Callon Petroleum Co (CPE) 2016 Q4 法說會逐字稿

Operator: Welcome to the Callon Petroleum company's fourth-quarter and fiscal year financial and operating results conference call. All participants will be in listen-only mode. As a reminder, this call is being recorded. A replay of the call will be archived on the company's website for approximately one year. I would now like to turn the call over to Eric Williams, manager of finance for opening remarks. Please go ahead, sir.

Thank you. Good morning and thank you for taking time to join our call. With me this morning are Fred Callon chairman and chief executive officer, Gary Newberry chief operating During our prepared a residential a presentation we boated yesterday amp to our Web site so I Ken much to download the presentation if you haven't already. If you can fine slides on section of our website at www.callon.com, before we begin I'd like to remind everyone to review our cautionary statements and important collisions included on slides 2 and 3 ' today's presentation. We make some forward being into statements during today's call that refer to estimates and plans. Actual results could differ materially due to the factors noted on these slides and in our periodic SEC files. We also refer to some non-GAAP financial Myers which a comparison across boards and with our peers. For any non-GAAP nearest corresponding GAAP measure, you may find these reconciles in the append to the presentation slides and our earnings press release both of which are available on our Webb assignment. Following our prepared remarks we will open the call or QA and with that I would like to turn the call over to Fred Callon and direct the audits charged to slide 4 of the earnings presentation. Fred.

Thank you, Eric. And thanks to everyone for joining us this morning. As Eric noted we will be using the short slide comments I will start with highlights from 2016 on the first few slides. Slide 4 offers a snapshot of our null expanded footprint inclusive of other month rye added focus area which we've named spur located in ward and paying as county Delaware businessen, the acquisition France for many year that saw us year-end improved reserves by 70% and grow our annual production by almost 60%. Porum almost all of this acreage is squarely within established core and she did that he is to pursue repeateddible wellens had in four core areas that you are all compete for capital. In 2017, we will be drilling each of those areas as we increase our rig count to four by mid-year for the current plan to add a fifth rig by early 2018. As we will talk about more during the call beings we forecast this plan to deliver compounded annual production growth of over 50% through 2018, an importantly near term growth of nearly 60% from 2017 alone. The map also spots the location of our three currently active horizontal drill rigs with the most recent rig placed into service last month. You'll note that two of the rigs are now actively drilling from the southernmost portion of our Wild Horse acreage in Howard county as we increase activity in this area to convert the required resource basin into production and cash flow into a timely and capital efficient manner. We'll similarly be turning our focus to the Delaware in the coming months to bring forward the strong cash on cash return potential of that asset base. Turning to slide 5, we've summarized some our of off our key achievements for our company that highlighted not only our asset growth but a strong operational and financial position for the future. During the last quarter, we delivered see conventional production growth of 11 percent over the third-quarter with no corresponding increase in operational @ capital employed. Once again, highlighting the capital efficiency of our high-quality asset base. We recognize, however, that gross to gross state does not deliver value which is why we continue to be very focused on maximizing topline review force BOE for controlling and controlling costs to maintain consistent adjusted EBIDTA margins which have been remained stable in the mid 70% range for most of the year despite volatility in commodity prices. Also contributing to delivering value is the progress we've made reducing our cost to capital thanks to a very successful high yield offering in the fourth-quarter that reduced or long-term interest rate by nearly 250 basis points. Summary, 2016 was a year we're very proud of as an organization. Heading in '16 we made a strategic priority to stay on the 0 our front foot and identify opportunities to expand our footprint across which we could overlay our business model and expertise to ensure share returns. We believe we executed on that plan quite well, and have set ourselves up for a period of sustained organic production and reserve growth. and waterwaysens, it is attempting to accelerate our activity each further in the floss any we will add measured pace in the coming quarters with two key guideposts in mind. First, ensure that we've established the brother infrastructure that will allow us to control the timing of our well connects by reducing our cash margin paid to third party service providers and two, maintain our solid balance sheet in liquidity with a path to cash flow neutral a relative short period of time following any increases in rig activity. I'll now turn the call over to Gary Newberry other chief operating officer, senior vice president to provide an update on the operational front. Gary.

