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Executives

David Welch – CEO

Ken Beer – SVP and CFO

Analysts

Brian Lively – Tudor Pickering Holt

Dave Kistler – Simmons & Company

Richard Tullis – Capital One South

Stone Energy Corporation (SGY) Q3 2009 Earnings Call Transcript November 4, 2009 11:00 AM ET

Operator

Good morning, my name is Darryl and I'll be your conference operator today. At this time I would like to welcome everybody to the Stone Energy third quarter 2009 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).

I would now like to turn the call over to the Stone Energy CEO, Mr. David Welch. You may now begin, sir.

David Welch

Thank you, Darryl. Good morning and welcome everyone to our third quarter conference call. Joining me today is Ken Beer, our Chief Financial Officer, who will provide some color commentary on the financial results we announced last night. Ken will then turn it back over to me to provide you with a progress report on the execution of our strategy to grow gas reserves and production and price advantage basins and to grow oil in high margin basins, which usually means low cost primary recovered projects. After this we will have time for our Q&A. And Ken?

Ken Beer

Yes, thanks, David. We'll start with the forward-looking statement. In this conference call we may make forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties normally incident to the exploration for and development, production and sale of oil and gas.

We urge you to read our 2008 Annual Report on Form 10K 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, this call may refer to financial measures that might be deemed non-GAAP financial measures as defined on the Exchange Act. Please refer to the press release we issued yesterday which was posted on our Web site for reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures.

Finally, in this conference call we may refer to the term, probable and possible reserves, which the SEC guidelines currently prohibit us from including in SEC filings. Please reference our disclosure in the press release which was issued today that addresses this issue.

Let me start rather than going 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 only a few unusual items this quarter so my comments should be brief.

Our discretionary cash flow for the quarter was $107 million or about $3.25 per share substantially above the First Call estimate. Earnings of $51 million or $1.06 per share were also well above the First Call estimates.

As was the case in last quarter the third quarter figures incorporate the impact of the March unwinding of some hedges. Remember the effect of the unwound hedges flow through the income statement and into cash flow during the quarter for which the original hedge was put in place, in this case the third quarter despite the transaction occurring back in March. As noted in the release third quarter included about $36 million pretax or $23 million after of the previously transacted hedge benefits.

Another unusual item impacting the revenue line was a one-time positive adjustment on previous volumes associated with royalty relief. This amounted to about 0.7 Bcfe a day or 8 Mcfe a day of production added to the quarterly results.

This recognition of volumes stem from a recent third-party court decision involving royalty relief production going back to 1999, which we had not previously recognized. This adjustment added about $5.6 million to third quarter revenues and we would not expect any adjustments or additions going forward.

And the final unusual item to highlight is the lease operating expense accrual adjustment of $12 million. This figure incorporates the truing up of the initial accrual LOE estimates in the first half of the year to the actual expenses associated with various major maintenance projects and base LOE.

Now let's review the quarterly results. Production for the quarter came in at 239 Mcfe per day or 231 Mcfe a day excluding the royalty relief adjustment, still well above the second quarter volumes of 205 Mcfe per day, and substantially all of the hurricane related pipeline issues were resolved early in the quarter including the Tennessee Bluewater pipeline repair and our rerouted Amberjack oil line. Obviously, the other major factor positively impacting production was not having any down time associated with hurricanes, knock on wood for that.

As noted in the release we expect the fourth quarter volumes to be in the 225 per Mcfe per day to 235 per Mcfe per day range with the full year 2009 production guidance being in the range of 210 Mcfe per day to 220 Mcfe per day. Volumes for the month of October averaged around 240 Mcfe per day with oil remaining just under 50% of that mix. We do expect some down time at Amberjack during the quarter with the installation of the platform rig this month and it incorporated this in our guidance.

Oil and gas price realizations for the quarter came in at over $70,000 per barrel and 590 per Mcf or blended price of over $9 per Mcfe. That's highlighted before oil and gas split is now about 50/50, so our overall price realization is more skewed to oil and most (inaudible) players which further enhances our weighted average realized price.

Our hedge position increased prices by almost $11 per barrel for oil and 237 for gas adding a total of about $46 million to quarterly revenue. As noted earlier this includes 36.5 million recognized this quarter from the unwinding of the hedges back in March. Since our last release we have not added any more hedges and our hedge schedule is in the release.

