Good morning. My name is Kim, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter 2013 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) Thank you. Chairman and CEO of Stone Energy’s Mr. David Welch, you may begin your conference.

Okay. Thank you, Kim. And welcome everyone to our year end conference call. Ken Beer, our CFO will begin the meeting this morning with our Safe Harbor and review of our recent financial performance. He will then turn it back over to me for additional comments and we’ll then have a Q&A. Ken?

Thank you, Dave. Let me start with the forward-looking statements. In this conference call, we may make forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to all of the risks and uncertainties normally incident to the exploration and development, and production and sales of oil and natural gas. We urge you to read our soon to be file our 2013 10-K for discussion of the risks that could cause our actual results to differ materially from those and 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 the -- these financial measures and the most directly comparable GAAP financial measures. Again, rather then go through the year end results in detail, I will assume everyone have seen the press release and the attached financial, so accordingly I will just focus on some selected items on this call. First, our discretionary cash flow for the quarter was $142.5 million or about $2.85 per share and adjusted earnings for the quarter were $27 million or $0.60 or $0.56 per share both pretty much around the first call estimate. The fourth quarter and year end results had two previously disclosed one-time items, which did impact the final net income figure. First, the $27 million expense related to the early extinguishment of debt tied to the tender and redemption of our 2017 senior notes in November. This was part of the refinancing strategy of retiring the $375 million 8.625% notes due 2017 and issuing $475 million an…

Okay. Thank you Ken. 2013 was an excellent year for our company and its investors. Our common stock increased over 65% value during the year and given our opportunity set, we believe there's potential for more to come. To summarize the year’s operations, we were able to grow production by 10% in a year where we first expected production to be flat. This is a result of strong delivery by all of our business areas and our people did a really great job of execution. This helped to increase discretionary cash flow which fueled our capital program. We were also able to grow proved reserves by 12% which also exceeded our plan. Almost equally important, our net prospective resources increased from 250 million barrel of equivalence to 465 million barrels equivalents which is a good leading indicator of our ability to continue to grow reserves in the future. We've achieved an average compound proved reserve growth rate of over 20% per year since 2009. And we continue to add to our inventory of exploration prospects which provide us with significant additional reserve exposure. In 2013, we’re also able to reduce LOE by $14 million as we gained economy as a scale in Appalachia and paid close attention to cost in the Gulf. So all in all, this is an excellent year for Stone Energy. The current year feels even more exciting. Already we’ve made two discoveries in our first few exploration prospects of the year, Amethyst and Tomcat. Both of these prospects were drilled at a 100% working interest and both are within 5 miles of 100% owned Stone infrastructure. We expect to add Tomcat discovery on production later this year at an estimated rate exceeding 10 million cubic feet a day and are studying the reserve estimates and development…

(Operator Instructions) And your first question comes from the line of Dave Kistler with Simmons & Company. Your line is open. Dave Kistler - Simmons & Company: Good morning, guys.

Good morning. Dave Kistler - Simmons & Company: Real quickly, looking at the production mix in Q4, it looks like oil slipped down a little bit. I’m guessing some that maybe weather-related, don't know exactly but can you talk about how that oil mix looks going into Q1, and then call it 2014, maybe 2015 as well?

Yeah, Dave, it’s Ken. In the fourth quarter, you had the numbers a little bit biased by the catch-up volumes with the royalty relief which is all gas. We also had to catch-up up in Appalachia with the working interest, the final working interest adjustment, which again was mostly gas. So, I think you had a bit of a shading towards the gas side and also did have an increases out of Appalachia, which is again a little more gassy. In 2014, I do think you'll have a bit more gas kind of in that 52 plus percent type of a range because the growth is more on the Appalachian side. I would flip that around as we exit the year in the Cardona project comes online, obviously that is all oil. I think that's where you see a pretty big shift the other way as we enter 2015. Dave Kistler - Simmons & Company: Okay. I appreciate that. Then maybe switching over to cost side of things, LOE was obviously very impressed within Q4. When I look at full year ‘14 guidance, it looks like it starts to creep back up. Can you talk a little bit about what might be changing there that's driving it higher again?

