Aug 9, 2016
Executives
Eric Williams - Manager of Finance, Callon Petroleum Co. Fred L.
Callon - Chairman & Chief Executive Officer Gary A. Newberry - Senior Vice President-Operations Joseph C.
Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Analysts
Will O. Green - Stephens, Inc.
Gabriel J. Daoud - JPMorgan Securities LLC Jeb Bachmann - Scotia Capital (USA), Inc.
Ronald E. Mills - Johnson Rice & Co.
LLC Chris S. Stevens - KeyBanc Capital Markets, Inc.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Jeff S. Grampp - Northland Securities, Inc.
Kyle Rhodes - RBC Capital Markets LLC Irene Oiyin Haas - Wunderlich Securities, Inc. Derrick Whitfield - GMP Securities LLC Blaise Matthew Angelico - IBERIA Capital Partners LLC Jeanine Wai - Citigroup Global Markets, Inc.
(Broker) Raymond J. Deacon - Coker & Palmer, Inc.
Operator
Good morning, and welcome to the Callon Petroleum Second Quarter 2016 Earnings and Operating Results Conference Call. All participants will be in listen-only mode.
After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded.
A replay of this event will be available on the company's website for one year. I would now like to turn the conference over to Eric Williams.
Please go ahead.
Eric Williams - Manager of Finance, Callon Petroleum Co.
Good morning and thank you for taking time to join our conference call. With me this morning are Fred Callon, Chairman and Chief Executive Officer; Gary Newberry, Senior Vice President of Operations; and Joe Gatto, Senior Vice President, Chief Financial Officer and Treasurer.
During our prepared remarks, we'll be referencing the earnings results presentation we posted yesterday afternoon to our website, so I encourage everyone to download the presentation if you haven't already. You can find the slides on the Presentations page located within the Investors section of our website at www.callon.com.
Before we begin, I would like to remind everyone joining this call that our comments today include forward-looking statements. A variety of factors could cause Callon's actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements.
For a complete discussion of these risks, we encourage you to read our filings with the SEC, including our Form 10-K available on our website or the SEC's website. Today's call will also contain discussions of certain non-GAAP financial measures.
Please refer to the earnings release we issued yesterday afternoon and to the appendix of the slide presentation being discussed for important disclosures regarding such measures and the corresponding reconciliations to the U.S. GAAP.
You can obtain a copy of the earnings release in the News section of 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 four of the earnings presentation. Fred?
Fred L. Callon - Chairman & Chief Executive Officer
Thank you, Eric. And again, thank you to everyone for joining us this morning.
And as always, we appreciate your interest. As we discussed in our press release, this was another important quarter for Callon on several fronts.
We closed on two core acquisitions in the Midland Basin late in the second quarter, which added substantially to our inventory, and increased our surface footprint to approximately 35,000 net acres. Beyond those transactions, we attained the goal that we've been driving our activity for the last several quarters, which is living within our means while delivering sequential production growth.
It was important for us to prove our ability to pivot the business as necessary during periods of oil price volatility, which we expect will persist in a rebalancing oil market. This operational flexibility enhanced our financial strength, ultimately positioning us to take advantage of these two acquisitions in the quarter and stay on our front foot and continue to grow our business in the Permian Basin.
The map on page four shows our current acreage position comprised of the core Monarch, WildHorse and Ranger operating areas. As you know, we have been focused primarily in the Monarch area since late 2015, but have now added a second rig that will add activity and focus in Howard County later this year.
Page five outlines several key highlights from the busy last few months. On the strategic side, in addition to the larger acquisitions I mentioned, we continue to pursue bolt-on acquisitions in our core areas including a recent purchase of an additional 4% working interest in the CaBo area.
Our production in the second quarter was approximately 13,500 barrels oil equivalent per day, representing an 8% increase over the first quarter. Importantly, we continue to drive down our cost structure with cash operating cost just under $11 per Boe in the quarter which translated into an adjusted EBITDA per Boe of approximately $30 per barrel to help fund our capital program.
Our focus on blocking and tackling in a very challenged commodity price environment has clearly paid dividends. We've also been able to pursue incremental activity that will contribute to our long-term growth potential including density test in Lower Spraberry as well as our first completion in Howard County and the Wolfcamp A.
Silver City A 1H with a completed lateral length of approximately 7,400 feet was placed on first production in early July and produced over 48,600 barrels of oil equivalent, of which 90% was all oil in the first 30 days. We're very encouraged with early time performance which supports our technical views of Howard County acreage.
This area will be a key focal point for our second horizontal rig that was added back in service last week. Although we don't expect to see much production contribution from our second rig this year, we are increasing our production guidance to midpoint of 15,000 barrels of oil equivalent per day on the continued strength of our base program.
We recognize the challenges that still face the oil markets, but we believe the returns offered by Callon's deep well inventory combined with a solid financial position more than warrant an increase in activity in 2016 as well as a planned incremental increase in early 2017 if we continue to see signs of rebalancing and stability in the oil market. I'll now turn the call over to Gary Newberry, Senior Vice President of Operations.
Gary A. Newberry - Senior Vice President-Operations
Thanks, Fred, and good morning to everyone listening today. Moving to slide six, from a high level, another successful quarter for Callon on the operations front with exceptional day to day execution on the Lower Spraberry drilling program in the Monarch area.
Outside of the Monarch area, our team was focused on positioning for the future with continued investments that will benefit our long-term capital efficiency and well productivity. This included initiatives to establish facilities and infrastructure that support program development.
We also continue to dedicate substantial resources to evaluating enhanced completion techniques that will selectively test on upcoming wells. As Fred mentioned earlier, we will now be turning to efficient execution of the two-rig program at Monarch and WildHorse, as we – as well as getting prepared for the addition of a third rig in early 2017.
In the second quarter, we did experience unanticipated downtime at our Carpe Diem field which is our largest producing area. While we do factor in some downtime in our forecast, this was a unique situation caused by two offsetting fracs close to our lease line over a short period of time.
Several of our wells were watered out due to hydraulic interference which is typically mitigated by our artificial lift systems. However, we experienced power outages at the same time as this interference which severely limited our ability to de-water the field during the month of June.
As a result, we estimate that we deferred approximately 425 barrels of oil equivalent per day of production for the quarter. Since the end of the quarter, we have seen a strong rebound in production in July with a return to normal operations producing over 16,000 barrels oil equivalent per day at the corporate level for the month.
Turning to slide seven, I'll focus on recent activity in the three fields that comprise the Monarch area, predominantly located in Midland County. We continue to see solid repeatable results from our Lower Spraberry wells, as detailed here in the recent – and in the recent press release with 30-day IPs that typically range from 135 barrels oil equivalent per day to 160 barrels oil equivalent per day per 1,000 foot of lateral.
In an effort to further enhance the returns from this highly productive area, we have had success extending lateral lengths which can be seen in the cross-hatched acreage blocks at both Carpe Diem and Pecan Acres. In addition, we have just completed an agreement to drill 10,000 foot laterals northward from the western acreage block at Carpe Diem and are finalizing plans to do the same southward from the western block of Pecan Acres.