On the cost side, our reported LOE was $28 million. It's noted this figure was positively impacted by about $12 million and accrual adjustment tied to the over accrual from the first half of the year. Another reason for the low third quarter LOE was that we've pulled back on some of our normal major maintenance projects during the quarter due to previous liquidity concerns.

Including the accrual adjustments, we now expect to have our full 2009 LOE in the range of $160 million to $175 million, down significantly from the initial estimate at the beginning of the year of $190 million to $210 million and we've reflected this now in our updated guidance. It has been an impressive accomplishment from our operations group.

DD&A per Mcfe came in at $3.06, a little above guidance, partially due to low quarter-end gas prices and also partially due to the minimal reserve adds during this period of in-activity. And we've shifted our updated guidance to incorporate a slightly higher figure.

Reported interest expense was $5.2 million, with another $6.6 million in capitalized interest or $11.8 million in total cash interest.

As noted in the release our total debt at quarter-end was $650 million, down $175 million from December 31st and is split between the $400 million in sub-notes and $250 million in bank debt.

At October 30th our bank debt had been further reduced to $225 million or a full $200 million reduction for the year. We also have just under $69 million in LCs which leaves over $131 million in availability on our borrowing base, which was reaffirmed last month. Our cash position was about $91 million at October 30th which leaves us with over $220 million in liquidity.

Regarding CapEx, our third quarter CapEx was about $70 million, which included about $33 million spent on proactive hurricane risk mitigation work. This initiative includes enhancing the structural integrity of selected platforms as well as the plugging of a significant number of idle well bores or higher risk platforms. We believe we have dramatically lessened our hurricane cost exposure through this program, which is now substantially complete.

We would expect the fourth quarter CapEx to be approximately $70 million as well, which would get us close to our Board authorized $300 million CapEx budget for the year. The CapEx in the fourth quarter incorporates an early start on the drilling program at Amberjack, the drilling completion of the Cardinal/Blue Jay prospects and the additional drilling activity in purchased acreage in our Marcellus Shale play in Appalachia.

With that, over to Dave for additional comments.

David Welch

Thank you very much, Ken. The Gulf of Mexico shelf is our cash flow engine. It's our intent to keep it running in good form to provide a time bridge of production and cash flow until our growth engines in the Marcellus Shale and deepwater can ramp up.

Thanks to the Bois d’Arc merger last year, we have visibility into three years to five years of oil development drilling and more approved developed non-producing or behind pipe reserves than we have proved developed producing or producing reserves online right now. These two items should combine to keep our shelf production relatively flat for the next several years

The Gulf of Mexico shelf is still over 99% of our production and has helped us deliver a much improved balance sheet and a strong quarter underpinned by both production growth and decreased cost.

We have worked hard to capture both of these benefits and are enthusiastically once again focusing our attention to the business of finding, developing and producing new oil and gas reserves.

Production increased near the top end of our guidance as we executed 100% success rate hydraulic rig work over program, decreased cycle time for restoring off production wells, de-bottleneck platforms and optimized individual well rates.

In the third quarter, we also completed recovery of essentially all of the previous years' hurricane deferrals including simultaneously barging oil from Amberjack, while rerouting its export pipeline away from the mudslide areas north of the field.

We were able to reduce operating costs as we continued to capture synergies from last year's merger, streamlined offshore transportation, and rebid contracts for most of our major suppliers and services.

In addition, even in this year of tight capital, we've just about completed the theoretical hurricane risk mitigation of our offshore platforms. We're investing over $55 million to abandon 162 idle wells to mitigate the cost of recovering these wells in the future and the risk of platforms capsizing in future storms. We also decommissioned six platforms and 14 pipelines further de-risking the impact of any future hurricanes.

We have now moved the high risk portion of our asset base to a risk rating of less than 4.5 on a scale where we've never lost a conventional platform having a risk rating this lower and lower. We believe it's more cost-efficient to mitigate this risk than to insure it. And this work and the investment are now largely behind us.

Also, in the Gulf of Mexico shelf, we are advancing a multi-year inventory of drilling prospects to help maintain the relatively stable production for the next few years.

Our top three oil fields, Mississippi Canyon 109 or Amberjack, Ewing 305 and Ship Shoal 113, each have a couple of rounds of high margin, high return oil development drilling programs to underpin production stability on the shelf.

We treated this year in two parts. The first half in which we manage primarily for liquidity and the second in which we once again begun executing plans for growth. This quarter as we got back to drilling we made a discovery with our Cardinal prospect at Vermillon 96.

