Talos Energy Inc.
Q2 2013 Earnings Call Transcript

Published: 6 Aug 2013

[Operator:]

Good morning. My name is Debbie and I will be your conference operator today. At this time, I would like to welcome everyone to the Stone Energy Second 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. Mr. Welch, you may now begin your call.

[David H. Welch:]

Okay. Thank you, Debbie. This is Dave Welch, Chairman and CEO and with me this morning is Ken Beer, our Executive Vice President, Chief Financial Officer. Ken is going to discuss our quarterly financial results and then I’ll provide an update on our progress in implementing our strategic plan. We’ll then follow this with your questions. Ken?

[Kenneth H. Beer:]

Thank you, Dave. Let me start with 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 for and the development, production and sales of oil and gas. We urge you to read our 2012 annual report on Form 10-K and the recent 10-Q that should be filed tomorrow for discussion of the risks that could cause our actual results to differ materially from those that 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 we issued yesterday, which is posted on our website for a reconciliation of the differences between these measures and the most directly comparable GAAP financial measures. Let me go on rather than go through the second quarter results in great detail, we will assume that people have seen the press release and attached financials. Accordingly, I will focus on the selective financial items on the call. First our discretionary cash flow for the quarter was $170 million or $3.40 per share and the earnings for the quarter were $39 million or $0.78 per share with both of these results significantly higher than the analyst first call estimates either production for the quarter came in at over 45,000 Boe per days or over 270 million cubic feet equivalents per day are well above the upper end of our guidance which was 250 million cubic feet a day above. Our Marcellus volumes were strong contributor as our production fall on the Williams pipeline repairs in early May have been above expectations and projections. Also early production in June from the third well at the La Cantera was also helpful and importantly an active well work program helped our base Gulf of Mexico volumes for the quarter as well. The production split for the quarter was approximately 43% oil, 10% NGLs and 47% natural gas; NGL production has certainly showed an increase this quarter as both Appalachia and La Cantera through out NGL volumes. Our production guidance for the third quarter for 2013 is 42,000 barrels to 45,000 barrels equivalents a day or about 252 million cubic feet to 270 million cubic feet equivalents per day. We are currently at or slightly above the upper end of that range, but we do have some hurricane downtime baked into our numbers. Our guidance for the year has also increased to 41,000 barrels to 44,000 barrels equivalents a day. 246 million cubic feet to 264 million cubic feet equivalents per day which also incorporates potential hurricane and some operational downtime. Our quarterly oil prices realizations remained above a $100 per barrel and however there has been a narrowing of the Louisiana Sweet Premium above WTI which is now down to around $5 a barrel versus WTI still for us a very attractive price. Our realized NGL prices were down sharply versus the first quarter to under $30 per barrel as the Appalachian NGL prices continue to be soft and we also had some pricing adjustments versus the first quarter of the year due to timing lag on the reporting that we get from the NGL facilities, we would expect our prices to remain in the low-to-mid $30 per barrel range for the remainder of the year. Overall gas prices weakened during the quarter especially in Appalachia, but our gas hedge position help to keep our realized price above the $4 per Mcf mark. On the cost side, our LOE was around $50 million for the quarter reducing our unit LOE per Mcfe to around $0.02 or $12 per Boe. Although we might see this creep back up very slightly in the third or fourth quarter our operations guys are clearly doing a good job in keeping LOE cost down. The transportation processing and gathering expense of almost $9 million mirrored the big increase in NGL volumes especially in Appalachia given the increased production guidance for NGLs; we have also increased our guidance for this expense line. Our DD&A rate for the quarter average just under $3.50 per Mcfe which is at the upper end of guidance and the accretion expense should remain at just under $8.5 million per quarter. Our base G&A before incentive comp is running around $15 million per quarter which is just at the upper end of guidance for the year, as noted on the last conference call we do expect G&A to trend upward as we’ve seen increases in personnel and salaries, particularly as we step up our peak water efforts. Reported interest expense is currently running around $9 million per quarter down slightly from the last quarter as our unevaluated properties increased which impacts our reported interest. There is still about $4 million in non-cash interest in that number mainly tied to the convertible notes accretion. The total cash interest that’s going out the door each quarter and running at just over $15 million per quarter. Regarding taxes, we are still projecting around a 36% reported tax rate, although we are showing a $7 million current tax benefit this quarter which is another tax refund from the carry back from the current year’s estimated tax loss, so again looking to get tax refunds during the course of this – back half of this year. CapEx for the quarter came in at around $190 million and for the six months, we were at $325 million. Just to note, we did have a $20 million upward adjustment to our first quarter, reported CapEx that we had in the first quarter press release and this puts us on a run rate right on our budgeted $650 million. A note though with our deep water program ramping up in the second half of the year and maybe some upward pressure on that CapEx figure. Debt position, our debt position remains stable at $975 million, if we assume the $300 million face value for the convertible notes or around $920 million if we use the recorded discounted figure for the convertible notes. Our $400 million borrowing base remains – on our bank facility remains undrawn and we exited the quarter with over $225 million in cash. During the quarter, we did add just a couple more hedges to further protect our 2013 and 2014 cash flow in CapEx program and included the updated hedge position in the press release. Bottom line, really strong quarter and we’re in good financial shape as we enter into an active deep water program. That should wrap up the financial overview and with that I’ll turn it back to Dave for his comments.

