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Stone Energy Corporation (NYSE:SGY)

Q3 2012 Earnings Call

November 7, 2012 11:00 AM ET

Executives

David Welch – Chairman, President and CEO

Ken Beer – EVP and CFO

Analysts

Mike Glick – Johnson Rice

Adam Lawlis – Simmons & Company

Sam Culbert – University of California

Curtis Trimble – Global Hunter Securities

Jeb Bachmann – Howard Weil

Hubert van der Heijden – Tudor Pickering Holt

Operator

Good morning, ladies and gentlemen. My name is Carla and I will be your conference operator for today. At this time, I would like to welcome everyone to the Stone Energy Third Quarter 2012 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks today, there will be a question-and-answer session. (Operator Instructions)

I do thank you for joining us. Mr. David Welch, Chairman, President and CEO, will now take over the call.

David Welch

Okay. Thank you very much, Carla, and welcome everyone to our third quarter earnings conference call. Joining us this morning is Ken Beer, who is our Executive Vice President and Chief Financial Officer. Ken is going to hit some of the financial highlights and then turn it back over to me for an update on some operational results and progress toward executing our strategy to invest in margin-advantaged natural gas basins and world-class oil basins. We’ll then be happy to take your questions.

So Ken, I’ll turn it to you, please.

Ken Beer

Thank you, Dave. I’ll start with forward-looking statements. In this conference call, we may make forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties normally incident to the exploration for and development and production of oil and natural gas. We urge you to read our 2011 Annual Report on Form 10-K and the most recent 10-Q that we filed for a discussion of the risks that could cause our actual results to differ materially from any of those forward-looking statements we may make today.

In addition, in this call, we may refer to financial measures that may be deemed non-GAAP measures, as defined under the Act. Please refer to the press release we issued yesterday, which is posted on our website for a reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures. And with that, I will move forward rather than go through in detail. I’ll assume that the people have seen the release and focused on selected items.

First, discretionary cash flow for the quarter was $143 million or about $2.90 per share and earnings for the quarter were about $27 million, or $0.48 per share. Cash flow was about $0.20 above first call average estimates, while earnings were about $0.05 or so under.

Production for the quarter came in at just under 42,000 barrel equivalents a day, or 251 million cubic feet a day which was well above the upper end of our adjusted guidance of 38,000 to 40,000 barrels a day provided after Hurricane Isaac in early September. The increase in volumes from Appalachia and from the incremental Pompano working interest purchased from Anadarko in late June helped to more than offset the shut-ins caused by Hurricane Isaac.

As is noted in the release, the fourth quarter guidance increased to 42,500 to 45,000 barrel equivalents per day or about 255 million to 270 million cubic feet equivalent a day as Appalachia continues to incline bolstered by the volumes from the second La Cantera deep gas well.

The third quarter production mix continue to have an effect of oil and liquids weighting with about 45% oil, 9% NGLs, and 46% natural gas. We would expect a slight shift for gas in the fourth quarter as incremental volumes from Appalachia and La Cantera #2 are more gas oriented.

The average price realization for the third quarter 2012 was just under $10 per Mcfe or about $59 per Boe helped by continued strong realized oil pricing and positive oil and gas hedges. The Louisiana sweet to WTI differential was about $15 per barrel in the quarter. And this should continue to bolster our overall oil price realization as substantially all of our current oil production is Louisiana sweet crude. This does help offset the current weak gas and NGL pricing.

On the cost side, our LOE came in at $61 million for the third quarter. The LOE was a little higher than expected due to higher seasonal major maintenance work and incremental LOE from the working interest acquired from Anadarko in June and some added expense from Hurricane Isaac. The LOE associated with our increasing Marcellus volumes are inclining as well. However, we would expect both the absolute figure and the per unit cost to decrease in the fourth quarter as the seasonal major maintenance drops off or the much of the actual cost from Isaac will flow through in the fourth quarter.

Accordingly, we’re adjusting our annual LOE guidance up to $210 million to $215 million that range, to account for the extra Isaac cost and the incremental Pompano LOE. The transportation, processing and gathering expenses are tracking within our guidance of $22 million to $28 million as the fourth quarter should continue to incline slightly with the increasing volumes.

And our G&A before incentive comp is running about $13.5 million per quarter as we have seen increases in personnel, particularly as we step up in our deepwater efforts. Additionally, there is a higher amount of non-cash stock vesting accretion that is hitting the G&A line this year.

