Nov 7, 2013
Executives
Fred L. Callon - Chairman, Chief Executive Officer, President, Chief Executive Officer of Callon Petroleum Operating Company and President of Callon Petroleum Operating Company Joseph C.
Gatto - Senior Vice President of Corporate Finance Gary A. Newberry - Senior Vice President of Operations Bobby F.
Weatherly - Chief Financial Officer, Executive Vice President, Corporate Secretary and Director
Analysts
Will Green - Stephens Inc., Research Division Joseph Bachmann - Howard Weil Incorporated, Research Division Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Michael Kelly - Global Hunter Securities, LLC, Research Division Chad L. Mabry - MLV & Co LLC, Research Division Donald P.
Crist - Johnson Rice & Company, L.L.C., Research Division
Operator
Good day, ladies and gentlemen, and welcome to the Callon Petroleum Third Quarter 2013 Earnings Conference Call. My name is Gwen, and I'll be your operator for today.
[Operator Instructions] I would now like to turn the call over to your host today, Mr. Fred Callon, Chairman and Chief Executive Officer of Callon Petroleum.
Please proceed.
Fred L. Callon
Good afternoon. Thank you for taking the time to call in to our third quarter conference call.
Before we begin, I'd like to ask Joe Gatto, our Senior Vice President of Corporate Finance, to make a few comments.
Joseph C. Gatto
Thanks, Fred. At this point, I'd like to remind everyone that this conference call contains forward-looking statements, which may include statements regarding our reserves, as well as statements, including the words believe, expect, plan and words of similar meaning.
These projections and statements reflect the company's current views with respect to future events and financial performance. Actual results could differ materially from those projected as a result of certain factors.
Some of these factors are discussed in our filings with the Securities and Exchange Commission, including our annual reports on Form 10-K available on our website or the SEC's website at www.sec.gov. We may also discuss non-GAAP financial measures, such as discretionary cash flow, PV-10 measure and adjusted net income.
Reconciliation and calculation schedules for such non-GAAP financial measures are available on our third quarter 2013 results news release and also in our filings with the SEC. I'll now turn the call back over to Fred.
Fred L. Callon
Thanks, Joe. Today's call is certainly a milestone event for the company, call that finds the company in the final stages of its transformation to onshore operator focused exclusively on the Permian Basin.
We closed on the sale for the majority of our Gulf of Mexico assets earlier this week as part of the divestiture that was announced last month. We also closed the sale of our Swan Lake field in the Haynesville Shale.
We've come a long way in the Permian Basin since November 2009 when we were producing 350 barrels of oil a day, to today, when we expect to be producing roughly 10x that amount by year end. In the past quarter alone, we grew our Permian volumes by over 30% from the second quarter due to our strong well performance and increasing level of drilling and completion activity.
Our outlook for the company is relatively straightforward. We continue to deliver production reserve growth from our de-risked asset base in Southern and Central Midland Basin; expand our inventory through continued delineation of emerging horizontal zones, Northern Midland acreage and down-spacing initiatives; selectively pursue acquisitions to add core areas for efficient horizontal Permian development; and aggressively pursue further improvements in our cost of capital as a pure-play onshore company.
We are in the midst of an exciting growth phase for the company. I'll now turn the call over to Gary Newberry, Senior Vice President of Operations, for an update on our recent activities in the Permian Basin.
Gary A. Newberry
Thanks, Fred, and good afternoon. I will start off by saying how pleased our team is with the progress we continue to make in the Midland Basin.
This progress extends beyond the well performance that I will talk about in a minute. Callon recently received the Bruno Hanson/Midland College Award for Environmental Excellence, which recognizes an environmental project, procedure or proposal that exceeds industry standards in the basin.
We received this award for our team's work within the city of Midland to address landowner concerns while safely developing our asset base. This achievement speaks volumes for our status as a well-respected operator in the Permian Basin.
