Feb 28, 2017
Executives
Eric Williams - Callon Petroleum Co. Fred L.
Callon - Callon Petroleum Co. Gary A.
Newberry - Callon Petroleum Co. Joseph C.
Gatto - Callon Petroleum Co.
Analysts
Gabriel J. Daoud - JPMorgan Securities LLC Ronald E.
Mills - Johnson Rice & Co. LLC Kyle Rhodes - RBC Capital Markets LLC Jeff S.
Grampp - Northland Capital Markets Sam Burwell - Canaccord Genuity Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Daniel Eugene McSpirit - BMO Capital Markets (United States) Chris S. Stevens - KeyBanc Capital Markets, Inc.
Jeanine Wai - Citigroup Global Markets, Inc. Timothy A.
Rezvan - Mizuho Securities USA, Inc.
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.
Eric Williams - Callon Petroleum Co.
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 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 & 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 statements 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 refer to estimates and plans.
Actual results could differ materially due to the factors noted on these slides and in our periodic SEC filings. We will also refer to some non-GAAP financial measures today, which we believe help to 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?
Fred L. Callon - Callon Petroleum Co.
Thank you, Eric, and thanks to everyone for joining us this morning. As Eric noted, we will be using the short slide presentation available on our website as a backdrop to our comments.
I'll start with highlights from 2016 on the first few slides. Slide 4 offers a snapshot of our newly expanded footprint, inclusive of our most recently added focus area, which we've named Spur, located in Ward and Pecos Counties of Delaware Basin.
The acquisition capped a transformational year that saw us more than triple our surface acreage position in the Permian, increase our year-end proved reserves by 70%, and grow our annual production by almost 60%. Importantly, almost all of this acreage is squarely within established core and conventional shale plays, giving us the optionality to pursue repeatable well performance in four core areas that all compete for capital.
In 2017, we'll be drilling each of these areas as we increase our rig count to four at mid-year, with a current plant to add a fifth rig by early 2018. As we will talk about more during the call, we forecast this plan to deliver compounded annual production growth of over 50% through 2018, and importantly, near-term growth of nearly 60% in 2017 alone.
The map also spots the location of our three currently active horizontal drilling rigs, with the most recent rig placed into service last month. You'll note that two of the rigs are now actively drilling on the southern-most portion of our WildHorse acreage in Howard County, as we increase activity in this area to convert the acquired resource base into production and cash flow in a timely and capital-efficient manner.
We'll similarly be turning our focus to the Delaware in coming months to bring forward the strong cash-on-cash return potential of that asset base. Turning to slide 5, we've summarized some of our key achievements for our company that highlight not only our asset growth, but a strong operational and financial position for the future.
During the last quarter, we delivered sequential production growth of 11% 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 growth for growth's sake does not deliver value, which is why we continue to be very focused on maximizing top-line revenues per BOE and controlling cost to maintain consistent adjusted EBITDA margins, which have 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 have made reducing our cost of capital, thanks to a very successful high-yield offering in the fourth quarter that reduced our long-term interest rate by nearly 250 basis points. In summary, 2016 was a year that we're very proud of as an organization.
Heading into 2016, we made a strategic priority to stay on our front foot and identify opportunities to expand our footprint across which we could overlay our business model and expertise to enhance shareholder 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.
With a large inventory of delineated projects in both the Midland and Delaware Basins, it is tempting to accelerate our activity even further in the near-term, but that is not our philosophy. We will add rigs at a measured pace in the coming quarters with two key guideposts in mind: first, ensure that we've established a proper 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 and liquidity, with a visible path to cash flow neutrality in a relatively short period of time, following any increases in rig activity.
I'll now turn the call over to Gary Newberry, our Chief Operating Officer, Senior Vice President, to provide an update on the operational front. Gary?
Gary A. Newberry - Callon Petroleum Co.
Thanks, Fred, and good morning to everybody. I'll start on slide 6 with a summary of our year-end proved reserves.
We had an exceptional year of growth in both total proved and PDP volumes, ending the year with a composition of 78% oil and 47% proved developed. Equally as important to the nearly 70% growth in proved reserves is the capital efficiency of our reserve adds with a drill-bit F&D of under $9 per BOE on a two-stream basis and under $8 per BOE on an estimated three-stream equivalent that most of our peers report.
Including our internal estimates for the proved reserves associated 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'll remain prudent in our PUD bookings, with only 105 locations currently included in our proved reserves versus a total producing horizontal 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 Spraberry results in both the upper and lower flow units, we've been very pleased with the results from our first Wolfcamp A well in Monarch, which has produced almost 100,000 barrels oil equivalent in the first 90 days of production. During the quarter, we were also active initiating our program development efforts in WildHorse.
