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Carrizo Oil & Gas (NASDAQ:CRZO)

Q3 2012 Earnings Call

November 06, 2012 11:00 am ET

Executives

Sylvester P. Johnson - Chief Executive Officer, President, Director and Member of Special Stock Award Committee

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

J. Bradley Fisher - Chief Operating Officer and Vice President

Analysts

Will Green - Stephens Inc., Research Division

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

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

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

K. Adam Leight - RBC Capital Markets, LLC, Research Division

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

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Todd Hattenbach

Dan McSpirit - BMO Capital Markets U.S.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Operator

Ladies and gentlemen, thank you for standing by. And welcome to the Carrizo Oil & Gas, Inc. Third Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded Tuesday, November 6, 2012. I would now like to turn the conference over to Mr. Chip Johnson, President and CEO. Please go ahead, sir.

Sylvester P. Johnson

All right. Well, thank you, all, for calling in. We had an exceptional quarter. Our staff did a superb job of running a growing operation while executing property sales, JVs and bond offerings. We beat our own production guidance, reaching record oil production, record revenue, record oil revenue, and record EBITDA. We're making a shift to oilier projects because the profitability is higher than gas projects and our increasing profit margins and best quarter F&D costs reflect that these are the highest rate of return projects.

Our potential Eagle Ford and Niobrara inventory of 800 drill sites means we potentially have an oil R/P of 70 years. We are not treading water hoping that natural gas prices will increase by DNG cars and trucks or waiting for new shale cat crackers and new gas plants to make our NGLs more valuable. We've improved our balance sheet by tactical sales, JVs and CapEx reductions and are pleased to say that our debt-to-EBITDA is now down to 2.6x. We have an undrawn revolver and $70 million in cash. We cut the drilling and completion CapEx by about $30 million from second quarter to third quarter and should see further reductions in the fourth quarter.

Paul Boling will now go over the financial results, and then I'll get back on and do the operational results, and then we'll do Q&A.

Paul F. Boling

Thanks, Chip. We achieved record oil production of 8,652 barrels per day, a 14% sequential increase over the second quarter 2012 and a 257% increase over the third quarter of 2011. Natural gas and NGL production was 101,576 Mcfe per day. Adjusted revenues, including the impact of realized hedges, was 100.5 -- $105.9 million in the third quarter compared to $92 million in the second quarter of 2012, a 15% sequential increase.

Average realized oil prices, including the impact of realized hedges, decreased to $97.56 per barrel in the third quarter as compared to $97.97 per barrel in the second quarter of 2012, while average realized gas prices increased 32% to $2.93 per Mcf from $2.12 per Mcf in the second quarter of 2012. And as discussed before, we have an implied basis differential to WAHA for the Barnett Shale gas market of about $0.85 per Mcf for our third quarter gas production. General guidance for the realized gains on derivatives in the fourth quarter of 2012 is going to be $8.5 million to $9 million based upon strip prices as of November 5.

Lease operating expenses were $7.1 million or $3.04 per BOE for the third quarter as compared to LOE of $7.3 million or $3.89 per BOE for the corresponding quarter in 2011. The decrease in operating costs per BOE is primarily due to the Atlas sale, partially offset by the higher operating costs per BOE associated with our oil production. General guidance for LOE in the fourth quarter of 2012 is $3.90 to $4.20 per BOE.

Production taxes increased to $3.4 million or 3.6% of oil and gas revenues for the third quarter compared to $1.3 million or 2.6% of oil and gas revenues for the same period in 2011. The increase in production taxes as a percentage of oil and gas revenues was primarily due to increased oil production, which has a higher effective production tax rate as compared to our natural gas production. Our general guidance for production taxes in the fourth quarter is 3.75% to 4.25% of total oil and gas revenues.

Ad valorem tax increased to $2.3 million during the third quarter from $1 million for the same period in 2011. The increase in ad valorem taxes is due primarily to new oil wells drilled in 2012, which have higher property tax valuations as compared to our natural gas wells. General guidance for ad valorem taxes in the fourth quarter of '12 is $2 million to $2.5 million.

General and administrative expense, excluding noncash items, was $6.5 million during the quarter as compared to $7.4 million during the corresponding quarter in '11. The decrease was primarily due to decreased compensation costs attributable to the 2011 annual bonuses to senior management, which were paid during the second quarter of '12, while in the prior period, paid in the third quarter of 2011. Our guidance for G&A in the fourth quarter is $8.5 million to $9 million.

