Callon Petroleum Co (CPE) 2016 Q3 法說會逐字稿

Good morning, and welcome to the Callon Petroleum Company's third quarter 2016 financial and operating results conference call. (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, Manager of Finance. Please go ahead.

Good morning, and thank you for taking time to join our conference call. With me this morning are Fred Callon, Chairman and Chief Executive Officer; Gary Newberry, Chief Operating Officer; and Joe Gatto, President and Chief Financial Officer.

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 Events and Presentations page located within the Investors section of our website at www.callon.com.

Before we begin, I would like to remind everyone to review our cautionary statement and important disclosures included on slides 2 and 3 of today's presentation. We will make some forward-looking statements during today's call that reference (technical difficulty) estimates and plans. Actual results could differ materially due to the factors noted on these slides and in our periodic SEC filings.

We are also (technical difficulty) some non-GAAP measures today, which we believe help facilitate comparison across periods and with our peers. For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the appendix to the presentation slides and in our earnings press release, both of which are available on our website.

Following our prepared remarks, we will open the call for Q&A. And with that, I would like to turn the call over to Fred Callon and direct the audience to slide 4 of the earnings presentation. Fred?

Thank you, Eric, and welcome to the call. As always, we appreciate your interest in Callon. We join you today as a much larger operator than just one year ago, having both doubled our net acreage position to over 40,000 net acres, and on target to exit this year at over 20,000 barrels of oil equivalent a day.

We've had several important accomplishments during the course of the last 12 months, including over $650 million of core acquisitions and associated capital raises. We're excited about what lies ahead over the next few quarters.

After several quarters of a restrained capital program that delivered consistent sequential growth, we're now positioned to accelerate the value proposition of our asset base across all three of our focus areas.

We started this effort during the third quarter with the return of our second horizontal rig, which is now dedicated to our Wild Horse area, while the other rig remains focused on the Monarch area. The team is now preparing for the addition of a third rig in January of 2017 and a fourth rig in the second half of 2017. This program will put us on a path to achieve an estimated 30,000 barrels of oil equivalent per day of production in 2018, while spending (technical difficulty) cash flow.

Given the expected volatility that accompanies a rebalancing oil market and the industry's focus on the Permian Basin, we've assumed a $50 per barrel oil price in 2018 as well as a 15% increase in drilling and completion costs from current levels to provide a conservative starting point for planning purposes.

In addition, we currently have a liquidity position of almost $500 million with a net debt-to-EBITDA ratio under 2 times, providing significant flexibility to deliver on our plans.

I'll highlight a few key points from last quarter and other recent activity on slide 5. Our production in third quarter was approximately 16,600 barrels of oil equivalent per day, representing a 23% increase over the second quarter.

While our LOE was slightly higher quarter over quarter, primarily due to less efficient operations at our recently acquired geos, which we're still building out infrastructure, our total cash operating costs before entries were made just over $10 per BOE, contributing over $28 per BOE to EBITDA per BOE in the quarter.

This quarter included the early contribution of drilling completion activity from areas outside the Monarch assets, which have been our sole purpose for the last few quarters. In the Ranger area we completed two wells, including Upper Wolfcamp B and a Wolfcamp A using latest-generation completion designs, expanding on our previous focus on the Lower Wolfcamp B, which has been a solid producing (technical difficulty) for us in Reagan County.

In the Wild Horse area, we continue to see exceptional results from Callon's first operating Wolfcamp A completion, the Silver City A01H well in northwest Howard County, which Gary will discuss in more detail, as well as an update on our program development plans in that area.

And finally, in the Monarch area we are building upon the solid performance of our Lower Spraberry program with photo-testing of well density concepts and expansion of our drilling efforts into Wolfcamp A, our fifth-producing in-hold in that area.

As part of our acquisition activity this year, we remain committed to a strong leverage and liquidity position combined with resilient cash flow margins and a deep inventory of well locations that can generate cash payback within two years at current strip prices.

We're well positioned to advance our plans to accelerate activity on a measured basis during the next 12 months. Now I'll turn the call over to Gary Newberry, our Chief Operating Officer. Gary?

