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Carrizo Oil & Gas (NASDAQ:CRZO)

Q2 2014 Earnings Call

August 05, 2014 11:00 am ET

Executives

Sylvester P. Johnson - Chief Executive Officer, President and Director

Paul F. Boling - Chief Financial Officer, Vice President, Treasurer and Secretary

J. Bradley Fisher - Chief Operating Officer and Vice President

Andrew R. Agosto - Vice President of Business Development

Jim Pritts - Vice President of Business Development

Jeffrey P. Hayden - Vice President of Investor Relations

Analysts

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Chad L. Mabry - MLV & Co LLC, Research Division

Daniel Braziller - Jefferies LLC, Research Division

Dan McSpirit - BMO Capital Markets Canada

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Jeffrey Connolly - Mizuho Securities USA Inc., Research Division

Jeffrey Grampp - Northland Capital Markets, Research Division

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the Carrizo Oil & Gas Second Quarter 2014 Earnings Call. [Operator Instructions] And as a reminder, this conference is being recorded today, Tuesday, August 5, 2014.

I would now like to turn the conference over to Chip Johnson, President and CEO of Carrizo and Gas. Please go ahead, sir.

Sylvester P. Johnson

Thank you, and thank you, all, for calling in. As we normally do, Paul Boling will give an overview of the financials, then I'll give an operation summary and then we'll open it up to the Q&A. Paul, you want to get started?

Paul F. Boling

Thanks, Chip. We achieved record oil production of 18,440 barrels per day. That's 57% above the second quarter of 2013 and a 23% increase from the first quarter of 2014. Natural gas and NGL production was 89,308 Mcfe a day. We exceeded the high end of our guidance range for both oil and natural gas and NGL production during the quarter. Given the continued strong production, we are increasing our 2014 crude oil production growth guidance to 57% from 54%.

Record adjusted revenues, including the impact of net cash from derivative settlements, was $182.4 million in the second quarter of 2014, including record oil revenues of $166 million.

Record adjusted EBITDA was $144.2 million in the second quarter or $3.19 and $3.12 per basic and diluted shares, which represents a 40% increase over the second quarter of 2013 and a 26% increase from the first quarter of 2014. Our total cash cost and expenses were $38.2 million for the quarter, comprised of $27.5 million in production cost and $10.7 million in G&A cost, which were below our guidance range. In the interest of time, please see the disclosure tables in this quarter's press release for further detail, including the third quarter and full year 2014 guidance.

Our drilling and completion capital expenditures for this quarter were $198.1 million. Approximately 78% of this quarter's drilling and completion spending was in the Eagle Ford. Our net debt to adjusted EBITDA ratio, using the trailing 4 quarters, was 2.1x for the quarter. We also look forward to completing our fall borrowing base redetermination, which is targeted for mid-October. As of July 31, we had $103 million drawn on our revolver.

Our significant oil hedge position for the balance of 2014 is 15,000 barrels a day, for over 75% at the midpoint of estimated crude oil production for the remainder of 2014. Using the midpoint of guidance, we also have over 90% of our estimated natural gas and NGL production hedged for the balance of this year. Please refer to the hedging table provided in the back of our press release.

Based on commodity strip prices on August 4, we would expect to pay roughly $8 million to $8.5 million on derivative settlements in the third quarter. However, this number will change based on movements and commodity prices.

For the third quarter 2014, we project that our total company realized price for crude oil will be approximately 94% to 96% of NYMEX. We are projecting a realized price for natural gas, NGLs combined to be approximately 72% to 78% of NYMEX. Chip?

Sylvester P. Johnson

Thanks, Paul. As Paul said, our net oil production is a record 18,440 barrels of oil per day was up 23% over the first quarter and represents the 15th quarter in a row that we've set a company oil production record. In the Eagle Ford, we are producing from 164 gross for 128 net wells with 3 drilling rigs running in 1 24/7 frac crew.

During the second quarter, we temporarily added a second frac crew, which has allowed us to complete 26 gross and 21 net wells during the quarter. At the end of the quarter, we had an inventory of 21 gross or 15.7 net wells, representing 5,900 net BOPD at potential initial production.

