Good morning. My name is Courtney and I will be your conference operator today. At this time, I would like to welcome everyone to the Stone Energy’s Third Quarter 2014 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer session. (Operator Instructions). Thank you. David Welch, Chairman, President and CEO, you may begin your conference.

Okay. Thank you, Courtney and welcome once again everyone to our third quarter call. Ken Beer, our Executive Vice President, Chief Financial Officer is joining us this morning and will begin the meeting with our Safe Harbor statement and a review of our financial performance for the quarter as well as updated guidance for the remainder of the year. He’ll then turn it back over to me for some additional comments on the market, our execution and our strategy. Ken?

Thank you, Dave. Let me start off with the forward-looking statements. In this conference call, we may make forward-looking statements within the meanings 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 tied to the exploration development production of oil and natural gas. We urge you to read our 2013 Annual Report on Form 10-K and the soon to be filed third quarter 10-Q for 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 in this call, we may refer to financial measures that may be deemed to be non-GAAP financial measures as defined under the Exchange Act. Please refer to the press release or reconciliation of the differences between financial measures and the most directly comparable GAAP financial measures. And with that, we will assume that everyone has seen the press release and the attached financials. Our third quarter adjusted earnings came in at $0.7 million about $0.01 per share, after accounting for non-cash, non-recurring full cost impairment of $47 million. The reported loss was about $29 million. Our discretionary cash flow for the quarter was just over $92 million, about $1.65 per share. Production was above, just above the upper end of our third quarter guidance but oil and particularly natural gas price realizations were weaker than expected which led to our earnings result being slightly below the first call estimates. On the ceiling test impairment was due to several factors including lower oil and gas prices, widening gas – negative gas differentials in Appalachia, produced oil price premiums in the Gulf of Mexico and higher projected future projected transportation processing and gathering expenses. If the prices…

Okay, thank you, Ken. Obviously, this fall has been a tumultuous time with crude prices in the near freefall in October and natural gas price differentials expanding rapidly in the shoulder months in Appalachia. This puts a strain on reserves and cash flow as the economic limits rise and individual wells and as we receive lower revenue for any given amount of production. So we’ll have to prudent as we move through this part of the cycle. It helps greatly to have a strong balance sheet and a litany of robust products to execute. Also the facts are that the population of the earth is still rising, driving demand ever higher while at the same time, almost every existing well is either declining now or soon will be. So, we know that investment in quality projects is still needed to deliver enough supply to meet future demand. Our focus is and has been in areas that are believed to be among the lowest unit cost of supply in the non-OPEC world. Specifically for gas that means the Marcellus and Utica and for oil it means deepwater Gulf of Mexico. We expect that the Appalachia differential will close somewhat over the upcoming months and quarters, and we have the luxury of high liquids content in our Marcellus gas to help support the economics of the investment. On the oil side, we’re approximately 50% hedged on 2015 production around $92 a barrel, and have been enjoying about $3 premium for LLS, a Louisiana light sweet over WTI. So, if the oil price were to average $75 or so in 2015, our average realization should still be near our planning price of $85 per barrel. That said, we’ve not yet set our 2015 capital budget but are preparing it now and are reviewing…

(Operator Instructions). Your first question comes from the line of Michael Glick with Johnson Rice. Your line is open. Michael Glick – Johnson Rice: Good morning guys.

Good morning, Michael. Michael Glick – Johnson Rice: Just looking for some more color on 2015 CapEx in kind of how you think about allocating capital across our portfolio and whether there with the levers to either ratchet down or ratchet up CapEx next year?

Yes, Michael we’ve and let Kent comment on this too. But we have put on our five-year plan, a range of $800 million to $1.1 billion. It feels like we’re certainly going to be at the lower end of that, maybe even below the lower end of it, just based on the way things are shaping up right now. There are some levers that could potentially move us up a little bit from the bottom and that would be things like higher sustained production rate from Cardona, a bounce back at gas pricing in the Marcellus, sooner rather than later. There is also, we’ve never joint ventured our Marcellus acreage that’s another lever that could potentially be reviewed. So there are number of things that we could potentially do to access a little bit more capital if we needed. And as far as philosophy and methodology, we try to look at the amount of net present value created per dollar of investment, is one of the criteria. We also look at the proximity of cash flow to the current time. And those are two of the main things that we’ll be looking at as we go through our CapEx procedure for next year. It really begins in earnest next week. Michael Glick – Johnson Rice: Okay. And then it looks like the first two wells you will drill with the floater are development wells at Cardona. What are the development costs per BOE associated with those wells? I think it’d be pretty low given the infrastructure already in place?

