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Executives

Gary C. Hanna - Chairman, Chief Executive Officer, President and Member of Environmental, Health and Safety Committee

Tiffany J. Thom - Chief Financial Officer and Senior Vice President

W. Mac Jensen - Senior Vice President of Business Development

Andre J. Broussard - Senior Vice President of Geosciences

Chad E. Williams - Senior Vice President of Production and Ex-Officio Member of Environmental, Health & Safety Committee

Analysts

Dan McSpirit - BMO Capital Markets U.S.

Stephen F. Berman - Canaccord Genuity, Research Division

Raymond J. Deacon - Brean Capital LLC, Research Division

EPL Oil & Gas, Inc. (EPL) 2013 New York City Analyst Day May 16, 2013 9:00 AM ET

Gary C. Hanna

Good morning to everybody. I think I know most all of you all in the room. I'm Gary Hanna. Welcome to our EPL Oil & Gas 2013 New York City Analyst Day. Appreciate your attendance. Just a couple of housekeeping items, just a safety moment for a second. We're, for those who aren't familiar with this space, we're on the third floor of the building. In the event of an evacuation, there's 2 exits. One's on the immediate left hand side over here and then on my right, just around by the elevators where you came up. So 2 exits, orderly fashion out the door, if you don't mind, in that unlikely in the event. We'll jump in and get started.

I will acknowledge these forward-looking statements. I'm sure you all have read through this and acknowledge the statements, thank you. As I usually do, I'll get around introducing the folks on the stand here just a second, but I always like to open up with kind of a 30,000-foot overview of the company for those that maybe are new to the story. Those that aware, we appreciate the interest. We are a pure-play shelf Gulf of Mexico, Central Gulf company, and we believe we're very much an oil value play. And you can see our assets line in the Central Gulf doing really a wraparound in the mouth of the Mississippi River. What you see on the screen here on Slide 4 is a map of our 7 key assets in the Gulf. Just make up about 95% of the value of our company. So it's, obviously, where we focus our time and resources and capital.

A very balanced strategy. If you look over the last couple of years, we are an acquire and exploit. We've put equal amount of weight on this. In fact, if you go back and you look at the capital allocation between acquiring and what we've done with the drill. But ironically, they're pretty even. They're pretty flat. So a very balanced approach to how we grow our company.

Very long-lived oil. In that way, we look very much like an on-shore player or piece. On a 1P basis, it's pushing out against 10 years, 13 or so plus on a 2P basis. We'll talk about why we think that 2P is a very real number for our company. You can see our market cap there, current pricing. We're traded, of course, in New York Stock Exchange.

In the next slide, on 5, this is a question we get asked a lot. Why now? What's changed, especially in the shelf of the Gulf of Mexico, that's allowed you all to triple the size of your company in 3 years? We've converted from being an 80% gas company to an 80% oil company. We've done all this while maintaining a very, very high quality balance sheet. Our current -- new debt to EBITDA is running about 1.2x. So we can make an argument we're even underlevered at this point, and we've done all of this without diluting the company. In fact, we've bought back 1.5 million shares in the last 18 months. So why can we do this today, where maybe this didn't happen over the last 15 or so years? We're going to try to answer those questions today. A lot of it is around the time frame in which they drilled these wells, the objectives they had at the time. Many of these companies were looking for gas not oil. At that time, they drilled these in maybe $5 to $20 oil price environment. Typical for them to bypass the fairly large sections of pay in order to get to a larger low but single LIBOR.

T.J. made me talk a little bit about her days at Exxon. And I used to say, "No, I -- don't complete that. Go down to that. Just leave it behind. We're finding these stringers in here with 0.5 million barrels in them." So it's one of the reasons that technology shift, we'll talk about that a lot today, and what's moved and the speed and the -- our ability to take that data now at a much, much lower cost and apply it on a large regional basis and what we're being able to now see in our fields, not only in the historic shallow pays but also down deep. So we'll spend a lot of time talking about that today, and I won't steal that thunder but it's amazing what's going on today. It's a real revolution.