In addition to progressing our facilities and infrastructure initiatives to support multiple rig activity, we have drilled three pads targeting both the Lower Spraberry and Wolfcamp A zones, with two of those starting to 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 are positioning to handle the production ramp in an efficient manner by leveraging the investments we are making in infrastructure and water handling. Now that we have the WildHorse program development 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. While we have been busy with integrating assets in the right way and steadily increasing activity, we have been equally focused on efforts to optimize the recovery of resources for our asset base, including enhanced completion designs and density spacing test.
We provided an example of how these two initiatives are being applied simultaneously and on 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 8 wells per spacing section test assumptions.
This latest spacing test also employed a larger proppant 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 capital efficiency for these wells, avoiding just accelerating reserves from offset locations. We are currently carrying our Lower Spraberry inventory into Monarch area at 11 wells per section, and we'll revisit this assumption once we have an extended production history from these two pads.
On the lower-left chart, we've plotted the performance of our first Wolfcamp A well in the Monarch area, versus a 1 million barrel oil type curve. In addition to a newer-generation proppant and stage spacing design, this well utilized diverter agents to enhance near-wellbore completion intensity.
We have been studying the application of diverters in the Permian for some time, and we'll be incorporating their use into more of our wells in the future. Moving to slide 9, we provide some early time data from the lower Wolfcamp A well in our Spur area in Ward County that is plotted against a 1.5 million barrel oil-only curve.
As seen in similar Delaware Basin wells and our over-pressured areas in the eastern side of the basin, the Corbets is producing with strong casing pressures and we expect it to flow naturally for an extended period of time as we manage pressure drawdowns to optimize longer-term performance. While we have data from other Wolfcamp A wells drilled in the area that 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 nanosurfactants.
This will be an important data point as we finalize our initial completion designs for the development program that will start in a few months. I'll now turn back to our recent results on the operating cost side on slide 10.
As we discussed last quarter, we are working hard to integrate the various operations that we have acquired over the last year. This process presents several challenges, including upgrading older tank 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 downhole repairs and workovers from suboptimal well designs and equipment.
In addition to the above, on our new assets, we experienced an unexpected spike in well failures in 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 pumps to increase drawdown and enhance production, which achieved the expected production increase, but also created an unexpected weakness in a certain section of the rod string, resulting in early repeat failures.
Fortunately, we believe we have turned the corner on this issue and will have this issue fully resolved by the end of Q1. Further cost reductions and efficiency gains will be achieved in the second half of 2017, once we fully build out our planned infrastructure projects to enhance water disposal capacity in WildHorse and Lonesome Draw areas, which have been a large driver of this increased expense.
And while we've recently stepped into a new operating area, 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 cover our operational drivers 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 across 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 WildHorse 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 Delaware Basin, spud to 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 cost below that implied by a $5 million well with a normalized 7,500-foot lateral. For our 2017 planning assumptions, we have assumed that our total well cost increases by 10% 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 that strives to dictate our pace of development and not be beholden to third parties. We will be finishing this year build-out of extensive water handling systems and production corridors in WildHorse, facilitating a path to multi-rig operations over time.
We also have some upfront costs associated with Spur, but these are much less than WildHorse given the amount of existing infrastructure such as saltwater disposal wells and water gathering lines that are already in place. Once we are past this initial capital outlay and despite the planned activity increase to five operated rigs, we see our facilities investment decreasing 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 outlook.
Joseph C. Gatto - Callon Petroleum Co.
Thanks, Gary, and thanks everyone for joining us this morning. On slide 14, we've summarized a few key points of our financial performance.
Production for 2016 was up approximately 60% year-over-year and over 10% sequentially from the third quarter. Our realized price per BOE produced for the fourth quarter was $42.13 per BOE on a hedged basis and $40.90 per BOE on an unhedged basis, which is amongst the best across our peer group and reflective of the high oil content in our production stream and favorable off-take arrangements.
Combined with a cash operating structure that decreased 20% in 2016, our adjusted EBITDA margin for the year was over $27 per BOE, leading to strong internal cash flow generation and contributing to a net-debt-to-EBITDA ratio that is now under 2 times, including the pro forma impact of the Ameredev acquisition. Despite some inflationary pressures entering the market, we expect our cash operating cost per BOE, excluding production taxes, to decrease once again in 2017, reflecting the impact of an increase in production base and the initiatives in progressing the efficiency of our recently 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 2 to 2.5 times, positioning us to drive an acceleration of organic PDP additions with a strong foundation of cash flow from our existing operations.
