Stone Energy CEO Discusses Q3 2010 Results - Earnings Call Transcript

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 |  About: Stone Energy Corp (SGY)
by: SA Transcripts

Stone Energy Corp. (NYSE:SGY)

Q3 2010 Earnings Call

November 4, 2010 11:00 AM ET

Executives

David Welch – President and CEO

Ken Beer – Chief Financial Officer

Analysts

Brian Lively – Tudor, Pickering, Holt

Scott Wilmoth – Simmons & Co.

Gary Stromberg – Barclays Capital

Jeff Robertson – Barclays Capital

John Selser – Iberia Capital Partners

Jeff Davis – Waterstone Capital

Operator

Good morning. My name is Sarah, and I will be your conference Operator today. At this time, I would like to welcome everyone to the Stone Energy Third Quarter Earnings 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. I would now like to turn the call over to Mr. David Welch, President and CEO of Stone Energy. Mr. Welch, you may go ahead

David Welch

Thank you, Sarah, and good morning, everyone. Welcome to our third quarter earnings call. Joining me this morning is our Chief Financial Officer, Ken Beer, who will discuss the financial highlights of the quarter. Then I’ll provide you a few general comments, followed by your questions. So, Ken?

Ken Beer

Thank you, Dave. Let me start-off with a 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 and Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties normally incidents in the exploration for and development, production and sale of oil and natural gas.

We urge you to read our 2009 annual report on Form 10-K and the soon to be filed third quarter 10-Q, for a discussion of the risks that could cause our actual results to differ materially from those in any forward-looking statements we will 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 for the differences between these financial measures and the most directly comparable GAAP financial measures.

With that, rather than go through the financials in great detail, we’ll assume that everyone has seen the press release and the attached financials. From a financial reporting standpoint, there were no significant unusual items in this quarter, so my comments should be brief.

Our discretionary cash flow for the quarter was $92.5 million or about $1.93 per share and earnings of $20.3 million, or about $0.42 per share, both of which were within pennies of the first call estimates.

Production for the quarter came in at 198 million cubic equivalent a day. During the quarter, we had continued permit delays on recompletion and workover projects on some third-party pipeline repairs and inspection delays before recommencing our drilling at Amberjack, fortunately, much of the delay on non-drilling permits seemed to be behind us and manageable.

As noted in the press release, after being just under $200 million a day in October, we are now above $210 million a day for the past few days. Volumes from the Vili well at around 2,500 barrel equivalents a day have certainly helped.

Oil and gas price realization after hedging came in at around $72.50 per barrel and $5.50 per Mcf or a blended price of $8.41 for Mcfe. And again, oil represents about 65% of our revenues.

Our hedge position reduced oil prices by $2.79 per barrel for the quarter but boosted gas prices by just under $1 per Mcf, or a net game on hedging of about $6 million for the quarter.

On the cost side, our LOE was $37 million, on the lower side of our annual guidance. However, we expect a slight increase in major maintenance expenditures in the fourth quarter. So, we’re maintaining our $150 to $165 million guidance for the year.

Note that we also had a $3 million operational expense relating to the cost of warm stacking the H&P Amberjack platform rig during the moratorium and we had a small loss from tubular sales out of our inventory for the quarter.

Our quarterly estimated tax rate at 40% was higher than usual, as we had some adjustments to our annual tax estimates, which hit the third quarter. In fact, a swing from 35% to 40% effective tax rate for the quarter equated into about $0.03 or $0.04 per share.

The higher state income taxes are now part of the equation. So, we are expecting a higher overall effective tax rate. We would now expect to show a 36% effective tax rate for the year versus our previous run rate at 35% and the catch-up was put in the third quarter. In addition, we had a catch-up on our current taxes for the quarter, as well.

Some of the increase in current taxes stems from a shift in capital expenditures away from projects that generated IDCs, which offset current taxes and into acreage acquisition in low risk Marcellus wells, which do generate less IDCs.

Our total debt for the quarter remained at $525 million and was split again between the $200 million sub notes due December 2014, the $275 million of our 2017 senior notes and just $50 million in bank debt.