We slightly adjusted our annual D&A guidance upward to account for the overall D&A run rate. Also, last year in the third quarter, our D&A line was positively impacted by a $3 million adjustment driven primarily by the recovery of some unaccrued insurance proceeds, so the year-to-year quarter comparison is a bit skewed.

Also regarding the interest expense line, we would expect to report a run rate for interest expense to be about $8.5 million to $9 million for the fourth quarter, with about $5.5 million being non-cash tied to a convertible note accretion.

The recent issuance of the $300 million 7.5 senior notes due in 2022 would suggest that this slightly higher run rate would come in to the fourth quarter. These notes will ultimately replace the $200 million 2014 notes by year end. And in fact, we have $136 million or so already tendered for closing tomorrow.

Pro forma for the $300 million offering of the 2022 notes and the redemption or tender for the 2014 notes and giving face value to the 1.75% convertible notes, our debt position will be $975 million. Additionally, our borrowing base figure of $400 million was reaffirmed by our bank group last week as part of our semi-annual redetermination exercise. As noted in the release, the facility remains totally undrawn.

We have added slightly to both our gas and oil hedge position since the second quarter and this information is included in the press release for your review.

That should wrap it up on the financial overview. And with that, I will turn it back over to Dave for additional comments.

David Welch

Okay. Thank you very much, Ken. We did continue our forward momentum this quarter despite the effects of low NGL and natural gas prices, Hurricane Isaac and these seasonally increased maintenance expenses that Ken referenced.

We grew production quarter-over-quarter and year-over-year delivering above guidance at about 42,000 barrels of oil equivalents per day. We posted our net income of $24 million, which is about $0.48 a share and discretionary cash flow of $143 million and $2.90 a share. All in all, it was a pretty good quarter as we beat consensus on cash flow and production while missing by a nickel on the net income.

In the third quarter, we brought on line the second condensate-rich onshore deep gas well, La Cantera and are now producing from both wells net to Stone approximately 18 million cubic feet of natural gas equivalent, which includes about 260 barrels of condensate and 600 barrels of natural gas liquids.

Also, production at our liquids-rich Mary field in the Marcellus Shale play continues to climb. During the quarter, we drilled six wells, frac two wells and brought seven new wells on production. We’re currently producing about 53 million cubic feet of natural gas equivalents, which includes 1,300 barrels of condensate and 1,900 barrels of natural liquids per day.

Production from these fields, along with the increased 25% interest in Pompano more than offset the decline in natural gas production that we’re managing in our legacy conventional Gulf Coast businesses. We are presently producing about 20% from the Marcellus, 5% from deep gas and 30% from deep water, so our new businesses are now producing about 55% of our total production, as the legacy conventional Gulf Coast assets began to play smaller role. Another highlight of the quarter is that we maintained a steady liquids volume percentage to average about 54% of total production. We still expect to deliver full year production within our original guidance.

To sum it up, the third quarter we grew production year-on-year 18%, up from the second quarter slightly. Higher seasonal maintenance, LOE, Hurricane Isaac and lower NGL and natural gas prices in the summer reduced net income slightly from the second quarter to $24 million in the third quarter, beating consensus on cash flow and was driven by outperforming on production and our price advantaged basin strategy.

The balance sheet remains strong. We issued the $300 million notes Ken alluded to in the third quarter and expect to use most of it to pay off the $200 million notes due in 2014. The new notes mature in 2022 and have a 7.5% coupon. On a pro forma basis, we expect to have approximately $240 million in cash and a $400 million undrawn revolving credit facility. So we should have liquidity of about $650 million until we’re in good shape to execute our three-year plan which is populated with exploration and development projects in each of our business areas.

As mentioned last quarter, most of the opportunities in our plan are already identified and owned by Stone. We continue to believe that we have the capital projects and the people to execute our plan.

Let’s take a quick look at each of the business areas. We think of our businesses and allocate capital into five areas, comprising the conventional Gulf Coast, deep gas, deep water, onshore oil and Appalachia. In the conventional Gulf Coast where we’re focused on workovers and oil development drilling only, we’re continuing an active workover program aimed at converting our proved developed non-producing reserves into proved developed producing reserves. This will help us maintain a relatively stable Gulf Coast oil production and cash flow profile. Our three-year plan in this area is strongly geared toward oil and condensate production and maintaining significant cash flow from current operations.

We also have quite large natural gas prospect inventory available if natural gas prices increase to a level high enough to attract capital and our somewhat liquids-rich deep gas play on the Gulf Coast, our successful second well La Cantera is now on production.

