolfcamp A tests in the area. -- Wolfcamp. But actually even as excited as we are, it's kind of an expected result. If you look at slide 9, you look at the two Oxy wells that is are just south of that well. Those wells, this well is really producing in line with what those wells did. Though we tried a few things from a completion perspective in line with trying additional sand loading and potentially some limited stage length testing that I'm not really wanting to talk too much about yet because I want to see the sustained performance of this well before I get too much into it. This is early in line with our expectation. This is in line with part of the excitement we have around Howard County in total. But very comparable to what Oxy delivered in the same area.

Great. So I guess, you know, that leads me to think that when you guys acquired this asset, what you were seeing within maybe that southern block where, where the Masters unit is a number of those existing wells, there's potentially uplift you guys provided that with your completion style then?

That is exactly right, Will. We're very excited about the potential here. We're happy to have this asset not only for the upward potential that we see from what's been delivered in the area by Big Star who did very, very well. We think we can outperform that and more. And it giving us a lot of running room for exceptional value creation within the company.

And you may have mentioned it but whenever this new Howard County rig goes to work, is it going to be focused on that larger southern block around where the Master unit is and now that you guys have seen some pretty good results up north, maybe you guys will stay up there for a little while?

Yeah, Will, what we're doing is the rig's working today but it's working right now in our Carpe Diem field drilling one of two long 10,000-foot laterals that we just put together on the west side of Carpe Diem. So we're excited about that. Once it's finished with those two wells, it will move to the larger block in the south where we see significant potential. And it will start on the east side of that block and march all the way to the west side of that block drilling two well pads. I think there's one excursion to the north that's planned as part of a lease obligation that we have to get done, but mostly we'll stay focused on the southern larger block. To be very efficient with how we bring these wells on, water sourcing, water disposal, connection to infrastructure, all that work is being done now which is part of our capital increase to be very well prepared when we put that to work to be efficient with the way we're suspending our monies.

Great. I really appreciate all the color, guys, thanks.

The next question comes from Gabe Daoud of JPMorgan. Please go ahead.

Hey, good morning, guys. For 2017 and 2018 appreciate the two-year outlook. Looks strong and it's certainly helpful for us but could you maybe just talk about the amount of infrastructure spend that's needed or maybe embedded in that capital number for both 2017 and 2018?

Yeah, for 2017 and 2018 we're probably around $30 million per year, Gabe at this point. We have a little bit of a ramp-up here in the back half of 2016. But, for planning purposes right now until we get going a little bit more on that program, right now our place holders around that $30 million per year.

Gotcha. Thanks, Joe. And then I guess during the quarter, at Pecan Acres, there's some 10,000 foot laterals that maybe on a 1,000-foot lateral basis an IP of 85, maybe 95 BOE seemed a bit low to me. Anything specific going own there or reading a little bit too much into the result maybe?

We're excited about the potential there at Pecan Acres. Those are exceptional wells. Again the 10,000-foot laterals that came online, you know, we did some flow back control on them early time just to get infrastructure hooked up early time but beyond that those are exceptional wells and we're really excited about the well that's currently drilling, the Wolfcamp A well because we see significant potential in the Wolfcamp A as well.

Gotcha. Thanks, Gary. One quick one final for me and I'll hop back in. For the third rig what will determine the exact timing on adding the third rig? Do you continue improvements in the cost structure? How should we just think about the timing there?

I'll start this but Gary can fill in obviously. From and operational perspective, one of the gating items is infrastructure and getting that in place in the right way. Gary, I don't know in you want to add anything to that but I know that's our ultimate gaining item to make sure we're set up to officially get after it and how you see that progressing. Maybe I can talk about the rest.

Yeah, again part of the reason we're focused on setting up not only Wildhorse, but also at the northern part of Ranger, to be efficient with the wells that we know we're going to be drilling in 2017 is we've been doing this since 2012 and we know the secret to success to be very efficient when you bring those wells online early time. And so that infrastructure spend as expensive as it is, it pays dividends over the long term. Many, many dividends over the long, long term for Callon because of the significant well inventory that we can leverage across that infrastructure once it's in. And so the gating item to me is to make sure that we're is the up in both areas as we're now currently set up in Monarch to be very efficient with what we do when we execute on the program. So I think we will be ready in January of 2017 just as I said. That's our plans. We've got everything in the works to do that now. And in my mind, so long as commodity prices hold up, we should be ready to go.