Yes, they should be pretty low given the infrastructure already in place. All we’re going to have to do is just drill the wells and time in. And so, the wells will be drilled from right there on location, you just need to add a jumper and a couple of flying leads and you’d be ready to hook-up. So, there is no real additional infrastructure that’s going to be required Michael, to bring those wells online, just the cost of drilling the wells. Michael Glick – Johnson Rice: Okay and just to clarify in terms of your current thinking of 2015 in Appalachia. It sound like the Marcellus will still kind of be the initial focus until late in the year when you do have a new build capable of drilling the Point Pleasant wells?

Right. I think, yes, and I think one of the questions we have to answer and we haven’t answered this yet, is do we have a continuous Marcellus development program until that rig comes or do we take a little bit of a gap in the year to conserve capital. So that’s one of the things that we’ll be looking at. Michael Glick – Johnson Rice: Okay, got it. All right, I appreciate it.

Okay. Ken, anything you want to add on that?

That’s right on target.

Your next question comes from the line of Jeffrey Campbell with Three Brothers. Your line is open. Jeffrey Campbell – Tuohy Brothers: Good morning. Actually, just quickly jumping on that last answer that you gave. If the keeping the Marcellus continuous or not is a variable. That almost sounds like that you anticipate that the Utica result is going to produce perhaps the highest return that you got in Appalachia. Is that correct?

Well, we think that the Utica has and of course we’ve only drilling exploratory wells, now we haven’t tested it. So, this is a little bit of uncertainty. But the way we’re modeling it now, we think that the Utica, even though it’s dry gas, we’ll have a higher return than the Marcellus on an incremental basis. And part of that is because the Marcellus has already paid for a lot of the infrastructure that we have in place there, so it’s a little bit of an unfair comparison. But on a going forward basis with you’re talking about a well that may cost twice as much as a Marcellus well, but it could have four to six times the rate so, in reserves. So that’s where the Utica gets pretty important. Jeffrey Campbell – Tuohy Brothers: Okay that was good color. I appreciate that. Just real quickly, last quarter you mentioned that there would be some testing on the Tomcat to see if it was essentially a one-well player that might support some additional drilling. Did you arrive at a decision on that?

We have not yet. The well is still producing about the same rate, holding up the pressures fairly stable. We need to watch it another couple of quarters before we know if we’re going to do any offset drilling. But we’re a little bit discouraged that early stages and a little bit more encouraged with it now. So we’ll keep you posted on that. Jeffrey Campbell – Tuohy Brothers: Okay. So it sounds like it’s actually declining at a better rate than you anticipated?

Yes, it’s sitting there at a stable rate. It’s been producing about 800 barrels a day for quite a while. The pressure on the well head had been dropping and the pressure is now starting to stabilize. So it stabilizes and the rate stays up, that would be a good thing. Jeffrey Campbell – Tuohy Brothers: Okay. And I’ll close with kind of a theoretical question, if the low oil prices persistent in 2015, where do think you would be more likely to add acreage if opportunities emerge? Would it be the Gulf of Mexico or would it be in Appalachia?

We probably wouldn’t be in a real high acreage adding mode if these low prices persist for an extended period of time. I think we’ve got enough acreage in the Gulf and in Appalachia to go for a decade or so. And we’re only using up in the deepwater maybe half dozen to a dozen leases a year. We have 120 leases there, so that’s a long inventory. We had believed our Marcellus gave us about eight years of running room and now with the Utica is there, then that stretches you out to a number of years. So, getting additional acreage is not a real necessity for us. Obviously price has declined and the price of acreage starts going down, then we have to look at it as an opportunity. Jeffrey Campbell – Tuohy Brothers: Okay, great. Thank you. And by the way, congratulations on the day rates you secured. I think you guys might have another business laying around there some place forecasting day rates. That was a pretty bold call back at the Investor Day and congratulations.

Thank you.

Thanks.

Your next question comes from the line of Matt Portillo with TPH. Your line is open. Matt Portillo – TPH: Good morning guys.

Good morning. Matt Portillo – TPH: Just a few quick questions. I know that you guys have already gotten quite a few on CapEx for next year. I was curious if you could provide a little more context around how much flexibility? As you look year 2014 program you spent I think around 30% of your budget on exploration and exploration associated spending. Could you talk about some of the flexibility around that spending target and how much that conflicts down over time if you wanted to pull back on the capital?

