Good morning ladies and gentlemen, thank you for standing by. At this time, I would like to welcome everyone to the Second Quarter 2014 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. Later, there will be a question-and-answer session. (Operator Instructions). Thank you. I would now like to turn the call over to Mr. David Welch to begin. Please go ahead, sir.

Okay. Thank you, [Teresa] and welcome everyone to the Stone Energy’s second quarter conference call. Ken Beer, our CFO and Executive Vice President will begin the meeting this morning with our Safe Harbor statement and a review of our financial performance for the quarter while also update guidance for the remainder of the year. He will then turn it back over to me for some additional comments on how we're doing executing our five-year plan. So, Ken take it.

Great, thanks Dave. And I will first start 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 normally incident to the exploration foreign development production and sales oil and gas. We urge you to read our 2013 Annual Report on Form 10-K and the most recent 10-Q for discussion of the risks that could cause our actual results to differ materially from those in any forward-looking statements we make today. In addition in this call, we may refer to financial measures that maybe deemed non-GAAP financial measures as defined under the Exchange Act. Please refer to the press release we issued yesterday, which is posted on our website for a reconciliation of the differences between financial measures and the most directly comparable GAAP financial measures. And with that, I'll move to the comments, we'll assume everyone has seen the press release and attached financials. Our second quarter earnings came in at around little over $4 million or $0.08 per share, there are few items which let us to be below the first call, earnings estimates including lower NGL and gas price realizations production falling within the lower end of guidance a much higher DD&A rate which is non-cash which certainly hit earnings and some smaller items that were mostly non-cash such as derivative expense and slightly higher reported interest expense. Our discretionary cash flow for the quarter was just over $117 million or $2.25 per share. Production for the quarter was 44,000 Boe per day or 264 million cubic feet equivalent per day which was just under the midpoint of our second quarter guidance. There were several small negative…

Okay, thank you Ken. And as Ken said just to reiterate that our production was slightly below midpoint of guidance, but that our future guidance which is adjusted for the shelf sale would have been reaffirmed have we not concluded the non-core shelf property sale. The quarter was filled with several important achievements that we believe indicate future value creation ahead. We are continuing to pursue our strategy to take advantage of the two technology breakthroughs at our industry deepwater and horizontal drilling and hydraulic fracturing. And we are still very well positioned to take advantage of both of these technologies owning a 107 deepwater leases, two deepwater hubs in the Gulf along with an approximate 35,000 net acres position in the super rich portion of the Marcellus shale and 28,500 net acres in the dry gas Utica in Appalachia. And both of these areas have material production and reserves are ready as well as significant and near-term development exploration potential. In the deepwater area, we have sanctioned the development of the Amethyst discovery that was announced in the first quarter. We own a 100% working interest in Amethyst and are targeting to be online by the middle of 2016. This well is expected to be a high rate completion, potentially exceeding 40 million cubic feet of gas plus an associated liquids of 60 to 80 barrels per million cubic feet. During the quarter, we developed a plan to build the flexible flow line subsea tieback to our Pompano hub. We have generated a project expectation timeline and are currently on track to deliver the project as planned. We placed the order for long lead time items such as the flow lines and umbilical in July. One of our most important development discoveries are earlier in the year are also…

Thank you. (Operator Instructions). And your first question comes from the line of Jeffrey Campbell of Tuohy Brother Investment.

Good morning.

Good morning.

Let me, I apologize in advance I missed the dollar figure as came on to the call. But I did hear you discussing your deepwater rig here in the negotiation say, back in the Analyst Day, you were talking about maybe being able to procure something for around 375 day rate. And I haven't seen any publicly announced contracts since that time that indicate that degree of softening. So just wondering are you still hopeful to get those kind of terms I think you modified your goals?

We're still hopeful, we don't have any ink on paper yet. But we're still in some good and serious discussion with two separate companies and I think we'll have a good chance to meet our original target.