We do believe we are the premium long-term play. Again, a very focused approach, targeted approach to our running our business. We do think we have prime real estate in the heart of this basin. Our key fields are all around large salt dome features. We talked about big fields getting bigger. It is true. So we have this pay, for instance, 51 square miles has made 1 billion barrels of oil and gas, still a tremendous amount of work to do in that field. And we're unlocking things all of the time with this new technology and new data, new reprocessing of data.

Excellent technical team. Match them up against anybody. Andre is here with us today. He'll go through a lot of how he's built that staff and the expertise we have there.

A lot of operational excellence. We'll have Chad walk through about how we run our business. You'll hear us talk about the word efficiency a lot today. So we're big on efficiency. Yes, I think it trickles to all of our costs, whether it be G&A or operating costs or F&D or margins or cash margins per barrel. Pick a metric and I think you'll see efficiency across the board. And again, I think our acquire and exploit strategy has worked very well, and we have an outstanding track record I believe there.

Quickly, kind of how we got to this point. You all know we reorganized this company in 2009. '09 and '10, we're really back in our feet on the underground, getting our business processes, making ourselves scalable, where we could have an organization that could grow at that speed, which is always my intent and do that where it looked effortless. That was the goal. So we can still grow this company significantly with the infrastructure that we have. We designed it to be scalable, so we have no concerns in that regard and it's all because we did that good work back in '09 and '10.

'11 was about demonstrating we could do some quality acquisitions and get started in that. We executed on the Anglo-Suisse acquisition in 2011, really transforming with the company at that time. Not only from an asset side but financially.

'12 was about demonstrating repeatability of our ability to buy those fields and that we could execute with the drill bit efficiently. That's really what '12 was about.

'13, we're trying to, in some ways, educate the financial community on the true value of our assets. We still think we're still materially undervalued. So it's about trying to show you all today that we do have a lot of running room. We've got a very, very deep inventory. We think we have the skill set to execute that. So that is really what we're into today.

Just very quickly on Slide 8. This -- I like this slide because it tells a couple of stories. You can see our base assets in the light blue at the bottom. The gray was Anglo-Suisse assets we acquired in 2011, a couple of small bolt-on deals from Stone in '11 and the W&T in '12. And then the light blue is the Hilcorp acquisition, which doubled the size of our company. We executed that in November of last year. So we've only had that asset in the house for a very short period of time. You can see the dark blue is our organic growth. So a high percentage over 50% of our production is driven organically. The other thing about that dark blue is that, that organic growth is really driven by the light blue Legacy assets and the gray, ASOP assets. Only 1,000 barrels of that is attributable to Hilcorp.

And as I've said in the past, you all know the story. We buy these assets. We break these fields down. We remap them, completely tear them apart. We get all the kinds of reprocess, data sets and that runs across the gamut of different types of tools. And how we do that? We get that data in house. We work it through teams. We generate a large inventory of prospects. We hydrate those prospects and we execute. And that's an evergreen process, we continue to fill that bucket. That process takes about a year. So you go back to that ASOP. We've spent $15 million in the first year. We spent $150 the second year. We'll walk down the hill, if you will. We're doing the same thing with Hilcorp. You'll really see the growth in the production rates and the reserve rates for Hilcorp in '14, '15, and '16. We're doing that work now. I'm very excited about what we're seeing. You'll see a lot of that in the show today.

So with that, I'll sit down. We have a list of -- you see the agenda here. T.J. will come up and kind of walk through some of the financial metrics for you. I think most of you all know T.J., seated to my left. And Mac will come up and just give a few words. Mac Jensen, he was our Senior Vice President in Corporate Development. He will come up, just tell you a little bit about what we're seeing in the A&D side. Andre Broussard, who runs all of our G&G efforts in our shop, will spend a few minutes mainly on the 2P story today. Then Chad Williams will talk a little bit about our operations and how we're doing that and how we're scaling that up and how we intend to remain efficient. And then Andre will wrap up on the back with 3P.

So with that, I will turn it over to T.J., again. Thank you, all, for being here today.