We are looking to build on our success in this area with the addition of a new bench in the Wolfcamp A with a 10,000-foot well that was spud last month at Pecan Acres. Given the large amount of oil in place in the Lower Spraberry, continued well density testing is very important to us not only to ensure maximum recovery, but also to avoid over-capitalizing the zone.
As discussed previously, we have moved to development on an 11 wells per section basis, which was performed in line with expectations and are now looking to methodically increase our well density. On that front, our 12-well per section test has not shown any degradation in performance after an extended period of time.
This can be seen on page eight in the top two charts, showing average cumulative production and intake pressure drawdown relative to a group of wells drilled on eight wells per section spacing. As a next step, we are currently drilling a three-well pad using 13 wells per section density and expect that pad to come online early in the fourth quarter of 2016.
I will now turn to page nine and a map of our position in Howard County, which we call the WildHorse area. As I mentioned earlier, we've been busy developing the facilities and infrastructure to begin program development of this acreage position in the coming weeks with our second rig.
We will begin with a focus on the Wolfcamp A in Central Howard County, moving from east to west on that position with two well-pad development. In future quarters, we look to broaden our program to include stacked development of additional zones in the Lower Spraberry and Wolfcamp B.
We recently placed our first Wolfcamp A completion on production on July 3 in our Sidewinder field, which is in the northwest corner of Howard County. Results to-date have been encouraging with average production of over 1,600 barrels of oil equivalent per day during the well's first 30 days online.
This result adds to a growing list of strong wells from multiple zones in Howard County and supports its emergence as a core area of the Midland Basin. We are still in the early days of our development, and will continue to evaluate our type curves and spacing assumptions with additional well data in coming quarters.
We've also been proactive in engaging our new offsetting operators in data trades and joint microseismic studies to add to our knowledge base and further our long-term plans for the area. A broader picture of our activity plans for the second half of 2016 is highlighted on page 10 of the materials.
We plan to drill and complete just over 10 net wells in the second half, which is a bit higher than the first half of the year during which we averaged about 1.5 rigs of activity. We will have operational activity at all three of our focus areas, targeting the Lower Spraberry, Wolfcamp A and Upper Wolfcamp B with average lateral lengths of approximately 7,500 feet.
In addition, we will continue our infrastructure build out at WildHorse and Ranger and continue to seek acquisition and partnership well opportunities across our asset base to optimize development. With these initial investments, we will be well positioned to increase our activity with a third rig as early as January 2017 as we plan for success in the business.
Which takes me to slide 11 and a snapshot of our portfolio of investment opportunities for the future. Following our recent acquisitions, we have increased our base of delineated potential locations from currently producing zones to over 900 which translates into 18 years of drilling inventory, assuming a three-rig pace.
More importantly, all of these delineated locations in our three focus areas are forecast to generate wellhead returns in excess of 25% at WTI prices under $55 per barrel, with 700 locations meeting that hurdle at a benchmark oil price under $45 per barrel. This is a solid starting point that provides long-term visibility with production growth in a rebalancing global oil market.
In addition, we will be working to expand this opportunity set through well density tests in the coming quarters and also pursue delineation of other prospective zones and acquisition opportunities. We have assembled an exceptional team that has delivered from both a technical and cost perspective, and we are looking forward to put that team to work on a growing asset base, with continued increases and drilling activity in the coming quarters.
I will now turn the call over to Joe Gatto, our CFO, who will pick up on slide 12 with the financial discussion.
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Thanks, Gary. The quarter ended June 30, Callon reported adjusted net income per share of $0.05, which excludes the after-tax effects of certain non-recurring and non-cash valuation adjustments, including impairments and derivative losses.
We also reported adjusted EBITDA of $36.2 million, a sequential increase of 41% from the first quarter. Both of these non-GAAP measures are reconciled in our press release.
Moving to a breakdown of revenues, we grew production by 8% over the first quarter of 2016. While we only placed 3.4 net wells on production in the quarter and experienced the downtime that Gary discussed, we benefited from just over a month of production from our Howard County acquisition and solid longer term performance from our Lower Spraberry program.
Our percentage of oil volumes was down 1% to 77% in the quarter, which was partially impacted by a new initiative to reduce back pressure on our horizontal wells. This optimization has had a positive impact on oil production, but also results in an increased flow of natural gas volumes under lower pressure conditions.
Overall, revenues excluding hedges grew 47% sequentially to $45.1 million, driven by the increase in production and an uptick in oil, natural gas and NGL realizations, resulting from improved benchmark pricing, as well as the positive impact of reduced transportation costs. Turning to slide 13, we've detailed our continued progress on reducing operating costs.
We are proud of the team's continued efforts on the LOE front which have reduced LOE by over 20% year-over-year. Combined with a lower cash G&A per BOE from an increasing production profile, we've achieved a 27% reduction in cash operating costs compared to just six months ago in the fourth quarter of 2015.
Deducting the $10.90 per BOE of operating and G&A costs shown in the bottom-left chart from unhedged price realizations, we generated over $26 per BOE of cash margin. This is excluding the impact of hedges to give a clear picture of our capacity for sustained cash flow generation.
This operating cost structure has consistently provided the flexibility to absorb fluctuations in commodity pricing over the last two years and is critical to our ability to accelerate activity in the third quarter. On slide 14, we've highlighted a few important elements of our current financial position, including liquidity of $345 million, including the impact of an increase in our borrowing base of $385 million in July and leverage of 2.3 times debt to EBITDA that aligns with our stated goals of maintaining this ratio under 2.5 times.
Equally as important on the slide is a chart in the top-right corner, which illustrates the achievement of our stated goal of living within our means. In the second quarter, discretionary cash flow exceeded our cash capital expenditures by nearly $5 million, clearly highlighting both the capital efficiency of our drilling program in our lean operating cost structure.
Combining this firm foundation of cash flow with an ample liquidity position, we are well-positioned to responsibly fund our growth plans that we will detail on the next two slides. Starting on page 15, we provided the details of our new 2016 capital budget including the return of our second rig this week.
Increase includes approximately $25 million for an incremental 6.5 net wells drilled and 6.7 net additional completions resulting from the addition of a drilling rig, and also an improved pace of our base one-rig program. Included in the updated budget is an incremental $15 million for infrastructure, seismic and land that represent investments that will benefit the efficiency of our near-term acceleration as well as our ability to increase activity in the future.
A look at our plans for this future is presented on slide 16, we've outlined the impact of the three-rig program starting in the first half of 2017 and continuing at that pace through 2018. This level of activity will deliver compounded annual production growth of approximately 20%, underpinned with a focus on the Monarch and WildHorse areas, in addition to modest activity in the Ranger area.
While the growth estimates are attractive, the underlying capital efficiency and cash-on-cash returns for our investments are evidence in the improving leverage profile at an assumed oil price of $50 per barrel and below. As we refine these plans, living close to our means and minimizing requirements for outside capital will continue to be an important consideration.
This plan honors that view, generating a free cash flow neutral position at approximately $50 per barrel of WTI in 2018 assuming our current type curves and well costs. I will now turn this call back to Fred for some final comments.
Fred L. Callon - Chairman & Chief Executive Officer
Thank you, Joe. Again, I'm sure you can understand why despite the current commodity price environment we're excited about the opportunities ahead and look forward to continuing to visit with you on that.
