Good morning, my name is Darryl and I'll be your conference operator today. At this time I would like to welcome everybody to the Stone Energy third quarter 2009 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator instructions). I would now like to turn the call over to the Stone Energy CEO, Mr. David Welch. You may now begin, sir.

Thank you, Darryl. Good morning and welcome everyone to our third quarter conference call. Joining me today is Ken Beer, our Chief Financial Officer, who will provide some color commentary on the financial results we announced last night. Ken will then turn it back over to me to provide you with a progress report on the execution of our strategy to grow gas reserves and production and price advantage basins and to grow oil in high margin basins, which usually means low cost primary recovered projects. After this we will have time for our Q&A. And Ken?

Yes, thanks, David. We'll start with the forward-looking statement. 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, production and sale of oil and gas. We urge you to read our 2008 Annual Report on Form 10K for a discussion of the risks that could cause our actual results to differ materially from those in any forward-looking statements we may make today. In addition, this call may refer to financial measures that might be deemed non-GAAP financial measures as defined on the Exchange Act. Please refer to the press release we issued yesterday which was posted on our Web site for reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures. Finally, in this conference call we may refer to the term, probable and possible reserves, which the SEC guidelines currently prohibit us from including in SEC filings. Please reference our disclosure in the press release which was issued today that addresses this issue. Let me start rather than going through the financials in great detail. We'll assume that everyone has seen the press release and the attached financials. From a financial reporting standpoint there were only a few unusual items this quarter so my comments should be brief. Our discretionary cash flow for the quarter was $107 million or about $3.25 per share substantially above the First Call estimate. Earnings of $51 million or $1.06 per share were also well above the First Call estimates. As was the case in last quarter the third quarter figures incorporate the impact of the March unwinding of some hedges. Remember the…

Thank you very much, Ken. The Gulf of Mexico shelf is our cash flow engine. It's our intent to keep it running in good form to provide a time bridge of production and cash flow until our growth engines in the Marcellus Shale and deepwater can ramp up. Thanks to the Bois d’Arc merger last year, we have visibility into three years to five years of oil development drilling and more approved developed non-producing or behind pipe reserves than we have proved developed producing or producing reserves online right now. These two items should combine to keep our shelf production relatively flat for the next several years The Gulf of Mexico shelf is still over 99% of our production and has helped us deliver a much improved balance sheet and a strong quarter underpinned by both production growth and decreased cost. We have worked hard to capture both of these benefits and are enthusiastically once again focusing our attention to the business of finding, developing and producing new oil and gas reserves. Production increased near the top end of our guidance as we executed 100% success rate hydraulic rig work over program, decreased cycle time for restoring off production wells, de-bottleneck platforms and optimized individual well rates. In the third quarter, we also completed recovery of essentially all of the previous years' hurricane deferrals including simultaneously barging oil from Amberjack, while rerouting its export pipeline away from the mudslide areas north of the field. We were able to reduce operating costs as we continued to capture synergies from last year's merger, streamlined offshore transportation, and rebid contracts for most of our major suppliers and services. In addition, even in this year of tight capital, we've just about completed the theoretical hurricane risk mitigation of our offshore platforms. We're investing over…

Sure. (Operator instructions) Your first question comes from the line of Brian Lively from Tudor Pickering Holt. Your line is now open.

Good morning.

Good morning, Brian.

On the Amberjack drilling program what are you guys expecting in terms of drilling complete cost per well production rates and ultimate recoveries?

I don't have a breakdown on per well cost. The overall programs in the $65 million to $70 million range and on the rate side of it we anticipate adding up to perhaps 6,000 barrels of oil a day production.

Brian, it's Ken. Just to make sure you're not just adding on top, obviously that will help mitigate a lot of the production, the natural decline that we would have, so that's --

And it will come on sequentially. They won't all pop on at the same time.

Correct.

That's helpful. In terms of going back to the cost for a second, what types of day rates are you seeing or expecting, I guess for this platform rig?