I think we have some pretty good levers to flex. I mean, and some of the bigger things are that we could turn down the Marcellus program for a period of time, okay. We could farm out the ENSCO 5803 for a slot or two if we want chose to. It’s a very competitively priced rig in the market. And we’ve had a number of enquiries already. So that gives us a lever right there. We could also either drill wells and not frac them or we could enter into a joint venture with other parties. So we’ve got a number of levers, we just need to sort through all the details of it and figure out which one is going to be optimal for us preserving as much optionality as we can for the future. Does that help? Matt Portillo – TPH: Perfect. That’s very helpful. And then, I guess just on the leverage side, of things as you guys look out into 2015, could you remind us on where you would like to keep your leverage targets? Just kind of what metrics you are focusing on and how you think about those progressing over the next year or so?

Yes, Matt, it’s Ken. One of the things we’re looking at is both leverage as well as flexibility and liquidity. As you know our – we’ve got the convertible notes which we’re doing ‘17 but the majority of our debt is really 2022. Our bank facility is un-drawn and I would expect this to start tapping into that facility slightly as we go into 2015. That’s what we do to have some elbow room. Again, we do look at debt to flowing barrel, we look at that EBITDA. There is no single item that dictates where we’ll be. I think we would like to keep our current roughly little over $1 billion of debt pretty much in check as we bring on Cardona production and bring on this additional Appalachian production. So, I wouldn’t look for big flex on the debt side. But it’s one where certainly the bank facility does provide us with that flexibility that we were – that we’ve been keeping in reserve. We still have $300 million of cash and $500 million of bank facility. So we think as we look at 2015, we’ve got some flexibility but to your question, we don’t want to keep pushing the debt side of the envelope. And that’s why as Dave pointed out, we really can both pull back in CapEx, maybe look at potential JV type of instruments. There are some other ways to try to move forward our capital programs, without disrupting the whole – all of the progress that we’ve made in terms of, particularly on the depot or with the portfolio of projects that we have in front of us and the rig commitment that we have for the ENSCO rig. Matt Portillo – TPH: Great. And my last follow-up question here in regards to the Pompano development program and the Amberjack drilling program you mentioned potentially sliding a bit to the right. Is there any color or context you could provide in terms of kind of how much capital we should be thinking about with those two kinds of programs in terms of just moving that capital to 2016 and beyond?

Each program is little over $100 million for the full program. Matt Portillo – TPH: Thank you very much.

And so, as Dave pointed yes, as Dave pointed out that’s obviously, that’s held our production so it’s not like it’s going anywhere. But those platform rigs are also pretty specific and you don’t want to miss a spot when it comes available. I mean, really the dynamic that we have to address or the balance that we have to address is the balance between production projects and then some exploration projects. We don’t want to just hunker down and do no exploration at all for the next 12 or 15 or 18 months. But we’re certainly right, and we recognize it that the platform programs are certainly very attractive. But that’s the balance that we’re trying to work through. And as Dave highlighted over the next couple of weeks, we will be really addressing 2015 and to some extent 2015 and even 2016 as we try to plan through what is clearly lower oil prices and probably lower gas prices. Matt Portillo – TPH: Thank you.

Your next question comes from the line of Richard Tullis with Capital One. Your line is open. Richard Tullis – Capital One: Thanks and good morning everyone.

Hi Richard.

Good morning. Richard Tullis – Capital One: Ken, just going back to the deep-water drilling scenario, what’s the estimated current daily all-in cost to drill your Mississippi Canyon area, including the new day rate, the 350,000 a day rate even though that rig doesn’t come available until next year?

You mean.

Let me just jump in for a second here and then Ken can give you the real numbers. But securing the rig, which is typically about half of the thing. But the spread rate is usually $500,000 a day rig has been about $1 million. So, we think that there may be a little bit of potential softness developing in the support area as well. So we haven’t locked into anything yet. But typically we would expect it to be under $1 million a day. Richard Tullis – Capital One: Okay, yes.

Maybe $900,000. In the Cardona, 6 and 7 will be very simple deepwater wells. I mean, I think that our estimated dry hole cost net would be $30 million something – there would be some facility cost as well. So, these are development projects that ultimately are very low cost from a capital standpoint. And importantly they give you almost immediate production and therefore cash flow. So, in terms of self-help, the two Cardona wells could provide a lot of self-help to a certain extent, you have Amethyst which, again will be more of a development project. Yes, it will cost dollars to complete the well and tie back, but it will provide pretty quick production and therefore cash flow. So, those are the type of projects that we have to stare out versus maybe some of our exploration projects that won’t give you that immediate cash flow but you want to try to do early on so you’ll know how to follow-up with the development program if successful. So those are some of the balancing acts that we’re faced with. The two Cardona wells are, it’s hard not to move forward with them because they are low cost, quick wells with cash flow and production associated with them. Richard Tullis – Capital One: And then if oil gets to a level or is at a level that you get concerned, one of the first things to go would possibly be that non-op exploration projects you have on the schedule for say over the next one year?