So, with that, I'll open the call to questions.
Operator
We will now begin the question-and-answer session. The first question comes from Will Green of Stephens.
Please go ahead.
Will O. Green - Stephens, Inc.
Good morning, guys.
Fred L. Callon - Chairman & Chief Executive Officer
Hey, Will.
Will O. Green - Stephens, Inc.
So, very good results on that Silver City well. Congrats on that.
I wonder if you can maybe talk about the reasons that well may have yielded such a better 30-day rate than some of the other wells within that area. Do you think it's a – is this a pretty similar stock (20:32) completion with just maybe hitting a pocket of some geologic favorability?
Did you guys try something new? I wonder if you guys could just add some color on what may have worked better there.
Gary A. Newberry - Senior Vice President-Operations
Hey, Will. This is Gary.
We are very excited about the well. It's really one of the northern Wolfcamp A test in the area.
But actually, even as excited as we are, it's kind of an expected result. If you look at slide nine, you look at the two Oxy wells, sort of just south of that well, those well – this well is really producing in line with what those wells did.
Though we tried a few things from a completion perspective in line with trying additional sand loading and potentially some limited stage length testing that I'm not really wanting to talk too much about yet because I want to see the sustained performance of this well before I get too much into it. This is really in line with our expectation.
This is in line with part of the excitement we have around Howard County in total. But very comparable to what Oxy delivered in the same area.
Will O. Green - Stephens, Inc.
Great. So, I guess that leads me to think that when you guys acquired this asset, what you were seeing within, maybe, that southern block where the Masters unit is, a number of those other existing wells, that there's potentially an uplift you guys can provide to that with your completion style then?
Gary A. Newberry - Senior Vice President-Operations
That is exactly right, Will. We're very excited about the potential here.
We're happy to have this asset not only for the upward potential that we see from what's been delivered in the area by Big Star, who did very, very well. We think we can outperform that and more.
And that gives us a lot of running room for exceptional value creation within the company.
Will O. Green - Stephens, Inc.
And you may have mentioned it, but whenever this new Howard County rig goes to work, is it going to be focused on that larger southern block around where the Masters unit is or now that you guys have seen some pretty good results at north, maybe you guys step there for a little while?
Gary A. Newberry - Senior Vice President-Operations
Yeah, Will, what we're doing is the rig is working today, but it's working right now in our Carpe Diem field drilling one of two long 10,000 foot laterals that we just put together on the west side of Carpe Diem. So, we're excited about that.
Once it's finished with those two wells, it will move to the larger block in the south where we see significant potential. And it will start on the east side of that block and march all the way to the west side of that block drilling two well pads.
I think there's one excursion to the north that's planned as part of a lease obligation that we have to get done. But most rig will stay focused on the southern larger block to be very efficient with how we bring these wells on, water sourcing, water disposal, connection infrastructure.
All that work is being done now which is part of our capital increase to be very well prepared when we put that to work to be – with the way we're spending our money.
Will O. Green - Stephens, Inc.
Great. I really appreciate all the color, guys.
Thanks.
Gary A. Newberry - Senior Vice President-Operations
Thanks, Will.
Operator
The next question comes from Gabe Daoud of JPMorgan. Please go ahead.
Gabriel J. Daoud - JPMorgan Securities LLC
Hey, good morning, guys. (24:18) 2017 and 2018, I appreciate the two-year outlook, it looks stronger and it's certainly helpful for us.
But could you maybe talk about the amount of infrastructure spend that's needed or maybe embedded in that capital number for both 2017 and 2018?
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Yeah. For 2017 and 2018, we're probably around $30 million per year, Gabe, at this point.
We have a little bit of a ramp up here in the back half of 2016. But for planning purposes right now, until we get going a little bit more on that program right now are placeholders around that $30 million per year.
Gabriel J. Daoud - JPMorgan Securities LLC
Got you. Thanks, Joe.
And then I guess during the quarter, at Pecan Acres, I guess there's some 10,000-foot laterals that maybe on a 1,000-foot lateral basis an IP of 85, maybe 95 Boe a day. It seem maybe a bit low to me.
Anything specific going on there or reading too much into the result maybe?
Gary A. Newberry - Senior Vice President-Operations
We're excited about the potential there at Pecan Acres, Gabe. Those are exceptional wells.
Again, the 10,000-foot laterals that came online, we did some flow-back control on them early time just to get infrastructure hooked up early time. But beyond that, those are exceptional wells.
And we're really excited about the well that is currently drilled on the Wolfcamp A well because we see significant potential in the Wolfcamp A as well.
Gabriel J. Daoud - JPMorgan Securities LLC
Got you. Thanks, Gary.
Then, one just quick final one for me and I'll hop back in. For the third rig, I guess, what will determine the exact timing on adding the third rig?
Do you need to continue to see oil around $45 to $50, maybe continued improvements in the cost structure? I guess, how should we just think about the timing there.
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Yeah, I'll start this, but for Gary can fill in. Obviously, I mean, from an operational perspective, one of the gating item is obviously infrastructure and getting that in place in the right way.
Gary, I don't know if you want to add anything to that. But I know that's sort of our ultimate gating item is make sure we're set up to efficient get after it and how you see that progressing.
Maybe I can talk about the rest.
Gary A. Newberry - Senior Vice President-Operations
Yeah. Again, part of the reason we're focused on setting up not only WildHorse but also the northern part of Ranger to be efficient with the wells that we know we're going to be drilling in 2017 is – we've been doing this since 2012 and we know the secret to success is to be very efficiency when you bring those wells online early time.
And so, that infrastructure spend, as expensive as it is, pays dividends over the long term, many, many dividends over the long, long term for Callon because of the significant well inventory that we can leverage across that infrastructure once it's in. And so, the gating item to me is to make certain we're set up in both areas as we're now currently set up in Monarch to be very efficient with what we do when we execute on the program.
So, I think we'll be ready in January of 2017 just as I said. That's our plans.
We've got everything in the works to do that now. And in my mind, as long as commodity prices hold up, we should be ready to go.
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Yeah. (27:52) you could see our planning is $47.50 and then going to $50 in 2018.
Obviously, we feel pretty comfortable in those ranges. And from time to time, we're going to see volatility.
We know that and we do want to keep the leverage certainly below 2.5 times and we've stressed things down. So, even if you look down into the low $40s flat pricing for the next couple of years, we maintain that goal of staying below 2.5 times.
We see a lot of flexibility from strong margins in the business, but there are – it's combined with structure, well cost, and what Gary talked about on the operational side, make sure we're ready to go at the right pace efficiently and avoid trucking, water disposal and things like that that they really start to hurt margins. So, there's a lot of things we look at, but our line of sight now is that hopefully January comes and we'll be in a position to have that third rig.
Gary A. Newberry - Senior Vice President-Operations
Right.
Gabriel J. Daoud - JPMorgan Securities LLC
Awesome. Thanks, Joe.
Thanks, Gary. I'll hop back in.
Operator
The next question is from Jeb Bachmann of Scotia Howard Weil. Please go ahead.
Jeb Bachmann - Scotia Capital (USA), Inc.