Okay. That’s fine. Thank you. In yesterday’s press release you mentioned Cardona and Cardona South coming online at approximately 12,000 Boe per day. At the Analyst Day, I thought you were guiding 10,000 Boe per day expectation, did I misunderstand or have you upwardly revised your expectations? And if it’s latter what’s behind the higher number?

Yes Jeff this is Ken. I think at the Analyst Day we really were suggesting and we have been pretty constant on this that both of these well we have kind of as suggested that the productions could be somewhere around 6,000 a day on per well. And so really we just putting them together and assuming somewhere around that 12,000 barrels a day, obviously we won’t know the exact number so we would bring them on, but that’s at least our estimate or projection and we have been pretty consistent with those numbers.

And I will give a little piece of color on that. If we had a 10,000 number floating around before, we have now competed the wells. And as I mentioned in my comments that the completions went off in textbook fashion meaning that we have really, what we think a really good completion. So I think we feel pretty confident, 12,000 barrels a day is a pretty good number.

Okay. Good. Always none of it positive here one way or the other. The last question I will ask is are you still on track to doing upper zone perforation in Tomcat, you mentioned how which you have gotten so far is oilier than expected. Is this still going to take place sometime late summer or early fall and what kind of production uplift are you looking for?

Yes. No I think basically what we have at Tomcat is what we have got. It turns out we got a little oilier well, when you translate that to equivalent production it’s not as high but obviously oil is more valuable. We’re going to do a shut in the well, do a build up test and kind of get an idea of reservoir volume and that will tell us whether or not we are connected to a large volume or just kind of an average volume. And if we are connected to something large there may be an opportunity to a couple of offset wells, if not than we are probably done at Tomcat.

Okay great. Thank you.

And your next question is from the line of Michael Glick of Johnson Rice.

Good morning. Just a couple of questions on Cardona. Once the loop system is installed, how long should the commissioning process take?

Well, the commissioning itself is probably a month or so. And then the ramp up is probably another month Michael. So, we're looking at a couple of months overall. We're not going to just try to bring these wells on it for a rate on day one. We'll bring them up slowly and let the -- both of these wells are frac pack. So if you bring them on slowly the frac, the sand and the frac pack or the gravel pack is kind of like a lock cab in house you know that settles a little bit after it’s, put in a dynamic situation and if you do that kind of on a slow and general inclining draw down basis, it settles in pretty nicely and generally they last long, long time. So, that's we're going to do with them. But I would count on a couple of months.

Got you. And then I guess what type of production profile should we expect for 2015?

Ken, have you got anything on that?

You mean the Cardona?

Yes, Cardona.

Typically, these wells if they come on about 12,000 barrels a day combined like we were talking about, you would expect to have constant production period for maybe six months or so and then start a little bit of a decline, that would be typical, I don't have the specific Cardona profiles in front of me to mark on.

Got you. And then just jumping over to Appalachian real quick. On the helipad you mentioned you are changing the completion on those wells versus the other wells in the area. What exactly are you doing differently there?

We just gone to a little bit denser stage spacing and maybe a little bit more dense profit.

Okay, got it. Thank you.

Thank you, Mike.

The next question is from the line of [Tom Nowak of Advent Capital].

Hey good morning.

Good morning, [Tom].

Sorry, if I missed this. But given the moving parts of Tomcat, Marcellus wells, Cardona, can you give us the evolution of the gas mix over the second half of the year and then through ‘15?

Yes, Tom. I think you’ll see obviously the properties that we sold, the non-core shelf properties were almost 60% gas, 40% liquids. But the volumes that we’re bringing on are primarily the Appalachian volumes which tend to be about 70% gas and 30% liquids. So, I think you’ll continue to see from the second quarter which I think was 51% gas. So, I think you’ll see a slight rise in gas as a percent of the total. As I alluded to on my comments, as the Cardona wells come on and kind of net to Stone would be somewhere around 7,000 plus barrels a day something like that, because we’ve got a 65% working interest. I think you’ll see a flip-flop where you should have slightly more oil and then NGL places liquids than natural gas in 2015.