This will be helpful in maintaining cash flow and should add five Mcf a day in rate to 10 Mcf a day in rate beginning sometime in 2010. We drilled this well while rig rates were low and expect to have a platform built to come online in the second quarter or third quarter.

Also, on the shelf, importantly, we're gearing up to place a drilling rig on our Mississippi Canyon Amberjack field platform. This is our largest field and our engineering group has been able to develop a safe procedure to shut the field in for only a few days instead of the month originally contemplated to install the rig. We expect to commence operations there in early December with a work-over project followed by four wells in 2010.

Turning to our first growth engine, the Deepwater Gulf of Mexico is consistent with our strategy to pursue low cost primary oil reserves. In the third quarter, at Garden Banks 292, 293 our partnership completed the Pyrenees discoveries first appraisal sidetrack and we believe the discovery will likely be commercial, even though the project is not yet sanctioned.

We are planning to drill another well in 2010 and then design the development and hopefully sanction the project leading to first production by 2012. Also in the third quarter, we picked up a 75% working interest in four deepwater blocks in De Soto Canyon, which contain the Jager and the Bobcat prospect [ph]. We won't drill these blocks at that high of a working interest of course, but having it now should give us additional trade currency in the future.

In 2010, we anticipate participating in two to four deepwater exploration wells. This is an important inflection point for Stone, as we turn from spinning the majority of our budget on seismic data and leasing to actually drilling. We can only add reserves and production by drilling and we're excited about getting ready to ramp up our activity in deepwater.

Our 2010 partner meetings are not yet complete so the exact deepwater projects drill next year are not absolutely certain, but they may include projects like the invader prospect, which is now called Floyd at Green Canyon 451, Phoenix at Lloyd Ridge 410 and possibly one or two other prospects, which are not yet determined.

Our other main growth engine, the Marcellus Shale, is also consistent with our strategy of developing price advantaged gas and world-class hydrocarbon basins. Being near the large east coast markets in an area with major trunk lines creates a commodity price generally higher than that of Henry Hub.

In the Marcellus, in the third quarter, we continued to build our position and started drilling wells. We've increased our 30,000 net acre holding slightly and may increase our position further in the near-term to intermediate-term.

We recently picked up two company operated rigs in the Marcellus, which are overseen by our Morgantown office and plan to drill six vertical wells by the end of this year. The wells drilled so far appear to have excellent well log responses and we're in varying stages of drilling, completing, fracturing, and testing these wells.

We plan to report these results to you in the first quarter and also expect to shift from vertical to horizontal drilling about this time. We plan to have our first horizontal well drilled and completed before the end of the first quarter.

Looking forward to 2010, our very preliminary capital allocation looks to be around $350 million, which is up about 15% from 2009 spending. This figure is preliminary, not yet approved by the Board, therefore it is subject to change, but in rough numbers we'll likely allocate about half the money to maintain production and assets on the shelf and split the remainder between deepwater and Marcellus.

In summary, we've shifted away from liquidity management to a disciplined organic growth mode and are poised to continue our recent successes.

With that, we'll now be happy to take your questions. Darryl, would you queue up the calls please?

Question-and-Answer Session

Operator

Sure. (Operator instructions) Your first question comes from the line of Brian Lively from Tudor Pickering Holt. Your line is now open.

Brian Lively -- Tudor Pickering Holt

Good morning.

Ken Beer

Good morning, Brian.

Brian Lively -- Tudor Pickering Holt

On the Amberjack drilling program what are you guys expecting in terms of drilling complete cost per well production rates and ultimate recoveries?

David Welch

I don't have a breakdown on per well cost. The overall programs in the $65 million to $70 million range and on the rate side of it we anticipate adding up to perhaps 6,000 barrels of oil a day production.

Ken Beer

Brian, it's Ken. Just to make sure you're not just adding on top, obviously that will help mitigate a lot of the production, the natural decline that we would have, so that's --

David Welch

And it will come on sequentially. They won't all pop on at the same time.

Ken Beer

Correct.

Brian Lively -- Tudor Pickering Holt

That's helpful. In terms of going back to the cost for a second, what types of day rates are you seeing or expecting, I guess for this platform rig?

Ken Beer

Again, why don't we give a range? I mean the platform rig would come down to I want to say kind of $45,000 a day to $50,000 a day type on or maybe high, I think $45,000 a day to $55,000 a day, something like that, but the point is there's a lot of additional incremental costs associated with the day rate, overall day rate, but we felt like the economics on this project we think are one of the best in the Gulf. I mean this is going to be adding rate immediately to the drilling off the platform. It's oily and it's adding primarily just new reserves, so this is at least in our minds, one of the highest return projects we have in looking forward to having the platform rig available to start drilling.

