Good morning. My name is Simon and I'll be your conference operator today. At this time, I would like to welcome everyone to the Stone Energy Fourth Quarter and Year-End 2015 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. Thank you. Mr. David Welch, Chairman, CEO and President you may begin your conference. David H. Welch - Chairman, President & Chief Executive Officer: Okay. Thank you, Simon, and welcome everyone to our fourth quarter and year-end 2015 earnings conference call. We're joined this morning by Ken Beer, our Executive Vice President and Chief Financial Officer. Ken will read our cautionary statement and review our financial performance. He will then turn it back over to me for an operational update and a few additional comments, and then we'll be happy to take your questions. So Ken?

Thank you, Dave. Let me first 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, development, production, and sales of oil and natural gas. We urge you to read our soon-to-be-filed Annual Report on Form 10-K for a discussion of the risks that could cause our actual results to differ materially from any forward-looking statements that we make today. In addition, in this call, we may refer to financial measures that may be deemed non-GAAP financial measures as defined under the Exchange Act. Please refer to the press release we issued yesterday for a reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures. With that, let me move on. We'll assume that everyone has seen the press release and the attached financials. So I'll focus on some of the key financial and operational highlights. Our fourth quarter results showed an adjusted $2 million of income before pre-tax, non-cash impairment charge of $351 million, which brought the reported loss for the quarter to $319 million. Our discretionary cash flow for the quarter was about $115 million, around $2 per share, although this would be close to $70 million, if you exclude a $45 million expected tax refund, which was included in the calculation. As was also the case last quarter, there was the $351 million non-cash ceiling test impairment, which was primarily due to the lower oil and gas and NGL prices, which are calculated using a 12-month trailing average. Additionally, if the prices in 2016 continue to stay at the lower levels compared to 2015 prices,…

Your first question comes from the line of Dave Kistler with Simmons & Company. Your line is open. David William Kistler - Simmons & Company International: Good morning, guys. David H. Welch - Chairman, President & Chief Executive Officer: Good morning, Dave.

Good morning, Dave. David William Kistler - Simmons & Company International: Real quickly, thinking about the curtailments and the guidance that you guys have provided, in the event that you lift the curtailments, can you talk a little bit more specifically about how that would impact transport and LOE? I know you mentioned that LOE – I mean the transport would certainly move higher, but can you give us a magnitude, and same thing with respect to LOE?

Yeah, Dave, it's Ken. On the LOE side, maybe just a slight increase in guidance. Again, you're not talking about a large absolute number to start with, and there are some – there's still some operating expenses that we incurred even while shut-in. So, small adjustment, maybe $5 million, something like that. On TP&G, again, it will be – it certainly will be a larger adjustment. Some of it is highly dependent upon the type of fees that we will be paying going forward. Certainly the fees that we paid for the first couple of quarters were just not economic, and so we backed off of that. But you can see for the first three quarters of the year, we were about $55 million. So kind of from a run rate standpoint, versus the $3 million that we had in the third quarter and maybe the $20 million that we are providing guidance on, the $20 million really incorporates the TP&G fees on Amethyst as well as the additional production in the Gulf of Mexico. But depending upon when, we would certainly expect to see that number move up pretty significantly, that $20 million TP&G estimate move up pretty dramatically, depending upon when we bring on the Mary Field. David William Kistler - Simmons & Company International: Okay. I appreciate that color. And then maybe switching over to the comments about remarketing of the rigs, and maybe looking a little bit more for specifics here, when you gave kind of the $40 million to $50 million of cost that might be incurred associated with that, I guess $6 million would be associated with the stacked rig up in the Marcellus, and then the balance would be probably more specific to the ENSCO rig. Can you talk about how that shifts around relative to your guidance? Is that balance already incorporating the two agreements that you have in place? Is it incorporating anticipation of another agreement with respect to farming out, just trying to dive into a little more detail there?