On slide 15, we entered 2017 with an undrawn credit facility and $66 million of cash balances, after adjusting for the closing of the Ameredev acquisition earlier this month. The impact of this recent acquisition on our current borrowing base of $500 million will be assessed as part of our regular spring redetermination.
In addition to our strong liquidity position to support our capital program, our total leverage position remains amongst the best in this midcap universe, with a pro forma net debt to LTM EBITDA of 1.7 times. In terms of asset coverage, our year-end standardized measure of discounted cash flow of $810 million at SEC pricing of approximately $40 per barrel oil and $2.70 per Mcf gas covered our net debt position by over 2 times, reflecting an appropriate matching of proved asset value in long-term debt capitalization levels.
As we enter a period of accelerating activity, we have also entered into additional 2017 and 2018 oil hedges, taking our average downside protection to approximately $48 on 8,450 BO per day in 2017 and $50 on 7,500 barrels of oil per day in 2018. On page 16, we picked up from Gary'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 million to $350 million. The previous capital budget estimate that we provided in November prior to incorporating the Ameredev acquisition was $275 million, including seismic and leasehold costs.
The increased amount of D&C investment over our prior 2017 estimate is largely driven by an additional quarter of activity from an assumed July 1 start date versus an October 1 start date for the third rig. This capital impact is also accentuated in the budget due to a change in the overall mix of our wells.
In effect, we are adding a quarter of activity drilling 10,000-foot wells in the Delaware that we currently assume to be in a range of $8.5 million to $9.5 million, including the leading-edge completion design that Gary discussed, as well as replacing a quarter of 7,500-foot laterals in the Midland Basin, wells with an assumed cost of $5.5 million, with higher cost Delaware wells with longer laterals. In terms of facilities, we added roughly $20 million to our previous estimates, all of which is intended for the Spur area both for the drilling rig arriving in 2017 and future increases in activity as our Delaware capital allocation grows over time.
It's also important to note that the initiation of our Delaware program has the effect of deferring the timing of the initial impacts of the third drilling rig due to increased cycle times from generally deeper wells relative to the Midland Basin combined with our footprint, which sets up for a high proportion of 10,000-foot wells. This is evident in our forecast when comparing our November estimate of 36.7 net completions in 2017, versus 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 the timing to first production of our Delaware pads in order to address any learning curve issues, and we'd 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 parameters 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 forecasted 2017 exit rate of approximately 23,000 to 25,000 BOE per day under the Midland-only program. On the operating cost front, we forecast continued year-over-year reductions in cash G&A and steady 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 Midland or Delaware Basin.
Given we are just stepping into the Spur position, we are assuming the rig will be in the Midland Basin, this presentation as a baseline. Under the case outlined here, we forecast 2018 production to increase to a range of 32,500 to 37,500 BOE per day, with associated capital of approximately $425 million to $475 million.
Our 2018 capital efficiencies benefited by a reduced level of fixed facilities investment and a Delaware drilling program that is hitting full stride. Due to the strong cash-on-cash returns from our combined Permian program, we expect to be cash flow neutral by the end of the third quarter of 2018 and be carrying a net debt-to-EBITDA position of under 1.5 times by year-end 2018, assuming a flat WTI oil price of $52.50 per barrel.
Under a strip price scenario, we project cash flow neutrality to occur one quarter sooner in the second quarter of 2018. If the last two years has taught us anything, you should always be expecting the unexpected.
We recognize that volatility will continue to be prevalent in our business, both in terms of commodity prices and the impact of a rapid increase in activity in the Permian. As a result, we never want to be in a situation where the past cash flow neutrality is too far into the future.
As we look further into 2018, following our current infrastructure investment program for future growth, we will have the flexibility to increase activity in both the Midland and Delaware Basins at our discretion beyond the five-rig plan outlined here. I'll now turn the call back to Fred for some final comments.
Fred L. Callon - Callon Petroleum Co.
Thank you, Joe, and thank 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 2018, the great asset base we've 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.
Gary A. Newberry - Callon Petroleum Co.
Yeah. Fred, before we get too far into the questions...
Fred L. Callon - Callon Petroleum Co.
Sure. Please.
Gary A. Newberry - Callon Petroleum Co.
...I just want to clarify one thing I did say.
Fred L. Callon - Callon Petroleum Co.
Absolutely.
Gary A. Newberry - Callon Petroleum Co.
That I kind of made the wrong reference to slide 8 when I said that was oil-only. That is BOE.
Slide 9 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 just want to clarify the slide 8, that Monarch is a BOE curve.