Stone’s net production from our deep gas business overall is about 19 million cubic feet per day of natural gas equivalent including 260 barrels of condensate and 600 barrels of natural gas liquids. We expect that a third well at the La Cantera discovery will be drilled and hopefully placed on production in 2013.

During the third quarter, we’ve also added a couple of additional deep gas prospects onshore in the same geologic mini basin of South Erath and La Cantera. These are La Montana and Thunder Bayou. So, we still see very good potential in this deep gas play which contains enough liquids to make it economically viable even with low gas prices experienced last summer and especially attractive as gas prices have rebounded by about 30% from the second quarter.

We were also the high bidder on two offshore deep gas blocks in the most recent lease sale and have a number of these deep liquids rich prospects offshore as well. These blocks were awarded to us by the BOEM in the third quarter and these are not the ultra deep gas plays that are being drilled by other operators. These are just around 20,000 feet.

Turning to deep water, several milestones were achieved in the third quarter. First, the deepwater joint venture with ConocoPhillips was triggered when the BOEM awarded us the key jointly bid block at our Carrack prospect under the terms of this agreement, Conoco and Stone bid on several leased blocks together and Conoco has the option to participate in four of our existing deep water prospects in Mississippi Canyon.

These prospects are the Marauder, Sherwood, TwentyOne and Carrack and we feel this is a win-win deal for both of us. We get a large highly capable partner who’s constructing a rig, retain a material working interest in some of our top prospects and received a cash stipend as well. So Conoco gains the immediate access to four high-quality deep water prospects in Mississippi Canyon, some of which may help underpin their rig commitment.

In addition to the Conoco deal, we have authorized the drilling our Amethyst exploration prospect which is a project with similar seismic attributes as industry discoveries at Isabela, Santa Cruz and Santiago. If successful, Amethyst would be a short subsea tie-back to our Pompano hub facility.

We’ve also authorized a rig commitment for two deep water rig slots in the 2014 timeframe and are seeking those slots in the rig market right now and hope to also get an option for a third slot. The rig is planned to be used for the drilling of our Cordona development well near Pompano and the Amethyst exploration prospect. We’re also maturing several other exploration prospects on leases we own in the area. These are all candidates to be tied back to our 100% owned Pompano hub facility if successful.

We’ve also placed in order for our subsea trees and other long lead time items and expect to conduct work on the Pompano platform commencing in 2013 for the platform to be able to accept additional subsea tie-back production. Our hub platforms at Amberjack and Pompano have enough spare capacity to handle an incremental 70,000 barrels of oil per day. We have a robust combination of development and exploration wells in the area and will be able to take advantage of this capacity.

In addition, we’ve authorized making drilling rig commitments to place a platform rig on Amberjack and Pompano. At Amberjack, we’ve authorized the drilling of two long-reach amplitude supported projects; and at Pompano, we are maturing three development wells to be drilled from the platform. We’re in the advanced stages of negotiations with drilling companies to lock down the rigs. So we’re gearing up in earnest to pursue the opportunities afforded to us through the Pompano acquisition, which closed at the end of last year and in the second quarter this year, and also the successful lease sale, wherein we won 23 additional blocks.

In our Parmer appraisal well at Green Canyon 867, the well was temporarily abandoned after we encountered over 200 feet of liquids rich gas pay in two zones that were both full to the base of their respective sands and over 40 feet of oil sands relative to the pay found over a 1.5 mile in the original – away in the original discovery wells. Seismic imaging of this field is complicated by the irregular top and base of the salt surface that sits above the fuel pays.

Accordingly, we are now acquiring advanced seismic data to determine next steps in the appraisal and development process. Once this data is acquired, processed and analyzed, we’ll have better intelligence of the size of the resource, and this will be a key factor in designing a development plan. We have a 35% working interest in Parmer, and expect that the next drilling activity will take place late in 2013 or 2014.

Our next deep water exploration prospect to be drilled is likely to be our Phinisi prospect at Walker Ridge 719. This well gets spud in the second quarter of next year to test the Wilcox potential of a four-way geologic structural closure located between the Jack and St. Malo discoveries which are also four-way geologic closures. The exploration plan permit has already been obtained and the well is now merely awaiting its slot on the rig schedule to commence drilling.

We own a 20% interest in Phinisi, which is operated by ENI. This is another high potential impact prospect for Stone. In our offshore oil area, there’s really nothing material to report at this time. We still have our small non-operated 1,800 acre Eagle Ford position, which is being developed and we maintain our options in the Cane Creek, Niobrara and Alberta Bakken areas.