You can see our planning is 4750 and then going to 50 in 2018. Obviously we feel pretty comfortable in those ranges and from time-to-time we're going to see volatility, we know that and we do want to keep leveraging certainly below 2.5 times and we've stressed things down so even if you look down into the low 40s, flat pricing for the next couple of years, we maintain that goal staying low 2.5 times. We see lot of flexibility from the strong margins in the business but it's combined with structure, well costs and what Gary talked about in the operational side, make sure we're ready to go at the right pace efficiently and avoid, you know, trucking water disposal and things like that that they really start to hurt margins. There's a lot of things we look at but our line of sight now is hopefully January comes and we'll be in a position to add that third rig.

Right.

Awesome. Thanks, Joe, thanks, Gary. I'll hop back In.

The next question is from Jebb Bachmann of Scotia Howard Weil.

Good morning, guys. Just a couple quick ones Gary first on the completion technique. I think you guys had a few pads where you were using 2,000 pounds per foot. I was just wondering how those were performing and if you had any feedback on those.

We're excited about that actually. We moved into it rather slowly but we're pretty excited about both aspects of higher sand loading and at least the early stages for what we've done for reduced stage length as well getting down to 200 feet. Seems to give us an uplift that we're pretty excited about. I'm not prepared to quantify it yet but we think it's money well spent. And 2000 pounds per foot, 200 foot stage lengths is likely going to be our standard going forward as we think about certainly Monarch and Ranger and we'll do some more experimentation certainly in what we think and work up and around Wildhorse. We're excited about that. We think again pioneer did a lot of the early time performance on that. We were happy that they published the way forward on it. We will be testing even shorter stage lengths in the upcoming fracs that we're going to do at Ranger. We're going to go down to 150-foot stages and so we'll see how that works and though we haven't jumped into the next level of completion enhancement, we are meeting and seriously considering where we test surfactants and other things as other people have published.

Okay, great. And just quickly on Howard, just curious how many acres, how many wells you guys co-offers with Rock Oil at this point?

We only have one well that we have joint interest in with Rock Oil. That's the poppa Giorgio with well. We own 5% or 6% working interest, in that well. We're happy with the way Rock completed that well. They did a good job to it. It validated our -- the potential that we saw down in that southern area and as we get in there and we try some of the completion techniques that we know are working for us now, in that area, we think we can even perform it a little higher level.

The last one for me, Gary, just curious what the rig rate is on that second rig that you guys are bringing back or have brought back?

It's the same as our current rig, it's $15,000 a day.

Great. I appreciate@, guys.

Thanks, Jebb.

The next question is from Ron Mills of Johnson Rice. Please go ahead.

Good morning. Just on the inventory slide, you added a couple hundred locations in terms of your base inventory. You know, what drove that increase? Is it going from 11 wells to 12 wells based on that spacing test or was there something else?

It was really an increase if 8 wells to 11, Ron. We haven't gone above 11 and we haven't gone above 8 in Wildhorse. And that's primarily Lower Spraberry focused. So that is what drove it mostly.

And then it second question with Wildhorse you talk about you're still evaluating the spacing in that area and also, you know, the density I'm assuming in all areas. So, has there been any testing in Wild Horse? I know a lot of people are testing multiple formation but have people started to drill wells on spacing tighter than 8 wells?

I'm not aware. Joe, with you aware?

There's been some early testing on Chevron pattern in the Wolfcamp A. It's been pretty limited to date.

Yeah.

More in the southern part of the acreage so we're keeping an eye on those. But it hasn't been an area with a lot of density tests at this point. It's really been more around progression on the zone, moving from Wolfcamp A to Lower Spraberry and now increasingly in the B. There's been one test each I believe in the D and in the middle Spraberry but I think you'll start to see some more density tests as we usually do, we'll do that in a measured way. And work with some of our industry partners to share data and make sure we're trying to insert ourselves pretty far up the learning curve before we start getting into those types of efforts.

All right. And just to follow up on one of Will's questions on the Silver City well, on a per thousand foot lateral, your well looks like close to 220 BOEs per day versus 150 to 185 on those two Oxy wells. So I know you said it came in kind of as expected but were you expecting that kind of performance on a per foot basis?