Fred L. Callon - Callon Petroleum Co.
Thank you, Gary.
Gary A. Newberry - Callon Petroleum Co.
Yeah.
Fred L. Callon - Callon Petroleum Co.
So, with that, we'll open the call to questions.
Operator
Thank you, Mr. Callon.
And your first question will come from Gabe Daoud of JPMorgan. Please go ahead.
Gabriel J. Daoud - JPMorgan Securities LLC
Hey. Good morning, Fred.
Morning, everyone. Gary, maybe this one's for you.
The staggered (26:41) at Sidewinder in Maverick, any early reads there that you could share with us in terms of early-time performance?
Gary A. Newberry - Callon Petroleum Co.
Yeah. We're pretty excited about it, I guess, is my early read.
I know there's a lot of interest in WildHorse, and there should be. We're still extremely excited about the Silver City performance.
It's still an incredibly strong well even after the extended length of flow back. The wells offsetting Sidewinder in that Silver City area are still flowing back and they're flowing back strong pressures, just like the Silver City well did.
But we're still too early to tell on really 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 is as we expected and there's probably nothing new. It has taken a little longer to get the water out of the way and get oil production.
But we're seeing good cuts on both of those wells. So it still looks like it's performing like we would expect it to do.
Gabriel J. Daoud - JPMorgan Securities LLC
Great. Thanks, Gary.
And then maybe just on 2018, and you guys mentioned not getting too far ahead of your skis in terms of upstream development ahead of a midstream infrastructure. And you highlighted cash flow neutrality by, I guess, second or third quarter of 2018.
But just trying to kind of think about accelerating further on the Delaware. And if you guys are willing to step on the gas and maybe outspend 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 should be, I guess, the second rig in the Delaware.
Just trying to frame how you guys are thinking about it.
Gary A. Newberry - Callon Petroleum Co.
Yeah. Again, I mean, I think you can kind of get a sense now.
Integrating these assets is important. Integrating them very, very well is even more important.
Having the right infrastructure in place, everywhere we work, and we can see it. I mean, we can turn wells on in Monarch and it's right there, because we've invested all the money that we needed to do to be very efficient at Monarch.
We've done the same thing at Ranger. We're doing that at WildHorse, 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 WildHorse. So I'm excited about preparing for both opportunities.
Gabriel J. Daoud - JPMorgan Securities LLC
Thanks, Gary. That's helpful.
Joseph C. Gatto - Callon Petroleum Co.
I think that sums it up. We're going to 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 having in four areas and the types of returns and the cash flow generation we're seeing, I think we're looking at scenarios now that further accelerate activity.
But we're getting through some of these infrastructure programs, stepping into the Delaware, sort of optimizing our completion design. So we have some things to take care of, but that's certainly on our minds to keep pulling forward some value here.
Gabriel J. Daoud - JPMorgan Securities LLC
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.
Ronald E. Mills - Johnson Rice & Co. LLC
Hey. Good morning, guys.
Just one question on the fourth quarter. Joe, I don't know if 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 kind of exceeding expectations?
Joseph C. Gatto - Callon Petroleum Co.
Yeah. I think that at least – it's hard around the downtime on the rod issues to just isolate that one component.
But as we look at December, we did look at that. So, relative to where we ended the December month, without the weather-related downtime and an estimate of some of these failures, again it's inexact, probably about 1,000 barrels a day that have cost us on equivalent in December.
And as 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 it's probably about 1,000 barrels a day there.
There's probably some other impacts in November. But that's one number that I have, Ron, and we can probably follow-up a little bit more with you.
Ronald E. Mills - Johnson Rice & Co. LLC
Okay. And then, Gary, just from a completion standpoint, I know you're talking about the increased density test now to 13 wells and increased proppants.
I saw in some of those, you're using 2,000 pounds, but in some areas also going to 2,800 pounds. What are some of the proppant concentrations that you're going to get up to this year, and is it going to vary by area?
Gary A. Newberry - Callon Petroleum Co.
Yeah, Ron. It will vary by area.
And again, we've kind of locked-in – we're not completely locked-in, but at least what we generally think about pumping today in the Midland Basin is about a few-hundred-foot stage lengths with 2,000 pounds per foot of proppant. We're very excited about this Wolfcamp A well 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 wells, as we've talked about before.
But they used diverter agents on that well. And so we're really excited about potentially incorporating that type of technology into what we're doing in the Midland Basin as well to further enhance performance of wells throughout WildHorse, Monarch and Ranger.
