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Executives

David Welch – President and CEO

Ken Beer – SVP and CFO

Analysts

Brian Lively – Tudor Pickering Holt

David Kistler – Simmons & Co.

Richard Tullis – Capital One South

Stone Energy Corporation (SGY) Q1 2010 Earnings Call Transcript May 5, 2010 11:00 AM ET

Operator

Good morning. My name is Beth, and I will be your conference operator today. At this time, I would like to welcome everyone to the first-quarter 2010 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Thank you. Mr. David Welch, President and CEO of Stone Energy, you may begin your conference.

David Welch

Okay, thank you very much, and good morning, everyone; and welcome to the Stone Energy first quarter 2010 earnings conference call. Joining me this morning is Ken Beer, who is our Senior Vice President and Chief Financial Officer.

Before beginning our call, it feels appropriate to acknowledge the families of those who have lost their lives or have been injured in the recent BP Transocean Horizon blowout in the Gulf of Mexico. This was and is a terrible tragedy that may have as yet unknown consequences. In the best of outcomes, the industry may learn something to make future operations safer and more reliable. The last significant U.S. Gulf of Mexico blowout happened in 1971, and some surface safety bowels came out of that incident. We will all be doing forensic work on the current event to try to ensure that it doesn't happen again. A unified command, comprising the multiple government agencies and the operator seems to be working well in dealing with the aftermath. Processes and protocols that are being deployed and practiced – are practiced and drilled often in our industry, and the organized approach feels to be an excellent job in managing the spill and trying to protect our precious coast and wildlife. As of now, the event has not had any material impact on Stone Energy's operations. We continue to produce and conduct our drilling programs with a watchful eye to events going on around us. We have activated our Incident Command Center to monitor the situation on a daily basis, and to respond accordingly to changing conditions. If anything material occurs, we would plan to provide you with an operational update.

With that, let us now turn to our earnings call. Ken will first go over the financial highlights, and then he will turn the call back over to me for some additional general comments, and then we will be happy to take your questions. Ken?

Ken Beer

Yes, thanks, David. Let me first start with the forward-looking statements. In this conference call, we may make forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties normally incident to the exploration for and the development, production, and sale of oil and natural gas. We urge you to read our 2009 Annual Report on Form 10-K 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 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 was posted on our web site for a reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures.

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

Our discretionary cash flow for the quarter was about $115 million or about $2.40 per share, slightly above the First Call estimate. Our earnings of $26.6 million or $0.55 per share were in line with the First Call estimates.

Production for the quarter came in at 213 million cubic feet equivalents per day, down from the 220 million cubic feet equivalents for the fourth quarter of 2009, but on the upper end of our previous guidance for the quarter. The decline versus the fourth quarter was primarily due to aid the late in the repair of two third-party gas pipelines, which did come back on in late January, and some greater than normal weather restriction, which delayed a number of recompletion projects. Additionally, production from the Amberjack platform was down for a little bit during the first quarter due to the skidding of the platform rig to commence drilling of the Ibix well, and finally, there has been a normal decline curve for us to fight.

Our oil and gas split was about 45:55 for the quarter, as most of the recompletion projects were gas-oriented. Production for the second quarter is expected to be in the 210 to 225 million cubic feet equivalents range, and we are off with a good start in April. Oil and gas price realizations after hedging came in at about $70.72 per barrel and right around $6 per Mcf, or a blended price of over $8.50 per Mcfe. Oil still represents over 60% of our revenues.

Our hedge position reduced our oil prices by about $6 per barrel for the quarter, but boosted gas prices by over $0.50 per Mcf, which settled in to an overall net loss on hedging of about a little over $2.5 million. Since our last release, we have added a couple of oil hedges and our hedge schedule is in the press release.

On the cost side, our LOE was $39 million, on the lower side of our annual guidance, although we would expect a major maintenance component of LOEs to increase in the next two quarters. DD&A per Mcfe came in at $3.09, in line with guidance, and our estimated tax rate was 36.5%, which included a small negative current tax, as we positively adjusted our estimate of current tax being due.

As noted in the release, our total debt at quarter-end remained at $575 million. It was split between the $200 million in sub-notes due December of 2014, $275 million of our new 2017 senior notes, and $100 million in bank debt. In April, we further reduced our bank borrowings to $75 million. This leaves us with over $255 million in availability, after adjusting for $63 million in the LCs.

Our reported first quarter CapEx was about $71 million. We expect our CapEx spending to increase over the next three quarters, and are maintaining our $400 million capital program estimate. As mentioned, a vanilla quarter from a financial standpoint. And with that, I will turn it over to Dave for additional comments.