Yeah, it should be pretty flat pronouncedly. I think the Appalachia is going to be relatively flat even with -- on an absolute basis even with arising volumes and it will trend up very slightly. And I think in the Gulf, our guys have done a good job of just keeping LOE as flat as possible. As you know, you do get some swings in the Gulf of Mexico just as it relates to major maintenance projects. It was typically or more in the second, third quarter. And so it really fell off, I guess in the fourth quarter. But the thought of the goal here is to come in somewhere around that $200 million mark again for 2014.

Just in general, Dave, on the LOE, our operational guys have got very efficient up there. The LOE cost has come down dramatically. We are probably getting to the point where we've achieved what we can do there. But in deep water, when Cardona comes online that's going to be done with fairly low incremental OpEx. So we should see a nice oil production increase with very little cost impact of that. So that's very important project for us. Dave Kistler - Simmons & Company: Okay. And if I look at your, kind of longer term guidance that you provided in some of your slides previously, with the success at Tomcat and with the success at Cardona, can you talk a little bit about does that influence that full year ‘15 production guidance higher, can you kind of give a little range, I guess between maybe 45,000 Boe a day to maybe 55,000 Boe a day? Can you -- does that help push that towards the higher end?

While there are so many other things, certainly those will help to push towards the higher end. There are so many other things going on and we are reluctant to put out any updated forecast right now. But in general, the way we put our multi-year projection together is with a risk factor on the success of projects and if you derisk them, we should get a bias upward on those particular projects. Ken, anything you want to add?

Yeah. I mean, you did highlight certainly for 2014, there is a chance of having some incremental volumes at tail end, certainly from Tomcat, which we would certainly expect to have on. We might actually get help in terms of exit rate with even the Cardona project if it comes on little early. So, again, as Dave pointed out a lot of it’s risk-weighted, but there are a lot of other factors that go into those longer-term projections that as you know, you can we’ll certainly change overtime. Dave Kistler - Simmons & Company: Great. I appreciate that. One last one just as you talk about testing the Utica, if it is successful, do you feel like you have enough transport in place up in the northeast to avoid any kind of bottlenecks there or you actively out trying to get more transport, just trying to get color in terms of how that might unfold?

Yeah. Our Appalachian guys are looking into just that, Dave, certainly with the Utica really coming on to the stage very quickly and with very high rates, that is an issue. As you know, we’ve got the Williams pipeline that comes through acreage. There are some other pipelines that come through that area. We tie into the TETCO line, which at least now has a fair amount of volumes. They can export volumes either going up to the northeast or actually can even be backhauled back to the Gulf Coast. So it is something that we are looking at and need to look at, particularly as we are talking about we could be enough for the area some little step-up in volumes. Dave Kistler - Simmons & Company: Great. I appreciate the additional color, guys. Thank you so much.

Thank you.

And your next question comes from line of Michael Glick. Your line is open.

Good morning, guys.

Good morning.

Just had a question on Amethyst, I was wondering if you could maybe walk us through kind of what you saw versus your expectations and kind of how it affects your view on other prospects in the area?

Well, I will just take a general stab and Ken may have some additional color. We found about the amount of pay that we were anticipating in well. It was a mild surprise I would say a complete surprise that it was more gas than oil. But it may have some implications for some other prospects in the area that, now that we understand what the seismic signal is telling us, we can take that to other prospects and applied that to better differentiate what we might be looking at on some of our other prospects such as Derbio and others that we are looking at within that overall area.

