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Stone Energy Corp. (NYSE:SGY)

Q2 2010 Earnings Conference Call

August 4, 2010 11:00 am ET

Executives

David Welch - President & CEO

Ken Beer - SVP & CFO

Analysts

Oliver Doolin - Tudor Pickering Holt

Richard Tullis - Capital One Southcoast

Jeffrey Robertson - Barclays Capital

Kelly Krenger - Bank of America

David Kistler - Simmons & Company

James Sivigny - Deutsche Asset Management

Operator

Good morning. My name is Mason and I'll be your conference operator today. At this time I would like to welcome everyone to the Stone Energy's second quarter 2010 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. You may now begin.

David Welch

Thank you very much, Mason, and good morning everyone. Welcome to our second quarter earnings call. Joining me this morning is our CFO, Chief Financial Officer Ken Beer who will discuss the final highlights of the quarter. Then I will provide few general comments followed by your questions. Ken?

Ken Beer

Thanks, Dave. I'll start up, just reading 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 the risks and uncertainties normally incident to 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 our soon to be file second 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 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 financial measures and the most directly comparable GAAP financial measures.

With that, let me move forward. Rather than going through the financials in great detail, we'll assume everyone has indeed seen the press release and the attached financials. From the financial reporting standpoint, there were no significant unusual items this quarter, so my comments should be pretty brief.

As you can see, the discretionary cash flow for the quarter was $116 million or about $2.40 per share, well above our first call estimate, and earnings of just over $29 million or $0.60 per share were also above the first call estimates.

Production for the quarter came in at 217 million cubic feet equivalents a day, up lightly from the first quarter 213. Our oil and gas split remained around 44% and 56% for the quarter, as most of the recompletion projects tended to be gas oriented.

Production for the third quarter is expected to be down a little in the 200 to 210 range, assuming minimal hurricane down time. We'll talk on this more later, but the decline is primarily due to delay in drilling at our Amberjack platform, as well as in the timing of receiving MMS approval on many normal operations, which included our recompletion and work over projects, and obviously that will affect third quarter volumes.

Permits or approvals, which typically might have had a one day turnaround was stretched to a week and a typical one week turnaround at the MMS, were taking a month or longer. However, we are seeing good signs of this paralysis abating, but the delays have indeed impacted our production outlook for the third quarter.

In terms of oil and gas prices, the price realization after hedging came in at just over $72 per barrel and around $5.50 per Mcf, our blended price of $8.31 per Mcfe with oil still representing over 60% of our revenues.

Our hedge position reduced oil prices by about $4 per barrel, but boosted gas prices by about $0.95 per Mcf, so a net gain on hedging of about $7 million when we include the ineffective portion of the hedges. So a small plus on the hedge side for the quarter.

On the cost side our LOE was reported at $37 million, certainly on the lower side of our annual guidance. We continue to keep expenses in check. However, we do expect a little bit of an increase in major maintenance expenditures in the second half of the year.

Note also that we had separately from LOE we had a $2.4 million operational expense related to the cost but we won't stack in the H&P Amberjack platform rig during the moratorium for the quarter and also a small loss from tubular sales out of our inventory. In the third quarter we would also expect roughly another $2 million operational expense that would be recorded in the quarter.

D&A came in at 316 per Mcfe which was in line with guidance. And then our quarterly estimated tax rate included a small negative current tax as we made a few positive adjustments on our estimate of the current tax being due. So again, a little adjustment there.

We also noted in the release our total debt at quarter end was down to $525 million and was split between the $200 million in sub notes due September 2014 to $275 million of our 2017 senior notes and then bank debt at $50 million which is down from the $100 million outstanding at the end of the first quarter.

Also in May, our bank group reaffirmed our borrowing base at $395 million, which leaves us with just over $280 million in availability after adjusting for those, just over $60 million in LCs.

Our reported second quarter CapEx came in just under $100 million. We will expect our CapEx spending rate to increase slightly over the next two quarters as we would expect to recommence drilling at Amberjack very shortly and we'll be accelerating some Marcellus drilling and are also reviewing some additional acreage acquisitions in the Marcellus and expect to have some drilling activity in the Rockies. We are maintaining our $400 million CapEx estimate, although any material acreage acquisition would really be on top of this figure.