Good morning, guys. Just have a couple of quick ones.
Gary, first on the completion technique. I think you guys had a few pads or using 2,000 pounds per foot.
Just wondering how those are performing or if you have any early feedback on those.
Gary A. Newberry - Senior Vice President-Operations
Yeah, Jeb, we're excited about that actually. We moved into it rather slowly, but we're pretty excited about both aspects of higher sand loading and at least the early stages for what we've done to reduce the stage length as well, getting down to 200 feet seems to give us an uplift that we're pretty excited about.
I'm not prepared to quantify it yet, but we think it's money well spent. And 2,000 pounds per foot, 200-foot stage length is likely going to be our standard going forward as we think about certainly Monarch and Ranger, and we'll do some more experimentations certainly in what we think can work up and around WildHorse.
But we're excited about that. We think again Pioneer did a lot of the early-time performance on that.
We're happy that they published the way forward on it. We will be testing even shorter-stage lengths in the upcoming fracs that we're going to do at Ranger.
We're going to go down to 150-foot stages. And so, we'll see how that works.
And though we haven't jumped into the next level of completion enhancement, we're meeting and seriously considering where we test surfactants and things like that, that other people have published.
Jeb Bachmann - Scotia Capital (USA), Inc.
Okay, great. And then, just quickly on Howard, just curious how many acres, how many wells do you guys co-operate with Rock Oil at this point?
Gary A. Newberry - Senior Vice President-Operations
Well, we only have one well that we have joint interest in with Rock Oil. That's the Papagiorgio well.
We own 5% or 6% working interest in that well. We're happy with the way Rock completed that well.
They did a good job with it. It validated the potential that we saw down in that southern area.
And as we get in there and we try some of the completion techniques that we know are working for us now in that area, we think we can even perform it a little higher level.
Jeb Bachmann - Scotia Capital (USA), Inc.
Great. And then, last one for me, Gary, just curious what the rig rate is on that second rig that you guys bring back or brought back?
Gary A. Newberry - Senior Vice President-Operations
It's the same as our current rig, it's 15,000 a day.
Jeb Bachmann - Scotia Capital (USA), Inc.
All right. I appreciate it, guys.
Gary A. Newberry - Senior Vice President-Operations
Thanks, Jeb.
Operator
The next question is from Ron Mills of Johnson Rice. Please go ahead.
Ronald E. Mills - Johnson Rice & Co. LLC
Good morning. Just to hit on the inventory slide, you added a couple hundred locations in terms of your base inventory.
What drove that increase? Is it going from 11 wells to 12 wells based on that spacing test or was there something else?
Gary A. Newberry - Senior Vice President-Operations
It was really an increase from 8 wells to 11, Ron. We haven't gone above 11 and we haven't gone above 8 in WildHorse, and that's primarily Lower Spraberry focus.
So that's what drove it mostly.
Ronald E. Mills - Johnson Rice & Co. LLC
And then, kind of the second question, obviously, with WildHorse you talk about you're still evaluating the spacing in that area and also the density I'm assuming in all areas. So, has there been any testing in WildHorse?
I know a lot of people are testing multiple formations, but have people started to drill wells on spacing tighter than eight wells?
Gary A. Newberry - Senior Vice President-Operations
I'm not aware. Joe, are you aware of it?
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Yeah. There's been some early testing on some of our chevron-pattern in the Wolfcamp A.
It's been pretty limited today, more in the southern part of the acreage. So, we're keeping an eye on those, but it hasn't been an area with a lot of density test at this point.
It's really been more around progression on the zones, moving from the Wolfcamp A to Lower Spraberry and now increasingly in the B. There's been one test each I believe in the D and in the Middle Spraberry.
But I think you'll start to see some more density tests as we usually do. We'll do that in a measured way and work with some of our industry partners to share data and make sure we're trying to insert ourselves pretty far up the learning curve before we start to getting into those types of efforts.
Ronald E. Mills - Johnson Rice & Co. LLC
All right. And just a follow-up on one of Will's questions on the Silver City well.
On a per thousand foot lateral, LLS well (33:58) looks like close to 220 Boe's per day versus 150 to 185 on those two Oxy wells. So, I know you said you were – came in kind of as expected.
But were you expecting that kind of performance on a per foot basis?
Gary A. Newberry - Senior Vice President-Operations
I guess, the answer is yes, Ron. We think that what we do and the way we do it we should be able to outperform wells that are in and around us.
We sold the Oxy wells. We knew that they were a little longer, but we felt that given the way we track these wells, which is a little different than what Oxy did, we would see the enhanced performance.
So, again, what we expected, it was really – the valuation that we saw moving into Howard County, we were happy to get the acreage position that we've got.
Ronald E. Mills - Johnson Rice & Co. LLC
Okay. And then the agreements at both Carpe Diem and Pecan Acres where you reached some sort of agreement with offset operators.
Is that something that you think you may be able to also execute on over in CaBo just given the nature of that acreage position being a little bit more checkerboarded?
Gary A. Newberry - Senior Vice President-Operations
Yeah. We certainly look to show offset operators kind of what we can do to add value to not only to Callon but to them as well.
And I think that's been proven over and over with the partnerships we have with RSP and others. In the Pecan Acres area, now, it's Chevron and the Carpe Diem area.
I don't think it will work at CaBo. Again, CaBo checkerboard is (35:51) is really still working toward doing even some vertical development in and around those areas.
So, I wouldn't expect that they're going to come in and do anything with us. At least, they haven't shown any indication as such.
So, I don't want to leave you alone there.
Ronald E. Mills - Johnson Rice & Co. LLC
Great. And then lastly, the incremental 4% working interest (36:11) 75%.
What does the remaining 25% look like? Because those incremental interests are usually some of the more attractive acquisitions.
You think you can get more in that area?
Fred L. Callon - Chairman & Chief Executive Officer
Potentially, we've had discussions over the last – since late 2014 when we entered that position. So, we talked to all of the working interest partners, and there is a couple more larger pieces out there that we'll stay in dialogue and hope to pick up.
But I think we've shown every couple of quarters we're able to take in a little bit more. So, we'll keep after it.
But there's certainly some more opportunities there.
Ronald E. Mills - Johnson Rice & Co. LLC
Great. All right.
That's it. Thank you, guys.
Operator
The next question is from Chris Stevens of KeyBanc. Please go ahead.
Chris S. Stevens - KeyBanc Capital Markets, Inc.
Hey, morning, guys. Great update last night.
Just wanted to touch on the 2017 and 2018 outlook. And when forecasting a production, are you still using the type curves that you've put forth in the presentation for Howard County.
It looks like those wells are a lot stronger than expected. So, is there the potential for some upside to that growth outlook just based on Howard County well outperformance?
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Yeah, in terms of the methodology, Chris, yes, it is based on the type curves that we used to evaluate the acquisition that we had laid out for the A. Clearly, we are encouraged by this initial result, but we got a lot more results to put out there before we start moving that type curve up.
But yeah, this forecast does assume our current type curves that we have out there that haven't changed. But we obviously hope as any acquisition we make, that we'll evaluate it honoring the data around it.
And it's up to us to get better in producing the resource. And we think we have the capacity (38:25) doing that, and yeah, we hope that there's upside to that going forward.
