Stone Energy's CEO Presents at Barclays Capital CEO Energy-Power Conference - Transcript

Sep. 4.12 | About: Stone Energy (SGY)

Stone Energy Corporation (NYSE:SGY)

Barclays Capital CEO Energy-Power Conference

September 04, 2012, 14:25 p.m. ET


Dave Welch - Chairman, President and CEO


Jeffrey Robertson - Barclays Capital

Jeffrey Robertson - Barclays Capital

We'd like to start our next presentation, we would like to welcome to our conference Stone Energy, with us from the company today to do the presentation is Dave Welch, Stone's CEO and I will turn it over to Dave.

Dave Welch

Thank you, Jeff. It's pleasure to be here with you. And we have a new format that we are going to unveil this afternoon and Thank you for being here to listen to it. I'll just skip the disclosure but obviously everyone knows that there is some speculative information in our presentation.

To tell you little bit about our company, we are growing E&P Company, we are about $2 billion enterprise value, we have a 12 month trailing EBITDA of about $640 million and cash on the balance sheet a little over $200 million. We are about $875 million of long-term debt in addition we have a $400 million bank facility and revolving facility with zero drawn on that facility.

We are growing our reserve base and also diversifying that reserve base at the same time we have about 100 million barrels of oil equivalent as of the beginning of this year. You can see the breakdown in the pie chart on the upper left that shows that about 27 million of this barrels are currently producing an importantly 33 million barrels are behind pipe, meaning we just have to put those on production when the zone on the bottom of the well waters out are pressure depletes we just set a plug and move up hole that’s generally less than $5 a barrel to conduct those operations. Than we have about 40 million barrel equivalents of proved but undeveloped reserves most of those are in the Marcellus Shale and our liquids rich Marcellus area.

We have grown our reserves about 20% since 2009, 20% compound annual interest rate our compound growth rate and our reserve base is also becoming more diversified if you were to look back just to the beginning of 2010 or the end of 2009 we had about 80% of our reserves were located in the conventional shelve which is our legacy asset base. We past forward to today, we were about equally spread in three different areas, the conventional shelf is about a third, the Appalachia is about a third, and the Deep Water Gulf of Mexico is about a third. Also our proved developed reserves base, the 27 million barrels I alluded to above, you can see the pie chart on the lower right, that’s about 56% oil and about 4% NGLs and 40% gas. So, we have a slight liquids waiting in our reserve proved producing reserve base.

We are also growing our production and diversifying it. If you look at the picture on the left you see our 2012 production guidance is 41 to 43,000 barrels of oil per day. As you know you just had hurricane Isaac that came through the Gulf of Mexico that has deferred some of our production, we now estimate that we will still be within this range but maybe toward the middle to lower end on the full-year annualized basis.

You see our production by commodity split is about 54% liquids, roughly 50% oil and 4% NGLs and about 46% natural gas. We have been able to also diversify our production base about half of that not quite half of it, it's is from our legacy asset and the other equal amounts basically from Appalachia and from the Deep Water Gulf of Mexico. You can see on the right there, that we have been able to grow our production base at about an 18% rate from last year to this year as well.

What we are really focused on doing is becoming excellent in exploration and in operations. I think there is an evidence to prove to you that we are doing that. Our strategy is to leverage the high cash flows that we enjoy from the conventional Gulf of Mexico to grow oil in material impact areas, to grow gas in priced advantage basins which means liquids rich today, to limit our reinvestment in our legacy assets, exercise discipline to what we are doing there is investing only in oil development programs, so we are not chasing any gas prospects that are in the Gulf of Mexico conventional shale and exercising discipline in our reinvestment plan there. And then we are also always interested in acquiring high quality properties.

From a portfolio management point of view we are balanced across different risk profiles, you will see that if you look at the chart on the right there, we have a mix of very low risk liquids rich Marcellus Shale, development opportunities and shelf oil development opportunities that generally have an 80% plus probability of working, balanced with some exploration at the high end in Deep Water Gulf of Mexico and in deep liquids gas exploration which is currently onshore South Louisiana. So, we have both ends of the spectrum covered there with low risk development and some higher risk but potentially higher reward exploration.