Regarding guidance, you might note a couple of adjustments on the production side due to the reasons listed previously. We're keeping the low-end of our guidance figure from the original $205 million to $225 million but we're bringing the high side down to $215 million, so the new guidance would be the $205 million to $215 million, again, within the original guidance but shading to the lower end.

Conversely on the LOE side, we're shifting guidance downward from the $165 million to $185 million range to start with down to the $150 million to $165 million. And this reduction stems from a combination of cost control on our base LOE of a lower major maintenance run rate and some minor adjustments, including a small insurance credit, as mentioned [previously] in our quarter from a financial standpoint.

So with that I'll turn it over to Dave for additional comments.

David Welch

Okay. Thank you very much, Ken. As you've heard, everyone, we delivered a solid quarter, in spite of the moratorium and its related issues. We've been unfortunate not to have been materially impacted by the Macondo incident subsequent federal moratorium.

We are actively working with a number of other companies and national organizations to address the regulatory and legislative hurdles which are challenging our industry right now. Our goal is to remain intact with the opportunity continue our future operations in the Gulf under an appropriate regulatory framework for independent oil and gas companies.

My remarks this morning are organized by the business segments where Stone is active. There are five of these areas to discuss this morning. The Gulf of Mexico conventional shelf, the Gulf deep shelf, Gulf deepwater, the Marcellus Shale and the Alberta Bakken.

On the conventional shelf, our strategy has been and is to focus on oil development drilling and we have one rig that was active, that was impacted by the moratorium, the H&P 206 which is a platform rig, located on our Mississippi Canyon 109 Amberjack platform where we were on the second well of a five-well drilling program. The first well was completed and placed on production in the first quarter and the second well drilled into the top of the pay sand when the well had to be plugged back and then suspended due to the moratorium.

When operations were suspended in lieu of releasing the rig, which took us a couple of years to secure, we and H&P agreed to a win-win deal to warm stack the rig on location, at a reduced rate which allowed the rig to stay on the platform and kept the highly experience crew available to us and this ended up costing us about $5 million total, $3 million in warm stack and a couple million dollars to reinspect and tear down all of the equipment and get it back out on the platform. But it proved to be far less expensive and much more efficient than releasing the rig, demobbing rig, then having to remobilize the rig again in the future.

So the good news is that the new BOE MRE which is the successor to the MMS has now granted us permit to recommence the drilling of our second well at Amberjack. As you probably know the Federal courts ruled that the first moratorium was invalid and a second moratorium which was issued applies only to floating rigs. So this allowed us to receive the permit to continue after complying with the new regulations.

We've not yet received the permits for the remainder of the Amberjack drilling program, but we have resubmitted the permit application that's are compliant with the new regulations and we do anticipate receipt of the required permits before the work on our second well is completed in mid September.

Along with everyone else to comply with the new regulations, we had to send the BOP stack, the choke manifold on shore to be torn down, tested and reinspected, that work has now been done and we expect to have this equipment back on location, reinstalled and ready to get back to operations within the next week.

In the second quarter we also brought online our Cardinal Project at Vermilion 96. This deal was discovered in 2009 and the platform was completed, installed and placed on production June of this year. Cardinal well is presently producing over 5 million cubic feet per day.

We are currently constructing our 2011 budget and expect to continue the focus in the conventional shelf on oil development drilling. We'll be drilling in our larger fields such as Mississippi Canyon 109, Ewing 305 and Ship Shoal 113. We do have a multi-year inventory of opportunities developing oil in these fields, which we believe should help us maintain our oil and gas balance and keep production and cash flow relatively stable.

Turning to some of the exciting growth things happening at Stone, the first is a deep shelf. Expiration in this business segment is consistent with our strategy of investing and primary oil and price advantage gas. In the deep shelf, natural gasses price advantage is due to a high Btu content, its proximity, the existing infrastructure. Unlike the conventional shelf, however, we believe the deep shelf contains undiscovered fuel size potential large enough to extract exploration capital.