Thanks, Fred and good morning to everybody. I'll start on slide 6, with aecium summary of our year-end approved reserves. An exceptional year of growth in both total approved and PDP volumes ending the year with a composition of 78% oil and 47% growth in proved reserves is the capital efficiency of our reserve adds with a drill bit FG. Under $9 BOE on a striatum basis on under $8 per BOE on an estimated three freedom equivalent, that most of our peers report. Including our internal estimates for the proved reserves associatessed with the recently closed Delaware basin acquisition, our pro forma reserves were approximately 106 million BOE at year-end, representing a compounded annual growth rate approaching 100% since 2013. Consistent with our historical practices, we remain prudent in our PUD bookings with only 105 locations currently approved in our current reserves including a horizontal some well count of 148. On slide 7, we've highlighted a few operational points for the quarter. All of our wells turned to production in the quarter were in the Monarch area which added to a sustained track record of delivering solid results as illustrated in the lower left chart. In addition to our strong lower train results in both the upper and lower flow units, we have been very pleased with the results from our first Wolfcamp man okay women's record plume an oil equivalent in the first 90 days of production. During the quarter, we were also active initiating our program development efforts in Wild Horse. In addition to progressing our facilities in infrastructure ininitiatives to support multiple rig activity, we have drilled three pads targeting both the Lower Spraberry and Wolfcamp A zones with two of those starting flow back since January. In addition, our two rigs are drilling in central Howard County including one three-well pad targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B zones. In summary, we are building momentum into the second-quarter and our positioning to handle the production ramp in a he efficient manner by hemping the investments we are making in infrastructure and water handling. progressing, we are turning our attention to the spur area and preparing for the addition of the fourth rig by mid-year with a similar philosophy around program development. In parallel with that preparation, we are currently flowing back a 10,000-foot Wolfcamp A well and preparing to complete a 10,000-foot Wolfcamp B well, both in ward county. want steadily increasing activity, we have been equally focused on efforts to optimize the recovery of resources four our asset base, including enhanced completion designs and density spacing tests. We provide an example of how these two initiatives are being applied simultaneouses and in Monarch area which is shown on the lower right chart on page 8. The graphic shows the performance of two pads drilled @ with 13 well spacing versus the initial eight wells per spacing section text assumptions. This latest spacing test also employed a larger profit loading and tighter stage spacing than previous wells. As you can see, we're actually seeing improved production results with the increased density. This performance has meaningful implications for both the number of wells we can drill and more importantly, the recoveries and at that point efficiency for these wells avoiding just accelerating reserves from offset locations. We are currently carrying our lowest Spraberry investor into Monarch area at 11 wells per section and will revisit this assumption once we have extended production history from these two pads. On the lower left chart, we've plotted the performance of our first Wolfcamp A well and the Monarch area versus a 1 million-barrel oil equivalent -- barrel oil I'm sorry, that's not equivalent, barrel oil type confer. In addition, to a newer generation profit and stage basing design, this well devised diverter agents to enhance near well bore completion intensity. We have been studying the application of diverters in the Permian for some time and will be incorporated their use Moving to slide 9, we provide some early time data from a Lower Wolfcamp A well in our spur area in ward county that is plotted against a 1.5 million bear oil only curve. As seep in similar Delaware basin wells in our over pressure areas in the eastern side of the basin, the core by the is producing with strong casing pressures and we it expect to flow naturally for an extended period of time as we manage pressure draw downs to optimize longer term performance. While we have data from other Wolfcamp A wells drilled in the area to support our type curve expectations, we will be watching this well to see the impact of several new generation completion techniques that we used, including 125-foot stage spacing, diverter agents and than owe Surfak ants. This will be an important data point as we finalize our initial completion designs @ for the development program that we'll start a few months. I'll now turn back to our recent results on the operating cost side on slide 10. As we discussed Hart quarter, we are working hard to I want grate the various operations that we have acquired over the last year. This process presents several challenges, including upgrading older taping batteries and equipment that is captured in repairs and maintenance, establishing more reliable and third party and operated water disposal solutions, a transitional period of heightened level of down-hole repairs and workovers from subopt million malwell designs and equipment why, in an I doings to our above new assets, we experienced an unexpected spike in well failures to our Ranger assets in the fourth-quarter which led to unacceptably high LOE and also caused unexpected downtime that impacted production volumes. To provide some detail, we implemented a program to lower the rod purposes to increase draw down and enhance production, which achieved the expected production increase but also created an unexpected weakness in the certain section of the rod string resulting in early repeat failures. Formally, we believe we have turned the corner on this issue and will be -- have this issue fully resolved by the end of Q1. Further cost reductions and efficiency gapes will be achieved in the second half of 2017 once we've fully billed out or brand infrastructure projects to enhance water disposal capacity in Wild Horse and lonesome drew areas, which have been been a And while we've recently accepted into a new operating area at spur, we see less LOE exposure primarily in water disposal given the relative active levels of historical horizontal development that required more operational focus and investment from the previous operator. My last two slides will could have our operational drives for the next several quarters. Starting on slide 11, we plan to turn approximately 34 net or 46 gross wells online in 2017. Targeting five distinct flow units cross our all four of our core operating areas. We will continue our focus on drilling longer laterals which has been enhanced with the addition of the Wild Horse and spur areas. We estimate our average lateral length for our 2017 development activity to be approximately 7,500 feet. Longer laterals in spur will continue to move this average up in the future as we increase our activity in the spur operating area. Given the longer lateral lengths and increased total measured depths in the day basin, spud the first production times are increased, pushing initial production contribution from our fourth rig into the fourth-quarter of this year and early 2018. @ lastly on slide 12, I'll address the capital side of the equation. We continue to deliver wells at a per completed foot 750 lateral for our 2015 planning assumes we have I did increases by 10 percent @ on average over the entire year. This assumption is intended to capture expected reflation in service cost as well as continued investment in completion design that add incremental value. And we expect to partially offset these increases by the operational efficiencies we continue to realize over time. In terms of facilities and infrastructure, this has been a consistent point of emphasis for us as a capital efficient operator, best drives to dictate our space of development and not be beholden to third parties. We will be finishing this year build out of ex-terms I have is water handling a ' a wild hours facilitating a path multi-rig operations over time. We also have some up fronts costs associated with spur but these are much less than Wild Horse given the amount of existing infrastructure so saltwater disposal wells and water gathering lines that are already in place, once we are past this initial our facilities investment idea creasing more than 40% to approximately $50 million in 2018. Joe Gatto our President and Chief Financial Officer will pick up on slide 14 with the financial discussion and longer term outlooks. morning. On slide 14, we summarize a few key points of our financial performance. Production for 2016 was up approximately 60% year-over-year and over 10 percent sequentially from the third-quarter. Our realized price per BOE produced for the fourth-quarter was $42.13 per BOE. On hedge basis and $40.90 per BOE on an unhedge basis. Which is an amongst best across our peer group and reflective of the high oil content in our production stream and favorable off take arrangements the gained with the cash operating structure the decreased 20 percent in 2016, our adjusted EBIDTA margin for the year was over $28 per BOE leading to strong internal ratio that is now under two times including the pro forma impacts of the mare acquisition. Despite some inflation father pressures entering the market we expect other cast rathing an excluding production attaches to at the crease once again in 2017. Reflecting the impact of a production base in the initiatives in progressing the efficiency of our repeatsly acquired positions. Before I leave this page, I'd like to highlight a comparison of our 2016 cash operating margin relative to our reserve addition costs. This internal cash generation per BOE produced exceeded two measures of reserve addition costs by approximately two to two and a half times. Positioning us to drive an acceleration of an organic PDP additions with a strong foundation of cash