Brian Lively -- Tudor Pickering Holt

Okay, that's helpful. Just shifting to the deepwater and kind of your allocation, I think you had said previously that the two deepwater wells to four deepwater wells for next year would be spaced evenly through the year. Are you still kind of on that in terms of your visibility on how the CapEx will be spent?

David Welch

It's pretty difficult to predict exactly when the spending is going to occur on those. As I mentioned in the text, we really haven't completed all the round of partner meetings yet, so, we do anticipate spending on deepwater pretty much throughout the year, but we may not have a well drilling at the beginning of the year, so it could be a little bit lumpy.

Brian Lively -- Tudor Pickering Holt

And last question, just on the Marcellus horizontal program. You're talking about the first, your first horizontal well being drilled and completed by the end of the first quarter. Is that going to be in Susquehanna County or is that going to be down in the Southwest area?

David Welch

I really can't tell you which one we're going to drill first. We hope to get horizontals drilled in both locations there next year, but we should be drilling in both of those next year and I'm not sure whether first one is going to be in West Virginia or Susquehanna.

Brian Lively -- Tudor Pickering Holt

Okay, any estimate on the actual number of gross wells you'll drill horizontal wells?

David Welch

No, let us get through this next Board meeting and have our preliminary budget assessed before I can give you a figure on that, but I would anticipate that we will have a pretty fair allocation to the Marcellus next year.

Brian Lively -- Tudor Pickering Holt

Great. Thanks, guys.

David Welch

Okay.

Operator

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

Dave Kistler -- Simmons & Company

Good morning, guys.

Ken Beer

Good morning.

David Welch

Hi, Dave.

Dave Kistler -- Simmons & Company

Hey, last quarter and obviously, we're probably a little ahead of tying things down, but last quarter you'd mentioned 2010 CapEx was going to be allocated about a third, a third, a third deepwater Gulf of Mexico Marcellus and shelf and now kind of splitting that half to the shelf and half to deepwater and Marcellus, any kind of refinement we should be taking away from that? Is the shelf economics exceedingly attractive right now with bounce back in gas prices, rig costs, etc..?

David Welch

Right. Let me just clarify that a little if I could, Dave. What we were talking about is a third of our drilling cost, okay? And on the shelf we also have maintenance and other costs so roughly half of the total capital go to the shelf, but probably a third of the drilling capital will go to the shelf.

Dave Kistler -- Simmons & Company

Okay, that's helpful. And then maybe just to dig in a little bit on the shelf economics with Cardinal and Blue Jay. Can you kind of walk us through your thought process on those types of targets, what your size are, what kind of gas price relative to rig rates that are generating a rate of return that make sense to go after it in this environment?

David Welch

Yes, first of all let me just say that the drilling on those gas projects on the shelf is a little bit more of an eclectic mix than it is a strategy and we have seen and have had the opportunity to pick up some rigs from time to time at significantly large discounts from what we would have had to pay last year. So when you combine that with the fact that you can get them on production pretty quickly that we get a little bit of a premium typically because of BTU uplift on Gulf of Mexico gas, those combined to make some of these gas plays economic, but our primary focus next year on the shelf is going to be drilling for oil at Amberjack. That's where the majority of our capital is going.

Dave Kistler -- Simmons & Company

Okay, that's helpful. And then just on the risk mitigation efforts that you guys moved forward with, how does that impact kind of the outstanding letters of credit that you have against that and how should we think about that from a cost perspective going forward? Obviously, I guess out of our models we should take out any kind of actual insurance payments, etc.,?

Ken Beer

Yes, it's Ken. Couple things. On the outstanding LCs there will be some slight adjustment downward. We're still kind of going through some of those numbers, but obviously there will be some positive adjustment from our standpoint. And then on the insurance side again, it's just a funny market and I would say unpredictable market so the thought processes was rather than lien on the insurance market let's lien on ourselves, and put a lot of dollars, insurance dollars, if you will, into one-time projects and put it behind us.

And as you may remember we're on a May to May insurance year, so we'll just look to see how that market evolves in the next four months or five months, but we feel like we have mitigated a lot of potential costs associated with another big hurricane coming through this risk mitigation effort, and as Dave pointed out, this whole project is now substantially behind us, I mean so we don't have to do the same thing year-over-year.

