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Carrizo Oil & Gas (NASDAQ:CRZO)

Q1 2013 Earnings Call

May 07, 2013 11:00 am ET

Executives

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

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

Andrew R. Agosto - Vice President of Business Development

J. Bradley Fisher - Chief Operating Officer and Vice President

Richard H. Smith - Vice President of Land

Analysts

Will Green - Stephens Inc., Research Division

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

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

Brian T. Velie - Capital One Southcoast, Inc., Research Division

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

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

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 First Quarter 2013 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded, Tuesday, May 7, 2013. I would now like to turn the conference over to Mr. Chip Johnson, President and CEO. Mr. Johnson, please go ahead.

Sylvester P. Johnson

Thank you, and thank you, all, for calling in. Our management team is pleased to announce another great quarter. We beat our oil guidance, our gas guidance at record revenue, record oil revenue, record EBITDA and came in under our key CapEx metric. Paul Boling will talk about the financials, and I'll go over the operational status, and then we'll open it up for questions.

Paul, you want to get started?

Paul F. Boling

Thanks, Chip. We achieved record oil production 9,311 barrels per day, a 57% increase over the first quarter of 2012. Natural gas and NGL production was 103,722 Mcfe a day. We reported record adjusted revenues and revenues for the quarter. Adjusted revenues, including the impact of realized hedges, was $118.2 million in the first quarter 2013. General guidance for realized gains on derivatives in the second quarter of 2013 is going to be about $2.3 million to $2.8 million based upon strip prices as of May 3. EBITDA was a record $93.3 million in the first quarter 2013; $2.35 and $2.31 per basic and diluted shares, respectively. That's a 33% increase over the first quarter 2012.

Lease operating expense was $10.2 million or $4.26 per Boe for the 3 months ended March 31, 2013, as compared to LOE of $8.4 million or $3.64 per Boe for the corresponding quarter in 2012. This increase in operating cost per Boe is primarily due to the higher operating cost per Boe associated with increased oil production, which we realized over the year. General guidance for LOE in the second quarter is $4.20 to $4.40 per Boe.

Production tax increased to $4.5 million for the first quarter compared to $3.1 million for the same period in 2012. The increase in production tax as a percent of oil and gas revenues was primarily due to increased oil production, which has a higher effective production tax rate as compared to natural gas. Our general guidance for production tax in the second quarter is 4% to 4.25% to total oil and gas revenue.

Tag-Along tax decreased to $1.9 million during the first quarter from $3.6 million for the same quarter 2012. This decrease in ad valorem tax is due primarily to the sale of Barnett properties and the Commonwealth of Pennsylvania February 2012 enactment of an "impact fee" on the drilling of unconditional natural gas wells that was recognized in the first quarter of 2012. Our general guidance for ad valorem tax in the second quarter of 2013 is $2.5 million to $3 million.

General administrative expense excluding noncash items was $8.3 million during the quarter as compared to $6.5 million during the corresponding quarter of 2012. The increase was primarily due to compensation costs related to an increase in personnel in the first quarter of 2013 as compared to the corresponding period. Our general guidance for G&A in the second quarter of 2013 is $15 million to $15.5 million, which includes an estimate for annual bonuses. Our general guidance for G&A in the second half of this year is $20 million to $21 million.

DD&A expense for the first quarter of 2013 increased $14 million to $45.6 million or $19 per Boe, which was in line with our first quarter guidance. Our general guidance for the second quarter 2013 is $19 to $20 per Boe, consistent with the first quarter guidance. We also completed our regularly scheduled borrowing base redetermination in April, which resulted in a borrowing base increase of $165 million or 45% up to $530 million. Currently, our borrowing base facility is undrawn.

Chip?

Sylvester P. Johnson

Thanks, Paul. I'll go over the operation status now. Current production is 25,833 net Boe per day. We have 95 million a day of natural gas and 10,000 barrels a day of oil production. Oil production is comprised of 8,700 net BOPD from Eagle Ford and 1,300 BOPD from the Niobrara. Our net production is about 50 million cubic feet per day net; Marcellus, 30 million cubic feet per day net and Eagle Ford other is about 15 million cubic feet per day net.