Okay. Fair enough. And then you’ve got a lot of projects in-house which is great and I do have even in ‘15 with okay liquidity cushion, but it does look like maybe towards the back half of ‘15 you’ll probably need to be considering additional funding. Any thoughts to that yet; is it selling down any projects that you have or you look for additional external capital?

Really, we're kind of entering the back half of this year and really the first half of next year, obviously in very good position. It allows us to really step back and evaluate a lot of different financial options whether it’s selling down some assets, selling some assets, bringing joint venture partners. We've talked about this in the past and we do feel it's important to keep our liquidity and flexibility, especially as we do have a number of different projects that are requiring capital; certainly we got a lot of time to evaluate different options. So, I think as I’d mentioned earlier, we’re certainly in good position now through to certainly well into 2015 and we'll evaluate the different options as we kind of roll into 2015.

Okay.

I’ll just add to that. But our main focus is getting our cash flow up, getting production growing, hitting the good -- a better oil mix as you asked on the previous question.

Okay, great. Thank you.

The next question is from the line of Patrick Rigamer of Global Hunter Securities.

Good morning, Patrick

Go ahead Patrick, your line is open

I am sorry. I had on you mute. Following the shelf sale, it looks like you guys have escrowed the funds potentially for a light kind exchange. You talked about potentially coring up some acreage in the Utica within the Mary Field, can you just talk about what that market is looking like these days and how that might play out with the [Lycon] exchange; is that eligible for [Lycon] exchange or?

Yes, kind of two separate questions. First on the 1031, thought there was effectively a free option; as always, we continue just to kind of look at different opportunities; gives us kind of a 45 day window for few thousand dollars. We can park it as we evaluate different potential opportunities on the acquisition side. So, it just seemed like for few thousand dollars to have what potentially could to be tens of million dollars of tax shield seems like an appropriate financial move. And we’ll continue to evaluate those opportunities over the next month and half. As it relates to acreage, acquisition up in the Wetzel County area and our core area, we do continue to look at adding acreage; it’s very difficult up there, as I think you’re well aware. There is very few larger tracks available, so we just continue within our parameter to try to add on to our four position.

Yes, the other thing I would just add to that is that our strategy is basically organic growth, but we are opportunistic and if an acquisition comes along, this is suggest the tax efficient way to take advantage of it.

Okay. And then on the initial Utica well, you are going to drill vertical section log and core and then drill the horizontal. It sounds like production is not expected until the fourth quarter. Do you think you release any interim data or how should we think about the data flow coming out of this well?

Again, we'll probably truly play that by year, try to get a sense as to the timing of it, does it dovetail for instance with our third quarter release. So again, we will -- when we have that information and that data, we will internally kind of have those discussions. And if go is appropriate, we will move forward with a separate press release.

Okay. And then the last one from me is at the Analyst Day, I believe you talked about some infrastructure upgrades in the Marcellus that could have a positive impact on realizations. Could you give us an update on that? And just kind of what’s going on in terms of the pricing situation there?

Sure Patrick. And on the midstream side, particularly as it relates to capturing better pricing out of the liquid side of that stream, those projects are continuing and have continued. Unfortunately obviously any sort of gains we are getting on cash and higher liquids realizations have been unfortunately negatively offset by gas price differentials up in the Appalachian region. So, I don’t -- unfortunately pricing is very dynamic and so we are taking effectively a small step forward but the gas pricing is causing us to take couple of steps back.

Okay, that’s it from me. Thank you very much.

Thank you.

The next question is from the line of Andy Peterson with Simmons & Company. Andy Peterson - Simmons & Company: Good morning.

Good morning, Andy. Andy Peterson - Simmons & Company: Taking David’s comments about trying to raise cash flow, should we think about you guys accelerating some of your shorter cycle assets like the Marcellus and depending on how this Utica well is tested, the Utica as well?

What I was really talking about is more along the lines of just executing on time, on budget and that sort of thing. And so, I wasn't really talking about bringing anything new into the equation just doing maybe sure, we don't have any delays in production and bringing online the things we've already articulated to you.