We have multi-year low risk inventory, we have a multi-year catalyst inventory. We balanced across both commodities and geography between the Gulf, Louisiana onshore and the Appalachia area.

We have achieved some movement in Deep Water, as you can see on the chart on the upper right; we just about doubled our production in Deep Water over the last year. Our strategy in Deep Water consists of several elements. The first is to enhance the value of our existing assets, and the existing assets that we have in Deep Water comprised 119 Deep Water leases to operated platforms that have excess capacity that can be used to process third-party production and seven producing fields. Second element of our strategy is to invest in high impact exploration. Third element is to acquire high quality assets and the fourth is to proactively manage risk. I have a slide on each one of those elements because Deep Water is becoming such an important part of our business.

Why do we want to be in Deep Water? If you look at the lower left there, what you see is a picture of well rates, individual well rates from the Gulf of Mexico shale and the Gulf of Mexico Deep Water. The green and the white which you can barely see which are closer to shore that’s a conventional shelf and the conventional shelf of [goodwill] is a 1,000, 2,000 maybe 3, 4,000 barrels a day. If you look out the Deep Water you can see the well rates out there at 10, 20, 30, even 40,000 barrels a day from a single well. So, that’s the lure of Deep Water and it's a very large price. It's in a politically stable part of the world in the Gulf of Mexico and it's been operating there for a dozens and dozens of years. And there are pretty favorable fiscal terms. So, we think it's a great place to be and we have made significant progress in the Deep Water over the last few years.

We have built a significant lease position; I mentioned the 119 Deep Water leases. We also acquired the Pompano assets and BP and Anadarko late last year and the middle of this year. We made discoveries at Pyrenees and Parmer, and Pyrenees is on production, it's one of our seven fields that are on production. Parmer we just recently drilled an appraisal well there that found some additional pay. We acquired Wideberth which is also already on production. And we built our Deep Water organizational capability within the company in three areas in exploration and operations and in the commercial arena.

One of the first elements of our strategy is to enhance the value of our existing infrastructure. You see in the upper left there is a lot of yellow blocks on that little map, each one of those blocks is about 5,760 acres and those are the leases that Stone Energy owns in the Mississippi Canyon area and that’s in the area of our two large Deep Water asset bases which are low Amberjack field on the left and the Pompano in the center of the map there. The different color dots that you see on that map represent the year that we plan to drill wells in these different leases.

We now have a visible three year plan for each one of our business areas, so we know we are going to be doing over the next three years and this is the picture for Deep Water. First to turn to Pompano, what we are trying to do to enhance the value of that infrastructure and we just closed on this December 28 and then on June 18 for the final 25%. We have increased our working interest to 100%. We have increased production since we took over the field on March 1 by 1500 barrels of oil a day by doing some remedial work in the field. We have decreased the lease operating expense of Pompano by $10 million a year. And we are processing third-party production which has offset the LOE as well. We have five developed wells in our three year plan. Two exploration tie back wells in the three year plan and we have already authorized the rig commitment for a platform rig to go on the Amberjack platform.

If you look at the little map on the right, you see at the top a picture of Pompano which has a platform rig on there. And we have three prospects or three wells, development wells that we plan to drill there and each one of those is in the range of 1 to 3 million barrels which is in stark contrast for the conventional shelf because we drill a conventional shelf development well generally that’s 3 to 500,000 barrels of oil. So, this almost in order of magnitude ramp up in terms of the potential for development drilling that rig should be on the Pompano platform in 2014 and drill those three wells.

Then you see to the right a floating rig development drilling at what we all our Cardona prospect which is approved undeveloped resource anywhere between 2 to 6 million barrels are actually two wells there. And then on the lower left that Amethyst and Derbio we have two exploratory prospects that range from 10 to 100 million barrels for those two prospects and for the two of them combined 5 to 50 million barrels each. So, that rig could be on location sometime in 2014 of 2015 as well.

At Amberjack, which is on the far left on the upper map, we successfully drilled seven wells in a row in successes there in 2010 and '11. We have five additional development wells to be drilled at Amberjack and our three year program and once again we have authorized the rig commitment for Amberjack platform rig and we expect that rig will be on location in 2014 to drill those wells.