David Welsh

Okay, thank you very much, Ken. As you heard, this was a good quarter, as we continued to deliver on the fundamentals of stable production maintenance and cost control, while we are ramping up our programs to begin growing the company. Our people did a great job with our base assets and delivered the strong quarter, with production being near the top end of our guidance, and LOE and SG&A expenditures near the lower levels. We are now focused firmly on growing shareholder value through tight management of the base business and adding profitable growth to that base.

We have continued with our strategy of emphasizing growth in oil, and price advantage gas in North America. On the conventional Gulf of Mexico shelf, we have allocated most of our drilling capital to oil exploration and development. We continue with drilling at our largest field, Mississippi Canyon 109, known as Amberjack, and are working on the debottlenecking project to produce more oil at Ship Shoal 113, which was Bois d'Arc's largest-producing oil field.

In the first quarter, we completed Ibix, which is the first oil well in our drilling program at Amberjack. This well averaged about 1650 barrels of oil per day since being placed on production in April, helping to maintain our production and cash flow, in addition to aiding our efforts to stay barely balanced between oil and gas. We have three additional wells to drill at Amberjack, and are presently drilling the Vili prospect, which should be completed this quarter. Although we don't believe the conventional Gulf of Mexico shelf has a large enough average field size to justify new field exploration, we are very excited about the deep-shelf and the deepwater exploration potential. We believe there are substantial reserves to be discovered in these plays, and that they are worthy of exploration capital allocation.

Our plan this year calls for commencing four to six exploration wells in these plays. We are not operating any of these projects at this time, but we do have an average working interest in these exploratory wells in the 15% to 25% range. We were also successful in the recent lease sale, being apparent high bidder on seven deepwater and four deep-shelf blocks, so our portfolio of opportunities continues to grow, and continues to improve in quality, as we have a greater inventory of prospects and can thus be more selective in the deployment of our capital.

In Appalachia, we also took advantage of the market there in the Marcellus to divest about 7,000 non-core acres for about $30 million. We have redeployed some of this money into our core Marcellus areas at lower dollar-per-acre figures, and even after this divestiture, we have still grown our Marcellus position to presently over 50,000 net acres. We are also redeploying some of this money into more oil and condensate from the projects, such as those in the Rockies. We are studying some other on-shore oil opportunities in the U.S. this time, and believe there are additional plays of this type that would fit with our strategy and may attract capital in the future.

In our core Marcellus area, we plan to drill 14 wells this year. We presently have two rigs running in the trend. One rig is drilling the vertical portion and the other is drilling the horizontal portion of these 14 wells. Thus far, we have drilled a vertical portion of about five wells, and have just spudded our first horizontal portion, as the rig came into our possession last week. We expect to pick up a second horizontal rig late in the second quarter, and should have some well test results to report by the third quarter.

Finally, in the Rockies oil basins, we have about 100,000 net acres in potential oil resource type plays, and expect a couple of wells to be drilled there later this year, with results to be known either late this year, or sometime next year. One of these wells is a non-operated 35% working interest horizontal well in the Alberta Bakken, which is offsetting recent activity by another operator.

So that is a summary of our operations in our quarter. With that, we will now be happy to take your questions.

Question-and-Answer Session

Operator

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

Brian Lively – Tudor Pickering Holt

Good morning, David and Ken. Looking at the oil spill issue and as we think about the potential liability of the operators and non-op positions directly related to the spill, can you give us any thoughts today that you have in terms of your risk management and how you think forward about allocating capital to more deepwater/deep-shelf projects versus the on-shore and shelf opportunities that you have?

David Welch

Well, I will give you a couple of comments, and then, Ken can pitch in if there is any more detail, but we do carry this blowout for mentioned risk on our deepwater wells, as well as on our shelf wells, and so we have looked at that to be a major component of helping to mitigate the risk. Second thing is that we do have good experience partners that we are dealing with in our non-operative operations, and I guess the third thing I would say is that even though this event is going on right now, these are very rare incidents. The last Gulf of Mexico U.S. blowout that I can recall was in 1971. So, we feel like that it is not going to hamper our ability to participate in deep-shelf and deepwater wells. Ken, anything you want to add?

Ken Beer

Yes. The only thing I would add, Brian, is I just think it is part to early for us to step back and make a lot of major strategic and tactical moves. Yes, there is a lot of forensic work to be done and it is certainly something that we will pay very close attention to, but I think it is important for us not to react dramatically, you know, within the first week or two of this event as opposed to step back and take a more measured look at you know, our steps over the next several years.