Yeah. And certainly the fact that it’s gas in Amethyst as you go to the east, it maybe a different high -- it might be oil in a different in a row. As you go to some of these other prospects as Dave pointed out, I mean, just understanding seismic signature was certainly important for us. This is an area as you know, Mike, that we control a lot of acreage, we’ve got a lot pf prospects in this area. So this was certainly a positive. Having a success here was certainly something that was helpful for us. It was 100% wells, so the idea of being able to take this 100% well and bring it back to the Pompano facility, whereas Dave pointed out earlier, virtually no extra costs will be involved in actually the hookup of gas, well, subsea is actually an easier process of project than oil over the long-term. So that might provide us with an easier solution as to relates to the development project itself.

Got it. And then shifting to Mica Deep, kind of in the success case, when could you get that project online, assuming a tieback to Pompano?

Well, they were actually two or three scenarios of how you might tie it back to Pompano and that would give you a range, I would say where from 2016 to 2017 or so, if it’s a tieback. Of course, there is also the outside possibility that's large enough to require zone structure and that would be a different game if that's the case.

Although even though there you might have initial.

Tiebacked up

Tieback with other two.

With other two, right.

Okay. Got it. Thank you very much.

Thanks, Mike.

And the next question comes from the line of Jeb Bachmann from Howard Weil. Your line is open.

Good morning, guys. Just a couple quick one to follow up on the production numbers, Ken, could you give us what current Pompano volumes are?

I want to say somewhere about 1,000 barrels.

So is that off a little bit from the peak you saw in ’13?

We’re going to see some very slight decline over the year, but it’s one of the real beauties with both Pompano and Amberjack is unlike most Gulf of Mexico decline curves that you think about and talk about which might be 30% or 40%, these are really closer to 8% or 10% decline curve or so and we are trying to continue to do some well work that will keep those volumes relatively flat through the year before they can hand the baton off to a Cardona volumes coming on.

Okay. And Dave…

Yeah, I am sorry, go ahead.

No, go ahead, Ken.

Yeah, but again from -- I don’t see Pompano or Amberjack for that matter having a steep decline this year to be relatively flattish.

Okay. And moving over to Cardona, I just wondered Dave if that exploratory tail that you are targeting, if that is looking to prove up another prospect in your current inventory?

Well, this would actually be one of the prospects that we have in inventory depending what we find, it maybe something that could be chased elsewhere. It’s not something that we think is necessarily prospective at the Cardona South well because due to salt and everything, it’s -- that zone will be diving beneath the salt and a little deeper. That’s not to say that it wouldn’t set it up, but this is not a high success rate test that we’re looking at down there, but we are only about 3000 feet away from it. And while we are that close, it’s worth taking a look at it. And if it does hit something, I am sure there will be other places that we will be able to follow it and maybe pursue a development program elsewhere. But the good news is that if it does find something completely new in the area depending upon what it is and how large it is it, it might be sizeable enough to take a completion and that would potentially give us another well at Cardona, at Cardona North.

Okay. If I heard correctly, you’re not going to be testing this target in the Cardona South well?

That’s correct, just the north.

Okay, got it. Thanks, guys.

Thanks, Jeb.

And your next question comes from the line of Matt Portillo from TPH. Your line is open.

Good morning, guys. Just a few quick questions for me. I guess starting off on the Marcellus, I was wondering if you could give us an update to your thoughts around downspacing? And then just as kind of the industry continues to move towards reduced cluster spacing, I wanted to get some color on how you guys are thinking about completion techniques in the play?

Sure. We always keep an open mind and try to monitor what’s going on in the industry. I think on average we have about a 750 foot spacing right now. There are some folks that are going down to 600 or even 500. We are watching those results closely and we are trying to model our wells to get the economic optimum and there is trade-off between cost and additional rate of reserve. So we are very active watching that. We will probably do a little bit of experimentation with a little bit tighter spacing between wells within a next year or so and we are also in all likelihood going to slightly reduce the stage length of our fracs. And so both of those will have the effect of raising the cost a little bit, but they will also potentially give us higher reserves as well as higher rate. So we are just searching for that economic optimum, but that could -- if we went from 750 down to 600 foot spacing, obviously that would add another 13% or 14% to our well count.