The second element of our strategy is to proactively manage our risks and one of the ways that we have been able to do that is by having a number of high quality, high working interest leases that we leased directly from the government and ourselves. And what this allows us to do is promote and joint venture partners where [labor pay] a disproportionate amount of the cost of exploration well to earn an interest in the well. And so far we did that on six projects. Pyrenees and Parmer were the first two, those are both drilled and they were promoted out and drilled. We were able to achieving a two for one promote. So, in one case we sold 10% of our interest and the partner came in and paid 20% of the cost of the well and in the other we sold 15% and the partner came in and paid 30% of the cost of well.

So, both of those promotes have worked very well. This allows us to maintain a material working interest in the prospect with the low cost exposure. It also allows us and one thing to announce here today is that we just formed a joint venture with a major company who is going to come in and pay a promoted interest in four additional of our Deep Water prospects over Mississippi Canyon area. And this will do great things for us that gives us an operator that’s got having a rig being built. It gives us a deep pockets partner and in the event of any upsets in the area and we are just thrilled about that deal. We hope to be able to continue to give more details on that in the next few months.

But so far you see these balls that are shown on the map up there, the purple or the two that have already been promoted and drilled. The blue color ones are the ones that we are subject to this new joint venture. And then we have the purple dots represent another 16 prospects where we have a high working interest that we have not yet done a promoted deal and so it represent future opportunities. The six that we have done so far is going to capture up to $100 million in value part of that is in well carry, part of it is in lease sale reimbursement and the rest of it to be captured as we drill those four prospects with our new major partner.

We have leased 22 of these prospects with high working interest and as I said we have 16 more that are possible for us to do that. So, that helps us to mitigate the risk in a very material way as we are able to drill more wells, keep our higher working interest and pay a lower cost to do that. So, that will continue to be part f our strategy to mitigate our risks.

One other strategy that’s not on here that would help mitigate risk is after discoveries made there is often as opportunity to spin down part of your working interest to capture the development cost from some other operator. And so we are keen to do that when the opportunity calls us.

The next thing that we want to do in Deep Water is invest in high impact exploration. We have visibilities I mentioned on a three year plan and in that three year plan we will be drilling somewhere between 2 and 8 tie back exploration prospects. We will be drilling two to four high potential exploration prospects and we just arbitrarily said if it's over 100 million barrels, its high potential is under 100 million, it's a tie back exploration prospect.

So, you can see we have quite an inventory there that would be done in the next three years. We have three Pompano platform wells as I showed you earlier; those average about 2 million barrels each. We have five Amberjack platform wells that average about million barrels each. And then two Pompano tie back development wells that also average about 4 million barrels each. So, that’s a pretty hefty work schedule and we have got really good visibility on those prospects, and when we are going to drill in the map, again the colors on the map show the year that we have a well planned to drill in the Deep Water is part of our three year plan.

And our whole 119 Deep Water leases which is more than just the three year plan shown here, there are 14 high potential prospects. There are 23 tie back exploration prospects, 14 platform development wells and five tie back development prospects. So, pretty robust inventory. We have been working on this for a long time and now it's coming into clear focus and I think it's going to give us excellent reinvestment opportunities for a significant amount of time to come.

We have also achieved a nice momentum in our liquids rich deep gas play which is onshore Louisiana and offshore. Our strategy there is to profitably grow liquids rich gas through exploration. You will see our progress that we have made in the upper right corner with our production plot we first came on production right at the beginning of this year, where we went from zero. We didn't even have this play two years ago. It actually spun out of the Macando incident when no one was able to drill in Deep Water. We are looking for another place to deploy our capital and came upon this play and it looks like it's going to have a quite a bit of running room associated with it. And so we are up to about just under 10 million cubic feet a day right now on the way up to about 20 million by the end of the this year. And you will see the three year plan there; we have about 2 or 3 wells planned for 2013 and 2 or 3 wells planned for '14 and '15.

Our progress so far as we created this new business area, we have made two discoveries so far that’s La Cantera and South Erath, those two are both on production. In fact the second well has been drilled at La Cantera, that well should come online later this month which will help make up for a little better the hurricane downtime that we suffered last week as a result of Isaac and then the well at South Erath which is already on production.

We have captured two additional prospects since the La Cantera, South Erath, La Montana and Tigre Lagoon are both in the same little geologic mini basin as the La Cantera and South Erath those will be drilled in 2013.