I guess the answer is yes, Ron. We think what we do and the way we do it, we should be able to outperform wells that are in and around us. We sold the oxy wells. We knew that they were a little longer but we felt that given the way we frac these wells which is a little different than with a Oxy did, we would see the enhanced performance. So it was again what we expected. It was really the valuation that we saw moving into Howard County. We were happy to get the acreage position that we've got.

Okay. And then the agreements at both Carpe Diem and Pecan Acres where, reached some sort of agreement with offset operators, that something that you think you may be able to also execute only over in CaBo just given the nature of that acreage position being a little bit more checker boarded?

Yeah, we certainly look to show offset operators kind of what we can do to add value to not only to Callon but to them as well and I think that's been proven over and over with the partnerships we have or with the RSP and others in the Pecan Acres area and now it's Chevron in the Carpe Diem area. I don't think it will work at CaBo. CaBo checkerboard is Baskin offsetting and Baskin is really still working toward doing even some vertical development in and around those areas. So I wouldn't expect that they're going to come in and do anything with us. At least they haven't shown any indication as such so I don't want to lead you along there.

And lastly the incremental 4% work interesting gets you up to 75%. What is the remaining 25% look like? There's incremental interest are usually some of the more attractive acquisitions, do you think you can get more in that area?

You know, potentially we've had discussions over the last since late 2014 when we entered that position, so we talked to all of the working interest partners and there's a couple more larger pieces out there that, we'll stay in dialogue and hope to pick up. But I think we've shown every couple quarters we're able to take in a little more so we'll keep after it so there's certainly more opportunities there.

All right. That's it. Thank you, guys.

The next question is from Chris Stevens of KeyBanc. Please go ahead.

Hey, 'morning, guys. Great update last night. Just wanted to touch on the 2017 and 2018 outlook and when forecasting production, are you still using the tight curves that you put forth in the presentation for Howard County? I'm just, you know, it looks like those wells are a lot stronger than expected, so is there the potential for some upside to that growth outlook just, you know, based on Howard County well out performance?

Yeah, in terms of the methodology, Chris, yes, it is based on the tight curves that we used to evaluate the acquisition that we had laid out for the A. Clearly we are encouraged by this initial result, but we've got a lot more results to put up there before we start moving that tight curve up. But yeah, this forecast does assume our current tight curves that we have out there that haven't changed. But we obviously hope is, you know, any acquisition we make that we will evaluate it honoring the data around it and it's up to us to get better in producing the resource and we think we have a good path to doing that and we hope that there's upside to that going forward.

And if looks like the 2018 guidance, looks like it maintains the three rig program. What would instead cause you to think about adding a fourth rig in a leverage looks like it's pretty healthy so how do you think about cash flow neutrality versus maybe continuing to accelerate just given the strong returns that you're seeing out there?

We'll keep an eye on that. We do run scenarios in terms of different levels of activity. I think that, we certainly want to see continued performance in Howard County. It is one well, right? We're encouraged by what the industry is doing. But, you know, an increase in activity would probably include incremental more activity in Howard so with some more well results, not only in the A but looking at our tests in the Lower Spraberry in B that we hope to be doing next year, I think that will certainly provide the foundation from an operational standpoint to accelerate that resource and then, you know, we'll monitor where we are in operating cost structure, well cost structure and balance sheet and add it all up. But now I think there's a lot of things to fill in before we start making decisions on that fourth rig but we obviously keep an eye on it and given the types of returns that we see are available and pay back periods that, we are comfortable with a period of spending outside of our cash flow if we see a path to getting back, closer living within our means within a short period of time.

Great. Thanks a lot.

The next question is from Neal Dingmann of SunTrust. Please go ahead.

Good morning guys. Hey Gary, just wondering, remind me again when you are in that third rig with then two of the rigs be focused in the Wildhorse one, maybe north and south and then one will be over in the existing acres? I am just not sure I am clear on that.