Tiffany J. Thom

All right, good morning. It's a pleasure to see a lot of familiar faces and also some new ones. So it's really, I think, fitting to start with 2012. And as Gary alluded to, we spent a lot of time over the last couple of years really building a platform that we could grow from, execute on, on a great acquisition in 2011, and 2012 really started to show the results of all that work. And we saw an increase in production, quite good, 21%. We focused on oil and drilled a lot of results and coupled that with cost efficient, driving our base assets to lower LOE, focus on our G&A.

EBITDAX rose at the highest level, $286 million that year. And then it -- all that dropped to the bottom line as we look at adjusted net income. And all the while, the stock price started to respond to what I think was 2.5 years of good execution. And as we kind of take stock in that appreciation, I think we recognized really it was just about us catching up to the peer group. We are flying a bit on the radar, and we think that today's lesson is really about what is the future growth in front of us and really how much we believe we've got running room in the stock.

We closed out last year with a great acquisition, as Gary mentioned, the Hilcorp acquisition. That was a great transition. As you look at 2013, it's really set us up nicely. We have a compelling outlook. We'll stay oily, 80% by production. First quarter was just a good leg into that. We just released out a couple of weeks ago and exceeded our guidance, hit on all cylinders. We looked at oil, looked at our revenues, highest-ever quarter EBITDAX. I think that's just a good thing for a window until what this year can hold. We will continue to see oil production increases ramping up throughout the year. We'll be up 70% plus and I think the bottom line is, we're projecting to see midpoint of our guidance on the EBITDAX side, $500 million, so up significantly from last year and really just doing that with just a modest increase in CapEx. So last year, we are at over around $226 million. This year, we'll spend around $300 million. So driving a very capital-efficient program and therefore, driving free cash flow. Bit of a novelty in this business, but we will be throwing off about $125 million of free cash flow. And we're doing that through a protected balance sheet in terms of our hedging programs. 62% is hedged on the oil side. We're doing that to protect our capital programs. We can stay free cash flow positive all the way down to $50 sprint. And that's just based on the fact that we struck $106 swaps, mainly burnt swaps for the majority of the program. We're hedged not only in '13, but I will point out also in '14. So we got great things ahead and just a terrific year ahead of us.

I guess, we all have our favorite slides in the deck. I like this slide because I think the focus today is really about the portfolio. Andre is going to come up here and he's real energetic. Like it's hard for us not to get excited about what we see going forward for the company. And this slide shows you, though, the track record of us being able to take our portfolio, those ideas, those opportunities, put a bit in the ground and start executing and seeing organic growth. And that's what this really shows. So It's great it shows doubling of the reserves. Some of that borne out of acquisitions, obviously, quite a bit as we've grown from 27 million barrels in 2010 to 2012 being at 77 million barrels proved. But as you really look at the organic growth, that's where the story is. So 9.9 million barrels of organic growth achieved in 2012 was borne out of the fact that we took the time, as Gary said, to study the assets that we acquired in 2011. And that is mainly driven by bit work, 2P being translated into proved as we looked at the results for 2012. And I know that's what you're going to be asking yourselves as you think about the portfolio, how large it is, how quickly can we get it translated into proved.

So years ahead of us, Hilcorp is not a part of that 9.9 million barrels. That's, as Gary said, to come. We saw it on the production side, and we're going to see it on the reserve side.

Cash margins do matter in this business. We have long life reserves. And Gary really talked about the R/P being a little bit more like an onshore company. And indeed, if we're going to be in the water for this length of time, many of our fields 15, 20 years of reserve life, we really have to do it efficiently and smartly on the cost side. And I think we do it well. We showed the highest cash margins against our peer group. The nearest peer on the cash margin side is $6 or so behind us. And obviously, with a little bit of more gas nature of some of our peers, they're -- we're twice their cash margins. So if you say, "Why don't you just -- that's a little bit muddy, let's just throw out the gas then." So we've done a line for you down there at the bottom that shows oil revenue, just strip out the gas, look at the oil and we're doing very well, $2 to $3, $4 better than the peer group. And the bottom line is this year, we'll produce around 6 million barrels of oil, somewhere around there. And if you think about that in the long line balance as and you're saving a $3 to $4 of 6 million barrels for 10, 15 years. It really adds to the bottom line. We just simply don't know how to do it in any other way but to be efficient. And that kind of brings me to the last slide that tends to kind of put it all together for you.