Chris S. Stevens - KeyBanc Capital Markets, Inc.
And it looks like the 2018 guidance, looks like it maintained the three-rig program. What would instead cause you to think about adding a fourth rig?
The leverage looks like it's pretty healthy. So, how do you think about cash flow neutrality versus maybe continuing to accelerate just given the strong returns that you're seeing out there?
Fred L. Callon - Chairman & Chief Executive Officer
Yeah, we'll keep an eye on that. We do run scenarios in terms of different levels of activity.
I think that we certainly want to see continued performance in Howard County. It is one well, right?
We're encouraged by what the industry is doing, but an increase in activity will probably include incremental – more activity in Howard. So, with some more well results, not only in the A, but looking at our test in the Lower Spraberry in B that we hope to be doing next year, I think that'll certainly provide the foundation from an operational standpoint to accelerate that resource and then we'll monitor where we are on operating cost structure, well cost structure, and balance sheet, and add it all up.
But right now, I think that there's a lot of things to fill in before we start making decisions on that fourth rig. But we honestly keep an eye on it and given the types of returns that we see are available and the payback periods that we are comfortable with a period of spending outside of our cash flow if we see a pass (40:03) to getting back closer living within our means within a short period of time.
Chris S. Stevens - KeyBanc Capital Markets, Inc.
All right. Thanks a lot.
Fred L. Callon - Chairman & Chief Executive Officer
Yes, sir.
Operator
The next question is from Neal Dingmann of SunTrust. Please go ahead.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Good morning, guys. Say, good for you, Joe, just wondering, remind me again when you're in that third rig, will then two of the rigs be focused in that WildHorse one maybe in North and South and then one will be over in the existing acreage, I'm just not – I'm not sure I'm clear on that.
Gary A. Newberry - Senior Vice President-Operations
Yeah, Neal, we're – again, remember the third rig is dependent on infrastructure build-out. And so, I think I'll be ready come January to where I can bring it on anytime in 2017.
And where it'd be focused actually is probably be shared between WildHorse and Monarch. We're set up perfectly in Monarch now that we've just completed a significant infrastructure build-out there to efficiently – more efficiently drill out the CaBo area, while continuing to work at Carpe Diem and Pecan Acres.
We'll be pipeline connected with crude oil at Carpe Diem in the next couple of months. And that'll put all of our fields on pipeline connection except for WildHorse.
We have significant interest at WildHorse for pipeline connections that will be in place prior to bringing these new two-well pads on production, so we're excited about that. We think that'll come early January.
So, a lot of things hinder around the timing, exact timing of the third rig. We're just telling you, it will be early 2017 is when the team's going to be ready to go.
And, yeah, who knows, depending on commodity prices, maybe a fourth rig later in 2017. But it all depends on that, but it will be shared between both Monarch and WildHorse.
We will drill a few wells next year in 2017 down in Ranger. We're excited about that.
Ranger's still an exceptional area. We're going to frac the two wells.
Actually, the two ducts (42:15) that are out in Ranger, we're fracing those this week with the enhanced fracture techniques that I just discussed earlier. And we think that provides even significant upside to the good results that we've already delivered there.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Well, a lot of things going on. All right.
And then, the de-water, was that, I assume, just kind of a temporary issue? Do you see for the rest of the year any recurring issues there?
Gary A. Newberry - Senior Vice President-Operations
Yeah, that was very odd, Neal, and it's not something you ever expect. And it was, clearly, unexpected.
Offset operator was fracing north and turned around and fraced south. Typically, we see that.
It never even affects us like it did this time because we normally have all of our wells up and running. We see a slug of water.
We de-water the area with our typical producing wells the way they are now. So, we only see a minor change in rate.
But unfortunately, when that occurred, we had a couple of storms come through the area that knocked the power grid off for Carpe Diem. And when we knocked the power grid off, whenever that happens, you always have the risk of losing a sub-pump or two.
We lost a couple of sub-pumps and we just didn't go in and repaired those right away because of the offset fracing – frac operations. So, we erred on the side of safety and being very cautious, and when all that frac operation was finished, we went in and repaired the wells and quickly de-watered the area just like you would normally expect and got the production right back.
So, it's not a normal thing that occurred. It just so happens that the impact and then the storms that knocked off the power grid and then the failure of a couple of sub-pumps, critical sub-pumps to de-water, kind of – all kind of hit together all at one time.
But beyond that, we've seen frac hits before and they're very temporary, very short-lived and we worked right through them and we never have to talk about them to this degree. But the whole chain of events that led up to this one caused a significant downtime period.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Yeah. Okay.
Certainly sounds unusual there. And then, just lastly for Fred or you or Joe, just when you look at M&A, not just for this year but in 2017, you guys still see a lot of opportunity and are you looking now still both in Midland and in Delaware.
And would you look even outside of the entire basin?
Fred L. Callon - Chairman & Chief Executive Officer
Yeah. This is Fred.
Yeah, I guess, short answer is yes. We see a lot of opportunity.
No, we won't look outside the basin. We've mentioned before we've been – certainly looked at the Delaware for well over a year, actively looking and trying to find the right entry point.
But we're still seeing a number of opportunities in the Midland Basin right now as well as the Delaware. We'll continue to look.
And, as you know, we're very much interested in continuing to grow the footprint out here. And so, hopefully, we're going to find some opportunities later this year.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Well, hope you keep an eye on and see if it's a Big Star (45:23), Fred. Nice job.
Thanks.
Fred L. Callon - Chairman & Chief Executive Officer
Thank you.
Operator
The next question is from Jeff Grampp of Northland Capital Markets. Please go ahead.
Jeff S. Grampp - Northland Securities, Inc.
Good morning, guys. Sticking up in WildHorse there and you guys kind of mentioned doing some multi-well pads just sticking in the Wolfcamp A, as well as maybe some stack pads when the third rig – if and when the third rig comes in 2017.
Just kind of wondering if you guys see kind of full field development up there? Does one look more advantageous versus the other in terms of sticking within one zone or going after multi zones or is it a little early to call given that obviously you just have the one result right now?
Gary A. Newberry - Senior Vice President-Operations
Again, just referring back to – Jeff, this is Gary, but referring back to slide nine. The color of those dots kind of show you a lot of activity has been done in the Wolfcamp A.
And we know that we can come in there and deliver a lot of value on the Wolfcamp A. And we wanted to get started on the right foot, and that's why we're focused on the Wolfcamp A.
But what we see, equal potential in the Lower Spraberry, honestly. And you can see the scattering of dots in the Lower Spraberry.
The Lower Spraberry is going to turn out to be just fine in this area. And we want to prove that up pretty early time, but we may not get to it in the first couple of pads, but we'll get to it sometime next year to where we have the Lower Spraberry result that we can talk about.
And then, certainly, the Wolfcamp B, we see a lot of – a large oil in place target there that we think we can exploit over time. But right now, Wolfcamp A, Lower Spraberry, we see as pretty equivalent and the Wolfcamp B shortly thereafter.
Jeff S. Grampp - Northland Securities, Inc.
Okay. Perfect.
And then maybe to give a little love to the Ranger area given that you guys had a couple of nice results this quarter. Can you just kind of talk about capital allocation to the Ranger area going forward?