We have sufficient production data from our initial 330-foot downspacing test to validate that spacing in areas that are near or on trend with the Irvin Ranch, where we did the pilots. As a result, our derisk inventory in the Eagle Ford has increased to approximately 815 net locations or approximately 15 years at our current drilling pace. If we also downspace our remaining areas to 330 feet, it would add approximately 105 more net locations during inventory. We've added 4,000 net bolt-on acres since early May, bringing our total to 71,700 net acres in the Eagle Ford. The average acquisition cost for this acreage was under $4,000 per acre.

In the Niobrara, we are producing from 100 gross or 42 net wells, with 5 gross or 1.5 net wells waiting on completion, representing about 400 net BOPD potential initial production. During the quarter, we began production from our initial 40-acre downspacing test. We're pleased with the results so far as both the A and the B wells in the pilot have been outperforming our Area 1 type curve. We're competing our second 40-acre pilot and currently expect to complete at least 1 more 40-acre pilot prior to year end. We've identified more than 125 additional net locations on our acreage position at 40-acre spacing, which would increase our drilling inventory to more than 590 net locations. We have one operated drilling rig running, and our current plan is to stay at that pace for the remainder of 2014, since we continue to participate in a large amount of non-op wells. Our non-op wells with Whiting and Noble are testing all benches in various combinations of downspacing within and between the Niobrara benches.

In the Marcellus, we are producing from 75 gross or 24.1 net wells in Susquehanna County, and Wyoming County, P.A., with gas sales into all 3 major pipelines. Given the extremely challenging local market pricing environment in Appalachia, we have elected to defer our remaining 2014 completion activity until next year. We're also continuing to shut in a significant amount of our production volumes when prices get too low. Our inventory of drilled but uncompleted locations in the Marcellus stands at 19 gross or 6.1 net locations. Our production capacity in the Marcellus is approximately 90 net million cubic feet per day, and we averaged more than 55 net million cubic feet a day in July.

In the liquids-rich area in the southern Utica in Ohio, we received the spudder rig for a 2014 drilling program late in the second quarter. We're currently drilling the top hole on our third 2014 well and expect to receive the larger rig later this month. We continue to expand our position in the condensate window, acquiring another 600 net bolt-on acres, bringing our drillable estimate to 21,600 net acres. We think that equates to about 145 net locations on 150-acre spacing.

During the quarter, we began to build a leasehold position in the Delaware Basin Wolfcamp play. We currently have more than 17,000 net acres in the play and hope to drill our participated well within the next 6 months. Total company production for the third quarter is expected to range between 19,100 and 19,500 net barrels of oil per day. The gas and NGLs' second quarter production should range between 55 and 65 net million cubic feet equivalent per day. Our 2014 drill and complete budget is being raised from $665 million to $685 million to $690 million to $710 million due to additional Eagle Ford wells drilled and completed and additional spending on Eagle Ford facilities.

2014 land CapEx of $90 million is being increased to $130 million because of successful leasing efforts in the Eagle Ford and Utica, as well as in the Wolfcamp.

We'd now like to open it up for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Chip, can you tell us what you're doing in the Permian, kind of what your thought process is? How big a position you want to get to? What you've been able to acquire so far? What the running room is out in those 2 counties? Can you just give us a high-level snapshot?

Sylvester P. Johnson

High level, we started looking at the basin about 2 years ago. We were disappointed with most of the well results we saw. But late last year, it seemed like the industry cracked the code and started making some big Wolfcamp, A and B wells particularly. And Reeves and Culberson, we started looking at buying acreage out there. We initially bought some acreage that included gassy and oily acreage. Since that time, we've let the gassy acreage drop and just kept the oily acreage and then tried to add bolt-on acreage around that, which we've been able to do. So we like the potential on the basin because it is oily. The results seem to be getting better. Some of the companies that we respect have moved into that area. Our acreage tends to be pretty close to Cimarex, EOG and Concho, also Conoco and BHP. So we feel like there's a lot of running room there. There's so much acreage in that base, and it's held by smaller companies that haven't drilled a lot of horizontal wells and probably need a drilling partner going forward. So we look at it as an area that we could expand into, if we like our early results.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay, no that's helpful. Eagle Ford, the downspacing pilots, I know you talked about you haircut the EURs, and it sounds like that was a conservative number. I mean, are they tracking? And I don't know how much production data you have on these. I guess, could you give us that? And then are those tracking the other wells that were drilled in the area? I mean, are you seeing any difference in -- at all? Or does everything thus far with the production history you have look like it's in line with the others?