Finally, turning to the Marcellus Shale in Appalachia, where we own about 90,000 net acres. We’re presently producing about 53 million cubic feet equivalents per day, which includes 1,300 barrels of condensate and 1,900 barrels of NGLs per day.

We still expect to drill about 25 wells this year with our one rig program and our liquids rich Heather and Mary areas in West Virginia. We expect to bring online another nine Marcellus wells before the end of the year, and these wells should bring our exit rate near 70 million cubic feet equivalents per day. So we’re happy with our operational results and with the equivalent realized pricing in our Marcellus wet gas area.

The prices for services have also weakened it with gas prices and we’ve just recently renewed our frac contract in Appalachia. Under the new contract and with increased efficiencies, we expect to save between $0.5 million and a $1 million per well depending upon lateral length and the number of frac stages. This will obviously enhance the economic returns in our high liquids focused area. In the aggregate, our strategy is continuing to work. The conventional Gulf Coast is still providing us with strong cash flow to support our growth areas and our new business are now contributing over half of our production.

Our longstanding focus on price advantage basin continues to benefit us during this period of low natural gas prices and we’re also still receiving about an $18 per barrel positive differential to WTI for essentially all of our oil production.

We expect that production will grow this year about 18% over last year and that our CapEx will be broadly in line with this cash flow.

With this, we’ll close and now we’d be happy to take your questions. Carla, I’ll turn it back to you, please.

Question-and-Answer Session

Operator

Thank you, Mr. Welch. (Operator Instructions) Mr. Welch, your first question comes from Mr. Michael Glick with Johnson Rice. Please go ahead, sir.

Mike Glick – Johnson Rice

Good morning.

David Welch

Good morning.

Mike Glick – Johnson Rice

Just a quick question on the Conoco joint venture. What is the cash stipend amount to?

David Welch

Well, it’s variable because it’s an option for Conoco to participate in those four things and the terms of the deal specifically are confidential, so I can’t really go into it exactly right now.

Mike Glick – Johnson Rice

Okay. And then, kind of looking towards 2013 just in terms of capital allocation, should we expect a similar allocation to what you guys have spent in 2012? And then looking to 2014, the deep water will grow to a much larger percentage of CapEx?

David Welch

Yeah, that’s probably a pretty good starting point. We’re going to come out with guidance and our capital program in the next few months and – but that’s not a bad assumption for working right now.

Mike Glick – Johnson Rice

Okay. And then in terms of the platform rigs, is that looking like more of a 2014 event?

David Welch

Yeah, we’re expecting those rigs in 2014.

Mike Glick – Johnson Rice

Okay. And Amethyst, what is your working interest in that prospect?

David Welch

We have a 100% working interest right now. It’s one of those that we might try to do or promote a deal with a partner. But it’s not one of these over-the-top deep water wells such that if push came to show, we might drill it ourselves.

Mike Glick – Johnson Rice

And any idea what the dry haul cost would be? I know it’s early, obviously.

David Welch

It’s in the $80 million range, something like that.

Mike Glick – Johnson Rice

Okay. All right. Thank you.

David Welch

It’s okay. Thank you, Michael.

Ken Beer

Thanks, Mike.

Operator

Our next question comes from Mr. Adam Lawlis with Simmons & Company. Please go ahead, sir.

Adam Lawlis – Simmons & Company

Good morning, guys.

David Welch

Hey, good morning, Adam.

Adam Lawlis – Simmons & Company

Any update on Marcellus infrastructure build-out? How is that impacting your outlook for 2013 considering your strong production growth we have witnessed recently from your Marcellus assets?

David Welch

Yeah, Ken, you can chime in if I quote something erroneously. But we don’t see any infrastructure limitations on our Marcellus growth profile. In fact, I think the situation is going to be getting better from a pricing standpoint as additional fractionation and other equipment becomes available. Ken, anything you want to add?

Ken Beer

Yeah, Adam, and again – so for both Mary and Heather, we ultimately tie into TETCo line, the Texas Eastern line. In the case of Mary, we’ll go through the old Cayman now, Williams facility or line – pipeline gathering system. In Heather, we will ultimately be utilizing a Eureka Hunter Line. But the ability to get our gas out is not an issue like you might see up in, for instance, Northeast Pennsylvania. The Tennessee 300 Line remains very tight. But for us, we don’t really see the ability to get the gas out as a critical issue this quarter.