I mean, if these results are repeatable with this new completion technique, does it start to become a little bit more competitive with some of the other areas or how do you guys see capital allocation to the Ranger area with the three rigs?
Gary A. Newberry - Senior Vice President-Operations
Yeah, again, for the two ducts (47:36) that we're about to complete later this week, we will go to significantly enhance completion. We'll go to 150-foot spacing, 2,000 pounds per foot of sand, slick water and we'll do some interesting things down there.
And we think we'll get the equivalent uplift that we're expecting there from when we went from really 1,500 up to 2,000. And so – and, really, the 250-foot to down to 200-foot stages.
And I expect that that will work out really well, but in next year's plant program, we only have three wells planned. So, it gives us the time to evaluate that and look at it, but we see that as a very good area.
The results that we've delivered at Garrison Draw and what we now see as Lonesome Draw there in the Ranger area and even an uplift still at our interrupting Upton County property where it all started for Callon back in 2012. We're very excited about this potential.
Jeff S. Grampp - Northland Securities, Inc.
Okay, great. And then last one for me.
Maybe, Joe, on the hedging front, how do you guys kind of think about building the book into 2017? Is there a price kind of floor you guys want to lock in or is there a certain kind of PEP (48:54) percentage or guidance percentage that you guys are looking to maybe build towards as we exit the year?
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Yeah. We've added some oil hedges and actually a little bit of gas here recently as well.
But historically, we've been 50%, 60% hedged. We're about 25%.
I think we'll try to move that up a little bit closer to 35%, 40% in the coming months as we get into next year and look to support some cash flows with a three-rig anticipated program. You could see that with the economics that we have embedded in our program, there's a lot of economics to go around even in the mid-40%s, high-40%s.
So, I think, the biggest thing that we'll look to do is try to introduce some optionality for upside in our program and whether that'd be through callers or three-ways to put a floor in somewhere in the mid- to high-40%s and provide some optionality, the upside is pretty important and that's probably because we don't want to take a position that we're going to lock in on swaps and not know where the cost structure might go and get squeezed on our margin. We think that this cost structure is going to be fine for a long time in terms of the capacity in the basin and what we've been delivering in our work with partners.
But we don't want to lock in too much on the headline in case things really do take off on headline commodity and you get a little bit squeezed if operating cost structure start getting out of whack as things are ramping up.
Jeff S. Grampp - Northland Securities, Inc.
Great color, Joe. Thanks for the time, guys.
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Sure.
Operator
The next question is from Kyle Rhodes of RBC. Please go ahead.
Kyle Rhodes - RBC Capital Markets LLC
Hey, guys. Good morning.
Fred L. Callon - Chairman & Chief Executive Officer
Good morning.
Kyle Rhodes - RBC Capital Markets LLC
I was curious if you gave a current rate on the Silver City well. It seems like you were careful not to list the production at the peak IP 30.
So, I'm just curious what you think that could ultimately wind up being?
Gary A. Newberry - Senior Vice President-Operations
I'm going to be consistent with my response on other calls about a single well response. We're very excited about this well's performing at high levels.
It is a single well. It really validates the way we evaluate Howard County.
So, give me another month or so and I'll tell you what the IP 24 and the IP 30 is.
Kyle Rhodes - RBC Capital Markets LLC
Got it.
Gary A. Newberry - Senior Vice President-Operations
And there is still only one well but lots of potential here.
Kyle Rhodes - RBC Capital Markets LLC
Got it. That's fair, Gary.
And then I guess is there a well cost you could share on the Silver City and maybe a target AFB (51:37) on the next two Howard wells you could share. Just curious what the new target well cost is given the enhanced inflation design, it sound like you're going to become standard here.
Gary A. Newberry - Senior Vice President-Operations
Yeah. Our current cost that we've kind of had out there of (51:50) about $5 million, just around $5 million for 7,500 foot well includes the cost of the enhanced completions.
So that's kind of where we are. We've been able to deliver that day in and day out.
And as Joe just mentioned, we see a lot of running room here within the service capacities, within the basin. There's a lot of companies that continue to seek us out as partners and we are so appreciative of all the service providers that work with us and working even all of their supply chains to the best of their ability to be able to deliver high quality, efficient work for Callon in order for us to continue these types of programs and deliver these types of returns.
That really gives us a lot of confidence in thinking about not only four rigs but maybe five rigs over time. I don't want to get too excited here but my team's kind of anxious to get to work.
Kyle Rhodes - RBC Capital Markets LLC
It's good to hear. Just wondering if you could maybe rank your three areas in terms of bolt-on opportunities whether it's organic leasing or non-op working interest acquisitions.
Is there one area where you think you think you've got a better edge to tack on additional acreage in the back half of the year here?
Gary A. Newberry - Senior Vice President-Operations
It's tough to say, because I think we've had success in all three of them. Even at WildHorse in the short period of time that we've owned it, we've been tacking on some things and – but if we had to force-rank them, I think it'd be pretty close – I think WildHorse probably be first, Ranger behind that and Monarch.
It's a little bit tighter in Midland County. But I said we've delivered on some incremental acquisitions around all three just in the last couple of months.
So, we feel pretty good about the running room.
Kyle Rhodes - RBC Capital Markets LLC
Great. And just one final one for me.
How are you guys thinking about the high-yield market this time?
Gary A. Newberry - Senior Vice President-Operations
We're certainly happy to see some of the initial activity through one of our peers and then an inaugural issuance here recently as well that – to reopen that market. The refinancing of the term loan we put in place in 2014 has always been pretty high in our agenda to put in a piece of capital that's a little bit more flexible, to reduce cost and give us another liquid security in the public market for us to tap from time to time.
So, we're certainly looking hard at it. The good thing is the term loan we have in place – there's no gun to our head to do anything right now, to do in 2021.
It's got a fine coupon. It is callable today at 102, and that will step down to 101 in October.
So, we're keeping our eyes on it. And most importantly, we'll be opportunistic and we'll find the best window to insert ourselves in the high-yield market and put that piece of capital in place.
Kyle Rhodes - RBC Capital Markets LLC
Guys, (54:59) I appreciate all the color. Thanks.
Operator
The next question is from Irene Haas of Wunderlich. Please go ahead.
Irene Oiyin Haas - Wunderlich Securities, Inc.
Hey. Good morning.
Thanks for providing us outlook into 2018. This is absolutely fantastic.
And just kind of curious, so thus far, your position basically is really trying to stay cash neutral at a $50 world and be able to grow. And what could throw off your scenario?
I mean any risk item that we should think about. And if yes, how sturdy is this outlook?
Do you reserve the right to kind of dial up or down, under what circumstances?
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
We always like to reserve the rights to do that. Because it gives some flexibility, Irene.
But like we – we feel, I think, pretty comfortable with borrowing any sort of real dislocation of oil prices sub-$40 that we want to stay on this path. We do see some strong returns on the portfolio in all three of our areas to accelerate here with the balance sheet in the position it is.