On slide 15, we enter 2017 with an undrawn credit facility and $66 million of cash balances after adjusting for the closing. Myriad acquisition earlier this month. He the impact of this repeat acacquisition bow owing pace of 500 millions will be assessed as part of our regular spring redetermines. In addition to you are strong liquidity position to support our capital program, our total leverage position remains amongst the best in the Smith cap universe with a pro forma net debt to LTM EBIDTA of 1 point # tiles. In terms of asset coverage our $810 million at SEC pricing of approximately $40 per barrel oil and 270 per MCF gas covered our net debt position over two in long-term debt capitalization levels. As we enter a period of accelerating activity, we've also entered into additional 2017 and 2018 oil hedges taking our average downside protection to approximately $48 on 8,450 BOE per day in twenty and $50 on 7500 barrels of oil per day in 2018. On page 16, we picked up from Delaware's discussion on 2017 operational activity and outlined our budgeted capital levels for the year. Our total operational capital program excluding only capitalized expenses is estimated to be in a range of 325 to 350 million. The previous capital budget estimate that we provided in November prior to incorporating the myriad acquisition, was $275 million, including seismic and leasehold costs. The increased amount of DNC develop element he ever 0 our briar 2017 investment is largely driven by an additional quarter ever of activity why a -- assumed July 1st start date versus a July 1st state tart a this capital impact is also accentuate in the budget to due to a change in the mix of our over all wells, in effect we are Admiralling a quarter of activity drill 10,000-foot drills in the dwell wear we current 8.5 to 9.5 million including the heeding edge completion stein that Gary discussed as well as replacing a quarter of 75000 lat 5.5 million with higher cost wells with longer laterals. In terms of facilities, we added roughly $20 million to our previous estimate. All of which is intended for the pure area both fort criminal rig arising in 2017 and future increases in activity as our Delaware capital allocation gross over time. It is also important to note that the initiation of our Delaware program as the effect of deferring the timing of the initial impact of the third drilling rig due to interested cycle times deeper wells relative Midland Basin find with our wells. This is evident in our forecast when comparing our November estimate of 36.7 net completions in 2017 verdicts our current estimate of 33 to 36 net completions even with the earlier arrival of the third rig. Overall, we believe that we are appropriately using conservative assumptions related to timing of production of our Delaware pads in order to address any learning curve issues and would expect to see improvements as our spur development matures. However, the positive impact of our Delaware investment program becomes readily apparent in late 2017 and early 2018 which I'll cover in a moment. Slide 17 summarizes our forecast of key operational and financial program enters in 2017. Highlighted by an annual production growth rate of approximately 60% at the midpoint of guidance. We expect that our 2017 production growth will be relatively even over the course of the year culminating with an exit rate in the range of 28,000 to 30,000 BOE per day in December 2017. This exit rate compares with the previously forecast 2017 exit rate of approximately 23,000 to 25,000 BOE per day under the midland only programs. @ on the operating cost front, we forecast continued year-over-year reductions in cash G&A and stead improvements in LOE as the year progresses. I'll finish up my remarks on slide 18 with a longer term view of the business and planning scenarios. Currently, we are planning to add a fifth rig in early 2018 in either the mid land or Delaware basin. Given we are just stepping into the pure position, we are assume the rig will be in the midland base ' for this presentation as a pace line. Up the case outlined here, we forecast 2018 production to increase to the range of 235 5U 203-7500 Bowe per day of effort sod capital of approximately 425 to 457 million. Our 2018 capital efficiencies benefited by a reduced level of facilities investment in the Delaware drilling program that is hitting full stride. Due to this strong cash on cash returns from our the end of the third-quarter of 2018 and be carrying a net to debt EBIDTA position of under 1.5 times by year-end 2018 assume a flat WTI oil price of $52.50 per barrel. Under a strip price scenario, we project cash flow neutral to occur one quart sooner in the second-quarter of 2018. If the last two years that is taught us anything which always be expecting the unexpected. We recognize that the volatility we continue to be prevalent in our business both in terms of commodity prices and an impacts of a rapid increase in the Permian. As a result, we never want to be in a situation where the past cash flow neutral is door far into the future. As we look further into 2018 following our current infrastructure investment program for future growth, we will have the flexibility increased activity in both the midland and Delaware I'll now turn the call back to Fred for some final comments.