DD&A expense for the third quarter of 2012 increased to $26.2 million -- increased $26.2 million to $46.5 million, which equates to $19.76 per BOE compared to the third quarter of '11 of $20.3 million or $10.84 per BOE. The increase in DD&A rate per BOE is largely due to the impact of the significant decrease in natural gas reserves in the Barnett Shale as a result of the Atlas sale, as well as the predominant increase in crude oil reserves in Eagle Ford that were added in '11 and in 2012, which has a higher finding cost per equivalent BOE. Guidance for the fourth quarter is $20 to $21 per BOE.

And I'll turn it back to you, Chip.

Sylvester P. Johnson

Thanks, Paul. Current production is 24,230 net BOE per day or 145 net MMcfe per day, with 95 million cubic feet per day of natural gas production and 8,400 barrels a day of oil production. These numbers are impacted by the property sales and 2 JVs we closed effective early October.

Oil production is comprised of 7,200 net BOPD from the Eagle Ford, 1,050 net BOPD from the Niobrara and 150 net BOPD, other. Barnett production is about 48 million cubic feet per day; net Marcellus, net 33 million cubic feet per day; and Eagle Ford, 14 million cubic feet per day. In the Eagle Ford, we are producing from 61 gross wells with 3 drilling rigs running our main 24/7 frac crew and an additional frac crew for 1 3-well pad. We currently have an inventory of 24 gross, 19 net wells with 9,200 net BOPD of potential production.

4 80-acre down-spaced wells have been drilled and are producing early data with confirmed down-spacing, but more history on the decline curves is needed for a broad decision. In the Niobrara, we are producing 1,050 net BOPD from 28 gross wells, with 3 gross 1.1 net new wells waiting on completion. Our first 160-acre down-spaced test wells were producing with no apparent interference, so we will drill at that spacing at least until we test an 80-acre down-spaced program. We have 1 drilling rig running and plan to stay at that pace until about year end, when a second rig will start drilling as part of our JV program.

In the Marcellus, we and Reliance are producing in Susquehanna County from 21 gross wells and just began producing from 10 new wells in Wyoming County. 4 additional Wyoming County wells should come online in late November, when Williams completes another pipeline tie-in. At least 2 well pads in Wyoming County have wells that have tested over 10 million cubic feet a day each. The Wyoming County gas flows through the new southern Laser line to Tennessee gas pipeline, which now has capacity and is seeing much smaller price deducts than a month ago. We are currently running 1 drilling rig and preparing for an early December start of our frac crew. We have 22 gross and 4.8 net wells waiting on completion. Our Barnett Shale activity is still focused on workovers and production optimization with no new drilling.

In the North Sea, we've anchored the FPSO over the wells and are close to completing the second of the 5 risers. Weather is delaying the other 3 risers and the operator has pushed first production into the first quarter. We are still working on a sale of the project. The lead bidder is making progress on due diligence and financing. If we sell the project now, we should net north of $100 million after debt repayment. If we keep the project, we'll net $75 million in 2013 after a debt repayment in U.K. taxes, and then have 4 or 5 more years after that. So either way in 2013, there's not a big difference in discretionary cash flow for that year.

In the liquids-rich area of the southern Utica in Ohio, our JV with Avista Capital has now closed on about 25,000 net acres after deducting the 19,000 acres we sold in the northern Utica. We continue to lease in the Guernsey, Noble and Tuscarawas County areas.

Total company guidance for the fourth quarter is expected to range between 88 to 99 net million cubic feet per day and 8,100 to 8,700 net BOPD or 22,766 to 25,200 BOE per day. We don't have an approved 2013 budget yet, but our current preliminary drilling plan with the rigs we have now and another Niobrara rig in early 2013 lets us grow domestic oil production 28% to 30% year-over-year, while gas production declines about 3%. If we keep the Huntington North Sea project, oil production company-wide will grow 80% to 85%.

With that, we'd like to turn it over to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Will Green with Stephens.

Will Green - Stephens Inc., Research Division

So I wanted to talk on the Utica a little bit. You guys said that you're continuing to kind of core up some acreage around kind of that Guernsey area. Is that with the backing of Avista still? Have they given you guys a go-ahead, given that sale kind of raised some funds? Can you just add some color on how that's working?