And then, I guess just as you guys have tweaked completion techniques throughout the year and tightened up some of the stage spacing. So I was wondering if you could give us an update on how you are thinking about kind of your more recent EURs in the wells or how does it performing relative to tight curve you previously presented?

Sure. We are going to probably go into some pretty good detail on that in the -- on our Analyst Day, but just for now what I can tell you is that we’ve looked at our production relative to other companies such as Range and others that are in the area and we are right in the same performance range that others are seeing. There are different ways people report reserves with ethane or not ethane and see you might see some big difference in EURs that are just according -- that vary because of the methodology. But when you lay the curves over one I know, we are pretty darn close to most other to other operators that are in the superrich area which means that over time we would expect that we may see some continuing heads to our reserves on a per well basis, ever decreasing amount over time. We’ve had a little bit of upward revision this year. We will continue to expect that over the next year or two. Ken, I should add to that?

No, I don’t.

Great. And then the last question, obviously the Utica looks pretty exciting given some of the offset wells you guys are seeing. As the play ends up performing as expected, how do you guys think about potentially financing some of the accelerated drilling across kind of the Marcellus and Utica or how should we think about that asset within the context of your portfolio over time?

First, let me just say it’s a great problem to have and hopefully we do face it in. We do have a lot of options on. Ken, you might want to mention a couple?

Yeah. And again, as you know it is early days here with this play. It’s something that we will have the luxury of kind of watching some other folks and what happens with their wells. A least for now we are looking at the single well to be drilled in the second quarter. Realistically, I would not look for us to have this huge ramp up in 2014 as opposed to may be thinking ahead to 2015 and then truly that between now and a year from now, we will look at a lot of different options if and as this play really materializes. As Dave pointed out, great problem to have, and again we will look to highlight how we would finance more aggressive Utica program once we feel like we’ve got the data to start going at the well.

And just a couple of things. We have never JVed our Marcellus acreage or our Appalachian acreage yet, so that’s one arrow we would have in the quiver. We’ve now started to build a track record in deep water where we could potentially do a JV in deep water. So there are number of levers, including what I will just call self help because one thing that we can do and it would greatly influence the financing needs in the futures can we get things online sooner. And so, we’ve challenged our teams to get Tomcat online as soon as we can and the same thing with the Cardona project. And hopefully, we will be able to beat the dates that we have established for those targets.

Great. Thank you very much.

Thanks.

And your next question comes from the line of Chad Mabry from MLV & Co. Your line is open. Chad Mabry - MLV & Co.: Thank you. Just looking at your slide on Cardona, wondering if you could provide some more color on where you think the Cardona’s discovery shakes out as far as your original expectations and then maybe what the exploration tail could potentially add there?

Yeah. First of all, I want to downplay the exploration tail a little bit because the only reason we’re really looking at that is because it’s only 3,000 feet deeper than where we already have drilled. And it’s probably not the kind of prospect that would justify drilling 15,000 to 20,000 foot well, but for 30,000 feet, it’s worth testing. But on the original estimates of Cardona, I would say that we are very pleased relative to our initial estimates. We had a wide range on that and we’re coming in and what we think is a very high economic return range. So we’re pretty pleased with that.

Yeah, Chad, I think we had out there that the two wells together the range was 2 million to 18 million barrels. So we cut that in half, 1 to 9 and our thought is that we’re pretty much right down the middle of the fairway and this is all. And as Dave pointed out, I think from an economic standpoint, we got it right where we want it. Obviously, it would rather always have it higher. We’ve all seen the AT&T commercials, more is better, but this is pretty much right what we’re looking for. And again, we’ll shift over to the Cardona South, which probably has a slightly higher chance of being on the upper end of that range if successful. Just the volume metrics might suggest it would be, maybe slightly higher if the same interval is filled with oil. Chad Mabry - MLV & Co.: Okay. And then just, I guess, similar question on the cost side, where are you -- have you shaken out versus the $54 million estimated well cost and then how much incremental infrastructure spend do you have remaining?