[David H. Welch:]

Okay. Thank you, Ken. All of our businesses performed very well this quarter and we achieved many important strategic milestones for the future. We delivered production well above our second quarter guidance and are increasing the upper end of guidance for the full year. Also our reserves were stable and are expected to grow again this year. Once again we generated significant discretionary cash flow of almost $170 million which substantially funded our $190 million of capital needs in the second quarter. The balance sheet remains strong as we ended the quarter with over $226 million in cash and our bank revolver remains undrawn at $400 million. We had no long-term debt obligations due until 2017. We continue to exploit our legacy conventional shelf assets as we develop our three growth areas, Appalachia, deep water and the liquids rich deep Gulf Coast. Our strategy remains the same as the last seven years to pursue investment and price advantage natural gas and material oil projects. Our proved reserves are still almost balanced with approximately 49% liquids and 51% natural gas as of December 31, 2012. The positioning and continued performance sets us up well for the execution of our three year plan. The three year plan includes an aggressive workover program with limited drilling investment in the conventional shelf, development drilling in the liquids rich onshore Gulf Coast business, continuation of our one top-hole rig, one horizontal rig program in Appalachia and now accelerating investments in the deep water Gulf of Mexico. That now also includes the market test of our non-core shelf properties for potential divestment this year. On the shelf, we plan to drill about five wells this year with the aim of maintaining a relatively stable liquids production rate but not trying to grow reserves there due to the limited size of our remaining opportunities. We have drilled three wells thus far and two of them are productive. First well drilled this year came on line at approximately 350 and is now producing 300 barrels a day and the second successful well is expected to come online in the third quarter. The fourth well is expected to spud in the third quarter and the fifth will follow in the fourth quarter. In Appalachia, we see about eight years of development drilling ahead of us that our liquids rich Mary field and for the next three years we plan to continue drilling with our one vertical rig and one horizontal rig program, one frac crew program in this liquids rich area. We now have an operations machine functioning smoothly with the execution of permits ahead of the pad construction, pad construction ahead of top-hole rig drilling, top-hole rig drilling ahead of the horizontal rig drilling. In completion, completed wells ahead of the frac crew and frac crews ahead of the flow back and hook up crew. So we’re now simultaneously permitting new wells, constructing pads, drilling top-holes, drilling and casing horizontal wells, fraction completed wells and hooking up completed pads to production. Our teams are executing with military like precision and the study program is yielding dividends for us as efficiency continues to ramp. We now expect to deliver about 30 new wells this year as our team continues to deliver improving results. Production from our wells appears to be holding up very well and our predicted EURs are ultimate recoveries are expected to rise as we gain more production history. We’re currently producing over 80 million cubic feet per day in Appalachia and average 75 million cubic feet in the second quarter. The current rate includes about 1,500 barrels per day of condensate and other 3,000 barrels per day of NGLs. We also expect the benefit from higher liquids pricing within the next year as new markets are accessed as a result of repiping processing equipment at the Fort Beeler plant and new fractionation facilities being brought online at the Martinsville fractionation plant. These uplifts will take place in several stages and by the end of the second quarter next year we could see as much as an 80% uplift in our liquids pricing. As our rates continue to increase and our liquids price rise, we expect that Appalachia could become a cash flow generator for the Company within the next couple of years. Self funding in cash generation is a huge milestone for any resource play and we look forward to achieving it in our Marcellus development. We’ve also drilled and fractured the short horizontal well to test the Upper Devonian shale, which lies just above the Marcellus that are Mary field. At the Upper Devonian is condensate-rich produces it commercial rates and is not already being drained by our Marcellus wells, it could materially enhance the value of