In Eagle Ford, we are producing from 87 gross or 68.3 net wells with 3 drilling rigs running and 1 24/7 frac crew. We currently have an inventory of 24 gross, 17.4 net wells, representing 6,400 net BOPD of potential initial production. Our Eagle Ford production is composed of -- 94% of our production has API gravity less than 50, which means we're getting a premium for those prices. And in March, we received $105.36 per barrel. Our 80-acre downspace wells have confirmed 750 for the wellbore spacing. Tighter spacing will be tested this summer. We've also completed the drilling of the Pearsall Shale well with a 2,000-foot lateral and plan to frac it in May.

In the Niobrara, we are producing 1,300 net BOPD from 45 gross or 18.0 net wells with 4 gross, 1.3 net wells waiting on completion, representing 340 net BOPD of potential initial production. Our first 80-acre downspace test wells are producing with no apparent interference, so we will drill at that spacing until a 60-acre test is completed in the second half. We have 2 drilling rigs running and plan to stay at that pace for the remainder of 2013.

In the Marcellus, we're producing from 24 gross, 8.8 net wells in Susquehanna County, and some 16 gross, 4.9 net wells in Wyoming County, 4 wells were temporary shut in due to adjacent operations. We should be back online in June. We are currently running one drilling rig and one frac crew. We have 35 gross or 11.1 net wells waiting on completion or hook up. Reliance Industries is our 60%-working-interest partner in all of these wells.

Our Barnett Shale activity is focused on workovers and production optimization with no new wells or fracs planned in 2013. These workovers have almost kept the Barnett Shale frac production through the first half or the first 4 months of the year.

In the liquids-rich area in the southern Utica in Ohio, our JV with Avista Capital has now closed on about 29,000 gross acres. We have a 50% working interest after exercising our option in January. We continue to lease in the Guernsey and Noble County areas. We have finished building the drilling pad and plan to drill our first well in Guernsey County this summer, and hope to have a post-frac, postmarination well test in the fourth quarter. Total company production for the second quarter is expected to range between 90 million and 94 net million cubic feet per day and between 9,600 and 10,000 net BOPD or 24,600 to 25,667 Boe per day.

Our 2013 budget still allocates $500 million to drilling and completions with $124 million allocated to land. We continue to expect 28% growth in oil production year-over-year and a 3% reduction in gas production year-over-year.

First quarter operating, drilling and completion CapEx of $127.7 million was below our projected budget of $128.6 million. Nonoperating CapEx was $9.0 million, which was above our $4.3 million estimate as a result of EP Energy accelerated in the completion of a number of Eagle Ford wells into the first quarter where we own a 32% working interest. Planned CapEx of $89 million included a planned $63 million option exercise in the southern Utica from Avista Capital that brought our working interest up to 50% from 10%. Second quarter drilling and completion CapEx is estimated to be $139 million, which is in line with our previous guidance that we would spend more in the first half of the year than the second half. CapEx in the second half will be reduced by longer Marcellus frac holiday, reduced facilities cost and reduced partner carry CapEx in the Eagle Ford. Land CapEx in the second quarter should be around $20 million worth between the Eagle Ford and Utica Shale.

With that, I'd like to open it up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Will Green with Stephens.

Will Green - Stephens Inc., Research Division

I wonder if we could start with the Utica. What is the JVs current capacity to add more Utica acreage? And what's your current appetite to grow there? And I guess, most importantly, is there any land left to be had around where you're looking?

Sylvester P. Johnson

We're still trying to add land especially tuck-in acres around our 3 main blocks in Guernsey and Noble County. And we're picking up a little bit of acreage every month that falls into that category. There are some bigger deals available out there that we've looked at. I think if we buy one of those, then we're going to have to sell more Barnett to pay for it. But there is -- there are some big packages out there. EnerVest has some acreage they've been trying to sell for some time. We're looking at that. Some of the other big companies have given up on being able to block up enough acreage. So they're willing to sell, and we're looking at those.