Thanks, Fred, and good morning to everyone listening today. I will begin on slide 6 and highlight the reactivation of our second drilling rig, that was idled at the end of February.

The rig was staffed with essentially the same crews and was able to efficiently drill our longest laterals to date at Carpe Diem in our Monarch area. The rig then moved to Howard County and drilled a Wolfcamp A well and a Lower Spraberry well on our recently closed Plymouth acquisition, immediately offsetting our Silver City well.

The same rig will drill two additional two-well pads, targeting the Wolfcamp A and Lower Spraberry within the newly acquired acreage prior to moving to our planned Fairway development in central Howard County.

Important to this development, along with the planned mobilization of our third drilling rig in January 2017 is the detailed planning for necessary facility expansions, which include water-sourcing, water-disposal, centralized batteries, and product off-take capacity to achieve the same level of efficiency in our new assets as we have demonstrated on our legacy assets.

We continue to achieve significant quarter-on-quarter production growth from the combined impact of our acquired production and organic growth, delivering strong well performance at or above type curves.

Finally, as shown on the lower right of the slide, we have continued to trend downward on cost, even with enhanced completions. However, I must say that as activity levels are ramping in the Permian, I expect to see more inflationary pressures on costs. We are assuming some cost inflation starting in 2017 as part of our three-year planning cases.

Moving to slide 7, I will highlight a very active quarter in our Monarch assets. We have drilled our second 13-well-per-section spacing test in CaBo while we continue to monitor early-time results from our first 13-well-per-section test.

In addition, as I previously mentioned, we drilled our longest lateral wells to date, with 11,500 feet horizontal sections at Carpe Diem. Furthermore, in partnership with RSP Permian, we drilled and completed stacked Wolfcamp A and Lower Spraberry wells on the east side of Pecan Acres, and we are currently drilling two Wolfcamp B and a Lower Spraberry well on the west side of Pecan Acres.

Slide 8 shows all existing producing wells along with a new activity in Wild Horse and Ranger. As mentioned, the drilling rig has already drilled a two-well pad offsetting our recently completed Silver City well, and the rig will be fully dedicated to Howard County going forward.

We are completing crude oil gathering and transport agreements and we should complete pipeline hookups in Q1 2017 for Sidewinder and Maverick, and Q2 2017 for Fairway, supporting our planned development.

Moving to slide 9, as promised I wanted to give you all a quick update on the Silver City well, as it is the most asked question I get from investors and analysts. The well has produced nearly 200,000 barrels oil equivalent in less than four months and the well is still producing over 1,100 barrels of oil per day.

We will apply the same completion design for the offsetting Wolfcamp A and Lower Spraberry wells, which will be completed later this month.

As the slide illustrates, the well continues to produce above our acquisition Wolfcamp A type curve. In anticipation of the question as to when we will revisit our type curve for this area and throughout Howard County, we will revisit this following the completion of the next several wells.

Slide 10 illustrates our current fracture stimulation plan for wells going forward. We are currently monitoring and evaluating our early-time performance of two tests in the Lower Spraberry and the Wolfcamp formations for tighter stage spacing. But for the moment, we are very enthused with the results of wells utilizing our current proven design of 200 feet stage spacing and 2,000 pounds per foot of proppant.

Slide 11 shows the early-time performance of wells stimulated with 150 feet stage spacing and 2,200 pounds per foot of proppant in the Wolfcamp A and B at Ranger. We're encouraged but need more time to fully evaluate the uplift.

The insert in the upper right side of the slide shows the planned 2017 development wells for Ranger, which are scheduled to be drilled in Q2 2017.

Slide 12 highlights the results of the encouraging 12-well-per-section spacing test in the Lower Spraberry along with the focus area for the 13-wells-per-section test in Monarch.

The early-time performance shown on slide 13 further supports increased density with staggered multilevel development for the Lower Spraberry.

Slide 14 shows the high quality and depth of our de-risked inventory, which supports the planned addition of a third rig in January 2017 and a fourth rig in the second half 2017.

On the right-hand part of the chart we've highlighted the ventures that will underpin our development program over the next few years, all of which generate cash payback within two years.