Brian Lively – Tudor Pickering Holt

Okay. Do you think though at a minimum that insurance premiums are likely to go up?

Ken Beer

We actually have just completed, as of May 1, our kind of May-to-May insurance renewal process. I think that speculation of insurance premiums moving up is probably, you know, appropriate, but how that affects each individual operator, again, just too early to tell. So, you know, we have got the next year behind us, but you know, what it looks like a year from now, I really do not. I feel like it is too early to tell, and again, you know, as David mentioned, from an incident standpoint, these are extremely rare, and honestly going forward, we feel we will be that much more focused on safety and failsafe systems. But, you know, I think in terms of the insurance coverage side, we will just have to take that a year at a time.

Brian Lively – Tudor Pickering Holt

Okay. And just staying in the deepwater, you disclosed spudding a Pyrenees well in May. Is that going to be an exploration or an appraisal well?

David Welch

No, that is going to be the development well that we will actually put on production.

Brian Lively – Tudor Pickering Holt

And what was the decision regarding doing that versus drilling to explore for the deeper targets? Was it more just trying to get production sooner or what was your thought on that?

David Welch

Well, as the operator, number one is kind of driving the bus with that, but typically that would be just to improve the overall economics of the play by getting cash flow as early as possible.

Brian Lively – Tudor Pickering Holt

Okay, and then moving north up to the Marcellus, you talked about 14 wells, horizontal wells planned for this year. What are you thinking today in terms of the split in terms of geography between the northeast, southwest, and potential central area of the play?

David Welch

Most of our drilling, I think about 10 of those wells are going to be in the West Virginia area, and the other four would be in Pennsylvania.

Brian Lively – Tudor Pickering Holt

Okay, last question. On the Alberta Bakken, talking about a drill test coming up or a well to be spud coming up. Will that be a vertical or is that going to be a horizontal well?

David Welch

I think that is going to be a horizontal well. Newfield is our operator up there. We have a 35% net working interest in that well, and I believe it is going to be a horizontal.

Brian Lively – Tudor Pickering Holt

Okay, thank you.

David Welch

Okay, thank you.

Operator

Your next question comes from the line of David Kistler, Simmons & Co. Your line is open.

David Kistler – Simmons & Co.

Good morning, guys. Real quickly, in your report, you outlined a lot of different things on the ops side or a lot of different opportunities. You know, obviously you have addressed that it is too early to be thinking about what the impacts are associated with the blowout in the Gulf of Mexico. But could you, just for all of us, maybe rank order how you look at each one of these opportunities or maybe put a couple of them into buckets as, you know, these are the key drivers that are most important to us going forward, just so we have a sense of how things might change should any sort of – you know, should there be any kind of adjustment towards, I don't know, operating in the Gulf in the future?

David Welch

Sure. Well, as you know, we have been in an effort to diversify on-shore for a few years now. And we have a pretty nice situation in the Marcellus that we continue to build on as one leg of that. We still have about 100,000 acres in the Rockies, a place that we can deploy capital. And then, we are looking at a couple of other on-shore oil opportunities right now that we may want to allocate some capital to. So, I don't think having opportunities to invest is going to be our issue going forward. We have developed quite a number of places where we could deploy capital, and if the pace slows down in deepwater for example, then we could ramp up our pace in some of these other areas. That is how I would address it. Ken, I don’t know if you have any other thoughts.

Ken Beer

That is fair. I mean, and again, I think regardless of the type of focus that will be on this event, I think operating in the Gulf of Mexico isn't going to stop. So I don't think we are in a position where all of the capital we were putting to the Gulf of Mexico would just cease to flow there. But as Dave highlighted, we certainly do have some other places to go with capital.

David Kistler – Simmons & Co.

That is helpful, I appreciate that. When I look at the Appalachia side of things, and when you look at some of the recent transactions that have taken place there, which are putting a value of, I don't know, north of $14,000 an acre on those assets. Is it something which you would look at and, right price potentially step out of –? I know it has been a focus for you for the last two years, but hard to ignore a price like that, potentially versus where you are in the development program?

Ken Beer

Yes, you know, I think the way I would describe it is that we have some core areas that we really like and think are going to really be great that we will probably hold on to. There are some other areas that may be more valuable to other people, but we can certainly consider prices in the neighborhood that you are talking about. In fact, if you know anybody, tell them to give me a call. But, you know, I think you will see us continuing to try to – I would just call it, coring up in the Marcellus for the areas that we think have the most potential, where you can get a nice, contiguous, easier drilling program (inaudible) that we can just start improving the efficiency of our program, as well as trying to establish that we can produce the reserves.