Will Green - Stephens Inc., Research Division

Got you. And then, a few have made comments that synergistic cracking in the Niobrara will actually start to improve the recoveries there. You guys mentioned that you're going to plan a 60-acre downspace test later this year. Can you give us any color on what the microseismic tells you so far? If you've done any recently?

Sylvester P. Johnson

Andy, you want to address that?

Andrew R. Agosto

Yes I will. I think our current plan is just to keep getting tighter until we see some interference. Obviously, we're also closely monitoring what our competitors, primarily Noble and Whiting, are doing. But based on where we are today, we're still outside of our best estimate of what fracture half length is from the microseismic we've seen.

Will Green - Stephens Inc., Research Division

Got you. And I think you mentioned $20 less in land for the Eagle Ford and Utica, in the land and seismic for this quarter. Is most of that going to be in the bucket of that Eagle Ford acquisition you talked about in the press release?

Sylvester P. Johnson

Yes. We -- that kind of straddled the quarter. So most of that's been spent. And I don't think there's much on the table right now. But that was the acreage block we were able to buy from a competitor in La Salle County because the leases were about to expire, and we were able to get a rig in there and start drilling and stitching the unit back together in time and saved a lot of those leases. We'll have to pay to extend some other ones, but still, the all-in costs for the whole block is probably going to be something like $1,600 per acre.

Will Green - Stephens Inc., Research Division

That's great. And then, the remainder, that's going to be Utica seismic I assume. What's the time frame for you guys getting that in and knowing what you got?

Sylvester P. Johnson

On the Utica, we're going to shoot some 2D lines basically along our well paths. But we already have enough 2D data around the drill sites we're on that we're pretty comfortable. I'm not sure there's been a lot of big industry 3D planned. But as the acreage positions gel and we trade and block up this acreage, I think that's all probably going to happen but probably not going to happen in the next 6 months.

Operator

[Operator Instructions] Our next question comes from the line of Kyle Rhodes with RBC.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

I was wondering if you could provide a little color on that La Salle County acreage deal, just in terms of location relative to your other blocks in La Salle and kind of initial results, if you've got any?

Andrew R. Agosto

It would be -- this is Andy Agosto. It would be towards the southeast of our biggest acreage blocks, but still in close proximity. We do not yet have any production results. As Chip mentioned, we have a rig drilling there now. We're drilling our third well on a 3-well pad. We'll move over and drill a 2-well pad after that. So some time, middle of the second half, we should have some production results from the completion on those well. But one thing we have done, obviously, is drill the pilot holes. So we have logs through the section and they look good.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

Got you. And should we expect that third rig in Eagle Ford to kind of stay in that new area for the rest of the year? Or is it kind of just these 5 wells you've got laid out, as-you-need-it kind of plan?

Andrew R. Agosto

We'll drill 5 wells. The rig will leave. It will come back. It's just going to go into our normal inventory at that point.

Operator

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

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

Say, Chip, just wondering in terms of Utica, on the drillings you're going to be doing, I mean, ideally what would you like to do as far as lateral length and all? I'm just wondering did your leases permit that today or are you in the process of trying to blocking things up?

Sylvester P. Johnson

We've got some pretty blocky positions right now. And I think the first well we're looking at drilling could be an 8,000-foot lateral. So we're kind of doing that routinely in the Eagle Ford and the lease position allows us to do that in the Utica. So I think that's how we're going to start.

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

Got it. And then on the you talked about looking at some acreage, [indiscernible] package in some others. Are you looking, I guess -- would you look as far as south as Washington County and would you go up maybe to Carroll County, or are you trying stay closer to your acreage where you have now?

Sylvester P. Johnson

We will go down about midway through Noble County. That's as far south as we've gone. We'll go into Harrison County and we'll go into eastern Tuscarawas County. Carroll is a little far north, but if we could see some more data up there, we might get interested.

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

And then, lastly, little bit about [ph] the La Salle deal that you did. It seems like there's other little pieces for sale. Do you see other opportunities like that, Chip, over in Eagle Ford where if you got a rig in there, you could by something potentially pretty attractive, and then drill it up to hold it?