Yeah, Neal, again, remember the third rig is dependent on infrastructure build-out and so I think I will be ready come January to where I can bring it on any time in 2017. And where it will be focused actually it probably will be shared between Wildhorse and Monarch. We're set up perfectly in Monarch now that we've just completed a significant infrastructure build-out there to efficiently, more efficiently drill out CaBo area while continuing to work at Carpe Diem and Pecan Acres. We will be pipeline connected with crude oil Carpe Diem in the next couple of months and that will put all of our fields on pipeline connection except for Wild Horse. We have significant interest at Wild Horse for pipeline connections that will be in place prior to bringing these new two-well pads on production. So we're excited about that. We think that will come early January. So a lot of things hinder around the timing, exact timing of the third rig. We're just telling you we will be early 2017 is when the team's going to be ready to go and yeah, who knows?

Depending on commodity prices, maybe a fourth rig later in 2017. But it all depends on that but it will be shared between both Monarch and Wildhorse. We will drill a few wells next year in 2017 down in Ranger. We're excited about that. Ranger is still an exceptional area. We're going to frac the two wells actually the two ducks that are out in Ranger, we're fracking those this week with the enhanced fracture techniques that I just discussed earlier. And we think that provides even significant upside to the good results that we've already delivered there.

Well, a lot of things going on. All right. And then the dewatering, was that I assume a temporary issue, do you see during the rest of the year any recurring issues there?

That was very odd, Neal and it's not something you ever expect and it was clearly unexpected. Offset operator fracking north and turned around and fracked south. Typically we see that. It never even affects us like it did this time because we normally have all of our wells up and running. We see a slug of water. We dewatered the area with our typical producing wells the way they are now so we only see a minor change in rate but unfortunately when that occurred, we had a couple of storms come through the area that knocked the power grid off for Carpe Diem and when we knocked the power grid off whenever that happens, you always have the risk of losing a sub- pump or two. We lost a couple of sump pumps and we just didn't go in and repair those right away because of the offset frac operations, so we erred on the side of safety of being very cautious and when all that frac operation was finished, we went into and repaired the wells and quickly dewatered the areas just like you expect and got the production right back. It's not a normal things that occurred. It just so happens that the impact and then the storms that knocked off the power grid and then the failure of a couple of critical sub pumps to dewater all kind of hit together all at one time. But beyond that we've seen frac hits before and they're very temporary, very short-lived and we work right through them and we never have to talk about them to this degree but the whole chain of events that led up to this one caused significant downtime period.

Yeah, okay. Certainly sounds unusual there. And then just lastly, for Fred or you, Joe, just when you look at M&A, not just for this year but this 2017, do you guys still see a lot of opportunity? Are you looking now still both in Midland and Delaware and, would you look outside the entire basin?

This is Fred. I guess sport answer is yes, we see a lot of opportunity. No, we won't look outside the Basin. We've mentioned before we've been certainly looking at the Delaware for, you know, well over a year actively looking and trying to maybe find the right entry point. But we're still seeing, a number of opportunities in the Midland Basin right now as well as Delaware. We'll continue to look and as you know we're very much interested in continuing to grow the footprint out here so hopefully we're going to find some opportunities later this year.

Hope you keep on (inaudible)Big Star, Fred. Nice job, thanks.

Thank you.

The next question is from Jeff Grampp of Northland Capital Markets. Please go ahead.

Morning guys. Sticking up in Wildhorse, there, you guys kind of mention doing some multi-well pads just sticking in the Wolfcamp A as well as maybe some stack pads when the third rig comes in 2017, just wondering as you guys see full field development up there does one look more advantageous versus the other in terms of sticking in one zone or going after multi-zones, or is it a little early to call given that you just have the one result right now.

Again, referring back to Jeff, this is Gary, referring back to slide 9. You know, the color of those dots kind of show you a lot of activity's been done in the Wolfcamp A and we know that we can come in there and deliver a lot of value on the Wolfcamp A we want to get started on the right foot and that why we're focused on the Wolfcamp A. We see a lot of potential on the Lower Spraberry. The lower Spraberry is going to turn out to be just fine in this area. And we want to prove that up pretty early time. We may not get to it in the first couple of pads but we'll get to it sometime next year until we get a lower Spraberry result that we can talk about. And certainly Wolfcamp B, we see a large oil and place target there that we think we can exploit over time but right now Wolfcamp A lower Spraberry we see as pretty equivalent and the Wolfcamp shortly thereafter.