In 2010, we anticipate participating in two deep shelf type wells, even though these happen to be just inside the coastline and are actually onshore. We have a 16% working interest in the 21,000 foot South Erath Prospect in Vermilion Parish, which is presently drilling and might be evaluated by the end of the year. And just a comment on the moratorium, the moratorium does not apply to these deep shelf drilling wells.

Then we also have a 25% working interest in the White House bayou prospect in Cameron Parish, which is presently in the permitting stage, and which could possibly commence in the fourth quarter of 2010 or the first quarter of 2011, and would likely be evaluated in 2011.

This prospect is further up in the Gulf Coast basin than some of the deep shelf discoveries you've heard about and it is also lower temperature and lower pressure in either Davy Jones, Blackbeard or Blackbeard East. White House bayou is presently planned to be drilled to a depth of just over 22,000 feet.

In bidding for deep shelf leases in the last lease sale, we face competition from others including Chevron. We were already partners with Chevron in a White House bayou prospect discussed earlier. So we're not the only ones that have identified the potential value in the deep shelf.

As we've mentioned in previous calls, we did contribute lease blocks in exchange for data and a small overriding loyalty interest in both Davy Jones discovery and the Blackbeard East prospect, which operated by McMoRan. So we were successful in the last sale in acquiring some additional blocks, containing deep shelf geologic structures and look forward to drilling those in future years.

Second area of excitement for us in the Gulf is the deepwater, where most of the prospectivity is oil and where the average undiscovered fuel size is still deemed to be huge. Obviously, the Deepwater Gulf is presently subject to the moratorium on drilling. But we believe that once Macondo is finally plugged and cemented, the industry will be in a position to meet the criteria laid out by the Secretary of Interior to allow drilling once again.

These criteria are prevents, intervention and contain on the prevention issue, rigs and critical equipment have been inspected and re-inspected. On the intervention issue, the BP equipment entered and deployed on Macondo can be made available to the industry for rapid deployment and on containment. Again, the rapid deployment of intervention technology combined with the massive amount of booms and other equipment manufactured and used for Macondo can also be made available.

In the intermediate to longer term, four majors have announced plans for $1 billion rapid response system, which should be available to the industry as needed. So we believe that the industry will be able to get back to drilling sometime within the near intermediate term future.

We were fortunate that the moratorium did not materially impact our deep water issues. The Pyrenees development well, which is now drilled and cased and soon to be undergoing tie back activities will still be brought on production in late 2011 or early 2012. We have a 15% working interest in this field and are looking forward to the new production from this discovery over the next several years.

While we were not spending money and are presently not spending money on standby time for any floating rigs, the moratorium has caused a delay and what is a very exciting part of our portfolio. We had planned to spot an additional two to three deep water exploratory wells this year. That looks like it's now going to be pushed out into 2011 or even potentially beyond for some of those. Our partners have indicated that they still plan to pursue our prospects when the moratorium is lifted and that is most likely going to mean these wells will start at the end of 2010 or sometime in 2011. The delay is disappointing but not debilitating for us. We have shifted most of the capital to increasing our position in the Marcellus Shale.

Turning to this third exciting growth area for us, the Marcellus, we have reconfigured and improved our acreage portfolio significantly in the second quarter. As a reminder, we have been studying the Marcellus geologically for almost five years and we believe we have a very good idea of where the best 10 to 20% of the 30 million acre fairway is located.

What we've done in the second quarter is to sell our interest in acreage where we believe the Rock to be of lower quality and to add to our position an areas where we believe the reservoir quality is higher.

Access to markets has also been one of the main criteria for acreage acquisition. So far this year we've sold off about 7,000 non-core acres roughly $30 million and have used that to acquire about 10,000 acres of core holding.

In aggregate, we've increased our total acreage position from about 30,000 acres at the end of 2009 to at present approximately 60,000 acres. But more importantly from the standpoint of what we consider to be top tier acreage, we've gone from 16,000 to 48,000 net acres. So not only is our total acreage count significantly higher, but the quantity of quality acreage has also dramatically improved.