But more importantly, the internal cash flow generation that I think we're showing with improved cost structure goes a long way to not relying on outside capital whether it be bank financing or otherwise. As Gary said, I think this is probably a little bit biased, but we can move this to the upside on a three-year look into 2018 that we hope to deliver on bringing a third rig back early 2017, continue to see results out of the WildHorse area, out of the A, to lower Spraberry to B, put that together in terms of a development program that gives us the conviction to stand up on other rig going into 2018.
So, if there was a bias, I think that we've been pretty measured in terms of the assumptions that we're using, in terms of type curves and such and it probably gives us, hopefully, a conviction later in 2017 if you're looking hard at a fourth rig. Gary's up.
(57:11)
Gary A. Newberry - Senior Vice President-Operations
Absolutely. Again, we're excited about what we have.
Again, we think, we're looking forward enough to manage the operation risk. I just don't want to go drill a bunch of wells and not be efficient with it.
So, I think about infrastructure. I think about pipeline connections.
And I think about water disposals and water sourcing and importantly, landowner relationships. I mean, we deal with a lot of landowners in a very highly professional manner that are all important to us, I guess, to the root of our reputation of doing things well and doing things right and really delivering on what we say.
It kind of pains me that the Carpe Diem production for the basin happened in the second quarter because we expect to be able to deliver on the results that we talk about. And so, if anything, we will be measured.
And going forward, we will be, I think, focused on trying accelerate bring value forward more so than slowing down. The only thing that I think is going to stop us is, like Joe just mentioned, a major upward movement or downward in commodity prices, and I just don't see that.
Irene Oiyin Haas - Wunderlich Securities, Inc.
And four rigs, is that sort of a comfortable rig count for you guys? I mean, just in case oil really start escalating, what's you comfort level in terms of rig counts?
Gary A. Newberry - Senior Vice President-Operations
Well, this is an interesting hot topic around here because we've been at three rigs before, and there was still a lot of capacity in this team. I've thrown out, at least, conceptually for us to be prepared – and these are wild numbers, so don't be putting any of this stuff in your models, but to be prepared for six.
The only time I ever saw any widening of the eyes of my team was when I threw out 10 at one time. So, we're very comfortable with increased activity.
We're not stressed at all. We have a very talented team and we can take on a good bit more.
Irene Oiyin Haas - Wunderlich Securities, Inc.
Great. Thank you very much.
Operator
The next question is from Derrick Whitfield of GMP Securities. Please go ahead.
Derrick Whitfield - GMP Securities LLC
Good morning, guys, and great operational update. So, going back to your nano-surfactant comment, how would you characterize the potential uplift you see from using this technology?
Gary A. Newberry - Senior Vice President-Operations
Well, that's why I'm trying to spend an awful lot of time studying it so that I can comfortably get behind the additional cost associated with it. I have a couple of meetings scheduled for the next couple of weeks to get further detail on some of the results that had been published, that are very exciting around it.
But certainly, nano-surfactants should deliver enhanced results over (01:00:16) time. There's no question about it.
What you're doing is as you're fracking that well and you're adding that surfactant; you're actually freeing oil that should be ready to produce in near term fairly quickly. And so, certainly, the early-time results should be higher than what you've seen in the area.
What I'm trying to get more comfortable with is the longer-term benefit related to the EUR. If it's a short-term acceleration, then you can justify the cost okay.
But I'm trying to get more comfortable with the enhanced EURs around some of the published data. And once I get comfortable with it in the cost cycle, then I'd be ready to go forward.
But your question is exactly why I've been a little hesitant and jumping right in and doing some. Because, as you guys know, I've said this over and over; I like the benefit of having fairly good offset operators around us that can prove up some of this technology for us.
And I'm getting excited enough about some of the more published, more recently published results that I'm anxious to kind of try one on my own.
Derrick Whitfield - GMP Securities LLC
Got it. And maybe just order of magnitude, what type of uplift are you seeing in the initial results based on these published, basically, tests?
Gary A. Newberry - Senior Vice President-Operations
Again, I'm not going to throw out any numbers on this call. I'm trying to get more comfortable with it myself.
I will try one. I promise you.
I will give one a shot. I just don't know which one I'm going to do it on yet.
And after I get those results, I'll be very comfortable about describing exactly what we delivered because I do get a little hesitant about some of the published results with only results (01:02:12) being around the best wells. So, there's a whole plethora of information out there that I'm digging into that's getting more and more comfortable with the technology.
What I'm uncomfortable with is the cost especially in an appreciating environment.
Derrick Whitfield - GMP Securities LLC
Thanks. And then maybe moving over to Monarch, based on your geologic model and industry results, is there any reason why 11 to 13 well per section density in the Lower Spraberry shouldn't work?
Gary A. Newberry - Senior Vice President-Operations
Not from what we've seen so far.
Derrick Whitfield - GMP Securities LLC
And how would you risk the upside as you see it right now across your other areas within Monarch?
Gary A. Newberry - Senior Vice President-Operations
The other zones within Monarch outside of the Lower Spraberry, we haven't done a lot of downspacing tests there yet, so I would suggest that that's zone-specific. The Lower Spraberry, it sets up nicely with the thickness and really the enhanced porosity in the Lower Spraberry to oil in place to support a higher density of wells.
It may or may not fit well with a higher density in the Wolfcamp B or even the Wolfcamp A as we test it here in the near term. But going from 11 to possibly 13, I can see that happening.
But I really want to get to the point where I have several offset pads drilled next to wells that have already tested downspacing on. That's really going to be the longer-term test.
So, I'll still be talking about this in the next two years probably before I really narrow it down to what the optimum spacing might be.
Derrick Whitfield - GMP Securities LLC
That makes sense. And then, last question for you.
Regarding the improvement that you guys have seen in your unit LOE expenses, how much of that do you attribute to self-help versus market?
Gary A. Newberry - Senior Vice President-Operations
I attribute a lot of that to infrastructure investment actually. I think it's planning ahead.
It's planning for growth. The companies that get out ahead of their programs without putting in the appropriate infrastructure or thinking about how that can be efficient with it, we'll have a higher LOE component.
Those who get ahead of that will be able to manage their cost and leverage that investment over a longer period of time.
Derrick Whitfield - GMP Securities LLC
Very good. Thanks, guys.
Gary A. Newberry - Senior Vice President-Operations
Thanks.
Operator
The next question is from Blaise Angelico of IBERIA Capital Partners. Please go ahead.
Blaise Matthew Angelico - IBERIA Capital Partners LLC
Hey. Good morning, everyone and thanks for taking my question here.
Just feedbacks on Ron's earlier question on spacing and I apologize if I missed this. But as you're putting your program together for next year and then into 2018, you discussed specifically what type of tests you guys are looking at in the Howard Country acreage.
I think late in the acquisition, it was six to eight wells in certain zones. I know it's early in the life up there, but any comments you have will be appreciated.
Fred L. Callon - Chairman & Chief Executive Officer
In terms of the model that we've laid out as Gary said, I think we're looking at two well pads moving across that acreage position. So, we aren't ourselves planning on doing really any downspacing test at this point in this plan at least next year.
We'll see how things develop. I think we're more focused on looking at stack laterals, Lower Spraberry, Wolfcamp A or adding B in there versus doing a lot of spacing tests.