I will now move to an operations update starting at the East Bloxom Field. We've recently placed 3 long lateral Upper Wolfcamp B wells on the production, with strong early time results similar to the 4 Upper Wolfcamp B wells previously on production.
We continue to see strong performance at this field, which started last year with the 321H. The 4 Upper Wolfcamp B wells drilled and completed to date have averaged 24-hour IP rates of 1,031 barrels of oil equivalent per day and 30-day rates of 600 barrels oil equivalent per day.
Based on these production results, which capture over 1-year of history, we recently increased our Upper Wolfcamp B type curve to 480,000 barrels oil equivalent in the area and will continue to review this estimate based on our increased number of wells, with well-established production histories. With the Upper Wolfcamp B de-risk at East Bloxom, we are focused on continuing to realize the cost efficiencies from our established infrastructure as well as expand our portfolio of drillable locations.
I will point out some recent initiatives on that front. During the third quarter, we completed our first Wolfcamp A well, the Neal 341H.
The well encountered a mechanical issue with the frac plugs, resulting in less than 1/3 of the well being properly stimulated. Despite these issues, the well produced at a 24-hour peak rate of 302 barrels oil equivalent per day and a 30-day rate of 178 barrels oil equivalent per day.
We remained encouraged with this formation and plan to drill our second Wolfcamp A well in the first quarter of 2014. Also in 2014, we will be drilling our first well targeting the Lower Wolfcamp B shale at East Bloxom.
Similar to the concept that we have proven at our Taylor Draw field, with production from both the Upper and Lower Wolfcamp B zones. Finally, we have started to plan our next round of pad development based on down spacing.
This will allow us to place 7 laterals across the section versus the 6 previously planned. I will now turn to operations at Taylor Draw Field.
We've drilled and completed 5 wells to date, with short laterals of approximately 5,000 feet based on these configurations on the eastern side of the field. 4 of these wells were completed in the Upper Wolfcamp B zone, 2 of which were completed in the third quarter.
These 2 wells, the Weatherby #2H and 3H, produced an average peak 24-hour rate of 634 barrels oil equivalent per day, which was 92% oil and an average 30-day rate of 354 barrels oil equivalent per day. The fifth well, the Weatherby 1H was completed in the Lower Wolfcamp B shale, which produced a peak rate of 755 barrels oil equivalent per day or 86% oil and a peak 30-day rate of 455 barrels of oil equivalent per day.
As discussed previously, we believe the Wolfcamp B can effectively and efficiently be developed with 2 independents and distinct level of horizontal wells based on micro seismic analysis in the field. We're in the process of completing a 3-well pad targeting the Lower Wolfcamp B with laterals of over 8,200 feet in length on the western side of the field.
This pad is currently expected to come online in December. These 2 fields provide a solid base of potential production and reserve growth for the foreseeable future.
Importantly, we have established the infrastructure and water capacity to support efficient pad development and are also moving up the learning curve on the important issue of well interference during completion of work. This will become an increasingly important issue for Permian operators as pad drilling becomes more prevalent.
With enhanced horizontal operating experience gained over the last 1.5 years, along with increased understanding of multiple ventures, a potential resource to be developed, we added our second horizontal rig in the third quarter. The rig drilled its first well at our Garrison Draw field in Reagan County and is currently drilling a 2-well pad at our Carpe Diem field in Midland County.
The Garrison Draw well was a 5,400-foot lateral and is currently flowing back with encouraging early results. The 2 Carpe Diem wells are planned to be completed in the first quarter of 2014.
Overall, we expect the coming months to be busy for the team in the southern and central basin. The company currently plans to bring 6 horizontal wells on production in the fourth quarter of 2013, including the Neal 323H and the 324H that are currently flowing back.
We expect this pace of activity will continue into 2014, with our 2 horizontal rig program. I will move to a discussion of recent activity in the Northern Midland Basin, and specifically, more of our Borden County acreage.