Okay. Perfect. And then maybe to give a little love to the Ranger area given that you guys had a couple much nice result this is quarter, can you just talk about capital allocation to the ranger area going forward? I mean if these results are, repeatable with this new completion technique, does start to become a little bit more competitive with some of the other areas or how do you guys see capital allocation to the ranger area with the three rigs?

Yeah, again, for the two ducks that we're about to complete later this week, we will go to significant enhanced completion. We'll go to 150-pacing spacing, 200,000 pounds per foot of sand, slick water and we'll do some interesting things down there and we think we'll get the equivalent uplift that we're expecting there from when we went from really 1500 up to 2000. And so and really the 250 foot down to 200 foot stages. And I expect that will work out really well but in next year's program we only have three wells planned so it gives us time to evaluate that and look at it but we see that as a very good area. The results that we've delivered at Garrison Draw and what we now see at Lonesome Draw there in the Ranger area and even an uplift still in our Upton county property, where it all started for Callon back in 2012, we're very excited about this potential.

Okay, great. And then last one for me, maybe Joe on the hedging front. How do you guys think about building the book into 2017? Is there a price kind of floor you guys want to lock in or is there certain kind of P-- percentage or guidance percentage that you guys are maybe looking to build towards as we exit the year?

Yeah, we've added some oil hedges and actually a little bit of gas here recently as well. But, you know, historically we've been 50%, 60% hedged. We're about 25%. I think we'll try to move that up a little bit closer to 35%, 40% in the coming months as we get into next year and look to support some cash flows with a three rig anticipated program. You can see that, with the economics that we have embedded in our program, there's a lot of economics to go around even in the mid 40s, high 40s. So I think the biggest thing that we'll look to do is try to introduce some optionality for upside in our program and whether that be through callers or three-ways to put a floor in somewhere in the mid 40s to high 40s and provide some optionality of the upside is pretty important. And that's because we don't want to take a position that we're going to lock in on swaps and not know where the cost structure might go and get squeezed on our margin. We think that this cost structure is going to be fine for a long time in terms of the capacity in the Basin and what we've been delivering and work with partners. But we don't want to lock in too much on the headline in case things really to take off on the headline commodity and you get a little bit squeezed if operating cost structures start getting out of whack as things are ramping up.

Great color, Joe. Thanks for the time, guys.

The next question is from Kyle Rhodes of RBC. Please go ahead.

Hi, guys, good morning. Was curious if you could give a current rate on the Silver City well. It seems like you were careful not to list the production of peak IP30s so I'm just curious what you think that could end up being.

I'm going to be consistent with my response on other calls about single well response. We're very excited about this performing at high levels. It's a single well. It really validates the way we evaluate Howard County. So given me another month or so and I will tell you what the IP24 and the IP30 is and it's lots of potential here.

That's fair, Gary. And I guess is there a well cost you could share on the Silver City and maybe target (inaudible) on the two Howard wells, just curious what the new target well cost is given the enhanced design. Sounds like they're going to become standard here.

Our current cost that we've kind of had out there about $5 million for a 7500 foot well includes the cost of the enhanced completions. So that's kind of where we are. We've been able to deliver that day in and day out and as Joe just mentioned, we see a lot of running room here within the service capacities within the basin. There's a lot of companies that continue to seek us out as partners and we're so appreciative of all the service providers that work with us and working even all of their supply chains to the best of their ability to be able to deliver high quality, efficient work for Callon in order for us to continue these types of programs and deliver these types of returns. That really gives us a lot of confidence in thinking about not only four rigs but maybe five rigs over time. I don't want to get too excited here but my theme's kind of anxious to get the work.

It's good to hear. Just wondering if you could maybe rank your three areas in terms of bolt on opportunities whether it's organic leasing or acquisitions. Is there one area where you think you've got a better edge to tack on additional acreage on the back half of the year here?

It's tough to say because I think we've had success in all three of them even at Wildhorse and the short period of time that we've owned it we've been tacking on some things. But, if we had to force rank them, I think it would be pretty close. I think Wildhorse would be first, Ranger behind that and Monarch it's a little bit tighter in Midland county but like I said, we've delivered on some incremental acquisitions around all three just in the last couple months so we feel pretty good about the running room.

Great. And just one time one from me. How are you guys thinking about the high yield market at this time?