In terms of the business platform, our ability to acquire and exploit and to exercise discipline. Again, we've really been disciplined on the capital side. You've seen our growth explode but yet bearing in mind that in every year, we've been free cash flow positive. We continue to see that going forward even as we increase our capital programs. We'll still be free cash flow positive. It's a bit of a self-fulfilling, self-funding program as we look at the quality of our assets and our ability to drive production increases.

I think what's really important is we've been balanced. And as you look at those years between 2009 up until 2013, you can see that, as you add up the capital we've spent, putting a bit in the ground and as you look at acquisitions, it's a pretty equal balance. I think that's driven a lot of discipline and I think a great balance sheet, great outcome, such that if you examine 2012 and look at how we are able to fund the acquisition that was in front of us, Hilcorp, $550 million of the $582 million that we spent in acquisitions was done just in last November on Hilcorp, and we left that transaction with $220 million of liquidity and in 1 quarter grew it back to $290 million. And, as Gary said, we're at a leverage between 1.1x, 1.2x right now and we're going to drive that down below 1x, arguably underlevered, just very short window coming out of a very large transaction.

We think we're set up to really -- look, I don't need to convince you but I think we're convinced that we've got the right approach and we're going to be very disciplined as you think about the pipeline of acquisitions, as you think about everything that Andre's going to talk to you about today. And we just don't want you to have in the back of your mind that we're going to do anything but approach the business in a very similar manner. We'll use the balance sheet right. We'll stay conservative. And I think, at the end of the day, we'll remain profitable.

So with that, Mac's going to come up and talk to you about how we've translated acquisitions into our business model and what he sees on the horizon. So...

W. Mac Jensen

Thanks, T.J. So we are going to talk a little bit about how we've used acquisitions to help grow the company and talk briefly about how we plan on doing more of the same going forward.

First, let's take a look at our strategy. It's a traditional game plan for independents. First, you start off by owning and acquiring quality assets in a focus area. We then dedicate multi-discipline teams to each of those core fields and apply a lot of resources and technology to make sure we understand the geology is well or better than anyone else in the basin. By doing this, we think we're able to recognize the value and the acquisition and not only recognize it, but have the confidence to pay for it. We also pride ourselves on being good faith and transparent negotiators, and these are the things that make you a preferred buyer in your region.

Let's take a look at where EPL just -- was just a few years ago. We started off with 2 core fields, the East Bay field and the South Tim Area. These fields comprise most of our 27 million Boe approved reserves. We are producing around 5,400 barrels of oil per day plus our gas. At that point, we had a very small but very talented technical team and a very small credit facility.

We started our acquisition efforts in earnest in 2010 and connected on our first deal in February of 2011. This was the acquisition of Anglo-Suisse Offshore Partners. It was a private equity portfolio company held in a fund that was nearing the end of its life with our applied capital. We got a great new opportunity set with this acquisition, and these fields also hold a lot of great upside as Andre will discuss in just a little bit. In addition to this, although we spent $200 million, we've traded an escrow of $100 million in financial liquidity by virtue of the transaction. And as part of the deal, we negotiated our ability to access the Debt Capital Markets as a condition to close. We also used the transaction to acquire a new lead bank. So on Valentine's Day 2011, we closed the acquisition. We closed a $200 million high-yield deal and we closed a new $250 million credit facility which was undrawn. It was definitely a major step forward for the company.

After that, we followed it up with 2 small bolt-on acquisitions, both spaced 6 months apart. This further consolidated interest in 2 of our core areas. The first deal was Main Pass 296/311. This is a complex that was, at that point, owned a 1/3, 1/3, 1/3 by Stone, EPL and Apache, who is the operator. We negotiated the acquisition of Stone's interest for approximately $80 million. But Apache had a pref right, liked the deal, too. They exercised their pref right. So we ended up owning the complex 50-50 with Apache. One thing I'd like to point out, that not only was just a good deal for EPL but is also a good deal for Stone. We timed it with Stone so that they could use these proceeds to buy some strategic deep water assets and a tax-free exchange, which they did. So it worked out well for both of us. 6 months after that, we acquired the remaining interest in our South Tim 41 field from W&T, so we now own that field 100%, and this is another area we like very much with a lot of great upside.