Sylvester P. Johnson

What we've seen so far is these IPs look just like the other wells. And the wells after about 75 days, still are infinite acting, meaning they're not seeing each other. And so ultimately, they're going to, and that's how we're going to know exactly what the effects of the interference are. But at this point, we haven't seen that.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And how much of this do you think you could do -- how much of your acreage would be, I guess, prospective for downspacing?

Sylvester P. Johnson

I think the numbers we quoted are probably 75% of the acreage. 60% to 75% is what we're saying we're now comfortable downspacing. The rest of it, we need to drill some pilots in that to see if it reacts the same way.

Operator

Our next question comes from the line of Neal Dingmann with SunTrust Robinson Humphrey.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Chip, just required [ph] overall question on just sort of divestitures, your thoughts on either the Marcellus, Niobrara or any other of your areas just on a go-forward. I mean, obviously, from a liquidity standpoint, you don't -- you're more than adequate there. So just your thoughts, I guess, when you balance either the liquidity or just the nonsales in general -- noncore sales in general.

Sylvester P. Johnson

Well, we haven't announced any noncore sales. I guess we've hinted in the past that once an asset is completely drilled up and turned into PDPs, we would probably entertain offers from MLPs for it. So at some point, the Marcellus could get there, but we haven't made that decision.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then speaking of the Marcellus, I guess, how long -- I mean, obviously, with the gas prices, is there a certain price -- what price would you have to see to obviously ramp activity back up? Obviously, you've pushed some things off there. Just if you could talk about that a little bit.

Paul F. Boling

Well, we'll probably ramp it up -- there'll be [ph] the landowner requirements, too. So at some point, we're going to have to ramp it up even if prices are still between $2 and $3 at the wellhead. So next year, we'll be watching that. We'll also be talking to the landowners to see if we can extend that if prices are low. But for us to just do it, we'd probably want to see $2.75 to $3 at the wellhead.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just last and moving over to Utica. A couple of things, just on that acreage you added to get to that 26,000 or so. Wondering what area you added on? Is that just -- you mentioned bolt-on. I just didn't know what particular area of yours you were adding. And then secondly, on the 7 wells that are there that are going to be drilled, your thoughts on sort of cost there and how you think about sort of spacing those.

Sylvester P. Johnson

Yes. The acreage we bought was mostly in Northeast Guernsey, but a little bit is down around the Rector well also. As far as well cost, I'm going to let Brad talk about that.

J. Bradley Fisher

I think as far as well costs go right now, we're looking at between $10 million and $12 million, depending on the lateral length of course. And to address the spacing issue, we're going to test between 800 and 1,000 foot between well spacing on our current plan.

Operator

Our next question comes from the line of Michael Glick with Johnson Rice.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

In the Eagle Ford, just curious to your thoughts on the rig count heading into 2015?.

Sylvester P. Johnson

We have contracted for a new rig next spring, and so our plan was to drop a rig and add a new rig. But that gives us an opportunity there to add a fourth rig. So we're running the math on that right now to see what that does to our adjusted EBITDA early next year. But that would be a perfect opportunity to do it.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Got you. And then in terms of the additional 330-foot downspacing test, what's the primary difference geologically between where those are going to be located versus Irvin Ranch?

Sylvester P. Johnson

Primarily, it is gas-oil ratio, but it's also permeability. And as we go deeper, we do pick up more gas. We never really get gassy where we have high-gravity condensate, but it's still going to affect the spacing. And so we just need to do a similar pilot where we go a little deeper in a higher GOR.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Okay. And what's the timing on that pilot look like?

Sylvester P. Johnson

I think the area we would like to do that pilot right now is scheduled for January or February.

Operator

Our next question comes from the line of Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just in terms of your 40-acre Eagle Ford development, are we to correctly assume that you guys are going to proceed with that in your drilling program on the 60% to 75% of your acreage at this point? Or do you want to kind of monitor that first pilot for more data here?

Sylvester P. Johnson

We actually have already begun drilling additional pads at 330 feet, and our plan would be to -- in those areas to continue full development at that space.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess with just respect to acreage adds here, it looks like you guys were pretty successful over the last couple of months, 4,000 acres in the Eagle Ford, increasing your budget here. I guess, do you guys have a range of how much additional acreage you think you can pick up by the end of the year here in the Eagle Ford?