David Kistler – Simmons & Co.

Great. And then, you know, looking at current liquidity, you guys have been able to develop a nice little war chest of capital. Is that something that you think about using to enter into some different plays potentially, or given what we know what is going on in the Gulf, do we just sit tight for a bit and, you know, effectively have that as an – I don't want to say insurance, because it is not really that – but as a nest egg to be used another day or allocated if costs go higher, et cetera?

David Welch

Yes, I think it is a little bit of both, David. We would certainly be interested in deploying part of that and keeping part of our powder dry as well. So, I don't think you will see us do 100% either way.

David Kistler – Simmons & Co.

Okay, I appreciate that guys. I will let somebody else hop on. Thanks so much.

David Welch

Thank you.

Operator

Your next question comes from the line of Richard Tullis, Capital One South. Your line is open.

Richard Tullis – Capital One South

Thank you, good morning. Looking at the oil/gas mix, I know it ticked down a little bit in the first quarter. How should we look at it going forward for the rest of the year? What kind of percentages do you envision?

Ken Beer

Richard, it is Ken. Again, a little tricky, but our sense is that it will have a slow trend back, you know, towards more of a 50:50 type. I think the range of 55:45 to 50:50 is the right range. Again, a lot of the recompletion and well work that we are doing tends to – hedge has just been focused more on gas, because you can't control which, you know, is going to come up all alone. But with Amberjack coming on, which is primarily oil, and the next several wells from Amberjack being focused on oil, our sense is that you might kind of slowly but surely move to kind of a 53 and maybe 52 type of a number for the second and third quarters.

Richard Tullis – Capital One South

Okay. And then speaking of the Amberjack wells, what sort of flow expectations do you have, something similar to the first well, say for the Vili well?

David Welch

Well, the first well is probably the highest-ranked well that we anticipate, and I would say somewhere in the 500 to 1000 barrel a day range would be something that we would look forward to on the other zones.

Richard Tullis – Capital One South

Okay. Pyrenees, what is the expected development cost for the project from here on out?

David Welch

You know, we haven't received an AFE for the operator yet, but basically all we need to do is just sidetrack this well that was drilled to take point, and then do this tieback to one of the platforms. And so, I expect that it will be highly economic going forward, but I haven't seen any AFE numbers yet.

Ken Beer

Richard, it is Ken. And remember, our working interest here of 15% would suggest that, you know, this is not a, as Dave said, this is a tieback, this is not substantial, you know, billions of dollars. This will be a propellant straightforward type of a project, fairly low cost project. And obviously, the positive is you get production relatively quickly. I mean, I think the target is laid bit earlier to 2012. But our capital allocation is small enough or modest enough, because it is a relatively small project to start work, and our 15% number, you know, allows us to fit this within just our normal capital budget.

Richard Tullis – Capital One South

And then hopping over to the Marcellus. I think you divested around 7,000 acres you had mentioned. What area was that in?

David Welch

That was what we consider to be non-core. It was separated to the east about 50 or 100 miles away from where our core area is located, North West Virginia. I have forgotten the exact county that that was in.

Ken Beer

It is in Pennsylvania, but as Dave said, it was kind of in a non-core area for us in Pennsylvania.

Richard Tullis – Capital One South

Okay. So you still have your position up in the Northeast PA and then –?

Ken Beer

Correct.

Richard Tullis – Capital One South

Okay. Now I guess all the activity, drilling activity that has occurred to date is down in West Virginia, the five verticals and now starting up with the first horizontal. What about the issue with the permits up in Pennsylvania? I guess the Philly City Council got involved to a certain extent. I mean how is all that going and how do you see it playing out?

David Welch

Well, I mean, it is difficult to predict where that is all going to go, but we don't see it materially impacting our program for this year.

Richard Tullis – Capital One South

When do you think you would drill your first well up there?

David Welch

We should get a rig for that area in the late second quarter.

Richard Tullis – Capital One South

Okay. All right, thanks, that is all I had.

David Welch

Okay.

Operator

(Operator Instructions). There are no further questions at this time, Mr. Welch.

David Welch

Okay. Well, thank you very much, Beth, and thank you everyone for joining us on our call. So long.

Ken Beer

Thank you.

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Source: Stone Energy Corporation Q1 2010 Earnings Call Transcript
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