Sylvester P. Johnson

We're trying. There's probably going to be around 4,000 to 5,000 acres per year it turns up like that. But we are starting to get to the end of the primary term on a lot of the leading leases that were brought in 2010. So there could be some opportunities here, where people start panicking and have to sell it or we can top lease it.

Operator

Our next question comes from the line of Marshall Carver [ph] with the Heikkinen Energy Advisors.

Unknown Analyst

A question on the first quarter production. You put in the press release that the feed on production was from better well performance. I assume that's the new well. But could you give a little color on how much better those wells were then your type curve in the Eagle Ford and Niobrara?

Sylvester P. Johnson

I think it was more lateral length on average, and we detailed that out in our presentation about how the type curves were some benefit, but we had factored a lot of that in. I think we're just drilling longer wells, and we're seeing the benefit of that. There were also some gains from just better efficiencies and not having to keep wells shut in as long around wells we were drilling and frac-ing. That happened in the Marcellus and in the Utica.

Unknown Analyst

So the longer lateral -- so what was cooked into the guidance versus what were the actual wells for the quarter on a lateral length?

Sylvester P. Johnson

I don't know. We'll have to take that out and get back with you.

Andrew R. Agosto

Marshall, [ph] this is Andy. Another thing we've begun a fairly aggressive program with installing artificial lifts in the Eagle Ford. Because of our choke management practices, we've tended to flow these wells for long amounts time. Some of our earlier wells, we're now putting on an dry pump and jet pump and we're starting to see the benefit of that as well.

Unknown Analyst

Okay. One more question. Do you have the number of net wells that were put online in the quarter in the Eagle Ford and Niobrara?

Sylvester P. Johnson

Yes, just a second. Andy's on his computer.

Andrew R. Agosto

Marshall, [ph] in the Eagle Ford, we drilled -- in the quarter, we drilled -- we TD-ed 11 wells in the Eagle Ford, 11 gross wells. And then we frac-ed 11 gross wells also. The corresponding number of net wells on those were 8.2 and 9.1.

Unknown Executive

[indiscernible] Niobrara.

J. Bradley Fisher

Sure, on the -- this is Brad Fisher. On the Niobrara, we TD-ed 12 wells in the first quarter. We frac-ed 11, those are gross. On the net side, we TD-ed 4.6 and frac-ed 4.2.

Unknown Analyst

And all the wells that were frac-ed were put on production?

J. Bradley Fisher

Yes.

Operator

[Operator Instructions] Next question comes from the line of Brian Velie with Capital One Southcoast.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Just a quick question on the new acreage that you added in the Eagle Ford. I know that from the presentation, the wells you're drilling this year in the Eagle Ford are particularly good at 540 MBOE EUR. Is the new acreage, is it too soon to tell whether they'll be kind of lumped in at that higher number? Or should we list those as more of like the 495 MBOE EUR that you have for out year production or out year wells?

Andrew R. Agosto

This is Andy Agosto again. Obviously, for this year, that EUR is partially reflective of the lateral length. We have a 27.5 stage average well for 2013. The wells in the new area, it'll be a mix of long and short wells, are generally, probably be a little shorter than that. But our expectation is we should see EURs per frac days similar on this acreage that we've seen in our other properties in La Salle County.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay, great. And then one more in the Utica. I know we've talked not long ago that you've seen kind of the asking price per acreage there increased pretty dramatically in recent months. Is that -- can you kind of give us some color around what the current pricing environment looks like for that acreage, both for maybe the big packages and then the bolt-on type acreage as well?

Richard H. Smith

This is Dick Smith. Pricing for fill, infill acreage like Chip was talking about a little earlier, where were filling in our blocks, is still pretty consistent in the $6,000 an acre range, in some cases, even a little less. But with the bigger blocks, where you have a lot, larger concentrations of acreage and things that add more value, prices are definitely higher. We have heard about individual lease prices on transactions in Harrison County of late, which have gone as high as $10,000 an acre. But we haven't had to pay that. We've just -- the highest we've paid to date has been around $6,000. So -- but obviously, the larger packages are going to command a little bit higher price than that.