Our most recent vertical test, the Lacey Newton 2801, was completed at the single-stage completion targeting the Mississippian chat formation. The well produced at a 24-hour peak rate of 326 barrels oil equivalent per day, which was 92% oil.
We're encouraged with this recent result and plan to drill another vertical well in early 2014 to continue our delineation efforts for this zone. I will now turn the call over to Bob Weatherly, our Executive Vice President and CFO.
Bobby F. Weatherly
Thank you, Gary. Our net loss for the quarter was $892,000 or $0.02 per diluted share.
This figure included an unrealized loss on commodity derivatives of $3.1 million. Excluding this unrealized loss and the related income tax effect, adjusted net income was $1.1 million or $0.03 per diluted share.
Operating revenues for the 3 months ended September 30, included oil and natural gas sales of $30.8 million from average production of 4,370 barrels of -- equivalent per day. These results compared with oil and natural gas sales of $27.4 million from average production of 4,337 BOE per day during the comparable 2012 period.
Crude oil revenues increased 12% to $27 million, with the 3 months ended December 31, 2013, compared to revenues of $24.1 million for the same period in 2012. Contributing to the increase in crude oil revenue was a 10% increase in realized crude oil prices compounded by a 2% increase in production.
The average realized sales price increased $105.11 per barrel during the third quarter of 2013 compared to $95.86 during the same period in 2012. The increase in production was primarily attributable to a 43,000-barrel increase in production from our Permian properties, partially offset for the sale of our deepwater Habanero field and normal-than-expected declines in our Gulf of Mexico fields.
Natural gas revenue of $3.8 million increased 13% during the 3 months ended September 30, 2013 as compared to natural gas revenue of $3.3 million for the same period of 2012. The increase primarily relates to a 16% increase in the average price realized, partially offset by a 3% decrease in natural gas volumes.
The decrease in production was largely offset by the 106 million cubic feet increase in natural gas production from our Permian properties. The decline in production was primarily attributable to the previously discussed sale of our Habanero properties and abandonment of our Mobile Bay 908 property, which was partially offset by an increase from our East Cam 257 field.
From a cost perspective, all of our line item expenses were in line with previously provided guidance. Our LOE for the quarter, which includes ad valorem taxes, was $13.11 per BOE, total company.
For just our Permian operations, our LOE was $11.21 per BOE, representing a 15% sequential decrease from the second quarter of 2013. General and administrative expenses net of amounts capitalized decreased $600,000 during the 3 months ended September 30, compared to the same period of 2012 and relates primarily to costs in 2012 for non-recurring employee-related items, including early retirements and severance expense, for which we have no similar cost in the current period.
Discretionary cash flow for the 3 months ended September 30, 2013, totaled $19.2 million. And net cash flow provided by operating activities, as defined by U.S.
GAAP, was $15 million for the quarter. Our capital expenditures for the quarter were $44 million, with 86% of these expenditures directed to drilling and completion operations.
At September 30, our total liquidity position was $59 million based on availability under our credit facility and cash on hand. We've recently completed a regularly scheduled predetermination of the borrowing base under the facility, which also factored in our recent Gulf of Mexico divestitures.
Our current borrowing base stands at $83 million, pro forma for the sale of the Gulf of Mexico properties. And this assumes the repayment of 50% of the outstanding principal of our unsecured senior notes.
To the extent the company elects not to redeem the senior notes before December 20, 2013, the borrowing base would be reduced by an amount equal to 25% of the aggregate principal balance of the 2016 senior notes outstanding on December 20, 2013 in excess of $48 million. I'll now take a minute to discuss guidance for the full year 2013.
We project the total company production rate for the full year to be 3,800 to 4,100 BOE per day, with oil accounting for 65% of these volumes. These numbers included in our latest estimates for the timing of the closing of both the remaining Gulf of Mexico asset sales and the Haynesville divestiture.
We expect production from our Permian assets to be 2,200 to 2,400 BOE per day for the full year, an approximate 40% increase over full year 2012 production in the Permian Basin based on 2013 midpoint. Please refer to our guidance press release, which provides additional details regarding guidance for 2013.