Like I said earlier, there is some spacing test going on as things are getting closer to program development in Howard County, but right now, we haven't dialed that into our program. I mean, we might change up some of the well locations as we get further into the program, but right now, we haven't put that into our plan.
Blaise Matthew Angelico - IBERIA Capital Partners LLC
Got you. Thanks.
Operator
And the next question is from Jeanine Wai of Citi. Please go ahead.
Jeanine Wai - Citigroup Global Markets, Inc. (Broker)
Hi. Good morning, everyone.
Fred L. Callon - Chairman & Chief Executive Officer
Good morning.
Jeanine Wai - Citigroup Global Markets, Inc. (Broker)
So back to the inventory. Just kind of wondering what a rough target inventory level you have in terms of the number of years?
I'm looking at slide 11 and I know you mentioned that there's potential to do maybe six rigs in the future, not in the next couple of years, but in the future. And slide 11 indicates that on a four-rig program, you have three years of drilling in WildHorse, six in Monarch and four in Ranger.
So, I'm also appreciating that there is inventory upside as to maybe 150 locations or so with the down-spacing that you've been mentioning. But just kind of wondering what your rough target is in terms of inventory level in each of your core plays.
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
Yeah. Again, we don't necessarily target any specific number.
We want to have as many locations that fit the criteria on the bottom right-hand side that can deliver value below – around – below or around $50. That's the world that we live in.
We think that the incremental investment comes in the industry at $55, $60. So, we need to be prepared to live below that.
In terms of how you characterize the inventory, I mean, we provided some math here. Three or six of four years in each of the core areas, that's if you assume all those rigs are in that area and nowhere else, just focused there for the whole period.
So, just with our delineated locations that are currently producing. So, the upside locations that I don't think you've taken into account, I mean, they are producing, offsetting our acreage.
We just haven't drilled them, so we haven't put in our account. I think our real number then that we would feel good about is somewhere between – and this is assuming four rigs, I think, it's at five or six but, let's say four, between 14 years and 25 years.
And the number's in there, it's certainly a comfortable range that we would like to carry certainly north of 10 years of inventory, an investment that's very visible to us with having upside there. But at some point, how much inventory do you want to carry that you're not going to get after for 20 years?
We want to be cognizant of that. So, I guess to answer your question, we don't see us being inventory-constrained.
I think we are constrained by making sure we're efficient before we accelerate too much and pull these returns forward.
Jeanine Wai - Citigroup Global Markets, Inc. (Broker)
Okay. Great.
That's really helpful. And then, following up on a few of the prior questions, and I know you've talked a lot about kind of managing the absolute outspend versus running to a leverage metric.
Just wondering what the absolute forecasted outspend is in 2017 on the 2.5 rig and 3 rig scenarios and kind of what changed versus the prior 1Q color that Callon would remain cash flow neutral for a few quarters and then just watching commodity prices?
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
I don't think it has changed really all that much. Second quarter, we were free cash flow positive.
Third quarter, we do have some infrastructure investments get ahead of, but there's really no meaningful outspend that we're seeing there. We laid out a three-year plan, so I'm not going to talk about any year specifically.
But under this three-year plan through 2018, we said in 2018, for the totality of the year, we're looking at being free cash flow neutral. That includes some quarters being free cash flow positive pretty significantly.
So, if you take the next – starting third quarter of 2016 through the end of 2018, on average, I think, the outspend comes out to be about $7 million on average per quarter. And, again, that includes periods of more or less than that from time to time.
I think our peak borrowings that we would potentially have under our borrowing base facility, while we're ramping up two rigs in a short period of time, which is a lot, you're going to go in a cash flow negative position. It's probably incremental $90 million to $100 million sometime later in 2017.
Jeanine Wai - Citigroup Global Markets, Inc. (Broker)
Okay. Thanks.
That's helpful. And then I guess just the last one for me.
At what WTI price does the well economics kind of turnover such that the outspend also delivers a balance sheet? It looks like, from slide 16, it could be something as low as low-$40s or maybe mid-$40s?
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP
If we assume, let's call it $42, $43 flat from today until 2018, we would still be at 2.5 times or less.
Jeanine Wai - Citigroup Global Markets, Inc. (Broker)
Okay, great. Thank you.
Operator
Our final question comes from Ray Deacon of Coker & Palmer. Please go ahead.
Raymond J. Deacon - Coker & Palmer, Inc.
Yeah. Hey.
Good morning.
Gary A. Newberry - Senior Vice President-Operations
Hi, Ray.
Raymond J. Deacon - Coker & Palmer, Inc.
Hi. I had a question about Howard County and the two well pads that you're going to be drilling starting early next year.
What would be the – would the target zones be the Lower Spraberry and the A? Is that the current plan?
Gary A. Newberry - Senior Vice President-Operations
Yeah. Ray, this is Gary.
But we're going to start with two well pads and just targeting the A for the first couple of pads. And the team is already anxious to prove up the Lower Spraberry.
So then we'll bring the Lower Spraberry in a little bit later in the year and then we'll be looking to test the B later after that. But we're very focused on delivering early time solid results in the A for now because it is the most worked and the most de-risked, and I think given what we've been doing in the Wolfcamp formation and other places around increased sand loading and down-spacing has an application here, and we'll be testing that as we go forward.
So, we're excited about the, A, and as I said before, we're equally excited about the value component of the Lower Spraberry and then we'll watch others, and if they're late to the game, we'll come in and we'll prove up to be ourselves with the capacity that we have.
Raymond J. Deacon - Coker & Palmer, Inc.
Okay. Got it.
Yeah. And then, it looked like Encana had talked about the potential to see a decline I guess.
What do you think there?
Gary A. Newberry - Senior Vice President-Operations
Again, we see potential on other zones and again we – as we just talked about inventory, we kind of talked about inventory on things that we know work, that have a high level of technical confidence around. And again, an advantage we've had is we've seen a lot of other people test additional zones and prove that up for us.
There's certainly more to be had in Howard County over time. We're just not ready to put it out there.
We're saying it's something we're ready to go going forward at this point in time.
Raymond J. Deacon - Coker & Palmer, Inc.
Okay. Got it.
And just one last quick one. You mentioned curtailing some wells and it was giving you a higher gas cut, I guess.
Do you think there'll be any EUR or MPD impact as a result of that or?
Gary A. Newberry - Senior Vice President-Operations
I think it's going to be positive. Again, I think what you referenced in his comments was that in some of our older fields we pull in and actually reduced the – manage to the point where we're able to pull additional pressure off of the formation, getting more stability in the downhole flow potential of a well, manage horizontal wells in a way that can both increase IP or production potential even in a drawdown condition and that's given us incremental oil and incremental gas.
And so over time, it will increase the EUR and bring forward value.
Raymond J. Deacon - Coker & Palmer, Inc.
Great. Okay.
Thank you very much.
Operator
That concludes our question-and-answer session. I would like to turn the conference back over to Fred Callon for closing remarks.
Fred L. Callon - Chairman & Chief Executive Officer
Once again, we do appreciate you taking the time to call in. And certainly, if anyone has any questions in the interim, don't hesitate to give any of us a call.
Thank you so much.
Operator
The conference has now concluded. Thank you for attending today's presentation.
You may now disconnect.