Finally, on slide 15 I want to provide a snapshot of our planned development as we add rigs. Our primary focus will remain in Monarch and Wild Horse as we expand our development into Wolfcamp A and B in addition to the Lower Spraberry.

We will be focused on adding the necessary infrastructure in the first half of 2017 to obtain the same level of operating efficiency across our newly acquired assets that we have demonstrated on our legacy assets.

We doubled our acreage position in 2016 and we are now focused on efficient production and reserve growth, which should add significant shareholder value going forward.

I will now turn the call over to Joe Gatto, President and CFO, for the financial discussion.

Thanks, Gary. I'll be picking up on slide 16, for everyone following along.

For the quarter ended September 30, Callon reported adjusted net income of $0.09 per share, which excludes the after-tax effects of certain nonrecurring items and noncash valuation adjustments.

We also reported adjusted EBITDA of $43.4 million, a sequential increase of 20%. Both of these non-GAAP measures are reconciled in our press release.

We grew production by 23% over the second quarter of 2016, resulting from 5.2 net wells placed on production in the quarter, and sustained longer-term performance from our Lower Spraberry program.

The period included a full quarter of production from the Big Star acquisition but did not include any volumes from the recently closed Plymouth acquisition, which will contribute just over two months to our fourth quarter production volumes after the transaction closed in late October.

Over all, revenues, excluding hedges, grew 24% sequentially to $56 million, driven primarily by the increase in production as realized prices on a combined BOE basis were almost equivalent the second quarter on both a hedged and unhedged basis at approximately $40 and $37 per BOE, respectively.

Turning to slide 17, we've broken out the key components of our operating cost structure before financing costs. We have sustained a two-stream cash operating cost structure of approximately $11 per BOE, including the impact of acquired properties that are progressing to more efficient operations under our model.

We estimate that our acquired fields increase our overall corporate LOE by $0.43 in the quarter, but these currently less-efficient fields were faced with increased activity from the completion of the [duck] inventories we inherited.

As Gary described, we expect the impact of our infrastructure and water-handling investments to address the disparity relative to our legacy fields over the next couple of quarters.

On EBITDA per BOE measure, we generated over $28 per BOE produced in the quarter, providing strong internal cash flow to fund our drilling programs.

On a net corporate cash flow basis, our total cash capital expenditures of $47.4 million were primarily funded by $42.8 million of discretionary cash flow as we continue to live largely within our means while increasing operational activity.

On slide 18, you can see that we entered the fourth quarter with a liquidity position of $485 million, including $100 million of cash balances after adjusting for the closing of the Plymouth acquisition and our recent senior notes offering that refinanced the term loan.

The debt refinancing transaction was important for us in a number of ways. It reduced our borrowing costs over the term debt by over 200 basis points, with one of the lowest coupon rates ever achieved by a first-time EP issuer in a single B ratings category; established a benchmark security for future debt financing.

Importantly, validated the credit quality relative to our peers with an issue rating of B plus from S&P and B3 from Moody's combined with recent trading levels that are within 50 basis points of larger peers such as Diamondback, Parsley, and RSP Permian, for similar maturities.

Our leverage position remains amongst the strongest in this mid-cap world, with pro forma net debt to LPM EBITDA at 1.9 times, which excludes the EBITDA contribution from the Plymouth transaction until we have completed historical financials for the acquired assets.

Combining this foundation of a strong balance sheet with a liquidity position representing almost 3.5 times our 2016 operational capital budget, we're well positioned to responsibly fund our growth plans that we will detail here shortly.

Slide 19 details our updated guidance for 2016, reflecting the partial fourth quarter impact of the recently closed Plymouth transaction as well as changes to our originally planned drilling locations in lateral lengths for the balance of the year as we optimize our development plans.

Relative to where we started 2016, we have increased our production guidance in excess of 30% for the year and reduced our LOE and cash G&A per BOE targets by 11% and 25%, respectively.

Operational capital program expenditures remain unchanged at $140 million, with approximately $100 million accrued through the third quarter.

We plan to complete a total of 23.8 net wells in 2016 with an average drilled lateral length of approximately 7,000 feet. As we look forward to 2017 and 2018, we expect both of those numbers to meaningfully increase, as outlined on slide 20.