Operator: Thank you, Joe, that you Gary. Again, as you can tell, we're certainly very proud of our accomplishments during 2016 but we're more excited I think about 2017 and '18. That the great asset base we put together and we think the outstanding operating team we have. We look forward to significant growth over the next several years and continuing to maintain flexibility with a strong balance sheet. So with that, we'll open the call to questions.

Fred before we get too far into the questions I just want to clarify one thing I did say.

Absolutely.

I made the woman's reference to shied # whipped that is oil only. That is BOE. Slide the was on my mind because that's a strong oil curve. They're both exceptional wells so I'm glad to have both of them but I want to clarify slide # at Monarch is a BOE curve.

That you Gary. So with that we'll open the call with questions.

Operator: Thank you, Mr. Callon. We'll now begin the question-and-answer session. (Operator Instructions). Question and Answer. of JPMorgan. Please go ahead.

Hi good morning, Fred, good morning everyone. Gary, maybe this one's for you. The stag every day and something test at Sidewinder and Maverick, any early research you can share with us in terms of early time performance. read. I know there's a lot of interest in Wild Horse and there should be. We're still incredit whether I excited by Silver City performance is incredibly a strong well even after the extended lengths of flow back. The well's offsetting Sidewinder in that sill Silver City area and are still flowing back and flow back pressures just like the Silver City well did but we're still too early to tell really on what those wells are going to do. That, as well as the Wolfcamp A well in Maverick, it looks to be a strong well as well. Now, the Lower Spraberry as we expected and is probably nothing new has taken a little longer to get the water out of the way and get oil production but looks like it's performing like we would expect it to do.

Great. Thanks Gary. And then maybe just on '18 you guys mentioned not getting too far of your skis in terms of upstream development ahead of up treatment infrastructure. You highlighted cash neutral I guess by second and third-quarter of 2018 but just trying to think about accelerating further on the Delaware and if you guys are willing to step on the gas and maybe add spent perhaps a bit more to pull forward some of that value and I guess presumably add a sixth rig at some point in the back half of 2018 which would be, I guess, a second rig in the Delaware. Just trying to frame how you guys are thinking about it.

Yeah, again, I mean, I think you can -- you can get a sense very, very well is even more important. Having the right infrastructure in place everywhere we work and we can see it. We can turn wells on in Monarch and it's right there because we invested all the money we needed to do to be very efficient in Monarch. I've done the same thing at ranger. We're doing that at wild hours and we'll have to do some of that still at spur. @ but to answer your question, we'll be in a position I'm pretty confident we'll be in a strong position to have that done and working as efficiently as we're working in Monarch today in 2018. So I think we'll have flexibility to go either way. And my view is, we go wherever the best value is. So it could be spur and it could be Wild Horse. So I'm excited about preparing for both @ opportunities.

Thanks Gary. That's helpful.

I think that's -- that sums it up. We can get in a position where we can be efficient but I think 2018, like I said, what we laid out here is five rigs, but given the optionality we're flow generation we're seeing, I think we'll continue -- we're looking at scenarios now to further accelerate activity, but we're you know, getting through some of this infrastructure completion design. So we have some things to take care of, but that's certainly on our minds to keep pull forward some value here.

All right. Thanks, guys. That's helpful. I'll let someone else on.

Operator: The next question will be from Ron mills of Johnson rice. Please go ahead.