Sylvester P. Johnson

Well, I mean, we started out the year, our goal was in the 10,000 range. Obviously, we're very pleased that we've essentially hit that or are very close to hitting that. We do have some additional opportunities. I think it would be a stretch to say we'd double again what we've already done this year. But I think our hope is we can certainly add several thousand more acres by the end of the year.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. I guess just jumping over to the Utica. You guys talked about your gas processing looks like being delayed a number of months. Is that going to have an impact on your Utica drilling program and in your flows on the oil side as well? Can you talk to that?

Sylvester P. Johnson

Well, it doesn't have any impact on the drilling program, but it's going to have an impact on production guidance. So when we get to 2015 numbers, we'll have to account for that. Basically, the problem we've had is that the Rector wells made a lot more condensate than the midstream companies were expecting. And we've had to rewrite contracts to deal with extra condensate and stabilization. And so that's all a good thing in terms of profitability. But it's going to require more facilities from the midstream companies than they were planning on building.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, that's helpful. And I guess, in terms of your production guidance, you guys have been kind of consistently beating the range here on oil. I mean, I guess, it looks like to me that third quarter may be a bit conservative. I mean, how are you guys kind of thinking about that at this point?

Sylvester P. Johnson

Well, we don't think it is. The reason we keep beating is that the Eagle Ford is so strong, and some of the new Niobrara wells have been strong. But we've also learned the hard way over the last 10 years how to account for shut-ins and facility work and artificial lift and cleanouts. And so all that's baked into our numbers, and that goes into how we plan all this out.

Operator

Our next question comes from the line of Tim Rezvan with Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

I noticed a lot leverage at midyear crept up barely above that 2.0 threshold that you had discussed. It seems, obviously, the acreage acquisitions pushed that up. Do you anticipate that kind of reducing out into 2015? Any comments on that?

Sylvester P. Johnson

Yes. We think it -- well, it comes down in the third and fourth quarter, too. Part of the reason for that run-up was that we've spent about an extra $35 million on the second frac crew in the Eagle Ford in the second quarter. And we've seen a little bit of that production, but a lot of it's coming on in the third quarter. And we also kind of lucked out and had all the acreage deals close in the second quarter. I think third quarter, to date, we've only closed $4 million of land deals. So -- and we quit frac-ing in the Marcellus, so CapEx in the third quarter should be coming down while the EBITDA is going up.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. And then on the topic of that second frac crew, how do you think about the backlog of wells waiting on completion into year end?

Sylvester P. Johnson

Well, we like where it is now. That gives us kind of a throttle to go into 2015 with, so that's what we're trying to figure out right now, is when to bring that down in 2015 and what that'll do for our oil guidance.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. And then one last one, just touching on the asset sales. I know you haven't formally disclosed anything. But given your ability to kind of close on acreage additions elsewhere, would that kind of change your thought or erase your sense of urgency to sell other positions such as the Niobrara?

Sylvester P. Johnson

,

Well, if we have great opportunities, then we will obviously look at where we could raise money to do that, and maybe that would accelerate a sale of something that's not a core asset.

Operator

Our next question comes from the line of Chad Mabry with MLV & Co.

Chad L. Mabry - MLV & Co LLC, Research Division

Had a clarification on the increased inventory in the Eagle Ford. It looks like you're at 815 net now from maybe 651 previously. Just curious if you could provide a breakout. What comes from the 330-foot downspacing and what was added on the acreage front there?

Andrew R. Agosto

Yes, Chad, this is Andy Agosto. We added roughly 200 locations to the inventory from that number you quoted. I would say 75% of that is from the downspacing if you want to use the order of magnitude.

Chad L. Mabry - MLV & Co LLC, Research Division

Okay, that's helpful. And then, I guess, shifting over to the Utica. It sounds like most of your acreage adds were there in the condensate window. I know that industry has kind of looked a little harder at the dry gas window. Is that something that you're considering at this point? Are you still kind of sticking with that core area?

Sylvester P. Johnson

We're still trying to buy in our core area. We dabbled with the dry gas area. But with the collapse in netbacks and dry gas prices in that area, we're looking at that again a little more carefully. Just looks like Southwest P.A. and Southeast Ohio are going to have the same problem that Northeast P.A. has with just too much gas.