Sylvester P. Johnson

Yes. We now are planning to go all the way to their $170 million investment level or at least they've committed that. So I think we're over $120 million total now and trying to get all the rest of the acreage we can in those areas at these prices.

Will Green - Stephens Inc., Research Division

Got you. And then still no definitive plans on when you'd spud a first well down there?

Sylvester P. Johnson

No, we've started permitting some wells and we'll probably start building some locations. There are still -- we don't see a big rush to do that. We're surrounded by Gulfport wells, Antero wells, Anadarko wells that all are -- or appear to be extremely profitable. So since there's not a lot of infrastructure in the area, we're focusing our capital right now on tying up acreage.

Will Green - Stephens Inc., Research Division

Got you. And then on the Eagle Ford, you noted down-spacing to 80 acres. Can you talk about how much interference you are or not seeing so far and how those wells have kind of come back?

Sylvester P. Johnson

I guess, during the fracs, we have seen some interference, but that's pretty typical in all the shale plays we're in. The IPs appear to be pretty consistent. The initial pressures between down-spaced wells and nondown-spaced wells seem the same. But we just need a few months of production to make sure that we're really proving up some new reserves here and not just accelerating.

Will Green - Stephens Inc., Research Division

Got you. And in -- and once we do -- I assume we will get some confirmation that 80 acres is working, given what we've seen from other operators. What prevents you, you guys, from adding another rig in the Eagle Ford at that point?

Sylvester P. Johnson

Just CapEx. I mean, as soon as we have the capability to add another rig, we will. It will obviously take more than 3 rigs over the long haul to develop all the acreage. But we're already growing at 28% to 30% a year, and adding more rigs just doesn't seem like a prudent use of capital.

Operator

Our next question comes from the line of Jeff Hayden with KLR Group.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

Chip, I missed it. What was Q3 CapEx again?

Sylvester P. Johnson

The drill and complete capital is going to be about $133 million.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

All right. And what's kind of the budget looking like for the year now for CapEx?

Paul F. Boling

Hang on just a second. The approved budget for drilling CapEx is $526 million.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

Okay. And that's unchanged?

Paul F. Boling

That's unchanged at this point. We're in the process of developing an updated plan that we'll review with the board, and that should be occurring shortly. We've got a meeting lined up. And also it is well-timed in regard to the recent transactions we just did, our Niobrara JVs and the Avista Utica transaction.

Sylvester P. Johnson

In the fourth quarter, we have lower frac costs in the Eagle Ford. We have lower working interest and a carried working interest in the Niobrara. We're actually paying about 30% of what we were paying per well in September. And in the Marcellus, we dropped a spudder rig because it got so far ahead of the big rig that we can drop it and get it back later. As far as frac holidays, we'll still take frac holidays in both the Eagle Ford -- well, we're in a frac holiday right now in the Marcellus. We'll start frac-ing again with them early December. But we'll take another frac holiday in the Eagle Ford because the frac crews get ahead of the drilling rigs.

Paul F. Boling

Jeff, this is Paul again. We'll -- our plan is that once the 10-Q is filed, which will be probably sometime tomorrow, we plan on posting a summary of CapEx on our website.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

Okay. I appreciate that. And then just kind of one other question for me, and then I'll jump back into queue. Looking at the activity in the Marcellus here over the next year, what kind of year-over-year growth rate do you have for the Marcellus to get you to kind of a 3% overall decline in natural gas production?

Sylvester P. Johnson

Brad will look that up while I'm telling you why it declined. The Barnett, we're not adding any production and we sold off about 1/3 of our production. So the Marcellus growth essentially makes up for no activity in the Barnett and the sale of 1/3 of the Barnett.

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

I'm just curious on the 2,000 acres you picked up in La Salle County. How much did that cost?

Sylvester P. Johnson

We're generally paying about $5,000 to $6,000 per acre. If it's really stranded, I mean, like an undivided mineral interest that doesn't really have anywhere to go but to us, we might get it cheaper. But when we're buying acreage or decent 100% acreage around us, it's generally $5,000 to $6,000 per acre in La Salle County.

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

Is there much opportunity to pick up incremental leases around you guys?