We're certainly happy to see some of the initial activities through, you know, one of our peers and then an inaugural issuance here. Recently as well to reopen that market. You know, refinancing of the term loan we place in 2014 has always been pretty high on our agenda to put in a piece of capital that's a little bit more flexible at a reduced cost and give us another liquid security in the public markets for us to tap from time-to-time. So we're certainly looking hard at it. Good thing is the term loan we have in place, there's no gun to our head to do anything right now. Due in 2021. It's got a fine coupon. It's callable to the at 102 and that will step down to 101 in October. We're keeping our eyes on it and most importantly we'll be opportunistic and we'll find the best window to insert ourselves in the high yield market and put that piece of capital in place.

Guys be I appreciated all the color. Thanks.

The next question is from Irene Haas of Wunderich. Please go ahead.

Good morning. Thanks for providing us outlook into 2018. It's absolutely fantastic. Just kind of curious, so thus far, your position basically is really trying to stay cash neutral at $50 world and be able to grow. What could throw off your scenario? I mean, you know, any risk item that we should think about and if yes, how sturdy is this outlook? I mean, you know, any risk item that we should think about and if yes, how sturdy is this outlook?

We always like to reserve the rights to do that because it gives us some flexibility, Irene but we feel I think pretty comfortable with barring any sort of real dislocation of oil prices sub 40 that we want to stay on this path. We do see some strong returns on the portfolio in all three of our areas to accelerate here with the balance sheet in the position it is and more importantly the internal cash flow generation that I think we're showing with improved cost structure goes a long way to, not relying on outside capital whether it be bank financing or otherwise. As Gary said, I think this is probably a little bit biased that we can move this to the upside on a three-year look into 2018 that we hope to deliver on bringing a third rig back early 2017. Continue to see results out of the Wildhorse area, out of the A, the Lower Spraberry to B put that together in terms of a development program to gives us the conviction to stand up another rig going into 2018. If there is a bias, I think that we've been pretty measured in terms of the assumptions that we're using in terms of tight curves and such and probably giving us hopefully a conviction later in 2017 to be looking hard at fourth rig. Gary?

Absolutely. Again we're excited about what we have again. We think we're looking forward enough to manage the operational risk. I just don't want to go drill a bunch of wells and not be efficient about it so I think about infrastructure, I think pipeline productions and I think about water disposal and water sourcing and importantly land over relationships. We deal with at lot of land owners in a very highly professional manner that are all important to us that gets to the root of our reputation of doing things well and doing things right and really delivering on what we say. It pains me that the Carpe Diem production happened in the second quarter because, we expect to be able to deliver on the results that we talk about. And so if anything, we will be measured in going forward. We will be I think focused on trying to accelerate and bring value forward more so than slowing down. The only thing that I think is going to stop us is like Joe just mentioned, a major downward movement in commodity prices and I just don't see that.

Four rigs, is that sort of a comfortable rig count for you guys, just in case oil really start escalating. What's your confident level in term of rig counts?

Well this is a interesting topic around here because we've been at three before and there was still a lot of capacity on this team. I've thrown out at least conceptually for us to be prepared and these are wild numbers so don't be putting any of this stuff in your models but to be prepared for six. The only time I ever saw any widening of the eyes of my team when I threw out ten one time. So we're very comfortable with increased activity. We're not stressed at all. We have a very talented team and we can take on a good bit more.

Great. Thank you very much.

The next question is from Derek Whitfield of GMP securities. Please go ahead.

With good morning, guys. Great operational update. So going back to your nano surfactant comment, how much would you characterize the potential uplift you see from using this technology?

Well, that's why I'm trying to spend an awful lot of time studying it so that I can comfortably get behind the additional cost associated with it. I have a couple of meetings scheduled for the next couple of weeks to get further detail into some of the results that have been published that are very exciting around it. But certainly nano surfactant should deliver enhanced results over time. There's no question about it. What you're doing is as you're fracking that well and you're adding that surfactant, you're actually freeing oil that should be ready to produce near term fairly quickly. So certainly the early time results should be higher than what you've seen in the area. What I'm trying to get more comfortable with is the longer term benefit related to the EUR. If its a short term acceleration you can justify the cost okay but I'm trying to get more comfortable with the enhanced EURs around some of the published data and once I get comfortable with it and the cost cycle, then I will be ready to go forward. You were question is exactly why I've been a little hesitant in jumping right in and doing some because as you guys know, I've said this over and over. I like the benefit of having fairly good offset operators around us that can prove up some of this technology for us. And I'm getting excited enough about some of the more published -- more recently published results that I'm anxious to kind of try one on my own.