Operator

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

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

Can you just give us a snapshot recap of how you're thinking about '13 in as far as cash flow, CapEx. And then, you gave [ph] a round number for '14, does that number move a little higher now with the positional Eagle Ford acreage? Or can you talk about your outlook this year or next year for cash flow, CapEx?

Sylvester P. Johnson

I think this year we're still talking about $620 million of CapEx and about $320 million of cash flow from operations, and then we had about $100 million of cash that came in from the sales at the beginning of the year. So we had about a $200 million shortfall, and that's what we're looking at different ways to fund that, possibly with selling some gassy assets.

In 2014, our CapEx program is essentially the same, with 3 rigs in Eagle Ford, 2 in Niobrara and 1 in Appalachia, which probably will move from the Marcellus at some to the Utica. So really, the CapEx shouldn't change much. The land budget could go down a little bit because we won't have that $63 million option payment due next year. And cash flow will represent a 28% increase in oil production.

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

Okay, so no big acceleration next year. Just kind of keep this high-grade acreage and drill what you need. But no big acceleration plan for '14, at this point?

Sylvester P. Johnson

Yes. And like that new Eagle Ford acreage, that just kind of goes into the pool. I mean, that we still run the same number of rigs. Our working interest on that will be -- that will be 67%. We have a partner that came with the deal that has 1/3 of it.

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

All right. And can you just -- maybe you mentioned this, and I'm missed it. But what is the current sale of -- or what's the current status of the Barnett -- potential Barnett sale? Can you just talk about where you're at in that process?

Sylvester P. Johnson

What we've done is start interviewing advisors, and we're kind of going through a process now to find out what each advisor thinks we could sell it for, or what the market's like, how they would market it. And then we're going to make some sort of decision. We're looking at selling 2/3 of it, or maybe all of it. We're just not sure yet. We're kind of glad that we waited because we benefited from this run-up in gas prices, and that's making the value a little higher.

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

Any timing you want to give us, Chip?

Sylvester P. Johnson

I think we'll probably try and get it done this summer. We still have an undrawn revolver. So we're not hurting to come up with the cash right now. But we know where we'll be at the end of the year, so that's why we need to do it.

Operator

[Operator Instructions] Our next question comes the line of Graham Tanaka with Tanaka Capital.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

I was just wondering if you could extend that discussion on cash flow and CapEx to 2014 and the out years? And what might you do as your CapEx does approach? I think your cash flow is approaching CapEx. When would that be?

Sylvester P. Johnson

We've modeled that out a couple of times and I think we get to parity sometime in first half of 2014. And at that point, we'll just have to decide whether we want to increase the CapEx as the cash flow goes up and stay at parity. We certainly have enough opportunities. We have about a 10-year inventory in the Eagle Ford to drill, and that hasn't gone down at all because we've been able to add as much acreage as we've drilled up. So that probably one of the first places we would accelerate once we have cash flow ahead of CapEx.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

What are your projected IRRs now, given prices where they are, on the different plays that you're in? And therefore, what at the margin will you be putting additional capital into. It looks like Eagle Ford. I guess, Utica is still waiting on it.

Sylvester P. Johnson

Yes, we think we're making a 90% IRR in the Eagle Ford at these prices. In the Niobrara, and this is all detailed in our presentation, we're probably down around 45% to 50%. Marcellus is actually at about 45% at these gas prices because we're just drilling in northeast Pennsylvania.

Utica, we're going to assume that the economics in the Utica are going to be like the Eagle Ford; a little higher well cost, but a lot of liquids and well also and lower royalty.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

So what are kind of the preliminary thoughts on what the range of IRRs there? I know it's really early, but based on what you've seen with others.

Sylvester P. Johnson

I think we're going to be 50% to 100%.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

50% to 100% range?

Sylvester P. Johnson

Yes. I know people have come up with some higher numbers than that. But we don't have enough data to go over 100%. It's pretty hard to do things over with 100% very long.

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 few quick questions for me. In terms of the Utica, can you give us an idea. You mentioned some of the larger packages in the market. Can you give us an idea of kind of relative size or scale of those packages versus your current portfolio? Or how big of a deal you potentially you think you could do in the Utica?

Sylvester P. Johnson

There's some deals out there that are as big as our current position. But in order to do one of those, we have to find some other source of capital than our budget.