But in the Delaware Basin, you pointed out the 2,800-pounds per foot. That's what that was pumped actually in the Corbets well by Ameredev, and that's what we plan to pump in the Saratoga well as we start to frac that well sometime next week.
So, we're looking at that. We see that higher profit loading, the diverters, as well as even nanosurfactants seem to be working quite well in the Delaware Basin, and we see that as a good starting point.
And we'll look at those wells' performance, as well as all the other new wells that are going to come on in the area prior to us even getting started 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'll change, it'll modify, but we'll always be looking at what not only us, but the entire industry is doing to be on the upper end of that learning curve on completion technology.
Ronald E. Mills - Johnson Rice & Co. LLC
Great. And then one last one.
Just in the Delaware, is the primary target going to be the Wolfcamp A? And then, on the Corbets and the Saratoga wells that were drilled by Ameredev, with the data that you have there, were you happy with where the laterals were targeted and how you might find your wells?
Thank you.
Gary A. Newberry - Callon Petroleum Co.
Yeah. The Corbets 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 we've shown you the curve. It's performing very, very well.
But the Wolfcamp B well, the Saratoga well that we're about to complete has landed about where we wanted. So we're okay with that one.
So there might be a little bit of optimization, 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.
Ronald E. Mills - Johnson Rice & Co. LLC
Great. Thank you so much.
Joseph C. Gatto - Callon Petroleum Co.
Thanks, Ron.
Operator
The next question will be from Kyle Rhodes of RBC. Please go ahead.
Kyle Rhodes - RBC Capital Markets LLC
Hey. Morning, guys.
Any update you can give on the Silver City well, maybe just how the oil cut's holding up? And can you remind me what's flowing through your production forecasts for WildHorse in 2017 and 2018?
Is it still a 700 MBOE Wolfcamp A type curve?
Joseph C. Gatto - Callon Petroleum Co.
Just a sec. Gary is just looking at some info here, Kyle.
Kyle Rhodes - RBC Capital Markets LLC
Sure.
Gary A. Newberry - Callon Petroleum Co.
Yeah. We've bumped the type curve in Sidewinder just a little bit.
We're getting closer to 1 million barrel Wolfcamp A type curve for 7,500 feet. And that's all associated with the production that we saw in that Silver City well.
That Silver City well today is still making 600 to 700 barrel of oil a day. I don't know how many days it's been on production.
It's been some time.
Joseph C. Gatto - Callon Petroleum Co.
Since July.
Gary A. Newberry - Callon Petroleum Co.
July. So...
Joseph C. Gatto - Callon Petroleum Co.
Oil cuts have not changed.
Gary A. Newberry - Callon Petroleum Co.
That's exceptional. Oil cuts have not changed at all.
It's a strong well. So we bumped our type curve in Sidewinder just a bit, but we didn't bump them anywhere else.
So it's right around 1 million barrels for a Wolfcamp A 7,500-foot well.
Kyle Rhodes - RBC Capital Markets LLC
Got it. So, fair to think what you're saying kind of early in flow-back on those other wells, there's nothing to kind of, I guess, go against what you saw on the Silver City well?
Gary A. Newberry - Callon Petroleum Co.
No. Not in the Wolfcamp A.
That well that's offsetting it is doing just fine. So, nothing to suggest that we moved too far or – we've got more to go yet.
We still just need more time. The other areas are similar to what we've already talked about previously.
We haven't moved those of course (37:52).
Kyle Rhodes - RBC Capital Markets LLC
Perfect. And then, any color you can give on the well cost for the Corbets?
I know you weren't in control there yet, but just curious if you have a number and how you're expecting well cost to kind of trend once you guys take over operatorship there.
Joseph C. Gatto - Callon Petroleum Co.
Yeah. We're still getting in the costs on that on a cash basis.
But it'd be at the higher end of that $8.5 million to $9.5 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 finalizing 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 could take advantage of and work on those costs with these leading-edge designs.
But, yeah, it was certainly a more expensive well than what we've been drilling.
Kyle Rhodes - RBC Capital Markets LLC
Great. And just one final one if I could.
In your slides, you mentioned optimization of off-take contracts in the Delaware. Any more details you can provide on that and how should we be modeling kind of your realized prices in the Delaware relative to the Midland going forward here?
Joseph C. Gatto - Callon Petroleum Co.
Yeah. For modeling purposes, what previous operator was achieving, what we see is probably about $1 back from what we're realizing in the Midland Basin.
In terms of optimization, again, stepping into 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 to further optimize the contracts that are in place, being only back $1. So what they were realizing is pretty good, just given how they were set up with legacy infrastructure.