our Appalachian asset. We expect to get an enhanced or an extended test on this well once the remainder of the wells is in its pad are completed and ready to flow back. We should have some initial idea of the results later this year. In the liquids rich, deep Gulf Coast area, the third development well La Cantera was a success has been completed and is now on production. Three wells in this field are producing over 120 million cubic feet per day, which includes 2,000 barrels of condensate in 2,400 barrels of NGLs as well. With the 35% working interest, our net interest shares of the production is approximately 30 million cubic feet per day, which includes 500 barrels per day of condensate in 600 barrels per day of NGLs. We plan to drill or participate in the drilling of two to four exploratory wells over the next three years in a liquids rich deep gas business. This is an attractive play for us and that we see other good exploration opportunities, also when discovery is made, it can be brought on production quickly. In 2014, we could possibly spud the La Montana prospect in the La Cantera mini basin and possibly the Tomcat prospect in the shallow offshore waters at West Cayman 176. During the first quarter, we increased our working interest in La Montana from 25% to 100%. We now own both La Montana and Tomcat at the 100% working interest and plan to market them to the industry with the idea to keep as much as a 50% to 75% working interest with the smaller cost interest in these exploration wells. All of our deep gas inventory, our exploration prospects which were expected to offer high rate wells in material liquids content. Stone is the operator of and Tomcat. We have several additional attractive prospects being developed in our inventory and are keen to drill them in 2014 and 2015. One of them is the Pumpkin Ridge prospect, which is a new prospect in which we just acquired a 100% working interest and approximately 14,700 acres over the geologic structure. This is an Ultra Deep prospect similar to the Lineham Creek prospect being drilled nearby by Chevron, as well as has been reported by one of the partners is being productive in the Yegua sand, which is younger and shallower and thus less expensive than the Wilcox objective originally planned for the well. We still have a lot of work to do, but this may turn out to be an exciting opportunity for Stone in the future. In deep water, the stage is set for a large activity ramp in both development and exploration drilling. We believe this will result in significant increases in production within the next year and a half, starting with the Northern Mississippi Canyon corridor were anchored by the two 100% owned production hubs at Amberjack and Pompano, combined these and product pieces of infrastructure contain about 75,000 barrels per day of accessible production capacity with room for further expansion is needed. We have three wells near our 100% owned Pompano platform authorized for drilling. These are the Cardona development well, which we sometimes call it Cardona North, the Cardona South development well in the Amethyst exploration well, these were our first company operated deep water drilling wells in subsea tiebacks. All permits, rigs, vessels et cetera had been secured for the drilling of these wells. Amethyst is planned to be drill first using the Ocean Victory moored rig and the two Cardona development wells are scheduled for the Ensco 8502 dynamically position semi-submersible drilling rig. The Amethyst well should spud in late October as hurricane season is winding down and the Cardona North well should spud in late January or early February. We have been able to move the Amethyst well essentially out of the peak hurricane window and also move the Cardona drilling about three months closure to expected first production. These adjustments were reduced risks and enhance the rate of return on the projects. They do not delay the date of first production since the drilling is not on the critical path to delivering first production in the Cardona in the first quarter of 2015. The first quarter startup date for Cardona is a midpoint in the schedule, startup could potentially move forward or backward about a quarter, depending upon weather equipment deliveries and other factors. We continue to work to improve the schedule and we’ll keep you update as we progress. Our progress in the Cardona paid back thus far as good. We have ordered the long lead critical path items including trees, wellhead, subsidy valves, and have awarded the construction contract for the nine mile long umbilical, hydraulic, and electrical control line to Oceaneering. Currently, we are evaluating the EPIC contract for the flow lines, EPIC stands for Engineer, Procure, Install