Got it. And maybe just order of magnitude, what type of uplift are you seeing in initial rules based on these published basically tests?

Again, I'm not going to throw out any numbers on this call. I'm trying to get more comfortable with it myself. I will try one, I promise you I will give one a shot. I just don't know which well I'm going to do it on yet and after I get those results, I will be very comfortable about describing exactly what we delivered because I do get a little hesitant about some of the publishing results only just being around the best wells so there's a whole plethora of information out there that I'm digging into that's getting me more and mover comfortable with the technology. What I'm uncomfortable with is the cost. Especially in an appreciating environment.

Thanks. And then maybe moving over to Monarch, based on your geologic model and industry results, is there any reason why 11 to 13 well per section density in the Lower Spraberry shouldn't work?

Not from what we've seen so far.

And how would you risk the upside as you see it right now across your other areas within Monarch?

The other zones within Monarch outside of the Lower Spraberry? We haven't done a lot of down spacing test there is yet. So I would suggest that that's zone specific. The Lower Spraberry sets up nicely with the thickness and really the enhanced porosity in the Lower Sprayberry to an oil in place to support a higher density of wells. It may or may not fit well with a higher density in the Wolfcamp B or even the Wolfcamp A as we test it here in the near term. But going from 11 to possibly 13, I can see that happening. But I really want to get to the point where I have several offset pads drilled next to wells that I've already tested downspacing on. That's really going to be the longer-term test. So I'll still be talking about this in the next two years probably, before I really narrow down what the optimum spacing might be.

That makes sense. And then last question for you. Regarding the improvement that you guys have seen in your unit LOE expenses, how much of that do you attribute to self-help versus market.

I attribute a lot of that to infrastructure investment actually. I think it's planning ahead. It's planning for growth. The companies that get out ahead of their programs without putting in the appropriate infrastructure and thinking about how that can be efficient with it, will have a higher LOE component. Those who get ahead of that will be able to manage their costs and leverage that investment over a longer period of time.

Very good. Thanks, guys.

Thanks.

The next question is from Blaise Angelico of IBERIA Capital Partners. Please go ahead.

Good morning, everyone and thanks for taking my question here. This piggybacks on Ron's earlier question on spacing. I apologize if I missed it. If as you're putting your program together for next year and then into 2018 do you discuss specifically what kind of test you guys are looking at into the Howard County acreage the acquisition was 6 to 8 wells in certain zones. I know it's early in the life out there but any comments would be appreciated.

In terms of the model that we have and laid out, as Gary said, we're looking at two well pads moving across that acreage position so we aren't ourselves planning on doing really any downspacing tests at this point in this plan, at least next year. We'll see how things develop. I think we're more focused on looking at stack laterals, Lower Spraberry, Wolfcamp A or adding the B in there doing a lot a lot of spacing tests. There's some spacing tests going on as things are getting closer to program development in Howard County but, you know, right now we haven't dialed that into our program. I mean we might change up some of the well locations as we get further into the program but right now we haven't put that into our plan.

Gotcha. Thanks.

And the next question is from Janine (inaudible). Please go ahead.

Hi, good morning, everyone.

Good morning.

So back to the inventory. Just kind of wondering what a rough target inventory level you have in terms of the number of years. I'm looking at slide 11 and I know you mentioned that there's potential to do maybe 6 or 8 rigs in the future, not in the next couple years but in the future and slide 11 indicates that on a four rig program you have, three rigs of drilling a Wildhorse with six in Monarch and four in Ranger. I'm also appreciating that there's inventory outside of 150 locations or so with the downspacing that you've mentioning. I'm just wondering what your rough target is in inventory level in each of your core plays?