Adam Lawlis – Simmons & Company

That’s helpful. Thanks. And also a follow-up, when can we expect an update on the Upper Devonian and Utica Shale test?

David Welch

Yeah. I think the Upper Devonian – we’re going to try to drill a well in the Upper Devonian in the first half of 2013 to get a little test there. And we actually think the Utica is probably dry gas so that we probably won’t test for another couple of years.

Adam Lawlis – Simmons & Company

All right. Thanks.

David Welch

Ken, do you have any other information on that?

Ken Beer

Yeah, I mean, Adam, just for the Utica, as they said, as it is, at least in our acreage position dry gas, and as you know, it’s deeper than the Marcellus but the economics don’t seem to make sense. It’s $3.5 per Mcf. So, we didn’t feel inclined to put a Utica test on for this year or next. But as Dave mentioned, the Upper Devonian, that is something that we’ve got in the schedule for some time in the first part of 2013.

Adam Lawlis – Simmons & Company

Okay. And kind of along those lines, what is your macro oil and gas for you going out for the next couple of years and what point on the gas side would you guys be interested in kind of looking at gassier things like the Utica?

David Welch

Yeah, I think for Utica being deeper than the Marcellus, we’d have to get up 450 to 550 range for that to make sense.

Ken Beer

Right.

Adam Lawlis – Simmons & Company

All right. Thanks. That’s all I have guys.

David Welch

Okay.

Operator

Your next question comes from Mr. Samuel Culbert with the University of California. Go ahead, sir.

Sam Culbert – University of California

Hi. I’m interested in thinking about what your end game is? When will you start distributing some of your profits? When will you think about maybe joining up with some other enterprises?

David Welch

Ken, you want to talk about the dividend?

Ken Beer

Yeah, on the dividend side, we don’t have a dividend. We’ve got at least – we’ve got our opportunities that it’s such that our decision has been to really put capital back into that opportunities that – so to-date, we have not been a dividend payer. And I think at least for the foreseeable future, that’s something that we do and the board does at least look at and review, but for the foreseeable future we don’t see that step being taken as we’ve got our capital projects calling for our cash.

David Welch

Then on the deal side, what I would say is that we feel like there is a tremendous amount of value locked up in our prospectivity and in our assets. It isn’t completely reflected in the market, so I don’t think we have the company out looking for somebody to buy us right now. And on the other side of it, we’re always in the market looking to see if particular deals or combinations make sense for our shareholders.

Sam Culbert – University of California

Recently, the Williams Company split themselves into two pieces in order to realize more value for shareholders. Do you have any ideas about doing that?

David Welch

There is nothing on the horizon right now. We always consider, is it wise to have ourselves in three or four different areas. And we think it provides a good diversity. And if you get hit with a hurricane in the Gulf, it’s good to have some production on another area to keep the cash flow coming. So that’s our logic at this point in time, although I would never say never about anything.

Ken Beer

Now we have to worry about Marcellus getting hit with a hurricane. Luckily, we have the Gulf Coast.

David Welch

Right.

Operator

Our next question is from Mr. Curtis Trimble with Global Hunter Securities. Go ahead, sir.

Curtis Trimble – Global Hunter Securities

Good morning, everyone. Well, I was hoping I might be able to get either some pre-drill estimates or size of structure for the four prospects you mentioned in the Conoco JV, as well as possibly on the Amethyst and/or the La Montana, Thunder Bayou?

David Welch

Yeah. Well, these things have, as you can imagine, quite a wide range as they’re ranked wild cat-type things. But in general, some of those smaller ones are in the 5 million barrels to 50 million barrels range. And that’s – we kind of look at things as a P10 and a P9. In other words, a 10% chance it could be this large and 90% chance it would be at least this large. So that’s what those 5 million barrels to 50 million barrels would represent and that’s kind of the Amethyst range. Some of the others are a bit larger prospects that go anywhere from, again, from 10 million barrels up to 200 million barrels or 300 million barrels. So there are some large ones mixed in.

Curtis Trimble – Global Hunter Securities

And in terms of Parmer, would you expect to be able to book reserves on that? Or is the nature of insight into production just too far off for our 2012 reserve bed?

David Welch

Right. I don’t think we’ll book any reserves on Parmer this year and deepwater in general, you don’t book reserves until you sanction the development project, which has all of the subsidy tieback and all the other costs fully engineered and factored in. So it will be a little time before we book any reserves from Parmer.

Curtis Trimble – Global Hunter Securities

Okay. Good to hear.