Having said that, Andy one of the things I'll add is as we look at our portfolio of projects, we do take into account those projects that have a shorter cycle time versus longer. So we want to make sure that we don't have a bunch of big bets on very long cycle time projects as opposed to what we think is a more appropriate mix. We'll have some deep gas projects which have shorter cycles, we will take some bigger swings such as the Goodfellow type projects. But as Dave pointed out, we want to make sure is that we do execute projects like Cardona where we're able to finish drilling and hopefully that would bring this online within a six months time period is very quick cycle time, if we move forward with the Amethyst project and get that on as quickly as possible, obviously that's where cash flow comes in a little earlier and our net out of pocket capital is just lessened. Andy Peterson - Simmons & Company: That make sense. Thanks guys. And then also you talked about denser stage spacing and a little bit more propane in the Marcellus wells. What inning are we in as far as tweaking the completion design, and could you talk to the other things that you guys are thinking about doing in the Marcellus in the Appalachian region?

Sure. I’ll take a stab at this is a little bit speculative, but there is some interesting technology that’s been applied in some of the other resource plays, where in cross-linked fibers have been used to keep the propane vertically suspended better to try to get a better frac. That technology has not yet available in the Marcellus because the temperature is too cool in the Marcellus. But they’re working on those fibers now so that’s a possibility. Then there is also the possibility of adding a fiber pad kind of as you instead of a put in many stages the pump a set of frac, you pump a frac, then you would pump some fibers to seal off that frac, pump another frac, so you effectively increase the number of stages by putting this fiber pills in there and the fibers act as permeability barriers of course won’t flow through them but they dissolve with time and temperature. And so once they dissolved then you have a better frac than you have before. That’s been used in the Eagle Ford and then some of these other oil areas around the country, as soon as its available temperature-wise we’ll test it out in the Marcellus whether that’s going to result in a 2% improvement or a 20% improvement obviously it’s too early to tell. But I think we’re -- I think the industry is probably in the mid innings on technology we’ve learned a lot but there is still maybe some new things that come down in the pipe. Andy Peterson - Simmons & Company: Perfect, thank you for that. And then one last quick one for me on the NGL realizations, how should we think about going into the second half of the year, obviously Stone isn’t the only operator who has seen degradation in NGL realizations. But do you guys think that we won’t see an uplift until we start getting into the solar season in the winter months and just if you could provide any color on that, that will be really helpful?

I think you just said and I think as we look at the summer months in that low to mid 30s is probably the place that we will continue to see pricing fallout for NGL pricing, I think it will take us getting back into the winter months to have a bit of a rebound on that pricing. Andy Peterson - Simmons & Company: Excellent. Thank you guys, I really appreciate it.

The next question is from the line of Doug Dyer of Heartland Advisors.

Good morning gentlemen. Could you please tell me what the circumstances are led to Goodfella being pushed out for drilling into 2015?

It’s just a rig schedule thing with ENI there, they are the operator and they’ve got rig schedule the projects that they want to execute and it was their decision, it wasn’t anything that we had an impact on.

And Doug I think there is also the bone came back with a second request on their EP that cause a little bit of delay even from Eni standpoint.

Okay. And going back to Pompano and where you're going to be processing your partners or you are coming on Cardona, should I assume into your accounting for that is just straight forward, there won't be any type of offsetting that close to in your income statement when it comes to LOE?

Yeah. Now, you should assume that it is a direct offset to LOE and as Dave made the comment, effectively the dollars that we will get from our partner will be effectively a negative LOE and that's why our LOEs will stay roughly flat, if not down slightly relative to the barrels that we're bringing on for ourselves. So from accounting standpoint, you're not going to see that in the revenue line, you'll see it the contra expense to LOE.

Okay, alright. That's what I was looking to find out. And then when I run the numbers here with your new guidance and going into next year using today's prices, I'm coming up with an EBITDA number where you can do 6.75 next year, it doesn't look like it will take any heroic efforts to get there and I'm not even giving full credit for the production that comes on. And if that’s the case we are trading up four times price by the EBITDA. Do you think that's reasonable number that I'm coming up with 2015?