During this time period, we looked at a lot of transactions. And we did full engineering reviews on upwards of over 100 million Boe of reserves. Didn't find anything that really fit our strategy. Looked like they might have been in the final analysis. They didn't until late 2012. We saw this transaction. We acquired all of Hilcorp's Gulf of Mexico shelf operations, buying 36 million Boe for $550 million. These 3 new areas fit our strategy very well and they fit the same profile as the rest of our assets. In addition to that, they provided us with a lot of critical mass, which enabled us to advance the company on a number of fronts. More operational synergies, further investments in our technology platform and a much lower cost of capital. We bought this acquisition using all cash just like the other transactions. We did a $300 million add-on to your senior notes -- to our senior notes, did a $200 million draw on a new $750 million credit facility and used cash on hand. And I think it's also noteworthy to relate that we asked Hilcorp and they agreed to hedge 2 million barrels of oil on their balance sheet prior to the close. This helped us derisk the transaction. It worked well for them, worked well for us. Just another example of how we work with sellers to make good transactions happen.

And so in wrapping up. We see acquisitions as building blocks of growth for the company. We've done a lot of things to create and maintain financial liquidity. We're achieving critical mass and they provide new opportunity sets for developing inventory.

These 7 fields that you see represent 95% of the proved reserve value of our company, which is a good thing. We like keeping the company nice, tight and focused. In addition to these acquisitions, we've also acquired 40,000 acres in our lease sales around these salt domes and around these fields to enhance and protect our position. But we're not done yet. We see a lot of interesting things coming down the pipe. And I think it's important to remember, and T.J. touched on it briefly, is after each of these acquisitions, whether big or small, the company has to remain self-funding post acquisition.

So in wrapping up. We see a lot of interesting things coming down the pipe and we're very interested in connecting on the next one. Thanks.

Now I'll hand it over to Andre Broussard, Head of Geosciences.

Andre J. Broussard

Thanks, Mac, and good morning, everyone. It's a pleasure to be here this morning. When we were here last year at Analyst Day, we were at a place where we've been about a year into our acquisition with Anglo-Suisse and we were talking to you about how we were going to execute on those properties. And so there was a lot less bubbling under the surface. So coming into this year at Analyst Day, that 77 million barrels oil equivalent approved reserve number is a function of the acquire and split model, where we've acquired some assets and some reserves. We've also executed on those reserves in our Anglo-Suisse properties.

And so like last year, this year, we have a lot of things that are just sitting underneath the service, if you will. So our 77 1P is what most people see. But beyond that, we've got things that are just below the surface, just like a large iceberg would and that is our 2P story. And our 2P story is basically 3 separate buckets. It was in the 2P, the first one being 16 million barrels of oil equivalent that this booked from our legacy properties. That's our third-party auditor booked number. Secondly, we have the Hilcorp assets that are currently being audited, reviewed by our third-party auditor. That's going to happen this year, so that will be a second addition to that 2P number. And then last but not least, is the inventory of 2P prospects just like the ones we've execute on, on Anglo-Suisse. And once we still have to execute on Anglo-Suisse as well as our Legacy assets, that comprised an inventory that exceeds about 50 million barrels of oil equivalent, about 58 projects, and that, as Gary said, is an evergreen and growing process. So we're very excited about our ability to go -- execute on properties just like the Anglo-Suisse properties, very low risk, very high-quality prospects.

And then last but not least, we'll go a little bit deeper. As we continue to unlock the opportunity sets within our fields and we begin to put together regional framework, we're beginning to understand that there's a section below our fields. Our fields produce very shallow. And so as we look a little bit deeper, we're finding there's an upside reserve potential 3P, if you will, of about 150 to 300 million barrels of oil equivalent. So we'll talk about each one of these this morning.