This guidance will also be posted on our website in the Investors section. Now, I'll turn the call back to Fred for his final comments.
Fred L. Callon
Thank you, Bob. Again, we appreciate everyone taking the time to call in, and we'll now open the call to questions.
Operator
[Operator Instructions] Our first question comes from the line of Will Green with Stephens.
Will Green - Stephens Inc., Research Division
Wonder if we could start in Borden with that vertical test you guys talked about. Could you expand on maybe what you learn with this test?
I mean is there any -- is it a sweeter spot of the formation, or just any color around that would be great.
Gary A. Newberry
Well, this is Gary. You're familiar with our previous results.
I won't get into those. But our goal was actually with this well, was to show that we had a significant resource to mine in this area, which we knew was there in the midst.
And whether or not we could actually, effectively, stimulate that well without getting into a lot of water. And frankly, that's exactly what we proved.
We got a good IP, and it's making 10 barrels of water a day. So I think we achieved pretty much our goal.
We actually located this well with a lot of geophysical information. We got 3D seismic across the area and we're utilizing the 3D seismic actually to help us understand where the best Ferocity is across the basin.
And now we got to go show you that -- and show ourselves that, that interpretation is correct and we can deliver similar results. And that's what the purpose of the early well in 2014 will do.
Will Green - Stephens Inc., Research Division
And then just kind of shifting to the land side. You guys after the gun [ph] sale, I assume you guys are maybe looking at both up around existing acreage in the Permian.
Can you talk about, are there many land deals out there to be had still in kind of the core of the play? And is that something we should expect you guys to be looking at over the next handful of quarters?
Fred L. Callon
Will, this is Fred. I think the answer is yes.
We are looking at it, and certainly, we'd like to find additional acreage acquisition opportunities in and around areas we're currently focused in, the counties. And we think there are opportunities out there.
They may not be large opportunities, but we do think they're -- continue to be opportunities to add kind of bolt-on opportunities. As we mentioned before, we also continue to look at acquisition opportunities, again, in our core area out here.
As we said before, I think everyone knows, there's certainly not a large unleased acreage positions out here, but we do feel like there are opportunities where there's acreage out here that we could add, maybe through a series of these transactions kind of materially add to our position out here.
Operator
Our next question comes from the line of Jeb Bachmann with Howard Weil.
Joseph Bachmann - Howard Weil Incorporated, Research Division
Just had a few questions, looking at some of the results. Notably in Taylor Draw, there's Upper Wolfcamp B.
Those compare favorably to your expectations or in line with expectations. Just a little more comments there, if you could.
Gary A. Newberry
Jeb, it's Gary again. We've got a fairly extensive review of well results in and around us.
And the results we're getting kind of match up with about 380 MBoe type curve for that area in Reagan County. And that's really what we're expecting, that's what we're seeing.
Joseph Bachmann - Howard Weil Incorporated, Research Division
Do you guys have any plans for next year to drill a Wolfcamp A test in Taylor Draw?
Gary A. Newberry
We're thinking of it around right now. We've got some couple of slots that we can do that on, and we may end up doing it.
We're really watching closely all of the near and by -- nearby industry activity. We're kind of in a bit of a unique spot and kind of like it, the fact that we've got a lot of really good operators in and around us, doing a lot of work, proven up these different levels.
So we got to pay close attention to it and be a very quick follower when those things really start materializing.
Joseph Bachmann - Howard Weil Incorporated, Research Division
And Gary, have you guys drilled, or are you really any deep Wolfberry pads at this point?
Gary A. Newberry
The only place we're drilling Wolfberry, meaning the vertical wells that we drill, would be in the Pecan Acres area, Jeb. And we just recently completed another Pecan Acres as well that was deep -- clear to the Barnett again.
And it's currently flowing back and we'll have it perform in here shortly.