Heir, good morning, guys. Just one question on the fourth-quarter. Joe, I don't know you were able to take stock of the kind of impact from the @ rod issues at Ranger and the weather and how much each of those impacts impacted the fourth-quarter since operationally everything else seems to be , you know, kind of exceeding expectations.

Yeah, no, I think that at least in -- it's hard around the downtime on the rod issues to just isolate that one component. to where we ended the December month without the weather related downtime and the estimate of some of these failures, again, it's an exact. Probably about a thousand barrels a day that it cost us on equivalent in December. And that's where we saw the spike in the workover activity. Again, it was throughout the quarter but it really spiked in December so I'm just focusing on December and I'd say probably about a thousand barrels a day and some other impacts in November but that's one number I have, Ron and we can probably follow up with a little bit more with you.

Okay. And then Gary, just from a completion standpoint, I know you're talking about you know increased density tests on the 13 wells and increased proppants I saw on some of those you're using two thousand pounds and also some of those areas using 2800 pounds. What are some of the proppant consent operations you're going to get up to this year and is it going to vary by area.

Yeah Ron it will be vary by area. We're not completely locked in but at least what we generally think about pumping today in the Midland Basin is about a 200-foot stage length with 2,000 pounds per foot of proppant. We're very excited by this Wolfcamp A well that -- that RSP completed it's in the Pecan Acres area and we're the operator of that area but we let them drill and complete the Wes as we've talked about before. But they use diverter agents on that well so we're very excited about potentially incorporated that type of technology into what we're doing in the Midland Basin as well to further enhance performance of wells throughout Wild Horse, Monarch and Ranger. But in the Delaware basin, you've pointed out that 2800 pounds per foot, that was what was pumped actually in the core by thes well by myriad and that's what we plan to pump in the Saratoga well as we plan to frac that well sometime next week. So we're looking at that, we see that higher proppant loading the diverters even as well as than owe is your facilities investment ants seem to be working quite well in the Delaware at those wells' performance as well as other new wells that are going to come on in the area prior to us even getting start the in July with our development program @ we've already set up several technical exchanges with several operators in the area to help glean additional information from them as we give them information that we've learned in the Midland Basin that applies to the Delaware basin as well as some of the data that we're acquiring, or getting with the new asset. So it will change, it will modify, but we'll always be looking at what not only us, but the entire industry's doing to be on the upper end of that learning curve on completion technology.

Great. And then one last one. Just in the Delaware, is the primary target going to be Wolfcamp A and then on the tore by thes and the Saratoga well that was drilled by myriad with the data that you have there, are you happy with where the laterals were targeted and how you might plan your wells? Thank you.

Yeah. The corpus well is in the Lower Wolfcamp A and it's a little higher than we would have landed it but it's still performing quite well. So we'll think about where we land that well, but it's performing well, it's a strong well now, it's still got considerable pressure on the casing. And you know, we've shown you the confer curve. It's performing very, very well. But Wolfcamp A, the Wolfcamp B well, the Saratoga we go that we're about to complete has landed about where we want it so we're okay with that. So there might be a little bit of opposition but again, that's some of the technical exchange that we want to have with some of our partners in the area and some of our adjoining operators. So @ we'll continue to refine that as we see it.

Thank you. RBC. Please go ahead.

Heir, good morning, guys. Any update you can give on the Silver City well maybe -- the oil cuts are holding and can you remind me what's flying our while who is for twenty and ate. Is it a 12700 BOE Wolfcamp A type curve? @. here, Kyle.

Sure.

Yeah. We bumped the type curve in Sidewinder just a little bit. We're getting closer to million barrel Wolfcamp A curve for 750 feet that's all associated with the production a we see in the silver sidewinder well. Is silver sidewinder well is still making 600 to # hundred barrels a day I don't know how many days it's been in production it's been sometime.

Since July.

Since July. So that.

The oil cuts have not changed at all. It's a strong well, so we bumped or type curve in side wipedder just a bit but we didn't bump them anywhere else. So it's right around a million barrels for Wolfcamp A, 700-foot well.

Got it so their to thing what you're egg earl flow okay ban those earl wells there's nothing I guess, go against what you stayed on the Silver City well.

No. Not in the Wolfcamp A. That well that's off sit setting it is doing just fine. So nothing to suggest that we should -- we've moved too far or we've had got more to go yet. We still need more time. The other areas are similar to what we talked aboutle previous. We have not moved those curves.

Perfect and any cover you can give the well costs the core by the. I don't know you're not in control there nurse juniors well costs to kind of friend once you guys take over operatorship there.

Yeah. We're still getting in the costs on that on a cash basis, but it would be at the higher end of that, eight-1/2 to $9 million range that we put out there I think is what we've been tracking. But there's a lot of things put into that well as Gary talked about. But again, we're finalizes our completion designs for that area. I think that there's certainly some things that we as a larger company that's more active than the previous operator can take advantage of and work on those costs with these leading edge designs, but it was certainly a more expensive well than what we've been drilling. @.