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

So as I think about that, would that be kind of a $50-million to $100-million type deal that you would be potentially looking at, and then you'd finance that through noncore asset sales?

Sylvester P. Johnson

Yes, there are a couple of deals out there that are $100 million deals. And we either have to bring in a JV partner or sell something.

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

Perfect. And then you mentioned in the Marcellus, generating very strong rates of return, kind of in the core northeast. So I was curious if you can just give us an update on how you think about your current inventory there? And as we think about that program going forward, what are kind of your longer-term plans for your Marcellus position? Obviously, you have the core northeast and then some of the C county acreage. Just curious how we should be thinking about that?

Sylvester P. Johnson

Well in the northeast, we probably have wells to drill in the Susquehanna and Wyoming County 'til about the end of the year. And then we have about a 20-well position in Sullivan County that we may or may not drill next year. We don't have to because the leases on it expire next year. But there's still a lot of blocking up in Sullivan County between Chesapeake and Chief that we need to do before we know how we're going to drill all that up. But that, it's pretty much in the end of northeast, PA, would be sometime around the end of 2014 if we drill all that up continuously.

In the C counties, we need a little help on gas prices there. There's still some testing we're doing on different parts of the Marcellus itself. It's pretty thick there. We're trying to find if there is an area that has better porosity or gas storage than we've seen. But it's probably not going to be -- it's profitable, but it's just competitive with some of the other projects. So it's hard to go do a 10% or 15% rate of return project there. We have better things to drill.

I was going to -- we also have some acreage in New York. We're just going to let that expire, I think. Not only is it not the greatest geologically, but the political barriers are too high. And some of our West Virginia acreage is like the C county acreage. It's just going to need higher prices. So we'll try to hold some of that together as long as the costs are cheap to hold it together. And we've actually sold a little bit of acreage recently in West Virginia.

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

And within Sullivan County, can you -- is there enough well control for you guys to have comfort in kind of how you think about the relative EUR versus your core Susquehanna, Wyoming? And then I guess, just a second question on the C county acreage, where do you guys kind of see the breakeven economics? Or where would that need to see gas prices to earn a kind of a 10% to 15% rate of return?

Sylvester P. Johnson

Now in Sullivan, we're very confident that those are going to be really good wells. They're going to be like Wyoming County wells if you're in the right part of Sullivan County and where we've now been competing and concentrating against the 2 companies I mentioned, that I think we all know that, and that's a good area. Those are going to be wells that will make 6 to 10 Bcf. There's now a pipeline into the area. There's 2 pipelines: one, I think it's Chesapeake, but one's TBR. So there's different ways to get the gas out. So I think that's all going to get developed. In the C counties, as the -- if we can get the well cost down and the gas prices to stay where they are now, I think it can make 10% or 15% rate of return.

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

Okay. And my final question, just on the Marcellus. As you guys kind of come to the end of the drilling campaign here for the core position, is this potentially an asset you may look to monetize at some point to really kind of focus down your portfolio into the more liquids-rich portfolio?

Sylvester P. Johnson

We talked about that. I think once the production is all about -- once our newest well is about a year old, then this has a lot of appeal to MLPs because you have pretty predictable flat production stream, and it can be hedged against different markets than what we're typically seen and buy. So somewhere a couple of years out, that might be the right thing to do.

Operator

[Operator Instructions] 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. Like we said, we had an excellent quarter. Operationally, we beat on oil production, gas production, came in under on our operated, drilling and completion budget, record revenues. We're still getting great prices especially in the Eagle Ford. And we have some catalysts coming up in terms of downspacing in both the Eagle Ford and the Niobrara, which could increase our NAV there. We should get this Pearsall well frac-ed this month. That can be interesting, in it's kind of at the north end of our acreage where we think that could have the most potential. We'll get the Utica drilled this summer. Between frac-ing, and resting or marinating, it would be a while before we have results. But we're surrounded by great wells that are oily and we know we're in the right space. So should be an interesting next 3 months and hopefully, we'll have some of these catalysts identified when we talk again. Thank you very much.

Operator

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

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