and Commission and applies to the construction of the flow lines, the integration and installation of all the subsidy equipment and the commissioning work required for the startup of production. We received several bits on the EPIC contracts and expect to make a selection, and execute this contract by the end of this month or the next. We are also in action, making the necessary platform modifications to Pompano to accept both additional new tieback wells and a platform rig thereafter. Thus far, we cleaned out one of the two needed J-tubes rising from the sea floor to the platform deck and we’ll be doing the second during the instillation of the umbilical. This worked in overall project to presently unscheduled and on budget. We have now secured platform rigs for both Pompano and Amberjack and planted drill four to six development wells from each of those platforms beginning in mid to late 2014. The platform drilling at Pompano would follow the Cardona platform related tieback work, so we should see production rising, not only due to Cardona that continuing to increase beyond that as a result of the subsequent platform drilling that will extend into 2015. So we’re poised for material production growth in our first Company operated Mississippi Canyon corridor from lower risk development drilling. We presently estimate that our deep water production rate could double from 10,000 to over $20,000 per day. In addition to this development drilling and our Company operated Amethyst exploration well, we expect to have two non-operated I guess exploration wells drilled through their objective sands and potentially evaluated by year-end, those are Taggart and San Marcos, drilled a 23% interest in the LLOG operated Taggart prospect located at Mississippi Canyon 816, which has a gross P90 to P10 reserves distribution ranging from 10 to 27 million barrels of oil. We expect to have the results on the Taggart prospect by November or December. We’ve also approved an Apache AFE for our 25% working interest to drill the San Marcos exploration prospect at Mississippi Canyon 983. This well should spud later this quarter to test the P90 to P10 reserves distribution ranging from a 11 million to 102 million barrels of oil. San Marcos is a Miocene Age geologic structure separated from shelves recently on Vito Discovery, which reported 600 net feed of oil pay. We may have the results of San Marcos by the end of the year as well. Next year in 2014, we expect a commence drilling of the first of up to four prospects in the previously announced Conoco joint venture. This could be the 21 prospect located at Mississippi Canyon 118. Also the partnership at our Parmer discovery at Green Canyon 823/867 has shot a state-of-the-art coil seismic data set there. This data is in processing now and should be available for interpretation to determine the location of the next appraisal well there possibly in 2014 or 2015. Additionally, we could see Guadalupe, Derbio/Mica Deep, Phinisi and Goodfellow spud at during 2014. These are all exploration wells in which we hold varying working interest. We own a 100% of an operate Derbio, which is near the Pompano field. It has a P90 to P10 reserves distribution ranging from 10 million barrels to 66 million barrels, and if Amethyst is successful Derbio’s chances of success increases significantly. We also own a 50% working interest in the Exxon operated Mica Deep prospect at Mississippi Canyon 211, this prospect has a gross P90 to P10 reserves distribution ranging from 6 million barrels to 72 million barrels of oil. It’s an offset to the recently announced Marmalard discovery to the south. In addition, we own a 20% working interest and a 13% working interest respectively in the ENI operated Phinisi and Goodfellow prospects in Walker Ridge. The gross P90 to P10 reserves distribution for Phinisi is 24 million barrels to 260 million barrels and for Goodfellow was 89 million barrels to 804 million barrels one or possibly both of these wells could spud in 2014. As you can see Deep Water has become a very active area for us, and we are expecting significant growth in both oil production and oil reserves over the course of our three year plan from Deep Water. To sum the company up, we’re moving forward successfully on all fronts of our strategic plan. We’re managing the shelf decline and testing the market to potentially sell our non-core assets there and are achieving growth in Appalachia. The Deep Water rich gas in the Gulf Coast and in the Deep Water Gulf of Mexico. Balance sheet is in good shape and we have a funding plan developed to execute on exploration successes that become further future development prospects. With this, we’ll now be happy to take your questions. Debbie?