La Montana we will be the operator of that well and it's our first sort of deep gas operated well. So, that’s a good milestone for us as well. We have some other prospects in the area. As you will note offshore we have a couple of these deep rich gas prospects and when I say rich gas these yield about 70 barrels per million of condensate. These things are available to be drilled over the next three years and you can see the color of the dots on the map which year's we planned to drill which ones.

We have achieved a nice little amount of momentum in Appalachia, our strategy there is to profitably grow our liquids rich gas to low risk development. You can see the beginning of the year; we just started with our production at the beginning of 2011. This year we are ramping up, right now we are producing about little over 56 million cubic feet a day equivalence. Our liquids rich gas has about 50 to 70 barrels of condensate for million cubic feet and an additional 60 barrels of NGLs per million cubic feet. And we are ramping up right now with Appalachia and it's going to be a nice contributor for us, we expect it will continue to ramp up production next year for us.

You see on the map on the lower right, we have three areas, really we have the Northern West Virginia area which is our liquid rich area, we have just under 40,000 acres there, about 38,000 net acres. And then in the Buddy area which is just to the east which is drier gas we have about 6,000 acres there as well. We are not really doing anything in Buddy, right now we are focusing all of our efforts on the liquids rich Mary and Heather areas, Christine is another 30,000 acre block, 31,000 acres we have in central PA, that little blurb is not on the right spot, it's actually in a different location from that. But that’s an area that we have some 10 year paid up leases and we are going to probably test a well there within the next couple of years to see what we have going on there. And then Katie and Andy is up in the dry gas area. We are on production there, but we are not planning any additional development there right now.

So, the progress that we have made in Appalachia so far is that we have grown our reserves to 170 Bcf equivalents which includes the condensate and the NGLs. We have gown our prospective resource base to over a trillion cubic feet in natural gas equivalents. And we have drilled over 55 Marcellus horizontals to-date, 25 of those are currently already producing and as I have said we are producing about 56 million cubic feet a day. And we have over 200 remaining drilling locations in the wet gas area and we are continuing to add additional acreage in that wet gas area to try to ramp up the number of wells that we are drilling. We are currently running a one rig program up there. We thought we might ramp up to a two rig program, but our one rig has gotten so efficient. We are getting the same number of wells drilled with the first rig as we thought it would take two rigs to do so. So, we are actually drilling about 25 wells a year with that one rig. So, that’s where we continue to do for the next couple of years.

Our three year plan is to continue to drill the condensate rich Mary and heather fields. We want to test the Upper Devonian Shale; the upper Devonian shale is just shallower than the Marcellus. We have rights to that in a number of areas and it's possible it could be a liquids barring as well. So, one of the things we want to do in 2013 is to test the Upper Devonian Shale.

We also have rights to the Utica Shale which is below the Marcellus, we believe most of our acreage is in the dry gas window and since our Marcellus is holding the acreage we are just viewing the Utica more or less as an option on gas price. But we will probably test a well in there to see what kind of capacity it has sometime within the next three years.

And then finally the Christine Area which is shown in the Central PA there we will probably drill a test well or so in Christine to test either the Marcellus or Upper Devonian or Utica. So, that’s how we are doing in the Appalachia, it's really you can see by the production chart starting to be material part of our business.

The liquids rich Marcellus remains attractive even at low gas prices. You can see our tight curve in the upper left shows production by year, this particular curves indicating in our liquids rich area that we are in the 5.5 or 5 to 6 Bcf equivalents per well. Our condensate yield is hanging in there at least 50 barrels per million and the NGL yield is about 60 barrels per million. That yields a very robust economic case.

If you look at the lower left you see gas price sensitivity ranging all away from $2 to $6 and then the net present value of each well shown on the vertical axis and at a $2 gas price it still got about 23% rate of return under current gas prices it's about 33 to 35% and then it's just goes on up of course if natural prices increase. So, it's an attractive return even at these low gas prices. And we are getting about $70 a barrel for our condensate so that’s what’s factored into that sensitivity model. And right now only $35 a barrel for the NGLs but it's still very helpful to have the NGLs and the condensate in the gas as you can see from the chart.