On this page, we've updated the long-term development outlook that we provided last quarter to reflect the increased activity program we are currently progressing. This planning scenario assumes the addition of a third horizontal rig starting in January 2017, with a fourth rig to be added in October 2017.

Out of the four-rig development plan, we would have two rigs dedicated to the Wild Horse area and approximately 1.5 rigs equivalence of activity in Monarch and 0.5 rigs equivalence of activity in the Ranger area.

This level of activity would deliver compounded annual production growth of approximately 40% relative to our 2016 production guidance through 2018.

Looked at a different way, if we normalize the 2016 starting point by assuming that this year's acquisitions all contributed production starting on January 1, 2016, this plan would still deliver 30% compounded annual production growth over the forecast period.

Beyond the program's robust growth potential, the underlying capital efficiency and cash-on-cash returns from our investments are evidenced by the improving leverage profile with assumed planning case oil prices of $50 per barrel and below.

Importantly, while we don't expect any material near-term service cost inflation in the current commodity price environment, our planning case assumes a staged increase in completed well costs over the next two years. We believe this is a prudent measure for long-term planning in a volatile environment in order to capture the impact of evolving completion designs and the potential for service cost inflation resulting from expected increases in core Permian Basin drilling activity.

As we have reiterated during the last several quarters, a clear path to living within forecasted cash flow will continue to be an important consideration as we increase our spending levels in order to manage volatility. This planning case honors that guidepost, generating free cash flow of $50 per barrel WTI by mid-2018. In addition, we forecast the out-spend in 2017 will be entirely funded by our existing cash balances, assuming an average $47.50 WTI oil price during the year.

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

Thank you, Joe. Again, hopefully you can see why we're excited about 2017 and we look forward to keeping you updated. So with that, we'll open the call to questions.

(Operator Instructions) Neal Dingmann, SunTrust.

Morning, guys; nice quarter. Just looking at slide 12 on the Lower Spraberry well density, just wondering -- the success you've had there on the 12-well spacing, because of that is that going to be the plan going forward? And how much tighter can you push that?

Hey Neal, this is Gary. There's been a lot of discussion by many of the companies around well density and I guess we'll continue our path of being somewhat conservative. Our current inventory still includes 11 wells across there. We're not going to change that until we see a little bit more data on these two wells. But we're still very encouraged, as you can see by the data.

Got it. And then just lastly, just on the rigs that you're adding. Obviously that continues to be levered nicely; why not add that fourth rig even earlier next year than late in year, given the results?

Another good question. The team would like to get going on it, but at the end of the day, we've got a lot of work to do on facility work. We've got to get that in. We'll be a little inefficient with the third rig coming in in January, but that'll only be for a short time, and I want to get that facility infrastructure in place before I bring that fourth rig in just to be -- I think that's the most responsible way to go.

Great, thanks.

Sam Burwell, Canaccord.

Good morning, guys. I was struck by the longer-term guidance you gave, 2017 and 2018. I want to dig in a little bit on the assumptions that underlie the net completions count in 2017 and 2018. Specifically, how quickly are you guys able to drill and complete the wells?

Again, the cycle time for drilling and completion is continuing to compress. We don't build a duck inventory at Callon. We like to get on the wells and complete them as soon as the rig moves off and fortunately, our partner in pumping services has been there right there for us all along the way.

But the cycle time for Howard County will actually come down. We've since drilled our first two wells, as I mentioned, on the new Plymouth assets and we're knocking three to four days off that cycle time in Howard County versus what we've been doing on the deeper part of the basin there in Monarch.

So I guess -- I don't have a number for you on exactly the cycle time from spud to first production but it's 15, 16 days to drill and a couple of weeks to clean up the location after the rig moves off and then another three weeks to fracture, stimulate, and then drill out. And then there's a clean-up period for that.

So at the end of the day, we're targeting around 17 wells per rig year at Monarch, and I think that'll go up at Howard.