You might note in late October, our bank group reaffirmed our borrowing base at $395 million, which leaves us with just under, I’m sorry, with just over $280 million in availability after adjusting for the $63 million in LCs that we had outstanding.

Also note that the bank debt has shifted to current because our credit facility matures on July 1, 2011. Because of the Macondo overhang, we elected not to redo our credit facility over the summer, as originally planned. Time has been our friend here, as the bank market has definitely improved and we are currently exploring alternatives for an extension or renegotiation of our credit facility, which would extend that due date.

Our reported third quarter CapEX was $143 million. Included in this figure is $53 million, which was accrued for pending Appalachian lease acquisitions, which were expected to close during the fourth quarter. Most of these leases are a tract of 10-year leases, which provides us with good operational flexibility.

Primarily due to the increase in Marcellus acreage acquisition, the Board has approved an increased capital budget of $425 million, up from the original $400 million. You’ll note we added a couple more hedges in 2011, which are included in the press release for your review.

I believe that wraps up the financial overview. And with that, I will turn it over to Dave for additional comments.

David Welch

Okay. Thank you very much, Ken. As was highlighted in our press release, we do see the third quarter as an important inflection point for Stone. Results of our activities in both the Gulf of Mexico and the Marcellus lead us to believe that we will more than replace our production this year, thus organically growing our reserves.

We also have several high potential exploration opportunities, which should be evaluated in the coming year. We spent the last several years creating these opportunities and look forward to seeing their results. Our base properties in the Gulf of Mexico shelf continue to provide cash flow to fund many of these growth initiatives.

The offshore moratorium caused substantial permitting delays over the past six months and temporarily impacted our production volumes. On the shelf, the new offshore regulator, the BOEMRE, seems to be getting back to business and is once again issuing straight-forward permits for projects such as recompletions, workovers and side tracks.

Additionally, permits for shallow waters slowly being issued. This is requiring us to do additional planning and apply for permits further ahead of project commencement dates to comply with the new normal. But we do expect to be able to conduct greenfield drilling operations on the shelf starting later this year.

For September and October, the pace of our recompletions and our workover program was back on track. Permits are taking longer, but with careful planning we’ve been able to get back to normal activity levels and our current production is back up to around 210 million cubic feet equivalents per day so far in November.

We had some excellent results in the conventional shelf in the third quarter. As we reported, drilling at Mississippi Canyon 109, our Amberjack platform, resumed in August after the original moratorium was revoked. In the third quarter, we drilled the best well in the field, the Vili prospect, which added new oil reserves and is currently producing around 2,500 barrels of oil equivalent per day. Platform rig is now skidded over and is drilling the Kili well. We’ll likely follow this one with another well or two at Amberjack, which we own with 100% working interest.

Also on the shelf, we’re moving forward in the new permitting process with the BOEMRE and expect to be able to commence drilling of an open water oil well, our Bronzeye prospect at Ship Shoal 113 by year end. Along with a few other shelf projects for 2011, we believe that activity at Amberjack, Ship Shoal 113 and Ewing 305, our the three largest oil fields will help us keep our volumes stable around the 200 to 210 million cubic feet equivalents per day level well into next year.

Our activity in Appalachia continues, as we’re ahead of plan on drilling our 14 well horizontal program. We’ve already completed the drilling of 11 wells and are almost finished drilling two more. So, we should not have any problem completing or exceeding the original 14 well plan.

We continue to feel encouraged about the outlook in this area, as our initial horizontal well in West Virginia tested over 7 million cubic feet per day and two additional wells have now been fraced and are flowing back frac water, as we speak with gas beginning to break through.

We’re also presently in the middle of pumping another frac and expect to have several more completed by the end of the year. We expect to see production from these new wells coming online between now and the second quarter of 2011, as infrastructure is built and connected. We may exit this year producing around 5 million cubic feet per day from the Marcellus with a nice ramp up in 2011.

Frac shortages have caused some delays on testing and production, but we expect this to ease next year as service companies are committing additional resources to address this demand.