We'll start with the technological review because we believe this is kind of the driver for our field exploitation and our growth organically. We'll also talk about how we use our business model along with that technology to drive that growth not only internally but also efficiently, quickly, how we do what we do. Then we'll look a little bit at that 2P inventory. We'll talk -- we'll give you a little bit of historical perspective of what's happened over the last year, especially in the Anglo-Suisse area. And then, we'll move into what we have in front of us. Give you a sampling of what that 2P inventory looks like and how it's going to continue to drive our growth going forward. We're just getting started. We're excited about it. And then we'll take about a 10 minute break and we'll get some coffee and then we'll have Chad come up and talk about operations, and then I'll conclude with the 3P program just beyond that.

So let's first talk about the technological evolution. Because one of the questions that we get asked often is, you're buying fields that are 30 to 40, 50 sometimes nearly 60 years old. How do you continue to make that field, that's big already, bigger? And if you go back and look historically at these fields, they have continued to get big and the reason they've gotten bigger is largely due to the technological evolution that's occurred specifically with seismic and drilling technology. And so this morning, I'd like to just kind of go back in time, look at how these fields have gotten bigger, what data they had, why they did what they did and why we think we can continue to grow those fields today.

So if you go back to the 1960 to the '80s, back in that time, they were shooting 2D data. And that 2D data was very, very widely spaced, about 1 to 2 miles between each seismic line. So the major -- when they were getting into the Gulf of Mexico, will -- all they could see was big structures.

Really couldn't dissect the fields very much, couldn't see the subtleties within those overall large structures, but they were very successful in finding those fields. And so with that technology, they've begun to drill up. As Gary talks about a lot, they just drilled on spacing because they couldn't connect all the dots between that 1- and 2-mile grid, it's very difficult to do. And so as they developed their field, they were very good at what they did because they drilled what they saw -- what they could see. But then at some point in time, those fields become more of a maintenance because they've drilled all they could see and they've become maybe a secondary field. They've moved on to newer opportunities. And so these fields become more of a maintenance type field. Well about the time that really seismic shows up in the 1980s, independents are starting to look at this 3D technology and they realized that the 3D technology is significantly closing that gap between those spacing, going from 1 to 2 miles spacing on the 2D lines down about 256 feet. So you can imagine the amount of resolution that's occurring within a field. You could connect 1 dot -- 1 to 2 miles across. That was at every 256 feet. You can see every subtle fault. You can start to see dips in the structures that are causing little mini structures. And so the independents started buying these major fields in the late '80s and early '90s and there's a second round of development in these fields, the redevelopment of these fields and these fields continue to grow. And so what they could see now is the subtle features, they could see a little bit more the structural interpretation but still can resolve everything. They couldn't resolve deep. They couldn't resolve the subtle fluid of structures, the reservoirs, the fluid types. So there was still a lot left to be uncovered. So then what happened in 2000, especially the late 2000s is there was a technological revolution. The 3D data that we shot in the '80s and '90s had acquired a lot of data. But there was an inability to really process and manipulate that data because the computer power and those type of things. And so there was a -- so what's happened in the 2000s is obviously, a net -- computing costs has come down. We've had the capacity increased, the speed increases. All of a sudden we're taking that 3D data and now we're beginning to use it in a way we never could use it before to unlock additional things such as fluid types, small structural stratigraphic features, things that all of a sudden are unlocking these fields in a new light. And that's what we've utilized at West Delta, and that's what we utilized in each one of our fields. And so let me just give you a sense of how significant these computing changes in our industry has affected what we do. The graph you see on the top right is Moore's Law and Moore's Law basically says, the computer capacity increases every 18, or doubles every 18 months. So in the last 6 years, we've had computing capacity doubled 4x. Additionally, if you look at the bottom graph, you'll notice that, that's a cost per gigaflop, which is 1 billion operations per second. In the last 6 years, it's dropped from $50 a gigaflop to $0.73. So when you think about what that allows mathematicians, the algorithms they can create to unlock these -- all the data that was acquired in this 3D data sets is significant. And because that cost has come down, all of a sudden, we can now utilize this, not only the little post to on our fields but we can do this regionally. So it allows our geoscientists to see, to size and to properly risk prospects in a way we couldn't before. And so what we're seeing now is that third round of development in these big fields and that's why these big fields keep getting bigger.