[Operator:]

(Operator Instructions) Your first question comes from Dave Kistler from Simmons & Company.

[David W. Kistler:]

Good morning, guys; great work.

[Kenneth H. Beer:]

Hi, Dave.

[David H. Welch:]

Good morning, Dave.

[David W. Kistler:]

Real quickly on the asset disposal or potential asset disposal, can you breakdown for maybe a production standpoint and use of capital, what would be constituted non-core versus core and maybe the impact that divestiture there would have on the borrowing base?

[David H. Welch:]

I’ll take the first part, maybe Ken can do the second. Basically we were looking at doing Dave is just keeping our two or three largest oil fields and pretty much everything else would be considered non-core.

[Kenneth H. Beer:]

Yeah, and to that really the thought is our focus has clearly been on these deep water projects and deep gas projects. We’ve got – they put couple of shelf deals that we have committed capital and importantly human capital to put the remaining assets in our shelf portfolio, really just haven’t spent the time certainly for someone else who can come in and spend the time in resources, it’s just going to make some sense. I think we’ve suggested it that the volumes if you look at the first or second quarters, somewhere around 20% of our volumes, most of that would be gas. One of the things it gives us some comfort is the inclining production that we’re seeing out of the Marcellus certainly can help fill any sort of void on the production side. And the thought, quite honestly was this was a property package that someone else might have a lot of activity and make it work for them and it can be a good win-win for both groups. So that was the thought having said that as Dave pointed out it is a market test we really don’t have to do anything, because financially we’re exiting the year, we got a strong balance sheet in terms of our cash undrawn facility. But we’re just looking to focus and refocus on really our growth areas and turn this baton over to somebody else.

[David H. Welch:]

Yeah, another way to think of it too, is that the opportunity set that’s embedded in these non-core properties has not been able to attract our capital given the opportunities that we see in Deep Water and thus these properties are more or likely worth more to someone else than they are to us and we expect to capture part of that value.

[David W. Kistler:]

Okay, makes sense I appreciate that. And then in the same sort of divestiture comment that really more selling down working interest, can you guys give us an update on the Amethyst prospect and the potential sell down there and ultimately is that something you consider just drilling 100% from Stone Capital?

[David H. Welch:]

I would say that we would consider drilling at a 100% from Stone Capital although we are still active in the market to get a partner and we are trying to find a promoted partner on Amethyst and so that work continues and I’m pretty optimistic that we will find someone Dave.

[David W. Kistler:]

Okay. I appreciate that. And one last one just hopping over to CapEx for a second, Ken you had mentioned looking at the 2Q run rate that could be biased higher can you kind of give us more definition around when you say biased higher are we talking 10% higher, 5% how should we be kind of thinking through that?

[Kenneth H. Beer:]

Yeah. Still a moving target again tied to a number of different variables including the working interest at Amethyst, as well as the timing of some of the other projects that we’re involved in whether it would be Taggart, San Marcos. And again, we just want to alert you that our run rate is may push that number a little bit, we do have some levers that can help address that. We obviously have the cash on hands, so it’s not a issue of us being scrapped from a cash standpoint. Again, this is more just moving the flag making sure people recognize a run rate, we just need to pay close attention to it.