I think everything is up for scrutiny. But those are something that we’ll certainly be taking a hard look at. Richard Tullis – Capital One: Okay. And then what’s your current gas realizations in Appalachia?

Well, they’ve gotten slightly better. I don’t want to call victory when you go from differential versus Henry Hub of $2 to now $1.20 or so. But certainly from a seasonal standpoint and they have some winter related bounce back, I think the fourth quarter and the first quarter, I think you’ll see those differentials come in pretty dramatically versus what we saw in the summer months. Richard Tullis – Capital One: Okay. What did the pre-drill reserve and cost estimates for the ENI, the Vernaccia?

That’s – yes, the reserve, the range I think was somewhere kind of P90 of 10/15 and…

10 to 100.

Yes, 10 to 100 is somewhat similar to Madison kind of thing, same type of range. Richard Tullis – Capital One: Okay.

Good thing about it is it’s one of these four-way closures. And they typically have a low higher success rate than lot of types of pre-ops. Richard Tullis – Capital One: Okay. And then Dave what was the pressure readings you gave on the Pribble well?

That was about, that has well head pressure of about 5,700 PSI. Richard Tullis – Capital One: Okay.

Then of course, if you add the weight of the fluid going down to the bottom hole, I think it’s a pretty high pressure gradient at a 0.88 or 0.9. So, that’s a lot of thrust power. So, we’re fairly optimistic about our well although still going to be another three or four weeks before we get a test. Richard Tullis – Capital One: Okay. And what was the final cost on that well?

I haven’t seen a final cost. But I think it was just under $14 million. Richard Tullis – Capital One: Okay, with a good bit of science.

Yes, that’s got some science to it. We got, I think we did take a core, the other thing that we’re going to be doing of course is if we get into a pad-mode, where we have a different purpose rig then you don’t have a rig mobilization on every single well. That will save money as well. Richard Tullis – Capital One: Okay.

We hope to get that cost down to the $12 million or so range. I think it’s kind of an interim target. Richard Tullis – Capital One: Okay. And then, just lastly, so, I guess PetroQuest La Cantera project, the production is a little bit less than expected because of ongoing facility work. Do you have that built into your 4Q guidance?

Yes, Richard. That, you’re correct, that La Cantera is down almost 40% to 50% from its peak. PetroQuest is doing some additional work on the project and we’d look to hopefully get that rate up again. Although I would caution you, I don’t think we would expect it to get back up to that over 100 billion a day growth type rate. But yes, the answer is yes. The range that we have incorporates not only La Cantera but kind of all of our fields we’ve kind of tried to do it somewhat bottoms up. Richard Tullis – Capital One: Okay, all right. That’s all from me. Thank you.

Great, thank you.

Your next question comes from the line of Doug Dyer with Heartland Advisors. Your line is open. Doug Dyer – Heartland Advisors: Hi, good morning gentlemen. If you could, could we get a little bit more color on the ceiling test write-down in terms of how much of the reserves are being written down and also if it’s in any particular area that you deem not commercial at this time?

Yes, Doug, it’s Ken. So, it’s really a multiple of factors. As we mentioned its oil prices coming down, oil price premiums coming down, gas differentials in Appalachia. We increased on a go-forward basis, our guesstimate or estimate on transportation processing and gathering charges. So if you put all that into the pod and you might remember this is all a full-cost pool, you have to go through kind of an accounting, some accounting steps to evaluate and compare your – the present value of your future cash flows that you’re just proved not possible would be proved reserves will throw off. And compare that to your basically some cost, your capitalized cost. And the result in number is somewhere over $1.2 billion to $1.3 billion. On that you have $43 million or $47 million ceiling test write-down because the capitalized, the capitalized portion that NPP&E was just slightly below, I’m sorry was just slightly above the present value of this cash flow. So, it was not one area or one issue, it was really the combination of a lot of – or those three or four different items. Doug Dyer – Heartland Advisors: Okay. And also I believe you said you’re 50% hedged with oil for 2015. What was that price again please?

Yes, I think it’s somewhere around 92.

92 some change. Doug Dyer – Heartland Advisors: All right, thank you.