Great. And just one final one, if I could. In your slides, mentioned optimization of optic contracts in the Delaware. Anymore details you can provide on that and loud should we

For modeling purposes, what previous operator was achieving, what we see is probably about a dollar back from what we're realizing in the Midland Basin. In terms of optimization, again, stepping in to this position as a larger public operator that has visibility on sustained development, we're getting a lot more attention from oil off take and gas gatherers and further optimize the contracts that are in place. Being only back a dollar is what they were realizing is pretty good, just given -- they were set up with legacy infrastructure. But we relationships he have with he have in the Midland Basin to expand them in the Delaware and to hope keep working on that. It made a meaningful impact on our Midland Basin topline as we've worked not only get the trucking to our pipelines but working on our get our tariffs down and developing pose hostage stamp type arrangements. So I think similarly we are starting from a good point but we think we can do better and pick up some more economics there.

Thanks for all the color guys, I'll hand it back.

Operator: The next question will come from Jeff Graham from Northland capital. Please go ahead.

Morning, guys. Just wanted to follow up on an early comment Gary that you made regarding the core by the well first. I think you said that 2800-pound of foot design and just wanted to clear. Did that incorporate any of these other kind of leading edge, the denser stage spacing diverters is your fans or any of those other things you guys why looking to incorporate.

It did it had 125-foot stage lengths, 2800 pounds per foot proppant loading, it had some diverter application. Not much but some. And then it did incorporate than owe surfactants, it did. All wells.

Okay. Great. And on the midland side, you guys mentioned still carrying eleven wells a section in the Lower Spraberry. With the results that we're seeing certainly look positive on density spacing is it just a matters of more production history to look to provide the inventory and kind of what's the timing be helpful.

Again, we're encouraged. Again, it's still early time in my mind. Important to me is actually more time on these pads and then I'd like to see some early time on the next completions at castle man, which are internal to the section immediately offsetting some higher density wells. So if I get some really positive indications early time I'll probably be able to move that estimation of density sometime by mid-year is my guess.

Okay. Great. And last one for me. I think it's on slide 12, you guys kind of highlight some potential monetization of your facilities and infrastructure investment. Just kind of wondering how you guys are thinking about that either from a timing standpoint a structure standpoint a JV to cost sure to any future build outs any kind of incremental details or thoughts there would be helpful.

Yeah. I don't think there's a a target date right now. I would say that we are working upon evaluating several operations at this point to just really help us with being capital efficient through the partners that we can team up with to help us with some of the capital infrastructure build out. But I wouldn't say anything imminent but we are working hard @ in the near term talking to several parties importantly trying to find the right partner see what makes sense for us. But we'll provide updates as the year goes on but nothing -- nothing right this fifteen minutes.

Thanks. Appreciate the time, guys.

Operator: The next question will come from Sam Burwell of Canaccord. Please go ahead.

Morning, guys. I wanted to touch on service costs looks like the guidance that you guys are giving in terms of inflation is the same that you gave in November. So I'm just curious if you've seen anything change on the grounds whether you've seen kind of realized costs to trends up in the past few months or if the ten to fifteen is still a modeled assumption?

Yes, Sam, this is Gary. The ten to fifteen% still is the right number that we can see outlook being right now. @ we have some cost move. We've seen a minor increase in sand cost and some chemical cost associated with fracing so that's gone up about 6% early time. Rig rates have stayed the same, at least at this point in time, but rig rates will go up a little bit in the next quarter simply because we've agreed that, heir, as the market moves we'll give some of that back to cactus who was a vital partner to us going forward. We've seen some increases in tubular cost as you probably heard from others, with all the demand that's come tune letters have increased quite a bit. So I think the assumptions we've given you are still pretty good for now until we see it more major moves overall across the basin.

Okay. Great. And then the follow up sort of touches on one of the questions asked before in terms of potentially accelerating in the Delaware like next year. But curious if you guys to go to two rigs in say 2018, would that require my meaningful addition to infrastructure facilities cap ex-that year or is your 2017 spend on a front end loaded up that you can dial up a rig without real changing that much of a nonDNC cap ex-next year?

Now, again I think -- wing the waive we've thought about it is the capital we're spending now gives us flexibilities to bring that rig forward in either areas. @ so I think we're pretty pleased what we're talking about with infrastructure in 2018. And the other thing we're looking at as Joe just referenced this issue around partnering with a third party. Baugh we don't want to go invest all this money themselves so we got to partner with the right third party on peak loading for water management. So if we partner for the right third party in all of our different areas which is what we're really opening up with discussion now with select parties, it really provides us even greater opportunities to accelerate production once we get LinkedIn to their systems. @.

Got T appreciate the color, guys. Thanks.

Operator: The next question will be from Neal Dingmann of SunTrust. Please go ahead.