Sylvester P. Johnson

It's pretty tough. There really are no leases left that are owned by the original landowner to speak of, so most of it comes down to trading or buying acreage from somebody that can't get to it. We've been very effective at putting together quick drilling units and moving rigs around to hold acreage that other bigger companies that bought way too much acreage 2 or 3 years ago can't get to. And so that's kind of an opportunity for us. But we're not talking about 20,000 acres here, it's -- if we can pick up 2,000 to 3,000 per quarter, that will be good.

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

Okay. And then just shifting to the Pearsall, I know there's been a lot of buzz on that play recently. Can you kind of talk about your plans? I know you're talking about drilling a test well later this year. But maybe from that and into '13?

Sylvester P. Johnson

I guess, our position on the Pearsall has been to try to preserve our northern acreage, where the drill depths are 11,000 feet and shallower, and watch what the competition has done. The best well right now to encourage you in the Pearsall is, I think, the BlackBrush well. But there's not much data on it. Some of the other Pearsall wells have started strong, and then it seems like the oil rate drops off and you end up with an okay wet gas well. But the well cost [indiscernible] is pretty tough, so we're -- I think we've never been [indiscernible] everybody is. And we're going to drill a well on one of our most northerly blocks. And it will be a horizontal well and we'll frac it and see what we get.

Operator

Our next question comes from the line of Michael Hall with Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

I guess, just a couple of quick ones on my end. Just thinking about 2013 and beyond, I guess, and just in terms of spending. I know you kind of outlined activity levels. But how do you think about the funding of that? Is that -- I mean, do you think by year end you could maybe be breakeven? I think in the past, you talk about being breakeven on your funding by the end of '13. Is that still in play? And if not, is it just kind of pulling on the revolver for the excess? Or are there any other asset sales that would be planned at this point?

Sylvester P. Johnson

I guess, right now, we still think at this pace, we will go cash flow-positive in the fourth quarter next year, and that excludes the North Sea. If we keep the North Sea, we'll probably be cash flow-positive in the second quarter next year for a quarter. But just the basic domestic program, cash flow versus CapEx goes positive in the fourth quarter next year. So I think we'll eventually end up at that point adding a rig probably in the Eagle Ford. And we'll just have to see where our debt-to-EBITDA is at that point. It should be somewhere down around 2x. And at that point, I think we probably -- even though you go in the hole a little bit when you add a new rig, it would be prudent to do that at that point.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay, makes sense. And then I guess, in terms of spending on acreage next year, what should we think about around that?

Sylvester P. Johnson

Probably $100 million. I just think it's going to be hard for us to spend a lot more than that on new acreage, especially in the Eagle Ford and the Niobrara. We'll probably keep buying in the Utica next year, but we're kind of getting to the point where it's mostly going to be tucking[ph] acreage around our existing blocks.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then if I could just comment on fourth quarter. I guess, first, make sure I heard the oil guidance right at 81,000 to 87,000 barrels a day for the fourth quarter. And then what's the -- what production, I guess, has been lost in terms of asset sales, third quarter versus fourth quarter? And it just seems like the prior 3 quarters, things have been pretty conservative on oil guidance. And I'm just trying to get a sense of -- are we looking at a similar situation in the fourth quarter? Or is there anything dragging things down I guess. Just trying to get a better sense there.

Sylvester P. Johnson

No, I think we've sold at least 500 BOPD already this quarter and the remaining JV with Haimo would take out about another 150 barrels a day. And we're not exactly sure when that will close. So that's the difference, as you've got about 650 BOPD we thought we'd have in the fourth quarter that we won't. And that's what knocks us down to a midpoint of about 8,400. We're still trying to be somewhat conservative on how we model all of our fracs and our shut-ins and when the wells come back. But I think we're getting more and more accurate with that. I don't think we're trying to add the numbers. Hopefully, we'll come in pretty close to the midpoint.

Operator

Our next question comes from the line of Adam Leight with RBC Capital Markets.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Just a quick follow-up on the transactions that have closed. Is everything but Haimo in the $70 million cash balance?

Sylvester P. Johnson

Yes. So Haimo, if that closes, would be about another $25 million of cash.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Okay. And I don't know if you can comment on this, but other than the financing of the potential buyer, are there any other gating items on sale [indiscernible] of the Huntington field or...