The other thing built into that chart is a well cost of $6.3 million. We are expecting that we will be able to drop about a million dollars from our well cost in the future as the price of services have come down and as our efficiencies have gone up.

This is a picture of some of the efficiencies that we have gained. The first graph in the upper left just shows the lateral length. We have been drilling longer and longer laterals over the last couple of years. We have gone from 3500 to now. Our recent wells are around 5600 feet of lateral drilling. And we even average around 5100 feet recently. Our frac stages we have gone from fracing right around 10 stages per well to over 16 stages per well, and at the same time we reduced the completion time from 7 days to 5.7 days. So, we have gotten more fractures away, more stages away in a shorter period of time. And we are also able to drill our wells faster as we have gone to pad drilling where we are drilling multiple wells from the same location. So, we have been able to reduce our drill and complete cost from $6.6 million down to $6.3 million.

And as I mentioned wells that we are drilling now and forward we expect to be drilling in the 5.3 to $5.5 million range which would have the effect of actually boosting this economic return or the sensitivity up by about $1 million per well. So, the rates of return would go up about 10% in each one of these cases if we were able to actually capture that $1 million per well which we are pretty confident we will be able to do it, because a lot of its locked in contractually with our frac company with the contract that we have with (inaudible) in Appalachia.

Let me turn to the conventional shelf which has been our legacy asset base, and as you remember if you look back on that chart we were 90% conventional shelf several years ago, now about a third of our reserves over conventional shelf. And our strategy there is to try to maintain a relatively stable oil production and allow the gas to bleed down by not reinvesting in drilling additional gas wells right now. The free cash flow from the shelf is still very important that’s oil curve there is over 11,000 barrels a day which throws off a lot of cash for us and over the last three years we have drilled 12 oil wells at about 75% success rate, those yield about 50% IRR and then worked over about 75 wells, those also have about 75% success rate. The success rate there comes usually from the mechanical success not from the question of whether we have oil or gas there, but they generate over 100% rate of return and so those are very attractive and we will keep doing that.

We have been able to hold our unit lease operating cost fairly flat which is also very important. And we have secured our first rigs to reef program as we move into the stage of having to pull out some of the platforms that are no longer useful. Once you have used up the whole all the wells and gotten all their oil and gas, you got to get rid of the facility within a year or so and so we have gotten our first permit to not have to pick that platform up (inaudible) we will be able to drag it over and drop into place.

And the beautiful picture you see on the lower right, that’s a picture of one of the offshore platform lakes. And these things are fantastic ecosystems are developed there on a typical platform; their numbers are something like 30,000 fish and 5 million in vertebrates to live on these things. So, we think it's a real win-win for us to abandon these facilities in place top them over. And we now know from surveying our Pompano facility which is almost 1280 feet of water, that you have life from basically the top to bottom. And so the governments kind of coming around and started issuing some permits. I think they are going to start letting us do that which would save us a significant amount of money in addition to keeping this infrastructure of coral and everything still alive.

And then the final achievement that we've had is we have been able to maintain our top quartile safety performance which there is a strong correlation I believe between safety performance and business performance. Our three year plan will drill another 10 to 15 oil development wells on the conventional shelf. We will work over somewhere between 50 and 100 wells, and then we will maintain our cost and production efficiencies. So, that’s kind of a walkthrough of our areas, when you put it all together, we try to allocate our capital to optimize value creation.

We run all of our opportunities through linear program to get an idea to optimize on net present value creation. We also try to put the constraint in of growing short-term cash flow, so we have more capital to work with. We want to provide some diversification. Our allocation has some repeatable plays in there with the Marcellus Shale. And it has some low risk projects with the development drilling and the conventional shelf and in Deep Water. And it has a few home run swings in our Deep Water large project drilling. It's liquids driven and it's substantially self funding. So, that’s our program for 2012. You can see the split almost equally between Marcellus and conventional shelf with the big portion going into Deep Water as well, lesser amount going into deep gas and a small amount and business development we are adding additional acreage to try to fuel the future of the company.

Cash flow really helps to fuel this three year plan that first chart shows our margin per barrel and you can see that we have been consistently in the 34 to $50 range in terms of margins. We benefit from Louisiana sweet crude pricing which is about 10 to $12 a barrel higher than WTI. We had cost and efficiency focus both working on keeping our LOE lease operating expense down and also getting our up time production higher. And then we are also benefit from having liquids rich natural where we have gas in our portfolio.