So let me give you an example. Some of the types of seismic that we're utilizing and kind of what that looks like. The 2 maps on the left. One on the top is the wells that we drilled off of 2D lines. You can see that the blue lines up and down and left and right, very wide spacing, few wells drilled because you couldn't really define the structure. But when you start getting 3D data sets into these projects, all of a sudden, you're able to unlock a lot more the subtleties of these fields, the hidden reservoirs and you can see the type of well work that is done when you're able to unlock and see things like you couldn't see them before. And so what are we doing today to see, to size and to risk. Well we're taking the time data that was shot. The 3D data set shot originally but reprocessing that data, so much less expensive now than it was even 10 years ago. You can do it in such a short of period of time because of the capacity and speed of computing. We are able to now get better images of that this sub-surfacing you see. The time on the left on the top panel and the depth on the right puts a much better picture. When you get to the middle section, this is some of the reprocessing we're doing internally and this is a normal resolution on the sides. So this is the way we get the data when it comes to us from our vendors. We were able to reprocess that data, bring more frequency out of that data and we're beginning to vertically resolve a lot of the subtle sands that are within these fields. Gary talked about the bypass play in our fields than when they were developed and we're able to start resolving those. And so we're going back and redeveloping those because we can now see them.

And then last but not least, we're actually able now to begin to start understand the fluid that's in our reservoirs. Is it oil? Is it gas? Is it water? And of course, it's very important for us to know if it's water and so the panels on the bottom are gather panels. So this is a derivative product from the 3D data sets. And you can see on the left, that gathered the brightness of the colors, the greens and the yellows, they decrease as they move left to right. You look at the gather panel on the right, they increase from left to right. For us, that's indicative of hydrocarbon indicator. And so that helps us de-risk prospects. If we can get comfortable at these hydrocarbons there, that's A great de-risker for us.

So we're using these types of technology to begin to unlock our fields. So then the question is, how do you organize yourself as an organization to do the things that Gary talked about. To get these great properties in, exploit these property quickly and efficiently and we believe it's basically 3 stools, 3 legs of the stool if you will. It's people and it's technology and it's focus, and we believe this is the building block for being efficient and in fast and a successful E&P company. And it's very simple, but we think a simple model when you execute it works really, really well.

So let's talk a little bit about people. We use a multi-disciplined approach. So what we have within our organization are geologists, geophysicists and an engineer. Those folks works side-by-side. They're highly experienced individuals. Our staff is probably experienced level -- in the Gulf of Mexico, is about 30 to 35 years. So very, very experienced. These folks are oil finders with proven track records. We want people to have a nose to find oil, not just people know how to map but people who know how to find oil and gas. Our teams are very, very inquisitive. We really encourage them to look at data, to look at the information they're getting and ask questions why, what if, how could I? Those type of things. And then as we've seen, we give them the tools in which they can go exploit us. And what we do in each one of our fields is every time we acquire a high-quality core asset, we put a geophysicist, geologist and an engineer on that field. So right now on each one of our core assets including the Hilcorp acquisitions, we've deployed teams onto those fields and so they're all currently working those.

And so let's talk a little bit about that technology toolbox. We talked about the data. What we're trying to do is give our guys the ability to see, to size and to risk. So to that end, we reprocess data, we sometimes, multiple times we would give derivative data and that's all with the effort to understand our structures, our reservoirs, our fluid types and our pressure environment. So we can understand what our wealth planning needs to be and so that we can de-risk not only the prospect but also the drilling of that prospect.

And last but not least, looking at new seismic acquisition. And so we we'll be talking a little bit more about that in the 3P. So we believe that using technologies and people obviously are going to help us create that growth and value creation but last but not least, it's about focus. We believe that you've got to let people alone, put them on a core asset, leave them on that core asset for a long period of time. Let them do those field studies and unlock the opportunity sets that are in those fields. And we believe that is very, very important.