Joseph Bachmann - Howard Weil Incorporated, Research Division
And I think, are there any Spraberry test for '14, any -- that you guys are scheduled at this point?
Gary A. Newberry
We're thinking about it, but we don't have it in permitting on the schedule. And likely, we might even focus one up in our Central Midland Basin is what we're thinking about it, Jeb.
But we don't have the permitting on the schedule at this point in time. A lot of good activity going on up in that area right now.
Joseph Bachmann - Howard Weil Incorporated, Research Division
And just a couple more quick ones, if I may. One, Bob, I think if I heard this correctly, you said the LOEs for the Permian were 1,121 per BOE for the quarter, is that right?
Gary A. Newberry
For the Permian, yes.
Joseph Bachmann - Howard Weil Incorporated, Research Division
And do you think that's a decent number going forward for the Permian?
Joseph C. Gatto
Sure, we always try to turn it back, but I think for planning purposes, that's probably a good number right now to go forward.
Joseph Bachmann - Howard Weil Incorporated, Research Division
And then last one, Fred, the chances of not repaying that 50%, you guys handicapped that at all?
Fred L. Callon
I think, at this point, there's a very good chance that we will pay down 50%.
Operator
Our next question comes from the line of Ryan Oatman with SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
I don't want to lose sight of the broader story of your improving leverage and liquidity while you're focusing on the Central and Southern Midland Basin. But that said, you do have a very big position up in the Northern Midland Basin, so I do want to understand this vertical pad.
You guys provided that 24-hour rate over 300 barrels of oil equivalent per day. Can you provide any information on how the extended performance looks, maybe perhaps, pressures et cetera.
Is that similar to what you've seen in a Wolfberry well, or do you expect that well to kind of come off a little bit stronger? Any color you can provide on the extended performance of that test.
Gary A. Newberry
Ryan, we're really early in this test. It came on with that initial IP about 20 days ago.
We're encouraged in the fact that it seems to be leveling out and has some pressure behind it. So being only 20 days into the test, we're still making today, about 130 barrels a day.
So it looks like it's going to hold in there nicely. So I can't tell you much more than that.
I can only tell you what I know today, so in another 3 months or 4 months, I'll know better. But the encouraging thing is it looks like it's got some pressure to it.
It looks like it's got some longer-term performance indications to it. And we're happy with the fact that we're not making hardly any water, which was really the drawback that we had when we drilled our Mississippian horizontal well.
We got into some water, and we just couldn't pump it off. So it's very encouraged.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
I agree. Why is that?
Why were you able to prevent this one for frac-ing in the water versus the horizontals?
Gary A. Newberry
Well, a couple of things for change. We actually use the linear gel on the first horizontal well, and we used a slickwater system on this one.
And we used a much smaller stimulation, so we were very careful that we didn't grow up and that we did not grow down, and all the trends and analysis suggest that we got a good stimulation on the zone that we have opened.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Great, and what about the well costs for this one -- or if that's not really kind of applicable. Do you think this is something that could be vertically developed, or do you think that this is something that needs to be developed horizontally to be economic, and you're really just trying to kind of prove same zone, proves that you've got a producing zone here without the water and then eventually go back horizontally after.
Gary A. Newberry
It's a little too early to tell, Ryan, but my initial thoughts are that we've put a lot of science into this effort. After our initial stumble, we've put a lot of science, in this effort.
And we need to prove up, at least, our current technical analysis of where the Mississippian prosody is best developed with our next well and then we'll know more about how we would go about developing this from either a vertical perspective, which would be a very low-cost vertical development, or as well as the potential for horizontal development, but it's just too early to tell today.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
And I think correct me if I'm wrong, have you guys provided any sort of potential locations for this concept? And when do you feel, one way or the other about prospectivity of those locations, either as they exist now or that number potentially moving higher.
And I'll leave it at that.
Gary A. Newberry
No, we have not provided any potential locations for either a vertical play or a horizontal play because we're way too early in Borden County or thinking about how we would efficiently go forward with getting access to that resource.