Morning guys. Gary, for your Joe just a little bit different kind of way to spin this on the cycle times now that you guys are progressing in the Delaware, how much difference do you anticipate the cycle time? If you could just talk about I know I want to make sure some don't realize that out there when I compare the Delaware versus midland when you guys think about a dollar spend or cycle time. Can you just give me some Delaware.

Yeah. Look, we're just getting into the Delaware program so you know, we have our estimates and we have a starting point and to give you a frame of reference what we're incorporating as a model, we think it's appropriate to be on the conservative side in terms of the getting wells on production but a rig that arrives in July, one, starting a to drill a two well pad for so thousand foot laterals we see initial production come in mid November to give awe sense of what type of extended cycle times that we're seeing for -- for two very long wells and a deep over pressured regime. We certainly hope to do better thatten that we got a plan for some extended times at this point just because we're stepping into the position and that's our modeling assumption for now and we'll revisit it as time goes on. But Gary, if you want to talk about how we thought about that.

That all fits cycle sometime to drill is a little longer and it's a longer lateral which we're happy to have that type of capital efficient opportunity. Shorter stages over that length of lateral takes longer to pump and it's takes longer to drill out and then it takes in the manner in which we have will manage the flow back there it will take longer to dewater and get the peak production. So that all that's the way we've generally thought about it and the way we've modeled it, and in the Midland Basin, we can bring cycle time and completion we can drill in a month and dewater. So it's maybe a two-1/2 to three-month cycle versus a five-month cycle.

And that's for a three well pad.

Right. So it's clearly different and and the challenge I have for my team is that's what wee planned for so let's go beat it.

No. Great point fair and that's what I was getting at with the bigger pads to make sure that everybody's sort of aware of that.

Right.

Ann then just lastly, on the enhanced completions again, as Joe said I notice earlier in the Delaware so maybe just pertaining to the midland since you've been there a bit longer, do you think you're reaching a point in some of your areas now where you think, you know, you might not be seeing a bit of diminishing returns and you've probably rate that point where you fight particularly on the sand or the lateral length?

I'm always open to learning more things, but I do think I'm starting to hitman issuing returns and it may be stiff to certain zones. Okay. I'll just @ give you some thoughts on what I'm kind of interested in right now. This issue of dewatering the Lower completions on there, I'm wondering if I can probably get equal to or better performance if I actually pull back on the Lower Spraberry completions but still keep the enhanced A completion. So I'm starting to feel like I'm at a plan issuing return and I don't know if I'll are Your Honor that any higher still I start area but I may be thinking about thinking about pulling back on some zones rights now.

Great details, thanks, guys.

Thanks, Dan.

Operator: The next question will be from Dan McSpirit of BMO Capital Markets. Please go ahead.

Thank you, folks. Good morning. Recognizing it's early stages notice Delaware basin, is there anything in your acquisition assumptions that are either proving aggressive or @.

Dan, in terms of how we looked at that asset base, it was you said penned on the Wolfcamp A and Wolfcamp B. Obviously we have a good data points with the core by the that's performing in line with our expectations there, early time we really haven't gotten the water off that well yet @ and we hope there's more to come. But I don't think we can say anything right now that's materially different, just given we just closed on the asset you know, a few weeks ago. But what I would say we're seeing as we talked to offset operators that there will be a lot of delineation going on in the area outside of that that base Wolfcamp program, probably more notely in the second bone spring and the Wolfcamp C or Lower Wolfcamp B as others term it. So I wouldn't say anything from an operational or type curve standpoint but just because it's early time. We'll have the Wolfcamp B frac starting here shortly so we'll have another data point to correlate because we were probably less aggressive on the Wolfcamp B curve just because there weren't as many data points that's somebody we'll be able to fill in the details but right now everything seems to be much in line with how we looked at the asset and we're pretty excited about some of these other merging zones while we didn't put value on we certainly recognize the resource was there and we'll look to continue to learn as some of those Flynn authentication drill goes on.

Got T appreciate it. As a follow-up, you just remind us of the HBP status both in the mid land and wear basins and maybe the rigs needed on it capitals required to hold the leasehold and maybe as a follow-up any acreage allowed to expire. @.

In terms of drilling commitments, it's really focused on the Wild Horse area on the back of those acquisitions that I think is probably one, one and a half rigs of activity over the next year or two. The Delaware basin position a fair amount of it was held by legacy production because there was legacy development there @ and then another big chunk is really under termed 2019 so nothing onerous or nothing we couldn't handle So I would say really the drilling obligations are going to be focused on Wild Horse but with two rigs running there today we don't see any issues that's going to drive our decisions.

Got it. Appreciate it. Have a great day. thank you.

Thanks.

Operator: The next question will be from Chris Stevens of KeyBanc. Please go ahead.

Heir, good morning, guys. You know, I will juniors wondering if you could maybe eliberate a little bit more on that increased type curve in the Sidewinder field in Howard. I guess what's behind that curve and you know, how much -- how much is the Silver City well out performing the one million barrel type curve at this point?