[David W. Kistler:]

Okay. I appreciate that definition. Thanks.

[Kenneth H. Beer:]

It doesn’t sound like he’s going to give you a number, Dave.

[Operator:]

Your next question comes from Michael Glick with Johnson Rice.

[Michael Glick:]

Good morning guys.

[Kenneth H. Beer:]

Hey Mike.

[Michael Glick:]

Just a good question on the CapEx front in terms of deep water infrastructure how much that spend is allocated into 2013 ahead of Cardona?

[Kenneth H. Beer:]

Do you know the exact number there?

[David H. Welch:]

You’re talking about I mean ultimately we will spend well North of 50, approaching $75 million before we even spud the first Cardona well. So we are doing some pre-spending I mean this is – in order to accelerate production after drill and again a pretty aggressive time table we’ll spud in and having projecting to have Cardona on production within a year part of recent provide for that to happen is we are spending the dollars on the front end. And so that’s again it’s going to be in that $50 million, $75 million range.

[Michael Glick:]

Okay. And then just in terms of the infrastructure itself, I mean is it designed for Cardona specifically or is it flexible enough to be able to cater to future wells in the area?

[David H. Welch:]

The subsea infrastructure is being built very flexibly, what we’re building is actually a flow line loop that would accommodate the two Cardona wells and two additional hubs. So you could tie back additional wells into this system and get them back on to the Cardona platform. So if lightning struck and something happened on the Cardona wells we have in the area something we have over a dozen development wells and over a dozen exploration prospects in the area. So we don’t feel like as much risk, financial risk in terms of putting the infrastructure in ahead off or simultaneously with the drilling of the two Cardona wells.

[Kenneth H. Beer:]

Yeah, Mike to Dave’s point again we are spending incremental capital to provide for that flexibility, we think it’s an exceptionally good investment because instead of having just one single dumb flow line back from the first Cardona well, we now have a system that provide to the flexibility of other wells or quite honestly other systems coming into this, this loop system. So yes more dollars in the front-end but probably we could hope a very good business decision.

[David H. Welch:]

Yeah. And just marginally incremental dollars on the front-end to provide that flexibility it’s not the whole Cardona developments, couple of hundred, $250 million or so and you’re talking about less than $10 million incremental to be able to provide this flexibility.

[Michael Glick:]

Gotcha. And then just given that opportunity you said in the area, I mean should we look ultimately at some of the non-op exploration prospects is being potential source of proceeds in the event of success to fund the operator (inaudible) area?

[David H. Welch:]

Sure. We are ready have PHA agreements with about $5 million or $10 million a year of production handling fees but our number one objective of course is to low that up with equity barrels. To the extent that there is extra oil that’s there we can certainly do one of two things, we can charge a fee to process other people’s oil for them which we’re doing somehow or we can leverage our infrastructure into an equity position and additional non-operated prospects, so it’s a very strategic piece of two pieces of infrastructure to have out there. And we’re really thankful we have.

[Michael Glick:]

Okay, great, thank you.

[David H. Welch:]

You bet.

[Operator:]

Your next question comes from Tom Nowak with Advent Capital.

[Tom Nowak:]

Hey, good morning.

[David H. Welch:]

Good morning.

[Tom Nowak:]

If you are able to get the sale of the shelf assets off your gross leverage debt-to-EBITDA would probably pick up fairly meaningfully. Should we expect a permanent reduction in your growth debt levels, would you be using the proceeds to call the eight and five eights of 17?

[Kenneth H. Beer:]

Really have not made any sort of public disclosure on the true use of proceeds at this point of time again the timing of this process would be some time probably would lap into early next year might be late this year or early next year. But in terms of use of proceeds really have not addressed that Tom.