Also and importantly, our operational results seem to be confirming our geologic and petrophysical models. This has given us the confidence to capture additional acreage in our two targeted core areas. We now own leases covering about 75,000 net acres in the play. We believe our position is substantially consolidated in the top tier areas of the Marcellus, which should yield superior results over the long-term.

Our team in Morgantown, West Virginia, has got into an effective group and in 2011 we expect to begin the shift from testing all of our different areas to a more efficient pad drilling program.

In the Rocky Mountains, we have three exploration projects with the potential for oil development if successful. In the Alberta Bakken, we own approximately 35,000 net acres and our partner, Newfield Exploration, has drilled a vertical portion of what is expected to be three horizontal wells for the evaluation of several intervals. We expect to horizontally test all three wells in 2011.

In the Paradox Basin, we have spudded our initial well in one of two units covering about 30,000 net acres, which we own in this area. Lastly, in the Rockies, we own over 10,000 acres in the Niobrara trend located in the Hanna Basin and may drill an exploratory well during 2011 to advance this play.

Let me return to the Gulf just to finish up. In the deep shelf geologic trend, we’re currently drilling at about 18,000 feet on the South Erath exploratory prospect, with a targeted total depth of 21,000 feet and hope to drill to TD and have some results before year end. We have about a 15% interest in this prospect, which is actually on land even though it’s what we classify as deep shelf geology.

Our other active deep prospect is the Lighthouse Bayou. It’s actually on land as well and it’s undergoing location preparation right now. We’re expecting to spud this well in December. It will be testing multiple geologic horizons and a very large geologic structure, and we own approximately 25% interest in this prospect. This highly prospective well is expected to take over six months to drill but we should see evaluation in 2011.

In the deep water, our exploration activity remains muted due to the uncertainty surrounding future permits. It is a good sign that the moratorium has been lifted but the time when drilling may resume is still highly uncertain.

We hope to move forward with starting some projects in 2011, but are unclear as to any timetable. However, we are moving forward with the development of the Pyrenees discovery, with productions still projected by late 2011 or early 2012.

As you can see, we have a deep inventory of prospects to choose from in 2011. We are constructing our proposed 2011 CapEx budget right now and expect Board approval in December. This is an exciting time for us at Stone and we look forward to the next several quarters as we execute on a number of our opportunities.

With this, we’re now ready to take your questions. Sarah?

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Brian Lively from Tudor, Pickering, Holt. Your line is open.

Brian Lively – Tudor, Pickering, Holt

Good morning.

Ken Beer

Hello, Brian.

David Welch

Good Morning.

Brian Lively – Tudor, Pickering, Holt

In the Marcellus with the 7 million a day published rate, can you talk about what you’re seeing on the three other wells you’re testing in terms of pressure, flow back rate, that sort of thing?

David Welch

Well, I don’t have any rates to give you on that right now. We have just literally finished the fracing on those wells within the last day or two. What I can tell you is that they look to be performing very well. We’re unloading frac water and starting to see gas breaking through, which is a good sign.

Brian, we’re going to have a Board meeting in early December and by then, hopefully, we’ll be able to put out our CapEx budget and also publish some rates on these other wells. So hopefully that will be forthcoming very shortly. I hoped to have a couple others to give you on this call, but it was difficult to get some fracing that’s lined up, so we’re running a few days behind schedule

Brian Lively – Tudor, Pickering, Holt

Okay. But on the completions, in terms of like the break over pressures, are they expected and similar to the first well?

David Welch

Well, we have seen good pressure. All of our Marcellus acreages in what we would deem to be the pressured section of the Marcellus. And so I would expect we would see, and we are in fact seeing pressures come up as we are testing these wells. So, I don’t have an exact number to give you but everything looks positive at this point.

Brian Lively – Tudor, Pickering, Holt

Okay. That’s great. And then, thinking about the dates to drill, one and then secondly, the spud to sales timing. Do you guys have some pro forma estimates as you start building a bigger log of wells?

David Welch

We do and we in fact have seen a learning curve from the beginning of our activities to our present state, and we have gotten much more efficient on the drilling of individual wells. The real efficiency is going to come in when we conduct our pad drilling and that’s really slated to begin next year. So, I think we’ll be in a good position to put that out here fairly soon, as well.