Yeah. And even that's a bit of a moving target in that we've got a probabilistic model that we're using. So, you know, this is somewhat of – ultimately it will be deterministically that happen or not. But we do have baked into our assumptions and into our numbers that we would have the farmout that is now going to take place starting, let's call it, March 1, and then followed by a second farmout. And then the back-half of the year, once those farmouts are complete, we'll either have the rig drilling for us at either Derbio or Lamprey, or we've got some modeling that has it as stacked. The $40 million really incorporates the rig subsidy that we are providing for the next, let's call it, roughly six months, as well as some chance of occurrence of just a – of a suspended or a stacked for the remaining four-plus months at a stacked rate. So that's how we come up with roughly $40 million on the other operational expense side. Again, it's – you know, we're looking at somewhere around $240 million-ish as where we stand currently. As we mentioned in the comments, our real push is to get that $240 million down closer to $200 million or certainly approaching $200 million, and there are some steps that we can take, but it's going to – I wanted to make sure that people recognize that some of those dollars are coming out through the income statement, not through capital expenditures. David William Kistler - Simmons & Company International: Okay. I appreciate the added color there. And then one last one. Can you give us any sort of update in terms of what you guys are hearing with respect to the Pemex well and maybe what that's doing with derisking Lamprey or with respect to selling down the working interest there? David H. Welch - Chairman, President & Chief Executive Officer: Yeah, thank you for that question, David. In all candor, we don't really know anything about it. There are rumors floating around the industry, but that's all we're really hearing. The one thing that we are – the one, I guess, positive piece of information that we do have is the rig is still on location. And we believe, but we're not a 100% positive, that they are sidetracking the well, which, if so, might be a positive indication. So, it's a tight hole. There's very little information available about it. We just know from GPS positioning that the rig is still on location. And I wish I could tell you more, but that's really all we know right now. David William Kistler - Simmons & Company International: I appreciate that, and thanks for sharing what you do know. David H. Welch - Chairman, President & Chief Executive Officer: You're very welcome.

Your next question comes from the line of Richard Tullis with Capital One Securities. Your line is open

Thanks, good morning, everyone.

Morning, Richard.

Ken, how much of the $200 million budget, you know -- continuing around on the previous line of questions -- how much of that $200 million budget is directly related to the deepwater rig, and how much does that roughly work out to on a daily basis?

Yeah, so I'll give you just some guidance there. The ENSCO rig, whether it's going to be CapEx or some sort of rig subsidy or stacking charges, we think it's somewhere around $85 million or so for the year. The Pompano rig, pretty similar, about $85 million. Appalachia, $5 million or $10 million. You got seismic at somewhere $20 million-plus. You've got some inventory, that's maybe $10 million to $15 million; recompletions, which is $10 million to $15 million, and then a P&A of roughly $20 million. So, if you add all that up, should be kind of in that roughly $240 million. I've mentioned that particularly on the Pompano platform rig of $85 million, there might be some downward pressure that we can exert there. That assumes, actually, a three-well program. And then the ENSCO rig, again, that roughly $85 million assumes we either are farming out, which we think we've got two farmouts, so that's part of that number, but then after that, as I had mentioned, we either going to – we will take it and drill with it or stack it, and it will – the way that we've got it modeled is we'll have to sell down some working interest, so that we come close to what that stack rate looks like. So, rough number, to answer your question, roughly, $85 million.

When you run the rig, is it in the ballpark of around 7,000 a day gross? David H. Welch - Chairman, President & Chief Executive Officer: Yes. So if you run the rig, the overall run rate is around 800 or so. And of course if the rig is cold stacked, you know, that's a lot lower rate. One of the strategies we're pursuing is to take a small working interest in other people's exploration projects who may not have a rig and then be able to come in at a 10% rate, so that the – you know, 10% of the 800 would be less than the cold stack rate. So that's the angle that we're pursuing there. And then of course there are other farmout potential that we may be able to achieve.

And, David, I apologize if I missed it. What is the cold stack rate? David H. Welch - Chairman, President & Chief Executive Officer: I don't know if we've ever declared that. Ken, have we?

No, we haven't. The stated rate – the working rig rate is about 340,000 Boe a day. But certainly the suspended number, suspended – if we decide to just suspend drilling on the rig, it certainly drops from there. David H. Welch - Chairman, President & Chief Executive Officer: I think we probably have a confidentiality agreement preventing us from disclosing that exact number.

Sure. Sure. I understand. The 2016 production guidance, could you roughly split that percentage-wise by area?

Yeah. It's pretty simple. It's pretty much all Gulf of Mexico except for, you know, roughly 20 million cubic feet equivalent from Heather and Buddy up in Appalachia.