Operationally we're now well into our 14 well horizontal drilling program plan for 2010. We're running three rigs out of our Morgantown office at present. One rig drilling the vertical portions of the wells and two rigs drilling the horizontal portions. Thus far we have completed the vertical portions of eight wells and the horizontal portions of four.

The four completed horizontal wells are waiting fracturing, which has commenced this quarter and which we hope to have some initial well rates to report to you at our next call. We are testing the optimal lateral links and have drilled wells with laterals ranging from 2,000 to 4,500 feet four wells we've built to date, the remaining 19 will have laterals ranging from 3,600 to 4,500 feet and we're generally running anywhere between 7 to 12 stage fractures in each of these wells.

If these wells perform as anticipated, we expect that between our activities in the Gulf and in Appalachia will be well positioned to organically more than replace our production and grow reserves for 2010. And our preliminary budget forecast the same for 2011 as well. So we're hopeful that this is a year we turn the corner and begin to consistently grow reserves organically.

Just a quick word on the Rockies, we have three low cost horizontal exploratory wells authorized in the Alberta Bakken for 2010. We have a 35% working interest in these wells which are operated by Newfield. Two of these wells have had the vertical portion drilled and the vertical portion of the third is drilling at the present. The horizontal portions will be drilled subsequent to well log and core analysis of the vertical portions of the well.

So we will not know whether this play is commercial until the wells are fragged and tested which is scheduled for late 2010 or early 2011. We have approximately 35,000 net acres perspective in this play, so if it does work, we would have some good running room to develop an all resource play in Montana.

So with this, we'll be happy to take your questions. Mason.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Oliver Doolin from Tudor Pickering Holt. Your line is open.

Oliver Doolin - Tudor Pickering Holt

I was just wondering could you maybe comment a little bit on the Pyrenees. We were wondering maybe what your CapEx plans are going to be for 2011, assuming the moratorium gets lifted, call it, first quarter 2010.

David Welch

We tend to give you the financial number and how much we might be spending on that next year. But just to reiterate, the moratorium really does not have any impact on Pyrenees. The well is already drilled. It's already completed. All we need to do is tie the well back and put it on production. And, Ken, do you recall the…

Ken Beer

Yes. The CapEx required for that at a 15% working interest is not a big number. It will be easily rolled into our 2011 budget. But today's point the current plan is to just move forward with a tie back. And so at present we do not have another well in 2011 CapEx budget if that's what you're getting at. It's really just a simple tieback and would hope to have that work done sometime late 2011.

Oliver Doolin - Tudor Pickering Holt

And then as far as your Rockies production plans, can we get any more clarity on when you expect to have those production rates for us?

David Welch

Well, like I said, the vertical portion is being drilled now. What we and the operator will all be doing is going through and looking at the well logs, determining where we want to put the horizontal portion, then the horizontal portions have to be drilled, then the wells have to be frac tested. And the operator is saying that that could take place in the fourth quarter of this year or first quarter of next year.

Operator

Your next question comes from the line of Richard Tullis from Capital One Southcoast. Your line is now open.

Richard Tullis - Capital One Southcoast

Looking at the permitting process in the Gulf of Mexico, I know you had mentioned at the beginning of the call that it's starting to open up a little bit. How many requests have you made, say, over the last couple of months for your Gulf of Mexico wells.

David Welch

Yes, Richard, the big thrust obviously for us has been to try to get Amberjack back up and running, so that's been where we've been more focused. We originally had a couple of conventional wells that we would have looked to started to drill sometime late in the summer, early fall. We have not put forth those permits. So right now the focus from us from a permitting standpoint has just been on Amberjack. And as Dave mentioned earlier, we think we are in a position where we've got all of our ducks in the row there and would hope to be continuing the drilling of the Vili Prospect sometime within the next week or two.