But we think we can further improve on that and leveraging some of the relationships we have in the Midland Basin to expand them in the Delaware and hope to keep working on that because it made a meaningful impact on our Midland Basin top line, as we work to not only get the trucking to pipelines, but work on getting our tariffs down and developing postage stamp type of arrangements. So I think, similarly, we're starting from a good point but we think we can do better and pick up some more economics there.
Kyle Rhodes - RBC Capital Markets LLC
Thanks for the color, guys. I'll hop back in the queue.
Operator
The next question will come from Jeff Grampp of Northland Capital. Please go ahead.
Jeff S. Grampp - Northland Capital Markets
Morning, guys. Just wanted to follow-up on an earlier comment, Gary, that you made regarding the Corbets well first.
I think you said that had a 2,800-pound a foot design and just wanted to clarify, did that incorporate any of these other kind of leading-edge, the denser stage spacing, diverters, nanosurfactants, or any of those other things you guys are looking to incorporate?
Gary A. Newberry - Callon Petroleum Co.
It did. They had 125-foot stage lengths, 2,800 pounds per foot proppant loading.
It had some diverter application, not much but some. And then it did incorporate nanosurfactants, it did, all of it.
Jeff S. Grampp - Northland Capital Markets
Okay. Great.
And on the Midland side, you guys mentioned still carrying 11 wells a section in the Lower Spraberry. With the results that we're seeing certainly looking positive on denser spacing, is this just a matter of more production history to look to provide the inventory?
And kind of what's the timing that you guys feel you need or just some more color on the outlook there would be helpful?
Gary A. Newberry - Callon Petroleum Co.
Again, we're encouraged. Again, it's still early time in my mind.
The 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 Casselman, which we are internal to the section, immediately offsetting some higher-density wells. So, if I get some really positive indications early time, I'll be able to move those type curves – or move that estimation density sometime by mid-year is my guess.
Jeff S. Grampp - Northland Capital Markets
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, structure standpoint, are there a JV to posture any future build-outs, or just any kind of incremental details and thoughts there would be helpful?
Joseph C. Gatto - Callon Petroleum Co.
Yeah. I don't think there's a target date right now.
I would say that we are working on evaluating several options at this point to just really help us with being capital-efficient, including 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 and see what makes sense for us. But we'll provide update as the year goes on.
But nothing right this 15 minutes.
Jeff S. Grampp - Northland Capital Markets
Okay. Thanks.
Appreciate the time, guys.
Operator
The next question will come from Sam Burwell of Canaccord. Please go ahead.
Sam Burwell - Canaccord Genuity
Morning, guys. I wanted to touch on service costs.
It 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 trend up in the past few months or if the 10% to 15% is still kind of a modeled assumption?
Gary A. Newberry - Callon Petroleum Co.
Yeah. Sam, this is Gary.
And the 10% to 15% still is the right number that we can see out looking right now. We have seen some cost move.
We've seen a minor increase in sand cost and some chemical cost associated with fracking. 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 to pay – as the market moves, we'll give some of that back to Cactus who is a vital partner to us going forward. We're seeing some increases in tubular cost, as you probably heard from others.
With all the demand that's coming, tubulars have increased quite a bit. Other services seem to still be holding in there pretty well.
So I think the assumptions we're giving you are still pretty good for now until we see more major moves overall across the basin.
Sam Burwell - Canaccord Genuity
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. I'm curious if you guys do get two rigs in, say, 2018, would that require any meaningful addition to infrastructure facilities CapEx that year, or is your 2017 spend kind of front-end loaded enough that you can dial-up a rig without really changing that much of non-D&C CapEx next year?
Gary A. Newberry - Callon Petroleum Co.
Yeah. Again, I think the way we've thought about is the capital we're spending now gives us flexibility to bring that rig forward in either areas.
So I think we're pretty pleased with what we're talking about with infrastructure in 2018. And the other thing we're looking at is, as Joe just referenced, this issue around partnering with a third party because we don't want to go invest all of this money ourselves.
And so, we got to partner with the right third-party on peak-loading for water management. And so, if we partner for the right third party in all of our different areas, which is what we're really opening up for discussion now with select parties, it really provides us even greater opportunities to accelerate production once we get linked in to their systems.
Sam Burwell - Canaccord Genuity
Got it. Appreciate the color, guys.
Thanks.
Operator
The next question will be from Neal Dingmann of SunTrust. Please go ahead.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Morning, guys. Gary, for you or 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 different do you anticipate the cycle times?
If you can just talk about – I want to make sure – it seems like some don't necessarily realize that out there when I kind of compare the Delaware versus Midland when you guys kind of think about a dollar spend or a cycle time. Could you just give me some sort of general how you think about it Midland versus Delaware?