We don't necessarily target any specific number. You know, we want to have as many locations that fit the criteria on the bottom right-hand side that can deliver value at below, or around $50. That's a world that we live in. We think that incremental investment comes in the industry at $55, $60 so we need to be prepared to live below that. In terms of, you know, how you characterize the inventory, we provided some math here. Three or six or four years in each of the core areas, that's if you assume all those rigs are in that area and no where else , just focused there for the whole period. So just with our delineated locations that are currently producing, so the upside locations that I don't think you've taken into account, they are producing offsetting our acreage. We just haven't drilled them so we haven't put them in our account. I think our real number then that we would feel good about is somewhere between and this is assuming four rigs, I think you had said five or six, let's say it's four, between 14 and 25 years. The numbers in there. It's certainly a comfortable range we would like to carry certainly north of ten years of inventory and investment that's very visible to us with having upside there but, at some point, how much inventory do you want to carry that you're not going to get after for 20 years? We want to be cognizant of that. So I guess to answer your question, we don't see those being inventory constrained, I think we're constrained by making sure we're efficient before we accelerate too much and pull these returns forward.

Okay. Great. That's really helpful. And then following up on a few of the prior questions and I know you've talked a lot about kind of managing the absolute offspend versus running to a leverage metrics. I'm just wondering what the absolute forecasted outspend is in 2017 on the two-and-a-half and three rig scenario and what kind of changed versus the prior (inaudible) that Callon would remain for a few quarters and just watching commodity prices?

I don't think it has changed really all that much. Second quarter we were free cash flow positive. Third quarter, we do have some infrastructure investments to get ahead of but there's really no meaningful outspend that we're seeing there. We're laid out a three-year plan so I'm not going to talk about any year specifically but under this three-year plan through 2018, in 2018 for the totality of the year we're looking at being free cash flow neutral. That includes some quarters being free cash flow positive, pretty significantly. So if you take the next -- start in third quarter in 2016 through the end of 2018 on average I think the out spend comes out to be $7 million on average per quarter. And again that includes periods of, more or less than that from time-to-time. I think our peak borrowing that we would potentially have under our borrowing base facility while we are a ramping up two rigs in a short period of time which is a lot, you're going to go in a cash flow negative position is probably an incremental $90 million to $100 million sometime later in 2017.

Ok that's helpful. At what WTI price does the well economic kind of turn over so the off spend also delivers a balance sheet it looks like from slide 16 it looks like it could be something as low as low $40s or maybe mid $40s

You know, if we assumed let's call it $42, $43 flat from today until 2018, we would still be at two-and-a-half times or less.

Okay. Great, thank you.

Our final question comes from Ray Deacon of Coker & Palmer. Please go ahead.

Hey, good morning. I had a question about Howard County and the two well pads that you're going to be drilling starting early next year. Will the target zones be the Lower Spraberry and the A, is that the current plan?

Yeah, this is Gary. We're going to start with two well pads and just targeting the A for the first couple of pads and the team is already anxious to prove up the Lower Spraberry so then we'll bring the Lower Spraberry in a little bit later in the year and we'll be looking to test the B later after that. We're very focused on delivering early time solid results in the A for now because it is the most worked and the most derisked and I think given what we've been doing in the Wolfcamp formation and other places around increased sand loading and downspacing has an application here and we'll be testing that as we go forward so we're excited about the A and as I said before, we're equally excited about the value component of the Lower Spraberry and then we'll watch others and if they're late to the game, we'll come in and prove up to be ourselves with the capacity that we have.

Okay. Go got it. And then it looked like Encana had talked about the potential to see and decline. What do you think there?

Again, we see potential in other zones and again as we just talked about inventory, we talked about inventory on things that we know work that have a high level of technical confidence around. And again an advantage we've had is we've seen a lot of other people test additional zones and improve that up for us. There's certainly more to be had in Howard county over time. We're just not ready to put it out there as saying it's something we're ready to go, bring forward at this point in time.

Okay. Got. And just one last quick one. You mentioned curtailing some wells and it was giving you a higher gas cut I guess. Do you think there will be any EUR or NPD impact as a result of that?

If anything, it would be positive. Again I think what Joe referenced in his comments in some of our older fields we've gone in and actually reduced, managed to the point where we're able to pull additional pressure off of the formation, get more stability in the down hole flow potential of a well. Manage horizontal wells in a way that can both increase IP or production potential even in a draw-down condition. And that's given us incremental oil and incremental gas and so over time, it will increase the EUR and bring forward value.

Great. Thank you very much.

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

Once again we do appreciate everyone taking time to call in and certainly if anyone has any questions in the interim, don't hesitate to give any of us a call. Thank you so much.

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