Richard Tullis - Capital One Southcoast

Okay. As you know the House passed its version of the Drilling Reform Bill last week with a clause on pending lifts liability cap for economic damages. And I just wanted to see what's your thoughts on that. I know the Senate is not going to vote on the bill before they break for their recess, but I just wanted to get your thoughts on it and just would you even consider going back to drilling if, say, the final version of reform bill has an unlimited liability clause in it for economic damages? What are your thoughts around all of that?

David Welch

Well, I mean, its way too early for us to be speculating in terms of what the outcome of all of this might be. All I can say is that it feels like cooler heads may prevail and the more time that's available to them to think about the real issues, the better legislative solution I believe that we'll end up with. We will just have to evaluate the legislation as if anything actually becomes law before we would determine exactly what we were going to do. Ken, you got any other?

Ken Beer

Richard, certainly we have been in touch with and have been pinning the insurance market to just get a sense as to what additional capacity might be there and what might cost. Currently, as you might be aware, we've got the $7 million worth of general liability coverage. If that number is forced to move upwards, again, it's just a cost issue and ultimately a capacity issue. Obviously you can't go to infinity. The insurance market would look to bring you up to a certain layer or certain level. But as Dave pointed out, I think we are too early to speculate as to exactly how the industry would adjust or perform. But from an insurance standpoint, we're at least making sure that we're in touch with the insurance markets to see what might be out there and what the cost might be. But at least for now, we're obviously happy to just keep our $75 million general liability level and kind of move ahead and move forward until the legislation either happens or doesn't.

Richard Tullis - Capital One Southcoast

Okay.

David Welch

Just from a practical standpoint, there are a few things to keep in mind as well regardless of what comes out in legislation. And one is that the likelihood of one of these things happening is very, very remote. This is the first blowout in the U.S. Gulf of Mexico since 1971. And whenever these rare events happen, people tend to underestimate the probability of one happening until one happens and then after that they vastly overestimate the probability it's going to happen again. That's one thing.

The other thing to keep in mind is that we have seen BP over the last 60 or 90 days really invent a new capture technology to be able to get back on this well bore. Can you imagine if one of those were already built and ready to deploy in two or three days instead of two or three months. The amount of oil that would have been spilled would not have been anywhere near the massive spill that we had here, probably limited to 1 to 10% of the amount of oil that actually got loose. And the four majors say they're going together to build this containment system.

And then finally we've got a lot more as an industry a lot more booms and everything else sitting out there to be able to get it to protect the shore faster. So when you put all of those things together, it feels to me like the real risk is not what comes out of legislation. It's how well are we as an industry prepared to deal with any potential highly remotely probable event. And I think we are positioned hugely in a better place than we were before Macondo obviously.

Richard Tullis - Capital One Southcoast

And I guess from a practical standpoint, you always get unlimited liability on clean up anyway.

David Welch

That's exactly right.

Richard Tullis - Capital One Southcoast

And lastly for me, what's the expected cost for the deep shelf wells?

Ken Beer

These wells vary in terms of their total cost, but they're generally in the $30 million to $40 million range.

Yes, Particularly, Richard, these are, as Dave mentioned in his remarks, these happened to fall just barely onshore. So the rig costs are far lower than which you might find offshore.

Richard Tullis - Capital One Southcoast

Excellent, and I guess its Louisiana jurisdiction as well?

David Welch

That's correct.

Ken Beer

Correct.

David Welch

So they're not subject to the moratorium whatsoever.

Operator

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

Jeffrey Robertson - Barclays Capital

Thanks. Dave, can you talk a little bit about your prospect generating efforts on the deep shelf in the context of the results you've seen so far from Davy Jones and the appetite for that play as you all formulate your 2011 budget.

David Welch

Yes. Jeff, very good question. We do have some data on Davy Jones and some of the other deep shelf wells that have been drilled out there. And the logs are very impressive. We've taken the tact that we know that some new equipment has to be designed and built before those wells can potentially produce. And so what we have done is gone up with the same type of play concept that moved up shallower in the basin.

In other words, our wells are targeting at kind of 21, 22,000 feet in depth as opposed to Blackbeard's over 30,000 feet deep. So we're at a lot lower pressure, lower temperature. The equipment to produce those wells exists off the shelf today.