Operator

Our next question comes from the line of from Dan Braziller with Jefferies.

Daniel Braziller - Jefferies LLC, Research Division

I was wondering, given the bump in CapEx guidance, what are your plans for eventually achieving free cash flow neutrality? Is that a goal of yours near term? And if so, is there an estimated time frame for that? And then separately, in the Delaware, what oil ratio are you guys interested in attaining there?

Sylvester P. Johnson

We have no plans to be cash flow neutral. Our plan is to run the company at about 2x debt to EBITDA. That's our plan. In the Delaware, we're looking for wells. Right now, basically, we're looking for wells that have an oil IP and EUR similar to Eagle Ford wells. So we like wells that come on at 600 to 1,000 BOPD. It really doesn't matter what the GOR is as long as they'll make that much oil. So that's what we're looking at.

Operator

[Operator Instructions] Our next question comes from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets Canada

Just following up on the last question that was asked. How do you balance investing in West Texas to lease acreage versus putting more capital work in South Texas to accelerate the value capture? Is it that you find returns potentially superior in West Texas to what remains to be drilled in South Texas? I mean, I was just trying to get a handle on how the company's aggregate return profile can change over time.

Sylvester P. Johnson

We're basically looking at other basins because we can't add enough acreage in the Eagle Ford because it's just gotten so competitive. Adding -- spending more capital to increase our oil growth rate in the Eagle Ford is not as beneficial to us in the long run as buying good acreage in future plays and thinking about our inventory 5 years from now.

Dan McSpirit - BMO Capital Markets Canada

Okay, great. And a few follow-ups, if I may, just on the Eagle Ford itself. How is the oil cut changing on Eagle Ford Shale wells that you've observed? And should that same profile be exhibited from wells that are -- that remain in the inventory? Just want to get a handle on how to model this.

Andrew R. Agosto

Dan, do you mean relative to gas, I presume, not...

Dan McSpirit - BMO Capital Markets Canada

Yes, correct, sorry.

Andrew R. Agosto

Yes. We really have not seen any market change in GOR in an aggregate sense from our portfolio. I mean, if anything going forward, Dan, because we'll be drilling probably less gassy, it could actually go down slightly. We could get a little more oily.

Dan McSpirit - BMO Capital Markets Canada

Okay, great. And your cost basis on the acreage that you've added in the Delaware Basin?

Sylvester P. Johnson

Just over $1,000 per acre.

Dan McSpirit - BMO Capital Markets Canada

Okay. And then lastly here, just the timing of the Brown 1H well results in the Utica?

Andrew R. Agosto

December. I think in December of this year.

Operator

Our next question comes from the line of Marshall Carer (sic) [Carver] with Heikkinen Energy Advisors.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Yes. This is Marshall Carver with Heikkinen Energy. The -- so on the midstream in the Utica, if you get something inked there, say, by the end of the third quarter, when would you be able to start really producing the wells? Just trying to get a feel for what the delay would be between the deal getting signed and announced and when production would really go up significantly.

Jim Pritts

Marshall, this is Jim Pritts. Right now we're kind of locating pads that are readily accessible to the various midstream operators. And once we sign a deal, it'll take some time to get in infrastructure to move significants amount -- significant amounts of condensate. And we would expect that ramp to start in the first quarter of next year.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Okay. So if something gets signed this quarter, you could have full production impact Q1 '15?

Jim Pritts

Yes.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Okay, great. The -- and in terms of the first Delaware Basin well, I assume that'll be a horizontal, and how much to you expect it to cost?

Sylvester P. Johnson

We're just assuming these will probably be $10 million wells to start, and that's for 5,000-foot lateral or more. I think we were using $8 million for a shorter lateral. First well we drill will probably have a lot of science on it, but, I mean, we haven't drilled one out there yet. So we're just trying to figure that out based on other people's drilling cost.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Okay. And then the last question would be the completions. Think people other -- others asked about this. But is it safe to -- how should we model the completions number for 3Q and 4Q? Should we model it very similar to the drilling? Or are you going to be building up a completions inventory? Or will that be getting worked off? Or how should we think about that 3Q and 4Q of this year?