[Tom Nowak:]

Is keeping your gross leverage level about where it is or flat or above or below?

[Kenneth H. Beer:]

And as I’d say right now kind of our debt position right now we really are very comfortable with you should looking at any sort of coverage ratios or metrics and we’re in very good shape and so we’re not looking to get our debt down substantially versus just have it, be it in this comfort level.

[Tom Nowak:]

And expected impact on the borrowing base?

[Kenneth H. Beer:]

Not a whole lot, we really did not push our borrowing base might notice as our borrowing base will actually cap at the $400 million, we certainly had the flexibility to take that number off in fact substantially and so to answer your question we really would not see a whole lot if quite – we wouldn’t really expect to see any change in the borrowing base.

[Tom Nowak:]

Okay sure. Thanks a lot.

[Kenneth H. Beer:]

Hey thanks Tom.

[Operator:]

Your next question comes from Richard Tullis with Capital One Southcoast.

[Richard Tullis:]

Thank you, good morning.

[David H. Welch:]

Good morning.

[Richard Tullis:]

Okay if just going back to your comment on the ultra deep well, sorry if I missed it, what were the plans there?

[David H. Welch:]

Well this is the Pumpkin Ridge, you are probably alluding to.

[Richard Tullis:]

Yes.

[David H. Welch:]

That’s a large geologic structure that we’ve acquired the acreage on, we are going to be doing some shooting some additional 3D data, interpreting that data and really trying to determine if it has potential for both (inaudible) as well as the Wilcox. And then if it does, then we’ll appropriately try to market at particularly promoted interest in this. So we can end up testing a potentially large reserve accumulation on a leverage basis. It’s very early days on that, but we just thought it was important for you to know that we have acquired that acreage position.

[Richard Tullis:]

And it’s would be on land, drilling off land?

[David H. Welch:]

It is on land. Yes, it’s on land. So would be substantially less expensive than these big deep ore or deep gas wells that you hear about that are offshore, is that right.

[Richard Tullis:]

Excuse me go ahead.

[David H. Welch:]

No, no go ahead.

[Richard Tullis:]

What would be the maximum working interest you’d be comfortable with that sort of well?

[David H. Welch:]

It depend on the market reaction, the promote that we’re able to get, we haven’t done a risk assessment on the well yet. So it’s very early for us to be able to speculate on that at this point of time.

[Richard Tullis:]

Okay.

[Kenneth H. Beer:]

We’ll keep you posted as we work through it.

[Richard Tullis:]

Okay. There has been some recent I guess positive news with the subsalt play in the shallow waters and then some additional interest by other parties and pursuant to play, how does Stone look at that subsalt play, the 15,000 foot to 20,000 foot level in the shelf?

[David H. Welch:]

We have a number of what I would call offshore deeper prospects in our inventory. The ones that we’re maturing right now are what I would say the easier ones which are onshore and one of the offshore ones, which is Tomcat is actually about 20,000 feet, but it’s not a subsalt. So that’s a little bit further out on our portfolio priority.

[Richard Tullis:]

Okay.

[David H. Welch:]

Some of that are immediate.

[Richard Tullis:]

And then if you do go forward with the Gulf of Mexico shelf sale, would you look to retain deeper rights across a lot of your acreage?

[David H. Welch:]

We’d certainly want to negotiate some interest in those deeper rights.

[Richard Tullis:]

Okay, okay. And then Dave you also mentioned that the Company could double deep water production from the current 10,000 barrel a day level, would combination of wells do you need for to come through for that to happen?

[David H. Welch:]

That’s really just on the heels of the Cardona development and some of our platform drilling and in fact I think the platform drilling should sustain growth even beyond that doubling as we move forward towards the end of our three year plan.

[Richard Tullis:]

Okay, good. That’s all I have. Thanks a bunch.

[David H. Welch:]

Okay, thank you.

[Kenneth H. Beer:]

Thank you, Richard.