Operator
Our next question comes from the line of Mike Kelly with Global Hunter Securities.
Michael Kelly - Global Hunter Securities, LLC, Research Division
I was hoping to take a look at some of your assumptions in the Permian going forward. Last quarter, you gave a 5,750 exit rate for 2014, just -- I wanted to confirm if that's still the right number.
And just talk about how you get there in terms of assumptions really just the completion count. You could allocate that over the next 4 or 5 quarters, and I think that will be helpful.
Gary A. Newberry
I guess to give you some general guideline on how we came up that number, Mike, we just took our 2 horizontal rig count set throughout the year drilling in around the 4 areas of development that we currently have. And that's Carpe Diem, East Bloxom, Garrison Draw and Taylor Draw focus primarily on our de-risked areas of 2 levels in the Wolfcamp B certainly in the Southern Midland Basin 1 level of Wolfcamp B in the Central Midland Basin, and one level of Wolfcamp across our entire [indiscernible] range acquisition and carry that out through 2014 contrary [indiscernible] and said this is what it could be, so that's about 15 wells per rig here, so about 30 wells, is what that is.
We're in the process right now of further refining our 2014 plan both capital and forecast. And we'll have something more refined for you some time, I guess, first quarter next year.
So that's generally how we built that out. The assumptions we gave on performance were really around a 480 Mboe type curve at East Bloxom and really about 380 Mboe type curve at the other 3 areas.
Michael Kelly - Global Hunter Securities, LLC, Research Division
And just kind of a general sense as your transitioning out to really, very fast-growing Permian pure-play here. Just the balance of that in acreage spending and increase well count here and how that really meshes with liquidity.
How do you guys see it in terms of liquidity situation. How that plays out in 2014?
And maybe even a little beyond that. [indiscernible] now, post the scale of the GOM.
Bobby F. Weatherly
This is Bob. I think as far as liquidity, I think we -- or looking very carefully, we're completing our budgeting, of course, for 2014.
Some of which had -- I guess, the timing has had a little bit to do exactly when we would complete our Gulf of Mexico sale and say, "Look, earlier than we thought we would." And we're looking at -- I think as we've seen our, I think as I noted that our borrowing base grew, actually grew by 10% from where it was, even taking out the impact of losing the reserves that we have in the Gulf of Mexico, primarily the oily reserves we had with Medusa.
And we looked with various programs that seems to be going very well. We look to continue.
They have DDP reserves for a pretty good rate to 2014, which we believe will continue to drive that borrowing base, [indiscernible]. And we certainly are proud planning around cash flows from cash flow from operations next year, which obviously, it creates in production worldwide.
It would be much better, and we also look for a borrowing base to be there. So we feel very good about our liquidity going into next year.
Operator
Our next question comes from the line of Chad Mabry, with MLDN Company.
Chad L. Mabry - MLV & Co LLC, Research Division
Curious to get your thoughts looking into next year on the Carpe Diem area and kind of what your program is going to look like? What your targets are, specifically looking at some offset operator showing some nice client wells, kind of in the vicinity.
Curious if you had looked at the potential for maybe some client wells up there next year?
Gary A. Newberry
Chad, this is Gary. Our focus initially here is going to be on the middle Wolfcamp B.
And with the 2 wells we're drilling right now, we'll get those completed early first quarter, next year. We'll move the rig away back to Bloxom and drill some wells and we'll come back and actually build 2 additional wells.
So we'll be in and out of Carpe Diem focused on the Wolfcamp B, the middle Wolfcamp well. We're really encouraged with that, simply because some of the offset wells to [indiscernible] of us.
Some of the very good wells have been reported there. And what's driving some of that is the lateral length, and we've got plenty room there to drill long laterals, as well as the deeper area that we are in the basin.
We're much deeper in the basin so we have higher pore pressures and we have good drive for the fluids to get to the wellbore. So we're encouraged with that, and that's what we're initially focused on.