Jeffrey P. Hayden

Marshall, let me -- this is Jeff. Let me circle up with you offline, and we can kind of nail down some of those assumptions for you.

Operator

Our next question comes from the line of Jeffrey Connolly, Mizuho Securities.

Jeffrey Connolly - Mizuho Securities USA Inc., Research Division

Following up on that Delaware question. What zone will the first well target?

Sylvester P. Johnson

We're not sure yet, but it'll probably be Wolfcamp A or Wolfcamp B.

Jeffrey Connolly - Mizuho Securities USA Inc., Research Division

Okay. And then moving on to the Eagle Ford. On the downspacing tests, did you change the completion at all on those wells?

Sylvester P. Johnson

No. It's a apples-to-apples test.

Operator

Our next question comes from the line of Jeff Grampp with Northland Capital Markets.

Jeffrey Grampp - Northland Capital Markets, Research Division

Chip, just kind of a high-level strategic question on rig counts. I know in the past you talked about likely adding a rig somewhere in '15, whether it be Eagle Ford or Utica. Just kind of curious how you view the Permian integrating. Is that going to be more detracting a rig from one of those other plays? Or would that be additive to kind of your existing plans as they stood prior to your entry?

Sylvester P. Johnson

I don't think that would be a big impact on 2015. I think right now, the first place to add a rig would be the Eagle Ford, and second would be the Utica, just because of infrastructure. And in the Permian, I think we have a lot to learn before we ramp anything up out there. And there's -- there are infrastructure issues out there and water issues out there. So that's going to be a little farther out.

Jeffrey Grampp - Northland Capital Markets, Research Division

Okay, got it. And then shifting over to the Eagle Ford. And I think you had made some comments in the past that when you guys lay out the downspace location counts that's not reflecting any infill drilling you guys could do between some legacy wells that have some wider spacing. Could you comment on if there's any plans to do that type of test on an infill and kind of what the opportunity set is there?

Andrew R. Agosto

We did have plans to test that. And in fact, we'll be moving to a pad where we're going to try that here in the next month or so. The overall scope of that opportunity is in the 20- to 25-well range, incremental.

Jeffrey Grampp - Northland Capital Markets, Research Division

Okay. And then just one last quick one on the Niobrara. Noticed that it looked like maybe some of the frac density that you guys had been employing out there maybe seemed a little bit conservative compared to what some other folks had been doing out there lately. Is that something you guys are looking at maybe doing some denser frac stages? Or are you pretty happy with the completions that you guys are laying out there?

Andrew R. Agosto

Well, I would say that -- and we're -- I think we're aware of what you're referring to. We're actually participating with, as Chip mentioned, Noble and Whiting in a number of their tests. We actually have tried various spacings, both wider and narrower than where we are today in terms of frac staging. And we've settled on where we are today based on those tests. That said, I mean, we're always open to changing it if we see either some kind of fluid formulation, sand concentration from other operators that seems to be working better. But I think we're pretty pleased with where we are today.

Operator

Our next question comes from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt & Co.

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just going back to the Eagle Ford. Are there any ongoing initiatives regarding completion optimization? Or are you primarily focused on testing downspacing at this time?

Andrew R. Agosto

Well, we've talked in the past about the fact that as we've gone across our different acreage blocks, we wanted, and Chip just used the term "apples to apples," we wanted to be able to compare geologically the formation. And to do that, we really needed a consistent completion approach. We are now at the point where we've started to try some different things. And hopefully in the next 6 months or so, we may have some color on that.

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then moving to the Delaware, how contiguous is the position that you've built so far there? And how do you, I guess, think about that going forward as you look for additional acreage?

Sylvester P. Johnson

About 80% of it is fairly contiguous. There aren't a whole lot of leases in the Delaware Basin where you end up with 100% of a 640. So it's all going to require working with other companies to put drilling units together. Most of the acreage is pretty close to the Reeves-Culberson line. But some of it is down farther south, in Reeves County south and east, kind of where most of the Clayton Williams drilling has been going on and Concho drilling.

Operator

[Operator Instructions] And our next question comes from the line of Graham Tanaka with Tanaka Capital.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Just the Wolfcamp or the Delaware Basin, what kind of IRRs are you potentially looking at relative to what we have currently?