So we believe if we make a discovery there, we're not subjecting ourselves to risks of equipment being developed that might be delayed or whatever the lower pressure, lower temperature certainly make it easier and more conventional in terms of the ability to produce them. So we're very hopeful that the Davy Jones and Blackbeard type of ultra-deep prospects work out, but as for right now we're not betting on that at the moment.

Jeffrey Robertson - Barclays Capital

And secondly, Dave, in the Marcellus, can you talk about how much of your acreage will be tested with your initial round of horizontal drilling.

David Welch

Well, we're actually testing portions pretty much spread across our whole acreage spread. So we'll have a very good indication after our program this year of just how our portfolio looks. And we already have a pretty good indication, Jeff, because you may recall we did drill about 10 vertical wells last year.

Jeffrey Robertson - Barclays Capital

And do you anticipate that you'll be able to expand your acreage position significantly from where it is today just given the market up there and the areas you've interested in.

David Welch

Over time I think that's certainly feasible. What we're trying to do, Jeff, is to manage our acreage buildup with our ability to make sure that we cannot only drill horizontals and book proved develop reserves but proved undevelop reserves.

We want to make sure we can get to the proved undevelop portion within the five year period required to keep the reserves on the books. So we don't want to just put them on the books just to end up having to take them off through four years later because we didn't get to all of the parts.

So between the balance of being able to drill all of the acreage we have now, I do think that we'll have the opportunity to improve our acreage position in the future. And I would expect that you might see some ramp up in our acreage within the next year for sure.

Operator

Our next question comes from the line of Kelly Krenger from Bank of America. Your line is now open.

Kelly Krenger - Bank of America

Hi. Thank you. Just a couple of questions. The CapEx is unchanged at $400 million. What's the kind of current distribution of that CapEx now among your different areas?

Ken Beer

We had some guidance figures out at the start the year and interestingly enough even though deepwater has obviously been pushed off the radar for 2010, we do have now a couple wells deep shelf. But it's still going to be roughly that 50% is going into the Gulf of Mexico conventional shelf and that's a combination of drilling as well as P&A as well as recompletions and work-overs. And then probably a little more than 25, maybe 30 plus percent is now more into the Marcellus, with the remaining 20% covering deep shelf, dollar still spent in the deepwater and that would include leases in seismic, etcetera, and then activity in the Rocky Mountains. So kind of 50%, 30%, 20% is not a bad guesstimate for the breakdown of this year.

Kelly Krenger - Bank of America

Okay. And I think also at the beginning of the year you anticipated that between Amberjack and maybe some, I can't remember if it was just Amberjack or a combination of Amberjack and some of what you were anticipating out of the Marcellus would keep production flat, with Amberjack being pushed out a little bit. It sounds like you still kind of believe that, I think what do you have, three or four wells left to go on Amberjack, that that will keep your production profile flat for a few quarters at least while you kind of ramp up production maybe in the Marcellus? Is that a reasonable way to look at things?

David Welch

Correct. And that's really what we're looking at. Obviously, the range we'd given in the beginning of the year of 205 to 225, we were heading towards the upper end of that range I think with some of the delays in both drilling at Amberjack and then overall delays on work-over and recompletion projects. That's kind of shifted down for 2010 and yet we're looking to continue with that approach of just trying to keep production relatively flat while generating excess cash flow to go into the Marcellus, go into the deep shelf and go into deepwater and a little bit into the Rockies. So we'll continue that investment approach, but you're correct, one of the keys is to keep production pretty flat around this level.

Kelly Krenger - Bank of America

And broadly, from kind of a cash flow and CapEx and balance sheet standpoint, I'm sure it's way too many moving pieces to give a sense for much past this year, but what's kind of your view on managing cash flow and CapEx? Is that going to run kind of so that they're equal, or I guess how do you view it in context with the balance sheet right now?

David Welch

It is kind of our general principal is to keep our CapEx within our cash flow. And if we see some unique thing that just is so compelling, we night deviate from that, but thus far we've been pretty disciplined.