Sylvester P. Johnson

We don't think so, but the potential buyer is going through due diligence and asking lots of questions. So I'm sure to them, there are a lot more issues than there are to us. It seems pretty straightforward to us, especially being in a nonoperator, and now that the FPSO is actually anchored in location and we started hooking up risers.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

And if the field starts production before the sale closes, is it still likely -- can you still get the sale done if you want to and they want to? Or does that...

Sylvester P. Johnson

It's good. I guess, there's less motivation for us to do the deal at that point. Then you're talking about selling PDPs instead of PDNPs. But there are still some regulatory hurdles we have to go through too with the DECC in the U.K. But we think all that can still be done and be finished right around year end if the buyer can come through.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Okay, great. Enough on that. Next year, in the Marcellus, would you anticipate kind of the frac-ing holiday on and off again? Or is it likely it will be more continuous?

Sylvester P. Johnson

I think we currently plan to have another frac holiday, probably time it with the weather. It's hard to get water to frac in the Marcellus during the summer. And so when we've gone through our plans, that looks like a good time to stop frac-ing to not only save CapEx but to reduce problems getting water and also because bringing on gas in the summer up there is not ideal. So that seems to make sense to us.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Makes sense. And now on the Pearsall test, do you have an estimate what the dry hole cost might be and what your expectations could be for that well?

Sylvester P. Johnson

I guess, on a development case in that area, I think we are still around 10,000 feet. Those are going to be probably $9 million wells. The first well though is going to be a science well with a pilot hole and it will probably be over $10 million.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

And do you have a predrill estimate on market size?

Sylvester P. Johnson

We've run some numbers looking at decline curves based on press releases from Cabot and BlackBrush. And it could be very profitable if the oil rates stay up. But that's the problem is, none of the wells that have been on for a long time have been able to keep the oil rate up. The Pearsall is not, by nature, a real oily rock, so I think it's going to take some work to find places where it's the oiliest.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Okay. Did you give an estimate -- expectation of timing on that test?

Sylvester P. Johnson

I think we'll have it drilled and cased before the end of the year -- Brad, when do you think it'll frac that well?

J. Bradley Fisher

Probably first quarter next year.

Sylvester P. Johnson

So we should be able to frac it in the first quarter. Back to Jeff Hayden's comment, the Marcellus, estimated to make 7 Bcf in 2012 and 16 Bcf in 2013. So more than 100% growth there. That's net to us.

Paul F. Boling

And understanding the budget hasn't been finalized in the Marcellus yet, so a little movement there.

Operator

Next question comes from the line of David Tameron with Wells Fargo.

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

I think everything's been covered, just one final question. You talked about the liquids growth next year of 28 -- I think you said 28% to 30%. Can you verify that number? And then just any idea where the split is coming from as far as is that 2/3 Eagle Ford, 3/4 Eagle Ford, 1/4 Niobrara and other? Can you give us any color on that?

Sylvester P. Johnson

I don't have that split, but I know now it has to be at least 3/4 Eagle Ford because we just dropped our working interest by 30% to 40% in the Niobrara, so even bringing on more rigs. And we almost have to bring on 2 more rigs just to get back to where we were before.

Operator

Our next question comes from the line of Kyle Rhodes with RBC.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

A quick one for me. Did you have a test rate on the West Virginia Marcellus well you completed last quarter?

Sylvester P. Johnson

We tested that well at about 1 million cubic feet per day and is now shut-in. I mean, that's not enough to justify drilling at these gas prices. There might be some pipelines in the area, but it looks like it's going to be expensive to get to one of them for that rate, and we're still trying to figure that out.

Operator

[Operator Instructions] Our next question comes from the line of Marshall Carver with Capital One Southcoast.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Yes, a couple of questions, please. You talked about having new budget numbers out in the next couple of days. I mean, could you give us some color? Is that expected to be slightly higher than the last budget unchanged, slightly down? Or how are you all thinking about that?

Sylvester P. Johnson

Yes. It should be unchanged. It's just going to go into more detail on where all the numbers are moving around, where the different regions spend or overspend or underspend, how the accruals work between quarters. There is just a lot of numbers that go into this. And trying to figure out all of that from the 10-Q, I think, is not fair. So we're going to put more detail out there.