Yeah. On the drilling we’re actually making really good progress on the drilling side occurred. At Cardona, we have got an approval from the government to do what we call a stack hop where we move from one well to the other without having to pull the BOP to the surface and so that saved us about 14 days, which at these spread rates is about $14 million over the two wells. So we’re pretty pleased with how that’s progressing so far. And on the infrastructure side of it, we’re pretty much on target. I would say, we’re on schedule and on target right now with the flow-line loop. And just to remind everybody, one other things we’re building in that flow-line loop is the capacity for two additional wells, two at the Cardona well and two at the Cardona South well. So that we find something and we need to tie another well at either those locations we can do so or we can use one of those for the tieback of an exploration well. As you know, we have a lot of exploratory projects in that area.

And just on that point, again, just having that infrastructure, as they point out, it allows us to either tie in a well or tie in another system, they can come through this whole Cardona loop system. And it does highlight the value of this Pompano facility because from the timing standpoint, where you able to hook up very quickly and not have to worry to build the facility and so from a cost standpoint where you have the awarded cost of anywhere from a $0.5 billion to $1 billion. We’ll be able to leverage that facility for a number of years because as you all know it’s rated at 60,000 barrels a day and we’re only going through about 5,000 barrels a vessel. So plenty of capacity available to us. Chad Mabry - MLV & Co.: All right. Thank you.

You bet.

And your next question comes from the line of Richard Tullis from Capital One. Your line is open.

Hey, good morning, everyone. Ken or Dave, the initial Utica test plan for Mary field, what are your initial design plans for that well lateral length? Will you do the resting period? Just kind of trying to figure out the timeline here for when we might get some results?

Yeah, I think it’s going to probably be pretty late in a year. The rig that we have for the Marcellus, we think would be a little bit of a stretch to get the Utica wells, so we’re having to get another rig and that’s going to take a little bit of time. So I wouldn’t expect that we get the well spud until late in the second quarter maybe. Then, we’ll drill it probably about the same vertical, I mean about the same horizontal link that we have o Marcellus wells. So, that’s about a 5,000 foot, give or take a few 100 feet. And then get our frac crew over there and frac it, getting it online late in a year or get a test late in the year.

The pad that we are drilling that from at least right at this moment, it doesn’t have the pipeline connection to it. Again, the idea was if this was going to drill a handful of Marcellus wells as well as the Utica well and we’re going to dovetail and have the frac crews coming with all of them at the same time, just as the pipeline is there to accept it. So we’ll have to certainly need that obviously pipeline there to flow the Utica well into and that might be the critical path item for us.

I would like to have the Utica test yesterday, but we also have to exercise the discipline of maintaining the economics of our ongoing program. And so that’s what Ken’s talking about doing this simultaneously. So just bear with us a little bit.

Sure. You may have mentioned this I apologize if you did. What your current development cost estimates for the recent discovery, Amethyst, Tomcat etcetera. Just is most of that incorporated already in your 2014 guidance, would you expect to spend this year on the development?

Yeah, Richard, kind of 825 is really is a good starting point. It will certainly get pushed up by some projects and also push down by projects, project that don't works and if you have a well that doesn’t work, then you won’t have the follow-up development costs associated with it. So we do everything on a risk basis and feel like at least for now, the Tomcat development and even the Amethyst development cost, we’ll look to absorb in that number. The Tomcat numbers is not a big number, it’s literally a mile. We’ve got that facility and platform is ready. It’s probably $5 million or something, $5 million, $10 million at most. Amethyst is a little different, but I think certainly you would expect and you point us to do a lot of fun in engineering just to make sure we know what we’re getting into before we just start spending money. So it could be that it's really more back half of the year before we even start to spend some real money on that. So from a capital standpoint, it might not be as big of a mover in 2014 but could certainly have some implications in ’15.