Joseph C. Gatto - Callon Petroleum Co.
Yeah. Look, we're just getting into the Delaware program.
So we have our estimates and we have a starting point. And to give you a frame of reference, what we're incorporating in this model, we think it's appropriate to be on the conservative side in terms of getting wells on production.
But a rig that arrives in July 1, starting to drill with two wells add for 10,000-foot laterals. We see initial production come in mid-November.
To give you a sense of what type of extended cycle times that we're seeing for two very long wells in a deep over-pressured regime, we certainly hope to do better than that. But we got a plan for some extended times at this point just because we're stepping into the position.
And that's sort our modeling assumption for now and we will revisit it as time goes on. Gary, if you want to talk about how we thought about that?
Gary A. Newberry - Callon Petroleum Co.
That all fits. Cycle time 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 takes longer to drill out. And the manner in which we will manage the flow back there, it will take longer to dewater and get to peak production.
So, 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 for drilling and completion, we can drill and complete in a month and dewater.
So it's maybe a 2.5 to 3-month cycle versus a 5-month cycle.
Fred L. Callon - Callon Petroleum Co.
And that's for a three-well pad.
Gary A. Newberry - Callon Petroleum Co.
Right. So it is clearly different.
And the challenge I have for my team is that's what we've planned for, so let's go beat it.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Great point, Gary. And that's what I was getting at with the bigger pads to make sure that everybody is sort of aware of that.
Gary A. Newberry - Callon Petroleum Co.
Right.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
And then, just lastly, on the enhanced completions. And again, as Joe said, I know it is early 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 that you've seen a bit of diminishing returns and you probably hit that point where probably won't go much higher on the enhanced completions, particularly on the sand or the lateral length?
Gary A. Newberry - Callon Petroleum Co.
I'm always open to learning more things, but I do think I'm starting to hit diminishing returns. And it may be specific 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 Spraberry and WildHorse, after we put these enhanced 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 the diminishing return and I hope nothing will push that any higher until I see clear results from other very capable operators in the area. But I may be thinking about pulling back on some zones right now.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Right. Great details.
Thanks, guys.
Gary A. Newberry - Callon Petroleum Co.
Thanks, Neal.
Operator
The next question will be from Dan McSpirit of BMO Capital Markets. Please go ahead.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Thank you, folks. Good morning.
Recognizing it's early stages in the Delaware Basin, is there anything in your acquisition assumptions that are either proving aggressive or conservative? Or maybe put differently, where do you see the biggest changes to be realized over the course of this year?
Joseph C. Gatto - Callon Petroleum Co.
Dan, in terms of how we looked at that asset base, it was underpinned on the Wolfcamp A and Wolfcamp B. Obviously, we have a good data point with the Corbets 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 that 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 a few weeks ago.
But I would say that we're seeing, and as we talked too to offset operators that there will be a lot of delineation going on in the area outside of that base Wolfcamp program, probably more notably 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 just to correlate because we were probably less aggressive on the Wolfcamp B curve just because there weren't too many data points. So, that's always something that we'll be able to fill in the details.
But nothing – everything right now seems to be very much in line with how we looked at the asset. And we're pretty excited about some of these other emerging zones that – while we didn't put value on, we certainly recognized that the resource was there and we'll want to continue to learn as some of the delineation drilling goes on.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Got it. Appreciate that.
And as a follow-up, can you just remind us of the HBP status, both in the Midland and Delaware Basins, and maybe the rigs needed and capital required to hold the leasehold? And maybe if, as a follow-up that, any acreage allowed to expire?
Joseph C. Gatto - Callon Petroleum Co.
In terms of drilling commitments, it's really focused on the WildHorse area on the back of those acquisitions that I think is probably 1 to 1.5 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 term that's 2019. So, nothing onerous and nothing that we couldn't handle with even just the one-rig program that we're building into.
So I'd say that really the drilling obligations are going to be focused on WildHorse, but with two rigs running there today, we don't see any issues that's going to drive our decisions.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Got it. Appreciate it.
Have a great day. Thank you.
Operator
The next question will be from Chris Stevens of KeyBanc. Please go ahead.
Chris S. Stevens - KeyBanc Capital Markets, Inc.
Hey. Good morning, guys.
I was just wondering maybe if you could elaborate a little bit more on that increased type curve in the Sidewinder field in Howard. I guess, what's behind that curve and how much of the Silver City well are performing the 1 million barrel type curve at this point?
Joseph C. Gatto - Callon Petroleum Co.