[Operator:]

(Operator Instructions) Your next question comes from Doug Dyer with Heartland Funds.

[Doug Dyer:]

Good morning, gentlemen.

[David H. Welch:]

Good morning.

[Doug Dyer:]

Looking into next year, it seems like we’re going to have a pretty big increase in CapEx and although I realize that you haven’t set any numbers for next year. Do you have a rough cut as to what CapEx for next year would be and how far would these shelf sale carry you into next year before we might be into a cash flow negative situation again?

[Kenneth H. Beer:]

Yeah, it’s Ken. And fair question, that’s one of the things we are looking at. We want to be in a position where we always have some options, obviously coming into the back half of this year with a lot of cash and undrawn facility on the potential sale of the shelf would certainly push us well into 2014, we still look to have that flexibility on our line. So that the thought is that this we certainly can and are still looking at our capital program for 2014 and haven’t made that public in really going before our Board. But the thought is to your point is it should be a pretty active CapEx program, unless make sure we have the funds in capital to execute and that’s where I think between the cash that the potential sale of the shelf and certainly that this fully unused revolver gives us plenty of flexibility. There are other things we can look at in terms of possibly raising some dollars, selling down interest, if we have a discovery we can sell down the interest or sell out of the interest. We’re looking at a number of our prospects bringing joint venture promoted partner. So those are some of the levers that we have that we’re working with that we have to work with. And we’ll just be able to evaluate as we move forward to the back half of this year and into next.

[Doug Dyer:]

All right. Thank you very much.

[David H. Welch:]

Thank you very much.

[Operator:]

Your next question comes from Curtis Trimble with Global Hunter.

[Curtis Trimble:]

Thank you. Good morning everyone. I was hoping if you could walk me through kind of the rig situation obviously you got things signed up parameters Cardona would be other – it looks like maybe as nine other deep water wells that you had to operate the non-op. Can you walk me through the rig situation on those issues looking to 2014, which have rigs, already assigned which need rigs?

[David H. Welch:]

Sure. The wells that we’re planning on drilling the Cardona and Amethyst those are all rig up as you’re aware. The non-operators have rigs for all of those non-operated projects. The only one that’s in that list I think is Derbio, which is an exploration well that’s somewhat although not completely contingent on Amethyst that well is slated for the back half of 2014 or maybe even in 2015 and that’s the one well that we do not have a rig for yet, so that’s the rig situation.

[Curtis Trimble:]

Again I appreciate it.

[Kenneth H. Beer:]

Again on the non-op for instance, Exxon has identified a rig from Mica Deep, ENI has appears to have a rig identify for an easy and/or Goodfellow, Apache has the rig coming for San Marcos and LLOG has a rig literally coming this month for Tegron. So at least for the next let’s call at 18 months, we think we’ve got the rig issue, we know which rig and roughly where.

[Curtis Trimble:]

Gotcha. And then in terms of the Conoco JV in 21 potentially in slotted into next year or not, I guess that you should have to be determined?

[David H. Welch:]

Well, Conoco is actually build in a rig and this could be I think may be the second well they would drill with that rig. So I think we’re all keen to push 21 forward. We’re going to meeting with Conoco later this month to try to come to a common understanding and common plan on how to go forward there. It’s a little bit complicated because you do have Chevron in the mix and depending upon whether we do. They put all those blocks together with Chevron and try to develop that together or whether we go competitive with Chevron and that will determine outcome of when the well and where the well might be drilled.

[Curtis Trimble:]

I appreciated it.

[David H. Welch:]

You bet. But the rig story is to have a rig.

[Operator:]

(Operator Instructions) Mr. Welch, there are no further question. Do you have any closing comments?

[David H. Welch:]

Okay. Thank you, Debbie and thanks everyone for joining our call. We’ll be with you again at the next quarter so long.

[Kenneth H. Beer:]

Bye-bye.

[Operator:]

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