Yes, we've really stayed away from coming out with any blessing on cash flow or EBITDA certainly a lot of it always depend upon pricing. But certainly to your point Doug we certainly would expect in 2015 to have EBITDA moving up even despite the sale of non-core shelf properties. We do expect that EBITDA number to step up versus 2014.

Alright. Thank you.

Thank you, Doug.

And your next question is from the line of Curtis Trimble of Brean Capital.

Thank you. Good morning, everyone. Just skiing an off of the little detail on the Amberjack platform potentially the initiate activity in 2014. I was hoping you could remind me of well profile and what you expected to define there with the four to six development wells that potentially could start drilling like to share early next year?

Yes let me think we have about four wells maybe five well planned there. These are wells that are in the neighborhood of a 1,000, 2,000 barrel a day type wells, so they will have a positive impact they won’t all layer in at exactly the same time because as soon as we drill one, we’ll put it on production. But it will be a good positive for us and help underpin our base. Ken, anything you want to add?

Yes I think in some of these wells will be under 1,000 barrels a day and you will see some decline as Dave pointed out there will obviously be sequential this is more to provide a good offset to just natural decline more than anything else, this isn’t going to dramatically increase production but provides good stability and particularly good oil production of the Amberjack platform.

Sure…

I think in aggregate, we are going to spend around $75 million there and we are expecting about 2,400 barrels of oil equivalent from the Amberjack program, the Pompano program is a little bigger so about $125 million program and we are expecting a peak rate of around 5,500 barrel a day for it, but Pompano won’t get started until the end of next year.

Right and that just has to do with the availability of the platforms that are capable of drilling off each platform, excuse me, are capable of drilling of each platforms.

Yes two things, one we have some platform modifications underway for both Amethyst and for Cardona, the Cardona will be long finish, but we will be working on the platform a little bit for Amethyst. So we want to get that work finished before we put a rig on there. And then the second is just the availability of the rigs and we expect to have the Amberjack rig available end of this year and Pompano before the end of next year.

Yes. To Dave’s point, I mean the Silver Lining, obviously we would love to have that Pompano platform rig as soon as possible but the Silver Lining has been, our guys have been able to make those platform modifications for both Cardona as well as importantly Amethyst. So, we’ve be given some extra time to do that with the pushback in that rig coming available. So, that would be the Silver Lining as we’ve been able to move forward, particularly with Amethyst.

Very good. Looking up in the Marcellus, can you tell me the number of Utica locations that you permitted? And as you are looking towards that, what you think optimal lateral lengths maybe and the number of frac stages prospectively that you would look to create over that optimal lateral length?

Sure. I’ll give you kind of our early view of it. We have probably less than a handful permits in hand right now. We are working on a development plan, which will drive our permitting schedule. And so, we expect that if our well works this year, sometime next year, mid-year to beyond, we might be in a position to start doing some Utica development. Ultimately, we think it’s going to probably be well over 5,000 feet of our horizontal need there, maybe even longer. So, I mean we’re drilling, I think 5,600 foot laterals in the Marcellus. I would expect that we’ll drill at least that or longer in the Utica if it works, just because you have a deeper zone, you have more expense on the verticals, so to keep the ratio of vertical to horizontal cost and to get the results per well. But that's going to have to be refined over time as we get a little data on what works the best before a program is settled in on. The good news is though, there probably, I don't know there will probably be a dozen or so Utica dry gas wells drilled in the area that will have some entail on not just what we do but what others are doing with respect to horizontal length and completion techniques.

Sure. And prospectively 32 to 35 stages over that 5,600 foot lateral give or take?

I think we’re doing something in neighborhood of 200 to 250 foot stages right now. So if you just divide that in there, give you the stays length, I am not sure exactly what they will work out to.

Very good. I appreciate the detail.

Thanks.

Thanks Curtis.

And there are no further questions at this time.

Okay. Well, thank you very much everyone for joining the call. A little bit of a pick up on the quarter I realize but I think long-term our plans are still intact and that we’re very excited about moving forward. And thank you for your patience and interest in the company so long.

Thank you.

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