Paul F. Boling

This is Paul. To clarify your question about budget. We are in the process of reviewing with the board. That won't take place until later in the month. So don't expect any kind of an update budgetarily until after that's completed.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. On the Pearsall, how many acres do you think you have that has potential for that?

Sylvester P. Johnson

I think we probably have 30,000 acres that we could drill, and a lot of that we can hold with Eagle Ford wells. But we're just concerned about the depth of most of the Pearsall and think that to be economic, you're probably going to need to be shallower than, say, 11,000 feet or maybe 10,000 feet, and you have to find the oil window instead of the wet gas window.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

So you have 30,000 acres that you think has Pearsall shallower than 11,000 or if you...

Sylvester P. Johnson

It's probably about half. It's probably about 15,000 acres is shallower than 11,000.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. One question on the North Sea sale. I mean, does that -- I mean, that could happen any day now or it could never happen or it could happen end of the year, beginning of next year. I mean, you phrased it as finalizing the financing. So what progress has been made on the financing? And do you think it will happen sooner or later?

Sylvester P. Johnson

I think we're going to know by the end of the month. The buyer is far enough along. We've negotiated enough. We've basically said, at some point, we just have to cut this thing off because the projects are going to be so close to being completed that the price would change. So I really think, by the end of the month, we're going to know, go or no-go.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. And one final question. Do you have that number of net completions in the Eagle Ford in 3Q and expected of 4Q?

Sylvester P. Johnson

I think we do. Yes, we frac-ed 10 wells and put 13 into sales in the third quarter. For the fourth quarter, it should be virtually the same amount of activity, so look in the low-teens.

Operator

Our next question comes from the line of Todd Hattenbach with Capital Risk Consulting.

Todd Hattenbach

I have a couple of questions on your Niobrara operations and the 2 JVs that you did with Haimo and Oil India. Can you comment on how much reserves you sold in those transactions?

Sylvester P. Johnson

No, but it wasn't a lot because we didn't have a lot of reserves on the books for the Niobrara. Better way to look at it, just because of where we were at the beginning of this year, [indiscernible]. We probably sold about 1 million barrels of proved reserves. A better way to look at it is on our investor presentation, we show what our probable reserves would be for the Niobrara with and without down-spacing, and that's probably a better number to use.

Todd Hattenbach

Okay, got it. And then also on your down-spacing, speaking of which, you mentioned that you're going to 80-acre or you're going to test at least that. Do you expect to see a drop in EUR on that? Or do you expect it to stay about the same as your 160s?

Sylvester P. Johnson

I would think it would have to drop some, I just don't know how much. And that's what we have to figure out. There are cases where down-spacing seems to increase EUR. We've seen that in the Barnett, but that's over, say, the first 3 to 5 years. In the Niobrara, there's just not enough data yet, or at least we don't have the data yet. Maybe EOG and Noble do, but we don't yet, so we're going to have to test that.

Operator

Our next question comes from the line of Kenneth Parker [ph], investor.

Unknown Attendee

What I wanted to know is on the sale of the assets to Atlas, the last couple of quarters, there has been an impact to the earnings per share. In the future, will that continue to be an impact to earnings in 2013?

Paul F. Boling

Are you talking about from a DD&A perspective?

Unknown Attendee

Yes, sir.

Paul F. Boling

The impact of that transaction has been pretty well baked in as of this quarter, so don't expect to see any change in the DD&A rate going forward as it relates to the Atlas transaction.

Operator

Our next question comes from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Can you review for us the inventory of undrilled locations in the Eagle Ford today and the spacing assumptions involved? And in speaking to the economics, at least at the field level, can you speak to the drill and complete costs today and what you might -- what we might see 6 months or even 12 months from now?

Sylvester P. Johnson

Hang on 1 second. In the Eagle Ford, we go to 80-acre spacing, we have 382 net wells. The current cost, because of the reduction in frac stage cost, is now $7 million or less for our average well, which is kind of the mid-dip level of our acreage.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And then turning to the D.J. Basin and the Niobrara, what is the timing of the test, the 80-acre test?

Sylvester P. Johnson

We are trying to permit that now. And especially if we get the second rig at the end of the year, early January, we should be able to get that drilled easily by the end of the first quarter.

Dan McSpirit - BMO Capital Markets U.S.