Okay. Yes, certainly makes sense you'd realize some efficiency gains in Howard. And then to follow up, you mentioned on the same slide designed to maintain leverage below 2.5 times under down-side price scenarios. I was just curious as to what's the minimum price that you guys feels justifies this acceleration activity, and then what would be that down-side price scenario that you're referring to in that sentence?

On the level of activity and pace, with a third rig we feel very comfortable adding that rig. We've just actually signed a contract for the third rig, as you see in our 10Q. So we are moving ahead with that and feel very comfortable in sort of the mid-$40s, where we are today, and what we've seen sort of on average over the course of the year.

We do do sensitivities down to $40 on the down side, and if we did see it sustained back of the curve, looking like something in the low $40s, I think it might push back our fourth rig timing a bit. But $45 and north, I think that this plans holds together well and certainly is going to hold below those target debt-to-EBITDA measures and also keep us on a path that we're not getting too far out over our skis on out-spend.

Good, great. Appreciate the color, guys.

Gabe Daoud, JP Morgan.

Hey good morning, everyone. Maybe just starting out in Howard -- I appreciate the prepared remarks but you mentioned you don't want to get too ahead of yourself from a infrastructure perspective. You want to make sure, obviously, that's all in place before you ramp. Gary, can you maybe just comment on how much more is left? And I guess, where you stand on the progress? And I guess specifically how much more there is left in terms of an actual spending amount?

And then maybe just another part of that question -- the 2017 and 2018 CapEx guidance. How much does that assume for infrastructure spend?

Yes, Gabe. We're really just getting started in Howard County. We just drilled our first two wells, we actually accelerated that drilling because we had the opportunity to do so. We had the rig up and running, our other assets were held by production, we could go in and drill these wells, offsetting the Silver City well, and bring that forward while we're actually in the process of figuring out the full course of water-sourcing and water-disposal and then the precise and exact locations for our central batteries.

But we can then get our off-take pipeline partners all connected to those batteries and be very efficient from spud to market.

But we're just getting started on that, and there'll be a significant amount of spend in really the first half of 2017. And that range of spend in total across all of our assets, including additional enhancements that we're making at Carpe Diem simply because the significant ramp in production that we've experienced there -- and then preparing ourselves for the drilling and completion of wells and being more efficient with the new assets at Lonesome Draw and Ranger -- that range of capital is going to be around $50 million to $60 million in 2017.

Thanks, Gary. Yes, Joe, go ahead.

Yes, sorry; a finer point on that. This year we're probably running around $40 million for infrastructure. But with the increase in activity under this development plan, we are pulling some activity, in terms of a fourth rig, into 2017. So that $50 million or $60 million is going to drop down probably into the $30 million and $40 million in 2018 as well as we pull forward some of that activity.

Again, once we move into a new area we like to set it up for the long term efficient development, and that's worked very well for us on our legacy assets. It does require us to bring forward some capital in the way we like to build this out, but over that time, we can then leverage that capital over a very long period of time with the inventory that we have to work.

Great, that's helpful. Thanks, guys. And then another one from me. I guess conservatively and prudently assuming rising well costs in 2017 and 2018, can you maybe just comment a little bit about how costs are trending over all and where AFEs are today?

And then I guess on the third rig that you just signed, is that at the same daily as the two already under contract?

Yes, Gabe, we haven't finished or AFEs yet because we haven't seen a significant uplift in costs early time yet. But we certainly expect -- when we look at the company that we work with, especially around pumping services, with the increased acceleration of some of the ducks out in the basin as well as -- really it's essentially the doubling of the rig count since May in both the Midland Basin and the Delaware Basin. We know that at least the best well-maintained frac fleets are starting to get full.

We're certainly well ahead of that with Pro Petro Services and others that we talk about; because they're already out there looking to see how they can meet and always be there for us throughout all of 2017. We've shared that program with them and they're saying, hey, we're right there with you, so we're happy with that.

But we recognize that there's going to be starting to see more and more pressures on specifically that part of the business. But we haven't seen anything yet so we haven't changed our AFEs.

But you can -- the guidance we're giving you, with even more enhancement to completions and the potential for some acceleration in service costs due to demand, then it's likely 10% to 15% over the next couple of years is what we're looking at.