Brian Lively – Tudor, Pickering, Holt

Okay. And then just jumping over to the Paradox Basin. I know it’s early. I’m not expecting any your estimates or anything like that at this point. But could you just discuss the geologic concept there and what attracted you to leasing in the basin?

David Welch

Yeah. Well, the Paradox Basin is a salt basin and it has a number of what you would term clastic intervals, which is a mix of shale and other type of clastic rock sands, et cetera. An And so these areas have been cored in other approximately areas oil and in fact, there’s an analog field about 20, 25 miles north of where we’re operating. And so it looks like this is an area that if we can get a horizontal well in the right zone and establish production, it’s got a lot of running room for us. So that’s what attracted us to it. We have some local expertise that have studied this basin for many, many years and it’s basically an analog play to one that’s worked further to the north.

Brian Lively – Tudor, Pickering, Holt

And do you think about it more like the, like a more of an oil prone shale, like the Eagle Ford or is it more like a Granite Wash analog?

David Welch

Well, that really remains to be seen. But it’s mostly, it’s pressured oil and so, the Eagle Ford has multiple sections to it. It could be similar to some part of the Eagle Ford oil but, and I’m not really that familiar with the Granite Wash.

Brian Lively – Tudor, Pickering, Holt

Yeah. I was just thinking in terms of is it more of just a tight formation or is it truly a shale?

David Welch

Well, it’s a mixture of shale’s and tighter rocks embedded within different salt intervals.

Brian Lively – Tudor, Pickering, Holt

Okay. Last question on the Gulf of Mexico in the wake of Macondo. Have you changed your estimates for maintenance capital to go in there to keep production flat?

David Welch

We’ve made some slight adjustments…

Ken Beer

Yeah.

David Welch

… but not very material, we -- as you probably may remember, Brian, we got very active with respect to trying to de-risk our offshore asset base a couple years ago, actually several years ago and we had a major push in 2009. Over the last five years we have abandoned about over 300 idle wells. And so, we’re very far advanced into de-risking our asset base out there, when you get rid of those idle wells, you take weight off the platform and you also remove surface area for a wave to hit. So, we’ve gotten a lot of that done already and I think the new regulations that are coming out, we’re in pretty good shape relative to what they are going to be requiring people to do

Ken Beer

And then just the maintenance CapEx for production purposes. Again, we certainly were put on hold for some portion of the year and we will probably not spend an extra few million dollars that we had planned. But as we were alluding to, I think the recompletion, the upgrades to some facilities, the workovers, that program is even though there’s some delays from what we were used to six months ago, it’s now manageable and kind of we’re in queue and can plan around it. And so those maintenance expenditures are kind of back on a more normal spending pattern

Brian Lively – Tudor, Pickering, Holt

Okay. That’s helpful. I’m just trying to get a sense of your confidence of keeping production flat at a reasonable cost in the Gulf of Mexico until we start seeing the production uplift from the Marcellus and some of the other onshore plays. So any color you can give on your ability with the new regulations or where you expect them to be to keep production flat at around that $210 million a day through next year, is really what I’m trying to hit on?

Ken Beer

Yeah. And I think we even tried to allude with Amberjack, we have the platform ready. We’ll drill another. The Vili well is drilling, I’m sorry the Kili well is drilling now. We’ll drill the northwest, after that might have even a third well. We may look to go to back to Ewing Bank 305 because the permitting, as you might be aware, the permitting on a side track off of an existing platform is far more straight forward than some of the new open water wells to be drilled.

So we’re trying to plan around potential permitting issues. We think we have enough kind of in inventory for the conventional shelf, that between the follow on Amberjack wells, Ship Shoal 113, the Bronzeye well and the 305 wells combined with two or three outside of the three core oil fields that we have, should keep us relatively flat when combined with the recompletions and workovers that we have scheduled for next year. So that is the game plan. So the answer is, that’s really for 2011, that is what we’re planning on doing

Brian Lively – Tudor, Pickering, Holt

Okay. That’s great, guys. Thank you for taking my questions

Ken Beer

Sure.

Operator

Your next question comes from the line of Scott Wilmoth from Simmons & Co. Your line is open

Scott Wilmoth – Simmons & Co.