We are also very aware of the client development you going on in the us lower Sprayberry and George Mill development is going on in that area. So we're watching [indiscernible], and we'll be very flexible on how we kind of move to another level once we see some additional emerging information coming out of the other offset operators.
Chad L. Mabry - MLV & Co LLC, Research Division
That's great. And just as a follow-up, just kind of curious what predrilled expectations are for those first 2 wells with a 9,000 foot laterals if you could.
Gary A. Newberry
The Carpe Diem wells, they're actually -- we actually finished one of them, and it was only an 8,100 foot lateral we cut a little short. But the next one, we'll be making it 9,000 feet.
And we're about nearly ready to set in immediate to go with the curve now. But predrilled expectations are anywhere from really 400 to 600 Mboe.
We see some incredible results up in that area so buried as they are, we think the way we execute, the way we frac wells, the way we perform, and at least the performance of our wells, compared to others around us, we should be at the upper end of that side.
Operator
Our next question comes from the line of Jeff Grant with Northrop Capital Markets.
Joseph Bachmann - Howard Weil Incorporated, Research Division
Just curious -- and most of my questions have been asked. But at East Bloxom, the downspacing is obviously real positive there.
But I was curious, what's the densest spacing you guys have results on to date, if you've actually drilled on that spacing yet? And if not, kind of what the plans are around actually testing that space and going forward?
Fred L. Callon
We have, Jeff. Actually, the wells at Taylor Draw today are actually on about 700-foot spacing distance now.
And that's really what the 7 wells per section gets you is about 724 feet between wells. And since those Taylor Draw wells are a little -- those Taylor Draw sections are scaling [ph] along, we get a little closer whenever we push 6 wells into the little sections.
So we have tested it a little already, and we believe it will certainly work at East Bloxom.
Joseph Bachmann - Howard Weil Incorporated, Research Division
Okay, so then in terms of -- I mean do you guys have plans for that? Maybe at the tail end of this year into next year to [indiscernible] lateral spacing them?
Fred L. Callon
We actually intend to actually kind of lock this down at 7 wells per section for now and kind of watch -- we've paid lot of attention to what's going on in the basin. And frankly, this concept's being tested by many.
So I think I'm just going to wait and see kind of what emerges as the standard development pattern from companies such Diamondback and Pioneer and others that are -- have put a lot of effort into this.
Operator
[Operator Instructions] Our next question comes from the line of Don Crist with Johnson Rice.
Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division
In looking at your presentation, the Borden County slide, the Lacey Newton looks like very favorable results compared to the SM wells that were drilled to the West of you all. Was the Lacey Newton drilled in the same formation or in the same part of the Mississippi as those SM wells were?
Fred L. Callon
It was certainly drilled to the same information, the Mississippian formation. We have, based on our 3D seismic, we were focused on some very well developed porosity within our acreage position.
We don't have 3D over the SM acreage, so I can't tell you how it compares favorably or unfavorably. And I know the SM wells, whether they're vertical or horizontal, I think they've had some exceptional results.
And I think they [indiscernible] that didn't pay up very well. But at the end of the day, we're just pleased to say that we've proven that we've got a significant resource on our acreage position, and we think our 3D seismic interpretation supports further work.
Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division
Are you ready to give sort of an inventory and tell us how many kind of bright spots you see across your acreage right now?
Fred L. Callon
No, sir. I want to prove the concept myself before I start counting at others.
So let me keep proving it. I feel real good about it today, and I might also feel better about it at the end of first quarter of 2014.
Operator
Ladies and gentlemen, that concludes our question-and-answer session.
Fred L. Callon
Again, we appreciate everyone taking the time to call in. In the meantime, if you have any questions, don't hesitate to give us a call.
Thank you.
Operator
Ladies and gentlemen, thank you for your participation on today's conference. This concludes the presentation.
You may now disconnect. Have a wonderful day.