Okay. And then, just Chip, looking at the JVs that you've struck here over these many months over the last couple of years, does this ultimately lead to something more, maybe something bigger, whether a complete sale of an asset under any one of these partnerships, like the Niobrara, for example, or maybe a partnership on land outside the U.S.?

Sylvester P. Johnson

I guess, it could lead to that. We viewed these JVs as being strategic partners that in all cases want to bring more capital to play in the U.S. So this, we're hoping, can be a source of financing either with them or through them to make more acquisitions in the U.S. So we can start looking at bigger packages and there are a lot of packages for sale right now, Niobrara, Eagle Ford, that we just can't afford without a financial partner. And so I think, at least our plan has been, and maybe some of these JV partners and the money behind them will open that up to us and we can plan in a bigger field.

Dan McSpirit - BMO Capital Markets U.S.

Okay. So the stage has been set, and maybe we see something bigger in 2013?

Sylvester P. Johnson

We would like to. We started looking at some bigger deals and we've shown them to these partners. And we'll see if they really want to do it.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And then last one for me. Timing of the 10-Q, is that by day's end?

Paul F. Boling

It will go out tomorrow.

Operator

Our next question comes from the line of Matt Portillo with Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just a couple of quick questions. On the CapEx side, I was curious, you mentioned the drilling completion costs for the quarter. I was wondering if you could just give us the total CapEx for Q3.

Sylvester P. Johnson

I think land and seismic was about $24 million. And that was down, I think, from about $47 million in 2Q. And then you'll have to wait for the Q to see all the capitalized stuff, or maybe that's already in the earnings release.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And then as we think about kind of heading into Q4, you mentioned the drilling completion CapEx is likely to trend lower. Do you have kind of a relative magnitude of where that may change?

Sylvester P. Johnson

Probably, at most, $10 million. And I'm just hesitant to say that because of the bigger driver is which wells were frac-ing and drilling in the Eagle Ford because the working interest can be different. So a 3-rig program, the numbers can move around a lot depending on who our partners are and how many. And I just haven't worked through that.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. Perfect. And then just one bookkeeping question, I'm sorry I missed it at the beginning. What did you say your total gross Utica acreage is at the moment?

Sylvester P. Johnson

About 25,000 acres, all in the southern Utica.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then just last question on the North Sea, I just wanted to clarify, I know that, that project has been financed -- your project financing. And I was curious, how we should we think about that debt if you guys tend to keep the asset? And where is that total value at the moment in terms of the project financing outstanding on the Huntington deal?

Sylvester P. Johnson

When the wells come online, it should be at $55 million, right around there. The banks get paid back first. And right now, the plan shows that they get paid back in 3 months, and then that's retired.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And do you guys have any planned exploration in the North Sea at this point?

Sylvester P. Johnson

We still have some licenses. We have still a big Fulmar project that archaeologists are trying to sell. And we just had a well drilled on one of our prospects that did not work. We were carried on that, Nexen was the operator. But we still have some more licenses that basically we have gotten at no cost, and we still think we can sell those to big companies.

Operator

[Operator Instructions] We appear to have no further questions on the phone lines, sir.

Sylvester P. Johnson

Okay. Well, thank you, all, for calling in. I know a lot of people are trying to vote today. I'm going to summarize here. And I know you're tired of hearing all this, but we're very proud of this quarter. I want to summarize how we've done on our strategy to shift to more profitable oil and improve the balance sheet.

Our oil production was up for the eighth straight quarter, 14% over the record second quarter. Record revenue, oil revenue and EBITDA, margins were up. Wyoming County, Marcellus project came online. The Gulf Coast sale was completed, the northern Utica sale was completed. CapEx was cut from over $160 million of drilling and completion CapEx to $133 million. We completed 2 Niobrara JVs totaling 30% with 2 different Indian companies and announced another 10% JV with a Chinese company, which got their Chinese government approval today. We did a bond offering to pay up our revolver. Revolver capacity increased. The revolver is undrawn and we have $70 million of cash. And our debt-to-EBITDA dropped below 3x. So I just ask you to compare our current multiple at 3.3x cash flow per share with any other company that makes 80% of their growing revenue from oil. So thank you very much.

Operator

Ladies and gentlemen, that does conclude the call for today. We thank you for your participation and ask that you please disconnect your lines.

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