Okay. Okay. Speaking of the surety bonds that you may need to put in place for the Gulf of Mexico, what would the potential cost of that be, Ken, and is there enough availability out there for that?

It's a good question and that's why I bring it up and that we honestly don't know those answers very much in limbo. There, we've been able to secure some surety bonds. We proactively actually this past year, we proactively went out and we've got a couple of $100 million of surety bonds already utilized. Our cost for that would – just for the current $200 million is probably $3 million or $4 million, not a big number. And if we had to double or increase by another $200 million or $300 million, certainly the expectation is that number would go up, but, Richard, hard to know exactly what that would move to. Its just – it's a very dynamic market. But to date, we've had a pretty good experience in both securing bonds and securing on that at least what we think are appropriate pricing.

That's helpful. And just lastly from me, Ken, what working interest would Stone look to reduce to, say, as acceptable range for the deepwater exploration wells, Derbio and Lamprey, Rampart versus the current 100% interest?

Yeah, I'll just say we'd probably ideally like to get down to 25% to 33% range with some kind of an industry promote (32:27). David H. Welch - Chairman, President & Chief Executive Officer: And to that, if you look, if we can get down to a cost basis of roughly 25% in that that is somewhat close to or in line with what the stack rate would be. So that's kind of why we figure we can target in that 25%, 30%, then we'd certainly rather be drilling than stacking.

That's all from me. Thank you.

Thanks.

Your next question comes from the line of Marc Kaufman with Institutional Equity (33:09). Your line is open.

Good morning. I was looking at the differential on oil in the fourth quarter. Was that a negative differential or positive? And I was wondering what you're thinking about for this year?

Yeah, the differential still (33:33) was certainly slightly negative in that we've got – we had some – our WTI – I mean, relative to WTI, we get a positive in the Gulf of Mexico, but any volumes that we get in Appalachia, which in the fourth quarter was small, would certainly be a negative. So in the fourth quarter, you had less of a differential than you would have seen in the third quarter, second quarter, and first quarter, because we just didn't have the Mary Field flowing. But the differential LLS versus Henry Hub has been positive by as much as – this past year, as much as $3, $4. It started to reduce in the fourth quarter and even now is just really $1 to $2. And then as I had mentioned, up in Appalachia, much more severe discount.

Certainly. A question, if I missed it, interest expense capitalized for this year, is that included in your CapEx number or is the CapEx number a cash number?

It's excluded from the CapEx number.

Thank you.

Your next question comes from the line of Jon Evans with JWEST. Your line is open.

Hey, Ken. I know you have a lot of moving parts with the CapEx, but, you know, if you assume kind of the guidance comes in where you thought with CapEx and the strip stays the same, where – how far do you think you get into the revolver?

Yeah, again, I probably won't come up with a number, but I think it's certainly the case that we will have to go into the revolver. We are $50 million into it, really, here in the first quarter, albeit realize in the first quarter, we had the Cardona well that we were drilling and we had Pompano that we were drilling, so any sort of pullback from those two which we would expect starting March 1 for the ENSCO rig and even with the Pompano rig in the back-half of the year, we certainly could look to pull back and stop drilling there. So, we certainly are looking for the facility to provide the gap between cash flow, but the exact number is indeed a moving target.

Okay. And then from the standpoint of the tax refund, the $25 million that you're going to get for 2016, do you know roughly when you'll receive that, and then will you receive the $20 million for 2017 also in 2016 or is that in 2017?

Again, this is the government coming back to us where we think we would have about half, or let's call it $25 million sometime in the summer, and then the remaining $20 million either late this year or maybe the beginning of 2017, we really don't know. It's probably important to at least recognize that there's roughly $45 million that is cash coming back to us that probably folks did not have in their model, but that we would expect to receive sometime in the next, let's call it, 12 months.

Got it. And then, can you just – can you talk a little bit relative from the standpoint – I'm sure you saw Gastar's news yesterday selling the piece, and that's kind of right where you guys are in the Marcellus, if you put that same kind of valuation, you guys would get somewhere between $250 million and $300 million. I guess, is selling assets or getting out of the Marcellus an option to help your liquidity, et cetera? David H. Welch - Chairman, President & Chief Executive Officer: Yeah, let me take that one. It's Dave. I think the best way to say that is that all options are on the table right now. I will say that long-term we love the Appalachia asset, that we feel like there's a lot of gas there. Our acreage is right in the core of the core. And doing some type of joint venture in Appalachia is something we've long contemplated, and we're certainly considering that along with all the other options right now.