The things that are behind that type curve are only the performance we saw from the Plymouth package when we got it as well as the Silver City and that's really it.

Okay.

Operator:

Just the wells that we had stepped in and I don't think in this presentation but in our other IR presentation that's up completion design are tracking a 1 million BOE so there's a body of work and then you add the Silver City on there, which is I think tracking 1.8 million BOE on that, you know, we're moving up closer to a million just in that area and just for the A. But that's really what's behind that.

Okay. Got T that million barrel type curve is still based on the older generation completion design in the Silver City's pretty significantly out performing?

That's correct.

Got it. Thanks a lot.

Yeah.

Operator: The next question will be from gentleman gene way of city. Please go ahead.

High good morning, everyone.

Morning. A gene.

Hi. Is sounds Ridenour focused on I want agree acquisitions from last year and setting up for mull if he year einterpret development mode. Can you give us any updated thoughts versus the December call on growing your overall footprint. I would say specifically, are you more or less inclined to enter into say a fifth operating area either in the midland or on the Delaware side?

Gentleman neap, I think as we talked about during the preparation, @ we think 2016 was a great year with a lot lot of great assets together and really looking at 2017 more from an organic standpoint and really, that's going to be the focus for us this year. And so, we're really not spending a lot of time looking for a fifth, core area right now. We feel like we need the market has supported us in a great way in 2016, got great assets and greats team. So we're focused on generating return from that. Certainly, we continue to look if there are opportunities that are certainly in and around our core areas we'll continue to look at those opportunities.

Yeah. And on that point. There's certainly in ward county and Howard, there are some smaller acreage positions leasing opportunities using brokers that we have employed so, there's some smaller things that if they came to fruition really something we would handle with the existing balance sheet and the flexibility we have from a debt perspective. So there's some smaller things that -- smaller pieces of acreage, couple hundred acres here or there connection tend a lateral position and really create some value at some lower price points so that's really the focus as Fred said, wouldn't characterize by any stretch we're looking for that fifth operating area at this point.

Okay. Great. Thank you for taking my call.

Operator: The next question will be from Kim rest band of any sexual owe. Please go ahead. breakdown that you provided it's on slide 10. I know you're now breaking out gathering and treating expenses as a separate item. I can see that that if mime looking at your bar chart correctly that kind of increased a bit throughout '16. Can you talk about what drove that decision and what you've seen that is making that expense go higher, I guess?

Well, I guess the decision to break it out I think is just to help with comparability across our peer group that I think most of them break it out. So just to break that element out of it because it's something that's a little less under our control. In terms of the increase, it was really a change in the contract structure that happened sort of mid-year really around Again, we forecast to be sorts of flat where we are on a per BOE basis throughout the year. So there was a change mid-year that did roll through but we don't see that changing from here, Tim.

Okay. Thanks. Thanks for the clarity. And then this is following up a bit on Sam's question. He asked what I was going to ask about the midstream build. So I'm under the impression I guess the fifth rig may be hurt county could be in Delaware. Is that dependent on how the facilities spend kind of unfolds in the next couple quarters? Is that the driver of that or is there something else where you kind of add that fifth rig?

Yeah. I mean, I'll start and maybe let Gary fill in. This year as you can tell, we have an accident amount of infrastructure spent to give us the flexibility to accelerate @ where we want where he want to sort put it simply and use that drill bit option amount across other as we decidiest these operate for '18. So I think right now is you know we're stepping into Delaware, we have some really encouraging results us. We want to understand that better, refine our completion designs. Really get to a point where we're up and running in that area and then make decisions in terms of where to best allocate capital and , you know, based on what we're running Monarch and in Ranger. I mean, there's a lot of areas that can attract capital at this point. So I think first and foremost is a great starting point. If we're going to have flexibility to move across these positions because infrastructure is there if we don't move at the rate pace. So I think before we say it's going to be in the Delaware or where in the midland we probably need to fill in a little bit more holes or get some more information around the spur asset. Before we bring it all together with the finer points. Gary, do you want to add anything to that?

No. I think the key is we're going to get efficient in all of our areas and we're going to have flexibility and once we're efficient and ready to go we can see line of sight for capital discipline around or balance sheet still, then we'll be ready to bring that value forward. It's a fairly straightforward process. We've followed it for the last several years and it's worked very, very well for us and we've just got to be prepare now on all these assets to be just as efficient as we were before. So that's the focus in 2017 that will give us tremendous flexibility in 2018.

Appreciate the color. Thank you.

Okay.

Operator: And this will conclude our question-and-answer session. I would like to hand the conference back to Fred Callon for his closing remarks.

Thank you. Once again, we do appreciate everyone taking the time to call in and take the time to ask the questions and certainly if you have any questions, don't ever hesitates to reach out to us. Thanks so much.

Operator: Thank you, sir. Ladies and gentlemen, the conference has concluded. A replay of this event will be attending today's presentation. You may now disconnect your