And the one thing that we’ve not spoken about which is not really a ‘14 issue in total, but it starts late in ‘14 and continues into’15. It’s just the platform development programs that we have both at Amberjack and Pompano. These are going to be some of the most lucrative estimates that our company is going to be able to make. We have about four, five wells at Amberjack that can be drilled starting late ’14. We have the rig lined up for that. We also have a rig lined up for the Pompano program, which we’re trying to choreograph with the tie in of all of Cardona, Amethyst and the platform drilling. It’s at a certain point, you don't want to have too many simultaneous operations going on. At the same time, you just can't physically do it. So we want to make sure that we create the opportunity to get our platform rig on Pompano at pretty much as early as we can get the rig. And those are the prospects that are offsetting and just going up different wells that produce anywhere from 5 million to 20 million barrels each. So there are low risk wells, high rate wells and fairly inexpensive to drill since it’s much, much deeper to drill from a platform than it is from the floaters.

The Gulf of Mexico non-core shelf assets that you still have up for sale, what’s the rough current production of assets and oil gas split?

So I want to say somewhere around 40 million a day equivalence mostly gas, probably now approaching I would think 65%, 70% yes. We sold off the two onshore properties (inaudible) and that was about 2,500 barrels a day and that was mostly oil. And again, the remaining part of the non-core assets are really all in the offshore.

Okay. And then just lastly, getting back to Mica Deep, what’s the pre-drill cost estimate on that well and what are your time expectations?

Its about $100 million well, give or take few million here and there which is not trying to be flip but its in the neighbourhood of $100 million and just one thing to be reminded of, we have a 35% cost interest in the well. So we will only be paying 35% of the cost but we will have a 50% working interest. So we were able to promote our partner into this well given the strength with the prospect and offset blocks that we own the 100% of it.

Okay. That’s all from me. Thanks so much.

Thanks.

(Operator Instructions) Your next question comes from the line of Curtis Trimble from Global Hunter. Your line is open.

Good morning everyone. Thanks for taking the question. Just looking at the Cayenne prospect that you mentioned and then follow up with South Erath and La Montana, possibly Pumpkin Ridge, can you give me an idea of what you're looking for either in terms of commodity price environment or success out of Mica Deep, Derbio, 21 Harrier, et cetera? What it would take for you guys to move South Erath, La Montana and/or Pumpkin Ridge on to the 2014 docket?

Okay, let me just start with the South Erath. That one is one that we do not operate. So that one, the timing of that is going to be contingent when the operator gets the whole well ready to go. So that one could conceivably be drilled in 2014. Pumpkin Ridge is one of these ultra deep type of projects. Its not as deep as the stuff offshore but its more like the Lineham Creek type well that Chevron has made a discovery. And then that one was probably going to be 15, there is no way that we would accelerate that into ’14. And then the La Montana is one that we spent the last several months getting complete control of that prospect. We now have a 100% ownership of it. And so we are going to want to find our partner that we can promote into that well and so that one does have outside chance that it would come in toward the tail end of the year but our most likely scenario is that the Cayenne well gets drilled and then potentially the South Erath. So that’s our likely deep gas scenario for this year. Then the reason we have the deep gas in the portfolio is that these are mostly onshore drill them and get online quick and even time gap which we discovered this month. I am pushing the guys try to get it get online in the first half of this year. No promise on that but that's what we're trying to do.

Good deal. And looking forward a little bit, 2015 beyond, providing that you've got expected success in the Utica, can you talk a little bit about preliminary discussions as to how you would blend Utica program in with the Marcellus program potential for stack laterals, things of that nature?

I think we are just on the -- we are like a kid in the candy store with that. We haven’t quite decided which pieces of candy we would want to buy and what order we would want to eating them. But certainly there is a good combination of having some dry gas mixed in with where our wet gas is. You could even potentially get some synergy by using some of these higher pressured Utica gas, as gas lift gas for some of our liquids to help maintain the liquid rates from our Marcellus. So there is a lot of synergy to be captured from that. If this pans out, our envision that we would be looking at and this is not a guarantee but we return to be looking at adding to our rig inventory up in that ledger.