Kelly Krenger - Bank of America

Okay.

Ken Beer

Yes, and to a certain extent, Kelly, you've seen in the first half of the year in fact we paid down debt, we paid down $50 million. I think I alluded to over the back half maybe we'll take some of those borrowings back and yet the concept is let's stay roughly within cash flow. As Dave mentioned if there are some unique situations, we might veer from that. But at least the initial mindset that we have going into our CapEx program is to keep it fairly close to cash flow.

Kelly Krenger - Bank of America

And I guess one last one on just kind of what you're seeing in the M&A market in the Gulf, if there is one right now. Is that something that would be interesting to you from where you would look to deploy dollars or not?

Ken Beer

It's always interesting to us, but I think we've got some really good potential opportunities that we have come up with, prospects and that kind of thing which would typically be higher return than you might get on in acquisition, so it would have to be something very unique to attract any dollars out of our capital budget for sure.

Operator

(Operator Instructions) Your next question comes from the line of Richard Tullis from Capital One Southcoast. Your line is open.

Richard Tullis - Capital One Southcoast

I just have one follow-up. For the Marcellus acreage, what's the distribution by county or just general area now that you've sold some acreage and acquired some new acreage?

David Welch

Yes, we've got about maybe 20% Northeast Pennsylvania. And these are pretty rough numbers so I'm just kind of going from a map I'm visualizing in my head but a little about 20% up in the Northeast Pennsylvania, probably 30% in Western Pennsylvania. And then about half of it is in Northern West Virginia.

Richard Tullis - Capital One Southcoast

Okay.

David Welch

Is that right, Ken?

Ken Beer

Well, that's pretty close.

Operator

Your next question comes from the line of Dave Kistler from Simmons & Company. Your line is open.

David Kistler - Simmons & Company

Real quickly on the credit facility just as a little bit of a refresher, when they redid it in May, were they considering the potential impacts of Macondo and a moratorium at that point and does that create any kind of, I don't know, I guess concern or reason to believe they might adjust it differently at the next redetermination?

Ken Beer

Certainly, I think Macondo has put some additional nervousness in the bank group. And yet as you pointed out, obviously, the redetermination was completed post the actual spill or event, incident itself. Somewhat nice to kind of have the summer behind us with the well hopefully being killed and we'll certainly look to have additional discussions as we go into the fall redetermination.

But I think if you look at what the affect of Stone either drilling or not drilling in the deep water on the expiration side, I think that doesn't have a whole lot of impact on a bank borrowing figure. In fact, you could almost argue that it's not really weighed at all.

And they will continue to look much more of just crude producing properties. Obviously, Amberjack coming back on, not only it's remained online but in terms of coming back on to Amberjack to continue with some of the drilling plans, I think that will certainly be embraced by the bank group and obviously something that's pretty important to us as well.

David Kistler - Simmons & Company

And tying that to your comments about staying within cash flow really over the next year or so and realizing there is almost $280 million, $300 million available under that borrowing base, not a huge concern if it moves around a bunch. But should we think about that borrowing base as kind of dry powder in the event that Deepwater Gulf of Mexico becomes for reasons unbeknown to all of us right now, but something that you can't go after going forward just because the liabilities are too big based on whatever the government decides? Do you look at that as sort of the dry powder to figure out kind of what other plays you might get involved with to kind of facilitate a longer term growth strategy?

David Welch

I guess, that would be one way to think about it, David. We kind of think of it as dry powder to protect us against any unforeseen liquidity things that might pop up on the horizon. I think we're pretty well positioned with places to redeploy capital away from deep water if it were required. Obviously the moratorium and the liability is not going to have any impact really on our Marcellus or Rockies areas. We've got another area that we're kind of looking at. I think we would just try to do that, not deviating too much from cash flow.

Ken Beer

But I was going to say, Dave, your observation is a good one. And if there may be some flexibility needed to kind of shift gears, but as Dave mentioned, I mean at this point we are moving ahead in our deep water program in the sense that we're not adjusting it. And if our partners move forward, we'll look to do so as well. But it does provide a bit of a buffer if we need to have some sort of a shift from one area to another.