David Welch

On the other hand, we are booking reserves from our deep gas prospects that are already drilled and that’s one of the benefits of being onshore with some of these other prospects is you can drill them in. When you make a discovery, you can book the reserves fairly soon thereafter.

Curtis Trimble – Global Hunter Securities

Very good. I appreciate the color. Thank you.

David Welch

Yes.

Operator

Your next question is from Mr. Jeb Bachmann with Howard Weil.

Jeb Bachmann – Howard Weil

Good morning, guys. Just a quick one from me. How many of those Amethyst type prospects do you guys have around Pompano at this point that are identified?

David Welch

Yeah, we’re working on several right now. I would say there are probably two or three more of that – three or four more of that I’m aware off and these are at various stages of maturity. But they’re pretty – they look to be pretty good prospects Jeb, so we’re pretty excited about them.

Jeb Bachmann – Howard Weil

And then I know you guys haven’t provided 2013 guidance yet. But just kind of looking directionally mainly on the oil side, would it be safe to assume that we should expect oil production to continue to grow while gas might fall off in 2013?

David Welch

Ken, do you got any thoughts on that?

Ken Beer

Yeah. Jeb, I would say just the opposite. If you think about in 2013, you’ll have the Marcellus providing some increasing volumes. You’ll have probably the deep gas sides, particularly at La Cantera and we have a third well providing some incremental volumes that’ll help the gas and NGL with maybe some condensate as well. On the oil side, really the 2013 oil program was going to be driven from the Pompano platform program, which really has been pushed off into 2014 because of rig availability. So, I would think that oil would be more – probably flat to down with gas showing some (inaudible).

Jeb Bachmann – Howard Weil

Okay. Thanks for the answer, guys.

Operator

Our next question comes from Mr. Hubert van der Heijden and my apologies, sir, if you would give your company name as you ask your question. Go ahead, please.

Hubert van der Heijden – Tudor Pickering Holt

Yeah, good morning, guys. This is Hubert of Tudor Pickering Holt. I guess starting with the deep gas project, can you talk a little bit there about the declines and I guess I’m trying to allude to how should we kind of think about the exit rates from the two wells at La Cantera that are currently on?

David Welch

Yeah, I’ll take a stab at that. It’s fairly early days and we think there’s a pretty sizeable reservoirs. I wouldn’t expect a huge amount of decline the first year in 2013. I would say the decline could be minimal and the fact that we’re going to try to get a third well out there at La Cantera, I think the operators are going to be proposing a third well and we haven’t approved it yet. But if we like it, that well would likely help production actually increase slightly rather than decrease next year.

Hubert van der Heijden – Tudor Pickering Holt

Okay, perfect. And I guess on the liquids-rich type curves in the Marcellus, you gave an update on cost. With a lot more wells down, are you guys still sticking to the curves that you have or is there some movement there?

David Welch

Yeah, we haven’t really changed any yet. Some of the new wells that we just brought on, we don’t have a huge amount of history on those, and I think our reserve engineers at Netherlands who do our reserves are reviewing that, and hopefully we’ll see some slight increases from what we have booked, but they’re not substantially different from what we’ve shown as our type curves.

Hubert van der Heijden – Tudor Pickering Holt

Okay. And last one from me; sorry to skip around, I guess. But, do you guys have some sort of an estimate on reserves or kind of like a 2P reserve number on the La Cantera prospect?

David Welch

I don’t think we’ve put anything out on that specifically. We do generally put our 2P reserves out in our annual reserve report and we will be updating that because 2P reserves are done by Netherland Sewell. But we think it’s a very good – the La Cantera is a very nice prospect and very nice addition of business for us and we expect that the reserves will – could potentially continue to drift upward a little bit.

Hubert van der Heijden – Tudor Pickering Holt

But from that I guess just to put a wide range around it, if I guess – is that kind of like 35 to 70 Bcf net to you guys or is that...

David Welch

That’s probably a pretty good range.

Hubert van der Heijden – Tudor Pickering Holt

Okay, perfect. Thanks so much.

Operator

(Operator Instructions) At this time, there are no further questions in queue.

David Welch

Okay. Well, thank you very much, Carla, and thanks everyone for joining our call. We appreciate your interest in our company and we’ll talk to you next time. So long.

Operator

Mr. Welch, we just did have one more question come in. May I go ahead and – all right. They’ve withdrawn, I’m sorry.

David Welch

Okay, thank you. I believe we’re done. So long.

Ken Beer

Thank you.

Operator

Ladies and gentlemen, that concludes today’s conference at this time. You may now disconnect your lines.

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