Good deal. I appreciate the color.

Thanks, Curtis.

And your next question comes from the line of Brian Kuzma from Sitcom. Your line is open.

Good morning guys.

Good morning, Brian.

Hey, Brian.

I think as we're kind of talking down the exploration component here at Cardona -- but is the aerial extent of that prospect significantly larger…

Its in a contained forward block to that we are in a Cardona north well. So the area of extent isn’t huge however I don’t want to downplay the result of our Cardona discovery or our Cardona well because as Ken mentioned it’s not toward the lower end of what we were expecting up there. So if we make a discovery in the lower portion, it could be a very nice discovery. I don’t want to downplay it too much what I was really trying to downplay is this is not something that has probably a 50% chance of working. And there is a high risk in that but if we do hit something there it should be very nice.

Okay. And then just to clarify the Cardona, it is at the midpoint of your kind of pre-drill estimate then for each well?

I would say that we are at least at the midpoint right now.

And then back up to the Utica, can you talk a little more about geologically, the differences that you see between your acreage and where that offset operator’s acreage was at?

Sure. The most recent well which is about six miles away from our drill pad, it’s really only about three or four miles away from the boundary of our acreage. That prospect is just slightly up deep from where we are, so we are going to be a little bit deeper, not a whole lot. We think we are in a good window for the proper temperature conditions to have formed gas but not overcooked it. So we are pretty optimistic on it, but until we drill a well and prove it, we don’t know for sure, Brian. But geologically speaking, temperature speaking, we should be in a pretty good place.

Okay. And where are the closest logs down through the Utica?

We have logs on our acreage through the Utica, if I am not mistaken, Ken, do you know anything to the contrary?

No.

I think there have been a number of wells that have been drilled where we, either east or north south or potentially on our acreage. So we have a pretty good idea of what the structure goes across our whole Mary and Heather Field. It’s possible that the Utica doesn’t make it all the way over to Heather, so we have almost a 40,000 acre stake there right at Mary where we think it should be prospective.

Okay. That sounds great. Thanks, guys.

Okay.

Thanks, Brian.

And your next question comes from the line of Dave Kistler from Simmons & Company. Your line is open. Dave Kistler - Simmons & Company: Hey guys. Just a couple of quick follow-ups, with Amethyst success, can you talk a little bit about how that influences the outlook for Derbio? I know, Amethyst was gassier than probably originally expected, but any kind of color you can give us would be great?

Okay. Well, we have learned something about the size mixing materials at Amethyst that we think are somewhat applicable to Derbio. So in a sense, it derisks the prospect of Derbio slightly. I would say maybe it gives another 10% on the probability scale at working, which is a good thing. As far as gas or liquids at Derbio, it’s very difficult to tell because Derbio is a little bit shallower. Therefore, we do not get as hot. Therefore, you would have the expectation that there is a possibility Derbio is oil. But given the fact that Amethyst is gas, there is also the possibility that Derbio is gas. So we are going to continue to work our data and probably reprocess a little bit of seismic to see if we can figure out there is any unique size mixing material that will tell us whether we are more likely to be oil or gas. We began working thus far to figure out if the size and signature told us that if we had sand or hydrocarbons. And at least, we confirm that we have hydrocarbons at Amethyst and probably a pretty good volume of them. So that’s a good thing. I will point out too, Dave, that there is a possibility that we would end up drilling another well at Amethyst. We have two fault blocks there, so it could continue to grow. Dave Kistler - Simmons & Company: Okay. I appreciate that, guys. Thank you.

You bet.

There are no further questions at this time.

Okay. Well, thanks everyone for joining the call. We appreciate your interest and we look forward to seeing hopefully all of you on May, the 20th, I believe. Is that the right date, Ken?

Yes.

Okay. Thank you and thanks for joining the call. Good bye.

Ladies and gentlemen that concludes today’s conference call. You may now disconnect.