Hi, guys. Just looking into 2011, I know you haven’t provided an official budget. Can we talk just about allocation of how you see next year’s dollars getting spent in terms of Marcellus exploitation and exploration both onshore and offshore?

Ken Beer

Yeah. Scott, again, as you pointed out, we still – that’s still a moving target. I think the one just general observation is that we feel pretty strongly that you will not see the type of dollars that we spent this year on acreage acquisition in the Marcellus.

I think we felt like this was a really good opportunity. Gas prices were low. These are areas that we had been targeting. We felt like we went in and kind of got the sweet spots that we’ve been stalking now for awhile. So I would not look for us to have the same expenditure on land.

I think on in terms of number of wells drilled in the Marcellus, I think you can, we would expect to see a pick up from the 14 wells that we drilled this year. Having said that, because of gas prices, I think whatever we come out from a budget standpoint will probably be less than we would of guessed six and nine months ago because of gas pricing. So the trend will be upward but it might not be the same angle upward.

As you know, we will be spending drilling dollars in the Rocky Mountain area both in the Alberta Bakken as well as in our Cane Creek Paradox Basin area. And then we’ve also highlighted, we will be spending dollars on the deep shelf or onshore deep shelf well at Lighthouse Bayou. So, I think you’re seeing a shift back to maybe a little more dollars being put, hopefully, in the drill bit, less of an acreage acquisition year in 2011

Scott Wilmoth – Simmons & Co.

Okay. And then, on the lines of bringing on less wells in the Marcellus, obviously, acreage you guys just picked up has a 10 year term. Can we just talk about your acreage as a whole and what are the leasehold obligations overall in the Marcellus?

David Welch

Yeah. We have really just minor leasehold obligations coming up in the next year or so. So we have plenty of time to plan that out. The program that we’re lining up should enable us to keep the acreage that we want to keep.

Scott Wilmoth – Simmons & Co.

Okay. And then what was the first horizontal well. What was the completed well cost on that?

David Welch

I don’t have that on the top of my head. Do you have it, Ken?

Ken Beer

Yeah. No. We really don’t have that and in fact, would like to kind of have three or four data points that we put together kind of with an average. But the well came pretty much where we were expecting. So, but, ultimately, this is a play that, it is a (inaudible) play. You have a portfolio of wells both on the cost side and the performance side and that’s probably what we’ll do, as Dave alluded to.

We’ll come out with, in December the next update as you mentioned we were hoping to have three or four wells to report on today but that got pushed off. So we’ll have three or four or five more that we can at least talk about in December and then start providing some average both well costs, as well as well results.

Scott Wilmoth – Simmons & Co.

Okay. And then on the Vili well, what’s the oil/gas split on that well?

Ken Beer

90. Yeah.

David Welch

90% oil.

Scott Wilmoth – Simmons & Co.

90%.

Ken Beer

Yeah.

Scott Wilmoth – Simmons & Co.

Okay. And then, lastly just when I think about your deep shelf exploration. Do you have any pre-drill unrisked resource potentials of the targets that you guys are going after and what is a typical drilling cost not necessarily a completion cost with that for those wells?

David Welch

Yeah. If you look at the field size distribution, which is the probability versus steel size. The deep shelf and this is before Davey Jones and Blackbeard have been put into the mix. But the last time the MMS put out a field size distribution, the average size in the deep shelf was 100 to 200 Bcf. One of our prospects is in that range. One of the others is more like a Davey Jones type size. So the one could be quite large. The South Erath project is just kind of an average deep shelf thing, and kind of 100 to 200 Bcf gross range.

Scott Wilmoth – Simmons & Co.

Okay. And then, so the Lighthouse would be deep larger?

David Welch

Yeah. The Lighthouse is quite large

Scott Wilmoth – Simmons & Co.

Okay. And then cost to drill on these wells?

David Welch

Well, since these are actually on land, the cost is significantly lower than the deep shelf would be. That was part of our strategy for two reasons. One, the well costs, these well costs are going to be in the $45 million gross range, whereas if we were offshore drilling, it might be $80 to $120 depending upon where you are.