Dave Kistler -- Simmons & Company

With that in mind then when I think of your liquidity or the cash available, is there a portion of that that I should just set to the side and assume it's going to be kind of inventoried for self-insurance going forward?

Ken Beer

To a certain extent, there's certainly been in the past and certainly going forward, there was some sense of being self-insured. We certainly had not insured all of our platforms. So there is an element of risk that we're bearing, but as we mentioned we think so much of that now has been mitigated by this current program.

Dave Kistler -- Simmons & Company

Great. Well, that's very helpful, guys. Thanks so much.

David Welch

Okay, David, thank you.

Ken Beer

Thanks.

Operator

Your next question will come from the line of Richard Tullis from Capital One South. Your line is now open.

Richard Tullis -- Capital One South

Thank you, good morning.

Ken Beer

Hi, Richard.

Richard Tullis -- Capital One South

Getting back to the production outlook going forward, I know David had mentioned that the shelf production should remain flat for a couple of years now and that makes up the majority of your production stream right now. Are we talking about from current run rate of about 240 million a day?

Ken Beer

I guess we're thinking more in terms of the 2009 guidance of 215 million to 220 million, something like that.

Richard Tullis -- Capital One South

Okay. All right. Thank you. That's helpful. In the Marcellus you'd added some acreage. What's your total acreage position now?

David Welch

It's a little over 30,000 acres. We're still doing some Greenfield leasing and we'll come out with a little report on that next time we get together, give you an update on just how much we've been able to add. But we have actively started leasing again.

Richard Tullis -- Capital One South

Okay. For 2010, do you just plan to drill horizontals up in Marcellus?

David Welch

There's probably going to be a combination of verticals and horizontals just due to the geography of lease position some time, but philosophically, we view the Marcellus as a horizontal play. So we're going to try to drill horizontals. In fact, you could expect us to even potentially pool some of our acreage with other operators that try to get specific wells drilled, so we could drill a horizontal in lieu of a vertical, and we're starting some discussions on that with people right now.

Richard Tullis -- Capital One South

On P&A liability, how much do you have now after the work that was completed in 3Q?

Ken Beer

Yes, if you look at the ARO, which at the end of the quarter, we've got 174 plus current of 20 or so, roughly 200 million of asset retirement obligation, obviously that's a present value number, but certainly we're pleased with the reduction over the course of this year of that number. That's pretty healthy reduction from the beginning of the year.

Richard Tullis -- Capital One South

I know your oil production is a percentage of totals around 48% to 50% now. Looking forward, do you see that being able to go considerably higher or do you think you'd just stay in the 48%, 52%, 55% range?

David Welch

I think probably 50/50 is not a bad number for the next year or two. If we see things changing we'll certainly bring that forward, but we've got Amberjack drilling, which is oily and then we've also got some Marcellus stuff, that's going to be starting up and depending on what we're able to achieve there, that will impact the actual balance. Ken?

Ken Beer

Yes, I think that's fair. I mean I think it's correct to highlight that, that Amberjack will be substantially all oil, but as Dave pointed out, we're hopeful to see some production boost out of Appalachia, which obviously would be gas. But I think effectively or at least for us it's probably a trend or a preference, particularly in the Gulf to go after oil projects.

Richard Tullis -- Capital One South

And Pyrenees, what are you thinking on prospect size now, confirmation of the prospect size?

David Welch

Yes, we'll just let new field speak to that. They're the operator and they own 40% of it, but we do think that it's going to be a commercial discovery and that we need one more well drilled for sure, next year, and we'll just see where we go from there.

Richard Tullis -- Capital One South

Okay, and then just finally, of the 350 million CapEx next year, how much of that's drilling?

David Welch

I would think that we would be drilling with over 60% of those funds. Ken?

Ken Beer

Yes, I mean, again –

David Welch

It's very preliminary.

Ken Beer

It's still in flux and as the shift between P&A dollars and drilling dollars and lease dollars and obviously you can take something like Appalachia, where there's going to be some decision points between putting additional acreage on the books versus drilling. So it's enough influx for us probably to duck the question now. We just wanted to give you some high level ballpark number on what we're thinking about from a CapEx standpoint, but truly have not poured a budget, so it'd be premature to come up with some specifics.

Richard Tullis -- Capital One South

All right. Well, thanks very much. I appreciate it.

Operator

There are no further questions in queue at this time.

David Welch

Okay, Darryl, thank you very much, and thanks, everyone for attending the call.

Operator

And this concludes today's conference call. You may now disconnect at this time.

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