Okay. And then just – you've had this on your slide before, the infrastructure sale leaseback. I mean, Pompano has got to be worth at least $300 million. Is that something you guys are still broaching or not?

Jon, it's out there. It's a bit more complex and really would have some ramifications on both the credit facility as well as the borrowing base itself, because all those reserves are tied to the facilities. And so, yes, it's out there as an option but it looks to be at least a relatively complex option at this point.

Got it. And then the last question, I'm just curious, I mean, are you guys trying to prepare for a pre-packaged bankruptcy? I mean, if you look at the converts, they're roughly trading it with about $168 million in value. The other bonds are $217 million roughly, so that gets you to $385 million. You've got $50 million out in cash. I mean, if you look at St. Mary's and you look at the platform, I mean, that's – we're $600 million alone, you get the oil for free. So do you feel like the bondholders are trying to push you into a pre-packaged?

Look, as Dave pointed out, we obviously are looking at a wide spectrum of a lot of different options, because in this environment, you need to look at everything. And as I had mentioned, we're looking at restructuring, we're looking at asset sales, we're looking at what else we can do to address what is clearly a very, very difficult environment from a pricing standpoint. But as I also mentioned, we really have not made a decision as to kind of our next step. So that's clearly something that management and ultimately the board will be contemplating.

Okay. Two last questions. Just from the standpoint, do you know – do you have any insight into when – you'll know back from the bank roughly if you're going to get some kind of amendment?

Yeah. So we actually have been in discussions with our bank group. Truly over the last four weeks, things have shifted around where we're looking at a different structure on the amendment and kind of shifted to a plan B with our discussions. And really just recognized that we weren't going to get something done before the conference call and before the 10-K. So those are conversations that we will look to resume sometime probably into this week. But I don't have a sense of timing but recognize we're not out of compliance. We're fine through the year-end and therefore through the first quarter. And actually it's pretty close as to what our total debt-to-EBITDA number looks like at the end of the first quarter. But our thought was, let's be proactive and at least have some of these discussions with the banks now.

Okay. One last one, I promise, just – and maybe don't want to answer it, but I mean do you guys plan on paying the interest in the convert in 31?

Yeah, again, we'll look at all options, but I'd certainly recognize that's coming down the pipe next month. And realize...

So is that a yes or a no?

Well, I just – I mean, realize it's not a big number. I mean, on the converts, it's not a big number. It's a couple million dollars. So – but again, we'll be reviewing everything.

Okay. Hey, thanks for your time.

Thank you. Take care.

Your next question comes from the line of Ron Mills with Johnson Rice & Company. Your line is open. Ronald E. Mills - Johnson Rice & Co. LLC: Hey, guys. A lot has been asked. Just curious, Ken, on your borrowing base, any sense as to how much of your $500 million borrowing base was supported by Appalachian basin and how that might have been impacted by the year-end reserves related to price revisions?

Yes, a fair question. So this is now going back to June, so that's what the fall was based on. You still had Appalachia as actually a pretty small component of the borrowing base calculation, just because even back in June, the PV-9, which the bank goes off of, still was looking at pretty low prices, but certainly there was some value, so I don't want to say it was zero. It was just reduced. Obviously at year-end 2015, from a SEC PV-10 standpoint would suggest that there's virtually nothing in for Appalachia at year-end. As to what the bank, Ron, will look like, there will be some value, but it will certainly be a reduced, even from mid-year, Ron. So, the borrowing base from a MAP (43:49) standpoint is primarily weighted towards the Gulf of Mexico. Qualitatively, I think, the banks recognize that Appalachia does provide very long-term stable reserves over many years, and so that we probably get some qualitative value out of Appalachia being there. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. And then, to get down to the $200 million, obviously you would have to be forecasting some sort of sell down in either Lamprey, Derbio or Rampart; did I hear you correctly? David H. Welch - Chairman, President & Chief Executive Officer: That's right. I'd say, there are several things that we're investigating. One is farming out the rig, and there are certain circumstances where we may be able to use our infrastructure, so we don't have a subsidy, so that would be a big help. Second thing is just selling down our interest in a couple of these wells that would be tied back to Pompano and not just Derbio, but Rampart is another oilier prospect, which is only a few…