The second reason that we like these projects back on land as a starter is that, one, you avoid the permitting issues, but two, you also are catching these similar geologic structures where they are 5 or 6,000 feet shallower, which means they are going to be much lower in terms of temperature and the pressures are going to be lower.

So the industry has the technology to just put these wells on immediately if they were, as opposed to having to do metallurgy, new elastomers, et cetera, if you were doing one out further away from shore.

Scott Wilmoth – Simmons & Co.

Okay. Great. Thanks, guys

David Welch

So we think it’s a good starting point for us.

Operator

Your next question comes from the line of Gary Stromberg from Barclays Capital. Your line is open

Gary Stromberg – Barclays Capital

Hey, guys.

Ken Beer

Hey, Gary. How are you doing?

Gary Stromberg – Barclays Capital

Great. Thanks. Hey, Ken, question on the revolver refi or extension. Would you look to increase the borrowing base there, ask for an increase and what are you thinking in terms of tenor?

Ken Beer

On the former, probably looking to be relatively flat. There’s really not a reason to push too hard and I would imagine that this would go right up to and maybe even an option to go beyond the ‘014, the December ‘014s. So effectively kind of a four-year deal.

Gary Stromberg – Barclays Capital

And would you be required to take the ‘14s out to do that or would they let you keep those in?

Ken Beer

Still up for discussion.

Gary Stromberg – Barclays Capital

Okay.

Ken Beer

This is one, Gary, where as we mentioned, during the summer it didn’t make any sense to engage to try to work through a facility but we don’t anticipate any issues coming back with what we think of as a very acceptable credit facility.

Gary Stromberg – Barclays Capital

Okay. That’s great. Thank you

Ken Beer

Our thought was really to get this quarter behind us, quite honestly and kind of move forward from there.

Gary Stromberg – Barclays Capital

So when can we expect to hear something, probably December or January?

Ken Beer

Exactly. That would be my expectation.

Gary Stromberg – Barclays Capital

Okay. Great. Thank you

Ken Beer

Thank you

Operator

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

Jeff Robertson – Barclays Capital

Thanks. Ken, in the Gulf of Mexico, can you talk a little bit about the mix in 2011 of projects from the workover and recompletion side, where you think it’s easy to get permits versus where you might have to go through the process to help maintain production?

David Welch

Let me just say, Jeff, most of the projects that we’re looking at doing in 2011 are the more routine type, even the drilling that we’re doing is mostly side tracks and that’s the process that they’ve been moving forward with. We just have, really, less than a handful of open water locations that we’d be looking at in 2011

Jeff Robertson – Barclays Capital

Okay.

Ken Beer

Yeah. And that’s what we’re alluding to is, really we feel like the permitting process for us, as it relates to new open water drilling for shallow wells will ultimately be very manageable because we’re not looking at the substantial number on the recompletions, workovers, Amberjack, 305, we kind of already feel pretty comfortable with our Ship Shoal 113 well that we’ll be drilling late this year. And as Dave mentioned, there may be two more, maybe three more wells but we kind of have a whole year to get those lined up.

Jeff Robertson – Barclays Capital

And secondly, in the Marcellus, can you just talk a little bit about the infrastructure availability in the area, to where you’re drilling your wells in terms of the time or the infrastructure needs to put in, any kind of gathering and processing?

David Welch

It’s a mix, Jeff. We have some that we’re going to be able to put right online and others that we’re in the process of building, gathering, et cetera, so we can bring them online. We should have everything from this program done pretty much and online before some time in the first quarter and into the second quarter of next year

Ken Beer

Yeah. Particularly and where we had most of the activity, which is in northern West Virginia, as Dave said, some of that is actually online. Some of it will be tied into some infrastructure build-out that’s ongoing literally right now with a third party. That we feel like some time in the second quarter should come on.

In the Christine area, which is Central Pennsylvania, again, we haven’t had a whole lot of activity on the drilling side. We’ve had a lot on the acreage acquisition side but during the course of next year, we’ll go hand and glove with the drilling side to make sure that we’ve got infrastructure plans going forward.