As far as the new rig that we just contracted, our two legacy rigs are contracted at $15,000 a day and the new rig came in at $16,000 a day.

Great. Thanks, Gary; that's good color. I'll hop back in line. Thanks, guys.

Thanks, Gabe.

Kevin MacCurdy, Heikkenen Energy Advisors.

Good morning, guys. Just to clarify, is the 2018 CapEx guidance based on 15% higher well costs from the present costs, or is that an escalation from 2017?

From current costs.

Got you. And if well costs don't go up, could you contemplate accelerating further beyond the four rigs?

We always keep that in mind. And again, it all depends on the efficiency of how we get set up with infrastructure. We just want to be efficient with what we do. We have plenty of inventory, as you know, that we highlighted on the slide. And we can get very efficient with rig activity going forward. But I'll be somewhat tempered with that pace until I get set up properly across all assets.

Got you; that's helpful. Thank you, guys.

Jeff Grampp, Northland Capital Markets.

Good morning, guys. Wanted to -- just looking at slide 8 here, with the detailed maps in it, and Wild Horse. Just kind of wondering -- looks like maybe there's some decent opportunities to kind of block things up and then maybe bolt on some acres like you guys have done in some other areas.

Can you maybe just talk about your outlook or how you guys kind of handicap your ability to do those types of bolt-on acquisitions or trades or things like that to further consolidate up in Howard County?

That's always a significant part of our work activities and our planning processes. We're already talking to companies that are all around us. Diamondback is close to our Sidewinder assets. Certainly Surge is in that area. In and around Maverick you've got QStar. Around Fairway you've got SM Energy.

So we've already developed, and had discussions at a technical level, and trying to establish stronger land relationships with those various companies to talk about joint venture wells or trades to block up for each of our individual assets.

And that's just an ongoing part of our business. It's just the normal course of our business. And fortunately we've got good partners around us that have the same strategy and the same motivation to do that as well.

So we're happy to be doing that, and we're certainly looking for other opportunities in this area and we'll be looking to see if there's any additional opportunities that come to market.

Okay. And just on the Ranger side of things with these couple of wells that you guys are doing some enhanced completions, just kind of wondering, if those end up playing out well and seeing some improved performance, how do you guys think about allocating capital to there?

I know it gets a little bit of activity, I think, back half of 2017, but could that potentially compete for a higher amount of capital than you guys are currently planning if these new wells kind of show some improved performance?

Well, first of all let me clarify that Rangers deliver solid results now. They deliver exceptional results today and yes, it competes well for capital even today. It's just not quite as good as the other two areas.

Fortunately, it is fully held by production except for a few wells that we have to drill in 2017. And so as we further refine the way we complete wells and get fully a more confident sense to a longer time period, that uplift is real and that costs then don't run away from us on services, then yes, we will clearly be dedicating some additional development for Ranger.

Because at [Hansen] Draw, the Lonesome Draw, and even our early time [Bluxom] wells, those are exceptional wells. Just that fortunately we've got so much great inventory that we're not -- we can be selective as to how we accelerate and where we go initially as we continue to build out our ramp in rigs.

Got it; absolutely, high-class problem to have. And last one for me, I think for Joe. On the borrowing base side, can you guys just kind of talk about expectations? You obviously had a nice production ramp and acquired some new production. How do you guys kind of see any future expectations on the borrowing base side of things?

Well, we're certainly in a very good position from a liquidity standpoint with the cash balances we have and 385 on draw. We're really in the midst of our review at this point that will include the Plymouth transaction. So it's a little bit early to say where things shake out, but I think an estimate of 20%, 25% is probably in the ballpark of where it'll go. But we do expect it'll be a decent bump in the borrowing base here in the coming months.

All right, perfect. Thanks for the time, guys.

Will Green, Stephens.

Morning, guys. We've focused a lot on the infrastructure build-out that needs to take place over in Howard County as you guys get ramped up. I wondered if we could maybe talk about how that affects OpEx in the first half, if at all. Being mindful that you guys are growing volumes at the same time, so that does kind of help from a fixed cost standpoint.

But shall we expect maybe a temporary uptick in, say, LOE or something in the first half of the year? Just how shall we think about that as we head into 2017?