David Kistler - Simmons & Company

And then, Dave, just following up on your comment where you said there is another area that you're looking at, is that onshore, offshore, can you give us, I'm not trying to play hot cold here, but try to point us in the direction?

David Welch

No. It's offshore. It's another onshore area. And we're very early stages of it. So I really can't even call it another area. It's just more or less an area of interest for us.

David Kistler - Simmons & Company

And just one last question on that framework.

David Welch

Yes.

David Kistler - Simmons & Company

Oily, gassy, just trying to think about product mix that you would be targeting going forward?

David Welch

Well, you know our strategy is either primary oil or price advantage gas. So it would either be oil or wet gas.

David Kistler - Simmons & Company

And then one last one just on the deep shelf stuff. Obviously pressures are lower. Do we think that we'll get any kind of pushback in the deep shelf just in general associated with people reassessing risks in the Gulf of Mexico? I know you guys are onshore, but obviously we've got a little bit of a different pressure regime and everybody, as you highlighted, pretty nervous?

David Welch

There could be, several factors work in your favor. One, the deep shelf is mostly a gas province. So you don't have that big threat of a big oil spill like you had at Macondo. That's one thing.

The second thing is that it's been a very, very long time since people had issues drilling on the shelf with respect to not being able to control their wells.

David Kistler - Simmons & Company

Yes.

David Welch

And equipment has continued to improve. You're going to now probably see some additional levels of redundancy in equipment. You're certainly going to see more frequent inspections. So I just think it's going to settle down here within some period of time, and I'm sure you probably saw this morning although it's early, California is still that BP did effect the static kill on Macondo and that will pave the way from the pump cement to that, get that thing gone once and for all which I think is going to be very helpful in terms of allowing cooler heads to prevail in terms of what type of legislation and regulation comes out.

Operator

Your next question comes from the line of James Sivigny from Deutsche Asset Management. Your line is now open.

James Sivigny - Deutsche Asset Management

I just wanted to press you a little bit on the Montana Bakken, if I could. My sense is that you guys and Newfield have had a good working relationship for some time, and I guess I'm just wondering if the first two wells two wells are commercial, simplistically that acreage seem like it might be a very attractive means of maintaining and growing your oil production on a risk basis. And as you think out to 2011, what's kind of the toggle there in terms of spending? Would you go into Newfield and want to allocate more capital there? And what are we talking about in terms of magnitude assuming that the first two wells are commercial?

David Welch

Well, let me just say we've got two verticals down and drilling another vertical. So we'll probably have three horizontal tests. Let me just say that this is a rank wild cat. Okay. It is not the same Bakken that people are producing over there in North Dakota and Wyoming. It's basically a completely different basin. So I don't want to get people thinking that this thing has got a real high probability, it's going to work. But if it does work, it does have a lot of running room for us and I would see Newfield and stone significantly ramping up the number of wells drilled next year versus what they're drilling this year. So I don't want to come out with a number, because I don't know what their number is. But it wouldn't be unreasonable for them to drill ten wells or something next year.

Ken Beer

And, Jim, Newfield will certainly be the driver there as a 35% non-op. I don't think we would look to push the timetable. We would really be more reactive to Newfield on that play.

James Sivigny - Deutsche Asset Management

Fair enough. Thank you.

David Welch

And the reason for that is that is that just the operators got to find the rigs. They got to have to have the people. You don't want to push them beyond a pace that they're capable of drilling the wells efficiently.

James Sivigny - Deutsche Asset Management

Just asking if you would put in the call, that's all.

David Welch

Well. If they work, we'll be definitely talking quite often.

Operator

And there are no further questions at this time. I'll turn the call back over to leadership for any closing remarks.

David Welch

Okay. Thank you everyone for being on our call. We appreciate the interest in Stone and we look forward to talking to you again shortly.

Ken Beer

Thank you.

Operator

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

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Source: Stone Energy Corp. Q2 2010 Earnings Call Transcript
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