Again, why don't we give a range? I mean the platform rig would come down to I want to say kind of $45,000 a day to $50,000 a day type on or maybe high, I think $45,000 a day to $55,000 a day, something like that, but the point is there's a lot of additional incremental costs associated with the day rate, overall day rate, but we felt like the economics on this project we think are one of the best in the Gulf. I mean this is going to be adding rate immediately to the drilling off the platform. It's oily and it's adding primarily just new reserves, so this is at least in our minds, one of the highest return projects we have in looking forward to having the platform rig available to start drilling.

Okay, that's helpful. Just shifting to the deepwater and kind of your allocation, I think you had said previously that the two deepwater wells to four deepwater wells for next year would be spaced evenly through the year. Are you still kind of on that in terms of your visibility on how the CapEx will be spent?

It's pretty difficult to predict exactly when the spending is going to occur on those. As I mentioned in the text, we really haven't completed all the round of partner meetings yet, so, we do anticipate spending on deepwater pretty much throughout the year, but we may not have a well drilling at the beginning of the year, so it could be a little bit lumpy.

And last question, just on the Marcellus horizontal program. You're talking about the first, your first horizontal well being drilled and completed by the end of the first quarter. Is that going to be in Susquehanna County or is that going to be down in the Southwest area?

I really can't tell you which one we're going to drill first. We hope to get horizontals drilled in both locations there next year, but we should be drilling in both of those next year and I'm not sure whether first one is going to be in West Virginia or Susquehanna.

Okay, any estimate on the actual number of gross wells you'll drill horizontal wells?

No, let us get through this next Board meeting and have our preliminary budget assessed before I can give you a figure on that, but I would anticipate that we will have a pretty fair allocation to the Marcellus next year.

Great. Thanks, guys.

Okay.

Our next question comes from the line of Dave Kistler from Simmons & Company. Your line is now open. Dave Kistler -- Simmons & Company: Good morning, guys.

Good morning.

Hi, Dave. Dave Kistler -- Simmons & Company: Hey, last quarter and obviously, we're probably a little ahead of tying things down, but last quarter you'd mentioned 2010 CapEx was going to be allocated about a third, a third, a third deepwater Gulf of Mexico Marcellus and shelf and now kind of splitting that half to the shelf and half to deepwater and Marcellus, any kind of refinement we should be taking away from that? Is the shelf economics exceedingly attractive right now with bounce back in gas prices, rig costs, etc..?

Right. Let me just clarify that a little if I could, Dave. What we were talking about is a third of our drilling cost, okay? And on the shelf we also have maintenance and other costs so roughly half of the total capital go to the shelf, but probably a third of the drilling capital will go to the shelf. Dave Kistler -- Simmons & Company: Okay, that's helpful. And then maybe just to dig in a little bit on the shelf economics with Cardinal and Blue Jay. Can you kind of walk us through your thought process on those types of targets, what your size are, what kind of gas price relative to rig rates that are generating a rate of return that make sense to go after it in this environment?

Yes, first of all let me just say that the drilling on those gas projects on the shelf is a little bit more of an eclectic mix than it is a strategy and we have seen and have had the opportunity to pick up some rigs from time to time at significantly large discounts from what we would have had to pay last year. So when you combine that with the fact that you can get them on production pretty quickly that we get a little bit of a premium typically because of BTU uplift on Gulf of Mexico gas, those combined to make some of these gas plays economic, but our primary focus next year on the shelf is going to be drilling for oil at Amberjack. That's where the majority of our capital is going. Dave Kistler -- Simmons & Company: Okay, that's helpful. And then just on the risk mitigation efforts that you guys moved forward with, how does that impact kind of the outstanding letters of credit that you have against that and how should we think about that from a cost perspective going forward? Obviously, I guess out of our models we should take out any kind of actual insurance payments, etc.,?

Yes, it's Ken. Couple things. On the outstanding LCs there will be some slight adjustment downward. We're still kind of going through some of those numbers, but obviously there will be some positive adjustment from our standpoint. And then on the insurance side again, it's just a funny market and I would say unpredictable market so the thought processes was rather than lien on the insurance market let's lien on ourselves, and put a lot of dollars, insurance dollars, if you will, into one-time projects and put it behind us. And as you may remember we're on a May to May insurance year, so we'll just look to see how that market evolves in the next four months or five months, but we feel like we have mitigated a lot of potential costs associated with another big hurricane coming through this risk mitigation effort, and as Dave pointed out, this whole project is now substantially behind us, I mean so we don't have to do the same thing year-over-year. Dave Kistler -- Simmons & Company: With that in mind then when I think of your liquidity or the cash available, is there a portion of that that I should just set to the side and assume it's going to be kind of inventoried for self-insurance going forward?