We also try to protect our future three year plan with hedging program. The middle chart just shows the hedges that we have in place for both oil and gas. It shows the percentage of our production that’s hedged; we typically try to hedge about 50% of our production figuring it will be half right or half wrong. And in 2012 we have hedges for about little over 50% on the oil side a little under on the gas side. So, we are just under a policy, but basically our 2012 and 2013 hedging programs are pretty much complete. You can see the prices we got on oil, 97, 100.65, 97.86 and $90, those are WTI prices and so we still enjoy that sweet crude premium on top of that.

Then on the gas side, we are from the 5.04, 5.30, $4 and $4. So, we have got started layering in our 14 and 15 hedges and we continue to do that to make sure we can predict our investment in our three year program.

You can see the bottom chart just shows that year-by-year how much of our future revenue is protected by hedges and over the life of the three year plan we got about $1.2 billion of more or less assured revenue coming toward us.

The other thing underpinning the three year plan is the balance sheet; our debt-to-market cap is decreasing over the last three years. You can see we brought that down from 40 to 32% or so. We have an attractive liquidity in the balance sheet. We have about $200 million in cash and we have $400 million borrowing base that is undrawn. So, we have room to continue to fund our program. Our reserves per share gone up from under 1.5 barrels to over 2 barrels per share and our debt per reserves gone from $8 down to around $6 per barrel and declining. So, some good trends on the balance sheet there, and that helps underpin our three year plan.

We think Stone is a very attractive investment opportunity. Why invest in Stone? First, we have significant and visible upside and the financial flexibility executed that three year plan is summarized on the upper right there. We have 10 to 20 Deep Water oil wells that we will be drilling. We have 75 to 100 resource play liquids rich gas wells that we will be drilling in Appalachia. We have about 6 to 12 deep liquids rich gas to drill an onshore South Louisiana and on the conventional shelf we have 10 to 15 oil development wells. So, pretty balanced portfolio.

We think we had a very attractive valuation. If you look at the bottom left there you see that we are trading toward the bottom in terms of the EV/EBITDA multiple and then also toward the lower end of the EV/SEC PV-10 value. And then we have shown some momentum on our share price over the last couple of years. We have got higher lows some higher highs and we are talking great bargain opportunity right now as our shares are trading where they are.

So, anyway that concludes the presentation Jeff.

Jeffrey Robertson - Barclays Capital

Dave, thanks. We got couple of minutes for questions before moving to the breakout room. This one right here in the middle.

Question-and-Answer Session

Unidentified Analyst

Given the opportunity would you be interested in entertaining the idea of purchasing assets both wells and maybe potentially infrastructure assets from ATP?

Dave Welch

They have got some nice assets, they would certainly be a good fit with our portfolio. It's kind of hard to figure out their situation is right now, but they are certainly be a good fit for some of their assets of what we are trying to do.

Unidentified Analyst

Are you experiencing any kind of transportation constraints in the Marcellus?

Dave Welch

No, I think we have plenty of opportunity to get our production in the Marcellus and things are actually getting a little better for us right where we are. There was a pipeline that we built that we were the anchored tenant for and that pipeline was built by [Canman] it's now been bought by Williams and I think they have intent to even expand that further, but we dun see any constraints on that right now or in the future.

Unidentified Analyst

Dave, just a question on capital, I think in your slide for allocation for 2012 you had about 75% devoted toward the Marcellus in conventional shelf development. In terms of 2013, I know it's still fluid but in terms of percentages would you still be somewhat similar in terms of development capital in exploration given some of the things in the Gulf and the Deep Water Gulf next year?

Dave Welch

Yes, we probably would be for 2013, but in 2014 I'd expect that the Deep Water pace is going to become the predominant capital (inaudible). So, it's changing, but it's not going to necessarily change that quickly in '13 but about '14 it could be a pretty good shift we could see 40% of our capital going in a Deep Water potentially in 2014.

Jeffrey Robertson - Barclays Capital

I'd like to thank Dave and Stone for being here today. Dave and the rest of the team will be available in the Riverside Suite breakout.

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