So, realistically there will be a lag, but if we feel like, especially with third-party infrastructure, it’s gotten pretty competitive and for instance in West Virginia. We really had three different options that were available to us. So we feel pretty good about having a real tight market for our gas and to build-out infrastructure to our locations.

So I think looking out to 2011, we feel like for the Christine area we’ll get a similar type of interest level for the area that we’ll be drilling out.

David Welch

Just to further close that out, Jeff, when we looked at buying acreage in the first place, we looked at the geology, the Petrophysics and the pipeline overlay. So all of our acreage is fairly proximal to major pipes to give us export to the market.

Jeff Robertson – Barclays Capital

Thank you.

Ken Beer

Thanks, Jeff.

Operator

Your next question comes from the line of John Selser from Iberia Capital Partners. Your line is open

John Selser – Iberia Capital Partners

Dave and Ken, good morning.

David Welch

Hey, John.

John Selser – Iberia Capital Partners

Obviously active in the existing fields, platforms you have in the shallow water, is there anything going on in the deepwater, is there? What are your thoughts along those lines and what are you seeing the other independents do or the industry doing for the deepwater?

David Welch

Deepwater is a big enigma right now, we do have a project that we discovered in 2009, Pyrenees, wells drilled. It is completed. It’s got a tree on it. So all it needs to do is have the tight back to the host platform completed and that’s underway. So that shouldn’t encounter any regulatory problems.

We do have one that we bought in the lease sale called (inaudible), which is the former Puma that also has some wells drilled in it. So, we know it’s a discovery and that one is operated by Mariner soon to be Apache. I’m not sure anything big is going to happen on that in 2011 but by 2012, whatever the new normal turns out to be, that one will probably be moving forward.

Then we have two or three exploration wells that are very interesting wells that we’d like to get drilled. But it’s just so uncertain in terms of when the industry is allowed to get back to work that it’s very difficult to predict and we’re not counting on any contribution in 2011 from any deepwater exploration to book reserves or add production.

John Selser – Iberia Capital Partners

You don’t have any lease issues at this point though? You do have the time on your side, don’t you?

David Welch

We do. Time is mostly on our side. We made our big lease push in 2008 and 2009, which is 10-year leases mostly. So, we should have plenty of time on our things.

John Selser – Iberia Capital Partners

Okay. Thank you.

Ken Beer

Thanks, John.

Operator

(Operator Instructions) And your next question comes from the line of Jeff Davis from Waterstone Capital. Your line is open

Jeff Davis – Waterstone Capital

Thank you. And seeing the press release, you mentioned some activity in the Paradox Basin in Utah. Now, I don’t have your slides in front of me here. But I recall another, I don’t know if that’s the stealth oil play that you’ve talked about in the past and if not, is there any update on anything you’re doing on that?

David Welch

That is it.

Jeff Davis – Waterstone Capital

Okay.

David Welch

We pretty much have our acreage position put together now and it’s in the Paradox Basin in Southern Utah.

Jeff Davis – Waterstone Capital

Okay. And I’m curious what -- how active are you looking at deals in the Gulf of Mexico and what your thought process is as it relates to looking at any acquisitions, and curious too in the context of where your stock is, if you’d use that as a currency, I mean, just as very basic math.

But if you look at your cash and kind of mark some of your onshore assets to market so to speak and eat through much of the value of your debt so you’re basically sitting here with based on EBITDA kind of 2, 2.5 times your market cap, so, stock seems pretty cheap to me?

David Welch

Right. And that’s our thought as well. I don’t think you’ll see us using it to go out and pick up something in the Gulf right now. It would have to be something that would certainly be accretive and that would mean it would have to be pretty low priced and it feels like we have some catalysts in our stock over the next year or so. We are not -- our focus is to try to just internally and organically grow the value of the company right now

Jeff Davis – Waterstone Capital

Okay. Thank you

Operator

There are no further questions in queue. I turn the call back over to the presenters for any closing remarks

David Welch

Okay. Thank you. Listen, everyone, we greatly appreciate your interest in Stone. And thank you very much for attending our call and look forward to talking to you again, so long.

Ken Beer

Thank you.

Operator

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

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