Great. Thank you, Doug.

Your next question comes from the line of Vans Shaw with Credit Suisse. Your line is open. Vans Shaw – Credit Suisse: Hi, yes, good morning. I just wanted to ask you guys if you could refresh me what percentage of your real production is coming from the deepwater Gulf, what percentage from on-shore and what percentage from the shelf stock?

This is Ken. I will do some eyeballing here. And you probably have and maybe I would just separate it into Appalachia and then really combine deepwater gas together and shelf. So, on the oil side, you have Appalachia, I think I’ve mentioned it before is about 13%. The remainder would be deepwater, kind of split 50-50 between deepwater and the shelf. Gas volumes now Appalachia is probably approaching 60% of our gas volumes with really deep gas, deepwater and the shelf kind of it at roughly 10% or 15% are little, each about 13% to 14% of the gas volumes. And then NGL volumes Appalachia is about 75% of the NGL volumes. So that gives you at least the sense, kind of byproduct where the volumes are coming from. Vans Shaw – Credit Suisse: Yes. So, I mean, also from your earlier comments you’re saying, main past 288 and ship shell 113 are pretty valuable situations for you producing oil and you can drill more platforms?

That’s right. They’re almost 5,000 or 6,000 barrels a day of oil. Vans Shaw – Credit Suisse: Got you. So, that’s interesting. Thank you very much. I appreciate it.

Thank you.

Your next question comes from the line of Andy Peterson with Simmons & Company. Your line is open. Andy Peterson – Simmons & Company: Hi guys, good morning. Can you talk a little bit about the rig flexibility in the Marcellus and Utica? If it comes to it could you guys drop that rig or what’s the contract on that?

I think the contract expires at the end of this year. So, we have the potential to either pop it or extend it at that time. Andy Peterson – Simmons & Company: Okay. Perfect, and then also just looking out at late 2015 with the Cardona 6 and Cardona 7. Is that – do you guys think that’s something that you would go ahead and drill in any sort of commodity environment just to increase reserves that have already been discovered? Or how should we think about the deepwater portfolio?

Yes, I think in the – Ken can give you his thoughts on that too. But I think we probably would drill those wells. There are, their high return, high rate of return and the production comes on almost immediately which provides cash flow. And that’s two of the main criteria that we’re looking for. The infrastructure essentially is almost already been paid for by the Cardona 4 and 5 wells. So, and essentially getting a free ride there with them. And that’s what makes them so attractive.

Yes, Andy. Those projects you can probably go down to well below $30 to $40 and they still will have a return associated with them as they point out as virtually, there is basically no LOE associated with it because the platform fees that are tied to it. And the platform itself, it’s all rough, mostly for the most part fixed cost. So, it’s hard to see why we wouldn’t move forward. Although your point is appropriate in that. At some point, you don’t want to produce into exceptionally low oil prices. But at $70 or $80, you still have excellent economics on those two projects. Andy Peterson – Simmons & Company: Perfect. That makes sense. Thanks guys.

You have a follow-up question from the line of Jeffrey Campbell with Tuohy Brothers. Your line is open. Jeffrey Campbell – Tuohy Brothers: Hi, and thanks for taking the question. I just wanted to make sure that I understood one part of the discussion with regard to the ceiling test. Because you said that you were anticipating higher transportation costs. But at the same time, we earlier had discussed the possibility of picking up some favorable transportation in Appalachia as some guys like say maybe WPX or some of the other guys that are kind of pulling back and have a lot of extra transportation. So maybe some of that could be obtained as the favorable price. Can you just kind of help me understand?

None of that’s factored in.

Yes, and also on the transportation side, you do have quarter-to-quarter you make some of these adjustments. So as it gets more favorable that actually would provide some positive for us. But we do try to look at it quarter-to-quarter. That’s just – that’s the process that we utilize. But to your point, yes, it could provide some help going forward. But it’s, again, these are not huge numbers rather more on the margin providing with – this quarter was a small ceiling test hit. Certainly, if gas prices particularly remained very low and the differential remains high relative to the Henry Hub, that’s probably a bigger fear that I have in terms of ceiling test issue versus the transportation process and then gatherings on. Jeffrey Campbell – Tuohy Brothers: Okay, good. Thanks, I appreciate that.

Okay.

There are no further questions at this time. I will turn the call back over to the presenters.

Okay. Thanks everyone. We appreciate you being on the call this morning. And hopefully we’ll be talking to you soon. Thanks a lot. Bye.

Thanks.

This concludes today’s conference call. You may now disconnect.