To a certain extent, there's certainly been in the past and certainly going forward, there was some sense of being self-insured. We certainly had not insured all of our platforms. So there is an element of risk that we're bearing, but as we mentioned we think so much of that now has been mitigated by this current program. Dave Kistler -- Simmons & Company: Great. Well, that's very helpful, guys. Thanks so much.

Okay, David, thank you.

Thanks.

Your next question will come from the line of Richard Tullis from Capital One South. Your line is now open.

Thank you, good morning.

Hi, Richard.

Getting back to the production outlook going forward, I know David had mentioned that the shelf production should remain flat for a couple of years now and that makes up the majority of your production stream right now. Are we talking about from current run rate of about 240 million a day?

I guess we're thinking more in terms of the 2009 guidance of 215 million to 220 million, something like that.

Okay. All right. Thank you. That's helpful. In the Marcellus you'd added some acreage. What's your total acreage position now?

It's a little over 30,000 acres. We're still doing some Greenfield leasing and we'll come out with a little report on that next time we get together, give you an update on just how much we've been able to add. But we have actively started leasing again.

Okay. For 2010, do you just plan to drill horizontals up in Marcellus?

There's probably going to be a combination of verticals and horizontals just due to the geography of lease position some time, but philosophically, we view the Marcellus as a horizontal play. So we're going to try to drill horizontals. In fact, you could expect us to even potentially pool some of our acreage with other operators that try to get specific wells drilled, so we could drill a horizontal in lieu of a vertical, and we're starting some discussions on that with people right now.

On P&A liability, how much do you have now after the work that was completed in 3Q?

Yes, if you look at the ARO, which at the end of the quarter, we've got 174 plus current of 20 or so, roughly 200 million of asset retirement obligation, obviously that's a present value number, but certainly we're pleased with the reduction over the course of this year of that number. That's pretty healthy reduction from the beginning of the year.

I know your oil production is a percentage of totals around 48% to 50% now. Looking forward, do you see that being able to go considerably higher or do you think you'd just stay in the 48%, 52%, 55% range?

I think probably 50/50 is not a bad number for the next year or two. If we see things changing we'll certainly bring that forward, but we've got Amberjack drilling, which is oily and then we've also got some Marcellus stuff, that's going to be starting up and depending on what we're able to achieve there, that will impact the actual balance. Ken?

Yes, I think that's fair. I mean I think it's correct to highlight that, that Amberjack will be substantially all oil, but as Dave pointed out, we're hopeful to see some production boost out of Appalachia, which obviously would be gas. But I think effectively or at least for us it's probably a trend or a preference, particularly in the Gulf to go after oil projects.

And Pyrenees, what are you thinking on prospect size now, confirmation of the prospect size?

Yes, we'll just let new field speak to that. They're the operator and they own 40% of it, but we do think that it's going to be a commercial discovery and that we need one more well drilled for sure, next year, and we'll just see where we go from there.

Okay, and then just finally, of the 350 million CapEx next year, how much of that's drilling?

I would think that we would be drilling with over 60% of those funds. Ken?

Yes, I mean, again –

It's very preliminary.

It's still in flux and as the shift between P&A dollars and drilling dollars and lease dollars and obviously you can take something like Appalachia, where there's going to be some decision points between putting additional acreage on the books versus drilling. So it's enough influx for us probably to duck the question now. We just wanted to give you some high level ballpark number on what we're thinking about from a CapEx standpoint, but truly have not poured a budget, so it'd be premature to come up with some specifics.

All right. Well, thanks very much. I appreciate it.

There are no further questions in queue at this time.

Okay, Darryl, thank you very much, and thanks, everyone for attending the call.

And this concludes today's conference call. You may now disconnect at this time.