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.

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.

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…

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…

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.

Good morning. Mike Glick – Johnson Rice: Just a quick question on the Conoco joint venture. What is the cash stipend amount to?

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?

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?

Yeah, we’re expecting those rigs in 2014. Mike Glick – Johnson Rice: Okay. And Amethyst, what is your working interest in that prospect?

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.

It’s in the $80 million range, something like that. Mike Glick – Johnson Rice: Okay. All right. Thank you.

It’s okay. Thank you, Michael.

Thanks, Mike.

Our next question comes from Mr. Adam Lawlis with Simmons & Company. Please go ahead, sir. Adam Lawlis – Simmons & Company: Good morning, guys.

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?

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?

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?

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.

Ken, do you have any other information on that?

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?

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.

Right. Adam Lawlis – Simmons & Company: All right. Thanks. That’s all I have guys.

Okay.

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?

Ken, you want to talk about the dividend?

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.

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?

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.

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

Right.

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?

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?

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.

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.

Yes.

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?

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?

Ken, do you got any thoughts on that?

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.

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?

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?

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?

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...

That’s probably a pretty good range. Hubert van der Heijden – Tudor Pickering Holt: Okay, perfect. Thanks so much.

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

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.

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

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

Thank you.

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