The things that are behind that type curve are really the performance we saw from the Plymouth package when we got it, as well as the Silver City, and that's really it.
Chris S. Stevens - KeyBanc Capital Markets, Inc.
Okay.
Gary A. Newberry - Callon Petroleum Co.
Yeah. I think that the wells that we had stepped into, and I'm basing this (54:30) presentation but our other IR presentation that's up there.
The legacy wells under an earlier generation completion design are tracking 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.
We're moving up closer to 1 million BOE just in that area and just for the A. But that's really what's behind that.
Chris S. Stevens - KeyBanc Capital Markets, Inc.
Okay. Got it.
So, that 1 million barrel type curve is still based on the older generation completion design and the Silver City's pretty significantly outperforming.
Gary A. Newberry - Callon Petroleum Co.
That's correct.
Chris S. Stevens - KeyBanc Capital Markets, Inc.
Got it. Thanks a lot.
Gary A. Newberry - Callon Petroleum Co.
Yeah.
Operator
The next question will be from Jeanine Wai of Citi. Please go ahead.
Jeanine Wai - Citigroup Global Markets, Inc.
Hi. Good morning, everyone.
Gary A. Newberry - Callon Petroleum Co.
Morning.
Joseph C. Gatto - Callon Petroleum Co.
Hi, Jeanine.
Jeanine Wai - Citigroup Global Markets, Inc.
Hi. It sounds like you're really focused on integrating the acquisitions from last year and just setting up for multi-year efficient 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 fixed operating area either in the Midland or on the Delaware side?
Fred L. Callon - Callon Petroleum Co.
Yeah. Jeanine, I think as we talked about during the presentation, we think 2016 was a great year, a 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 a great team. So we're focused on generating return from that.
Certainly, we continue to look if there are opportunities certainly that are in and around our core areas, we'll continue to look at those opportunities.
Joseph C. Gatto - Callon Petroleum Co.
Yeah. And on that point, there's certainly in Ward County and in 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 can extend a lateral position and really create some value at some lower price points.
So that's really the focus, as Fred said, when characterized that by any stretch we're looking for that fifth operating area at this point.
Jeanine Wai - Citigroup Global Markets, Inc.
Okay. Great.
Thank you for taking my call.
Operator
The next question will be from Tim Rezvan of Mizuho. Please go ahead.
Timothy A. Rezvan - Mizuho Securities USA, Inc.
Hi. Good morning, folks.
I just had a quick question on the LOE 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 I'm looking at your bar chart correctly, that that kind of increased a bit throughout 2016.
Can you talk about what drove that decision and what you're seeing that is making that expense go higher, I guess?
Joseph C. Gatto - Callon Petroleum Co.
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 some treating of some of the nitrogen volumes in the stream. Again, we forecast to be sort 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.
Timothy A. Rezvan - Mizuho Securities USA, Inc.
Okay. Okay.
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, maybe Howard County, could be in Delaware.
Is that dependent on how the facility spend kind of unfolds in the next couple quarters? Is that the driver of that or is there something else kind of behind where you add that fifth rig?
Joseph C. Gatto - Callon Petroleum Co.
Yeah. I mean, I'll start and maybe let Gary (59:34).
This year, as you can tell, we have a decent amount of infrastructure spend to get in place to give us the flexibility to accelerate where we want, when we want, to put it sort of simply, and to really use that drill-bit optionality across our whole acreage position, as we digest these acquisitions, get them running in the right way as we like to operate for 2018. So I think, right now, as we're stepping into Delaware, we have some really encouraging results from this first well and a lot of encouraging results around 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 best to allocate capital. And based on what we're running right now, both areas in Howard and in the Delaware, and in 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 we're in a great starting point. We're going to have flexibility to move across these positions.
Because the infrastructure is there, we'll be able to move in the right pace. So, I think before we say it's going to be in the Delaware or somewhere 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 final point.
Gary, do you want to add anything to that?
Gary A. Newberry - Callon Petroleum Co.
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 and we can see a line of sight for capital discipline around our balance sheet still, then we'll be ready to bring that value forward. It's a fairly straightforward process.
We followed it for the last several years and has worked very, very well for us. So we just got to prepare now on all these new 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.
Timothy A. Rezvan - Mizuho Securities USA, Inc.
Okay. I appreciate the color.
Thank you.
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.
Fred L. Callon - Callon Petroleum Co.
Thank you once again. We do appreciate everyone taking the time to call in and ask the questions.
And certainly, if you have any questions, don't ever hesitate 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 available for one year on the company's website. Thank you for attending today's presentation.
You may now disconnect your lines.