We are modeling a little bit of an uptick in LOE to compensate for that. In this last quarter, part of it was accentuated -- we were at one end and were doing some completions in areas that weren't quite efficient enough. So we start off from a point where things were a bit inefficient from water-handling, from electricity and power, running generators and things like that. And then we increased activity, which exacerbated a little bit.

We would aspect things to be a little bit elevated and that's how we'll model. And when we give guidance for 2017, I think it will reflect that for certainly the first quarter of 2017. But we hope with the investments that we're putting in, especially from water-handling and avoiding trucking water, which really starts moving the needle on LOE, that'll start having impact going into the second quarter of 2017. But we'll be reflecting that, probably.

We've been on a downward trend on LOE. As you said, we were benefitting from some increased volumes leveraged over some of the fixed components of LOE. I'd say it's probably going to be sort of steady state in terms of a level and hopefully start ticking down a little bit more meaningfully with the addition of volumes and better efficiency, probably in the second quarter of 2017 and beyond.

(Inaudible) It is, again, the real key -- Joe touched on it. It's really water disposal to make sure you manage that cost because of the early-time performance of these wells, and that's significant cost associated with that. And it's really -- they can certainly have the right electrical capacity around all these assets to avoid the use of generators and things like that. It improves your overall operational efficiency across the board.

And as things are ramping up in Howard County, there's a lot of third-party companies out there putting in assets, and we have plans to put in some of those assets ourselves. It's kind of part of that infrastructure build that we talked about. But all that does take time. We probably won't have efficient disposal in place until probably the second quarter of 2017.

Makes a ton of sense. I was just making sure we were thinking about that the right way. And then, we've talked about the type curve and when you guys address that over in that area, obviously Silver City's been a huge success for you guys right out of the gate.

I wonder if you guys could help us -- and you may have touched on this a little bit -- but how are you guys thinking about the 2017 guide in terms of what that area provides in terms of EUR? You guys still using that 700,000 type curve? Is it something that assumes some improvement there? How are you guys thinking about -- just on the 2017 guide from that area, what, from an EUR standpoint, is that contributing?

Well, we're incredibly encouraged with Silver City, of course -- what happened with that result. But it is a single-well result. You've heard me talk about these things before. And we're about to go ahead and complete another one in that same area. So at present our guidance, as we've laid out to you, includes our standard type curve and no uplift.

We'd certainly like to see the next well out-perform Silver City; that would be a wonderful result. But I just need more than one well in order to move that curve and get it into our longer-term planning process. So no, currently we're not including any uplift.

I would point out, though, that it does include a bit of an uplift because with the mix of longer laterals, Wild Horse is going to be biased a little bit more towards 10,000-foot laterals than what we've been doing in the past. So there is an uplift for that increased lateral length. We've put off things but hopefully, as Gary said, we continue to build a body of work, build upon what -- the very strong wells we stepped into based on older completion designs. We obviously talked about Silver City in quite detail.

But we start building out our roster of wells and see some longer-term performance due to the impact of enhanced completions that -- hope to revisit the type curves sometime in the second quarter of next year.

Got it. So on an EUR per lateral foot, or however you guys want to think about it, it's similar to the type curves you guys went into this asset initially -- that 700 -- whatever average lateral link that was, on an EUR for foot, if you guys are still modeling on that original type curve, right?

Yes. Certainly we're capturing the impact of the underlying PDP performance that's above that on the existing horizontal program. But as we step out to some of these probable locations that we start to drill, it'll be on a similar basis, on an EUR per foot, as we stepped into.

Great. Thanks, guys.

Kyle Rhodes, RBC.

Hey, good morning, guys. I'm wondering if you can give us an idea of the split of the two Howard County rigs that are going to be drilling on pads versus maybe focused on HBP?

And then, any updated thoughts on optimal spacing in Howard?

Yes, all of our rigs will be drilled on pad wells. We're not -- we don't plan to drill any single wells going forward. But it would be at least two well pads, and as we get the third rig out there perhaps we'd transition to three well pads. We're very encouraged -- kind of excited, actually, to -- early time here, go in and test the Wolfcamp B.