Andrew R. Agosto

Our modeling says that we can have 80% to 140% IRRs. And we don't have a great handle on NGL pricing out there, but the oil alone looks like it'll get us there.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

And so I'm sorry, what was the mix on oil again?

Andrew R. Agosto

75% to 80% oil.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

And what were you paying for acreage recently in the Utica? You gave us the $1,000 and the $4,000 for the Delaware and the Eagle Ford.

Sylvester P. Johnson

Yes. The biggest block we bought was at about $7,500 per acre. And the -- right around the Rector well, those prices are still more like $10,000 to $12,500 per acre. The Utica continues to be the highest-price area we're in.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

How -- other folks have asked about 2015 rig count, et cetera. What does the oil production growth look like for 2015? And what would be the major requirements to achieving those?

Sylvester P. Johnson

I guess, earlier in the year, we thought that we could get to an average rate next year of 26,000 BOPD. That's still our target. We'll probably grow faster this year. I think when we put that number out there, we were only growing 50% this year. Now we're at 57%. We're not willing to say we're going to grow 50% next year, but we're going to try to hit that 26,000 BOPD number. And the key to that will be basically frac-ing more wells in the Eagle Ford. So to do that, we're going to have to drill more wells, and we're just trying to plan out how we do that.

Operator

Our next question is a follow-up from the line of Dan Braziller with Jefferies.

Daniel Braziller - Jefferies LLC, Research Division

So on the Eagle Ford spacing assumptions, the -- on the old assumptions, I think you had discussed a PV10 of around $3.7 billion for undrilled or remaining to be drilled locations. Do you have an updated NPV10 number using the new 330-foot assumption? And then also along those lines, how do you balance accelerating activity in the Eagle Ford with acquiring more drillable acreage, whether that acreage is in the Eagle Ford or in the Utica or Delaware?

Sylvester P. Johnson

I'll let Andy talk about the first part. As far as buying acreage, we've said if we could buy good acreage in the Eagle Ford, that would come before everything else we do. We just can't find that much good acreage left. Our competitors are not giving any of it up. So we end up buying a lot of smaller bolt-on acreage, and that really doesn't end up being a big-enough number to affect our drilling. Utica acreage, there's not that much acreage there to buy either, so that's not much of an issue. Delaware, there could be a lot of acreage there, but we're not willing to commit yet to making a big investment there.

Andrew R. Agosto

Yes. As far as the NPV goes, I -- the expectation should be that it's going to go up substantially, and it will. I think we're actually going to provide some detail on that at EnerCom.

Operator

Our next question is a follow-up from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt & Co.

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I just had a quick follow-up on the Eagle Ford completions. Are you able to talk about what you're doing there in terms of stage counts or amount of proppant per well and just how it compares to the standard design?

J. Bradley Fisher

We can certainly talk about it. I mean, we really haven't changed what we've done out there since we had the Analyst Day Meeting. We're still -- we have -- we're a 6-entry point, 240-foot plug-to-plug, 350,000-pound, 80 barrels a minute. We use a hybrid with slick water and cross link, Joe. So we've been very consistent in our approach in frac-ing the Eagle Ford. It's about -- I think we're just shy of -- I think we're up [ph] 1,550 pounds per foot of effective lateral treated.

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And can you talk about what you're testing there in terms of increasing either stage count or amount of proppant?

J. Bradley Fisher

Right now we're doing some testing around what our frac fluids look like and what chemicals we're putting in. We're staying consistent with the stage count and the proppant.

Operator

Mr. Johnson, there are no further questions at this time. I will now turn the call back to you. Please continue with your presentation or closing remarks.

Sylvester P. Johnson

Okay. Well, thank you, all, for calling in. Again, congratulations to our team for another outstanding quarter. We continue to beat and raise guidance on oil production, which lets us keep growing EBITDA, EBIT, while natural gas and NGL prices soften. The Eagle Ford downspacing results are significant for our future reserves and drilling inventory, and we should have data on the rest of our acreage early next year. Niobrara downspacing results look positive from an IP standpoint, and we should have enough production history to make a conclusion on spacing by the next earnings call. We're excited about our ramp-up in the Utica with drilling progressing while we've been able to buy some key bolt-on acreage. And finally, we think the Delaware Basin could have promise based on recent industry success. So thank you, all, again for calling in.

Operator

Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines. Have a great day, everybody.

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