Yes. So, in the way our model works, there is a placeholder but it's a synthetic placeholder with a little bit of Lamprey in there and a certain working interest and a little bit of – I mean, Derbio at a certain working interest. And both of them rest versus just stacking the rig. So it's a synthetic placeholder, it's probably the best way to put it. Ronald E. Mills - Johnson Rice & Co. LLC: And then just to try to get some clarity on the flexibility, particularly around Pompano, you've done a workover, you're drilling a first development well. It sounds like you have at least one more development well that you have to do. And then, at that point, what would the steps be or what would be involved and what would the impact be if you ended up not drilling the third and/or the fourth wells at Pompano?

Yeah. We can pretty much just stack the rig in place, on location, on the platform, and take a breather. I mean, it's just very minimal charge for doing that. Actually even the contract provides for us to just hold on to the rig for some number of months. And then we can just monitor both our cash position as well as, quite honestly, the price of oil. So that's probably the biggest single lever. As I said, we have about $85 million projected for the Pompano platform rig, and certainly that is an area that could get pulled back if we elect just to stop after this next project. Ronald E. Mills - Johnson Rice & Co. LLC: And including the cost of the workover, I don't know how much that was, but that lever seems to be somewhere in that $30 million to $40 million range?

Yeah, probably closer to the $30 million, because there's still some things that we'll end up spending some money on, but, yeah, let's call it, roughly $30 million. Ronald E. Mills - Johnson Rice & Co. LLC: Great. Everything else was answered.

Yeah. Ronald E. Mills - Johnson Rice & Co. LLC: Thanks, Ken.

Thank you, Ron.

Your next question comes from the line of Jeff Robertson with Barclays. Your line is open.

Thanks. Ken, can you talk a little bit more about bonding requirements for the BOEM and if they come back and tell you, you need more bonds, how long does that take and is there a chance that to get the bonds or to get the bonds and could that cause any kind of disruption in either current operations or what you all plan to do?

As I indicated, still a bit – it's still a bit unclear because we just don't know, but the steps would be, we'd meet with them. We've actually been very proactive. We've met with them and communicated with them continuously. So I think we've got a fair amount of goodwill going to just this upcoming year. We'll walk through where and how much bonding would be required, and then put forth a plan in place. There have been other operators that have preceded us. There's at least a couple who have been working with BOEM for really – virtually most of 2015 and now into 2016 to try to layout a security plan for them, because it doesn't all have to be bonding, it can be some other forms of security. So we will look to certainly meet with BOEM. We've been in communication with them, but we really don't have anything that says right this moment exactly what our position – or what they see our position to be right now. But we're just trying to be transparent and at least make sure that people recognize during 2016 we'll have to address some bonding issues with BOEM.

And either Ken or Dave, can you all talk about what the market is as you go out and look for partners in some of these prospects like Lamprey? What kind of market it is that have the terms of what you might be able to expect on a promote (50:44) changed much in the last year? David H. Welch - Chairman, President & Chief Executive Officer: Yeah, I would say, the market generally, Jeff, has degenerated where it's tougher to get promotes. If you have a special situation though, like Lamprey could be, I mean, the whole principle of Lamprey really hinges more or less on what we see at Tiaras, because we think – and we're not 100% confident yet, but we think that the Tiaras well and the Lamprey well are the same prospect. They're just at the southern end, we're at the northern end. And so if they do in fact make a discovery, then obviously our well becomes more like an appraisal well rather than an exploration well, and that will open up a lot of potential partners for Lamprey. On the Derbio, Rampart piece, the attractive feature of those is that they are only five miles away from infrastructure that we own that has additional capacity. So they're a little bit unique from a regular type of prospect that if you were just going out to try to sell in a market, but the market is somewhat limited, but there are some people that have money and want to deploy those resources in good projects. And we think that those three are all good, or we hope that Lamprey is good and we think Derbio and Rampart are good prospects. I don't know if that's helpful, Jeff, but...

It does. Thanks.

And there are no further questions at this time. I turn the call back over to the presenters. David H. Welch - Chairman, President & Chief Executive Officer: Okay. Thanks, everyone, for participating in the call. We'll end the call. So long.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.