Because if we can see the overall performance and kind of match what Diamondback indicated was the potential a quarter ago, and we see really three areas there, three zones, that we can then get very efficient about how we, either vertically or horizontally, develop this area going forward.

So anxious to be able to park a rig up in the north part of Howard County around where the Silver City well is, and another one down in Fairway where we're putting in infrastructure down where SM Energy is quite active already. So that's kind of the plan for potentially the two rigs going forward in Howard.

As far as spacing goes, we're paying attention to what everybody else is doing and reporting, but at the end of the day, we haven't changed our thoughts there because we haven't gone out and really tested a lot quite there yet, and it's still eight wells per section in our inventory for essentially all three of those zones. Not quite all of them, but essentially all three is about eight wells per section.

Okay, great, thanks. I may have missed it -- so when is that Wolfcamp B planned for?

We're actually thinking about trying to get one in the schedule early next year when we bring the new rig on. We're hoping to be able to get that done; if not, it'll be probably mid-year. But we're trying to get a Wolfcamp B in the schedule so that we can really then get very comfortable with the optionality that we have and how we utilize our surface facilities. And really how we've planned this out in a more efficient manner going forward with potentially three zones of an equivalent value.

Great, guys. Appreciate the color.

Chris Stevens, KeyBanc.

Hey good morning, guys. I was just kind of curious on over at Monarch, whether or not you guys see the potential for three different landing zones within the Lower Spraberry similar to what some of the offset operators have been talking about, and whether or not you have any plans to maybe test that next year?

We certainly see lots of potential in the Lower Spraberry. And yes, we have partners -- many of those operators have talked about three different landing zones and we're kind of anxious to continue to share technical data related to all that body of work. But at present, we're still locked into two landing zones in the Lower Spraberry with a chevron pattern.

Okay, got it. And then in terms of a completion of design, how does your design over at Monarch compare to what you did on the Silver City well? And are you planning to test anything else at Monarch on the completion design front?

We moved to the Silver City design in most all the areas that we're currently focused on.

Okay, got it. Any plans to test diverter?

Well, we're certainly paying attention. And of course we know that that, as well as the manner in which we potentially space our perforation clusters, is an interesting, evolving technology.

We're happy to be partnered with RSP Permian, who's driving a lot of that technology on the wells that we have at Pecan Acres. So we're going to watch those wells, which they used some of that same technology, and decide from that performance.

Okay great, thank you.

Irene Haas, Wunderlich.

Hey, good morning and congratulations on a really good quarter and visibility and such. And my question really has to do with what keeps you awake at night. With the Permian being newly popular, looks like we're going from a bust to a boom again.

Aside from just worry about commodity prices and cost inflation, are there any sort of bottlenecks that could potentially kind of impact your ability to drill, complete, and sell your products efficiently?

Irene, like we've said, we're myopically focused on infrastructure and building relationships with the various landowners around there that help us with that, building relationships with third-party service providers around water disposal. We're very focused on that.

Once we get that in place, there's nothing that holds up back from drilling and completing wells as well as anybody.

Okay, great. Thanks.

Gabe Daoud, JP Morgan.

Hey thanks, guys. Just wanted to ask, I guess in Ranger an offset operator is talking about the potential for a second landing zone in the A. And then I guess just overall tighter density in the upper and lower B.

Could you guys maybe just comment on that, and if there's anything you plan on testing at some point maybe in 2017, squeezing in a density test at Ranger?

We're very pleased with all the attention that that's getting and happy to be close to some of those same operators that are talking about a second landing location in multiple zones, actually. More so than even the A. But for us, fortunately our near-term focus is going to be in Monarch and Wild Horse and so we'll let that evolve and we'll learn from them going forward.

But we don't have any near-term plans to test that in Ranger.

Got you; makes sense. Thanks, Gary.

Yes.

There are no additional questions at this time. This concludes our question-and-answer session. I would like to turn the conference back over to Fred Callon for closing remarks.

Thank you. Again, thanks, everyone, for taking time to call in this morning. If you have any questions, please don't hesitate to give us a call. Thanks a lot.

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