The other thing that we do is we're very, very collaborative. We believe that not only we're collaborative within that geology, geophysicist, reservoir or engineering team, but we're collaborative across our organization. We spent a lot of time especially working with Chad's group as it relates to how do we not only look at a prospect but how we look at that portfolio prospects. Because if we can opt, if we can execute on a portfolio versus the project, we create significant efficiencies.

And then last but not least, how do we innovate? Once we collaborate, how do we innovate? We identify projects, we begin to collaborate, how do we innovate to make them as efficient as possible to execute on them as quickly as possible so that we could grow the company.

And then last but not least, it's execution. So it's about identification. It's about collaboration, innovation and then execution. And it's a culture we've built within our company. The type of people that we've hired are people that can work well within that organization and that's culture, and we believe it's beginning to yield significant results.

So let's just take a step back and let's look at the Anglo-Suisse properties. You've seen a little bit of this, the 187% growth in our reserve base from the 9.4 million barrels we bought via the ASOP acquisition and the Stone bolt-on acquisition. What's really interesting is we're able to grow the proved reserves every year and push the 2P into proved each of the consecutive years. So we're really able to take our prospect inventory, our 2P numbers, execute on those and move them into proved. And we think that's the model for acquires that we want to continue to execute on and we believe when we look at the Hilcorp properties, the properties we bought, they're just like the Anglo-Suisse properties, except in 1 difference. If you look at the map on the right, you'll notice that we have 3 basic core areas out of the Anglo-Suisse acquisition. We operate only one. That's the West Delta one. In the Hilcorp acquisition, the 3 key fields that we bought, we operate all 3. So we believe we're going to take this model we've been able to grow significantly with 1 field, now we can multiply that by 3. So we're very excited about the ability to continue to grow our company going forward.

And you've heard Gary talk a little bit about not getting paid for the 2P, if you will. We believe that the 2P that we have is a very high quality 2P and we're able to execute on those and move those in the 1P very since. We feel very good about our 2P number, our ability to execute on it.

Let's talk just a little bit about some of the metrics from the Anglo-Suisse acquisition. This is production. In 2011 we bought it. This includes the Stone acquisition. 3,000 barrels of oil daily equivalent. Today, that's a 374% increase to 11,207, significant increase. Additionally, production, just on the proved reserve number alone is nearly doubled to 176%, and so 16.5 million barrels. And then last but not least, the present values increased 237% to 681 million.

So let's talk about the 2P bucket, if you will. It's basically, we talked about earlier is 3 different parts. First is the legacy part where we've got NSAI booked reserve number 16 million barrels. And that comprises of 2 equal parts. One is the PUD roll off. We have the SEC rule. We have to roll off PUDs every 5 years, and so those are proven reserves. They get rolled back into P1. And so when you think about that, half of that 16 million barrels. That's a pretty solid number. It's just going to execute on it and getting it in the queue to bring it back to proved.

The second part is performance adds. And so when you look at prospects like we've executed on just in the last year with the Anglo-Suisse opportunity acquisition, when we bring those reserve numbers to Netherland, Sewell, they're going to get part of those numbers to us in proved and they're going to get part of us -- of them to us in probable and they'll give us additional proved reserves as we perform it, perform its ads. So this is a very high quality number. We believe it's about as close to proved as you can get and our inventory is not too dissimilar from it. Our inventory is very much like the things we've executed on in the Anglo-Suisse acquisition. And so we're now working in building that inventory. As we mentioned earlier, it's about 50 million barrels plus of oil equivalent on the upside on that inventory. This is a new projects to go execute on and that portfolio is continuing to grow. Right now, we have about 58 projects within the 2P inventory. If you look at the pie chart on the upper right there, you'll see that the Legacy assets are in green and the new Hilcorp acquisitions in blue. And so our project inventory right now is weighted towards the Legacy properties. Keep in mind that we've had the Hilcorp acquisition in-house about 6 months. So the fact that we have 24% of the portfolio is already Hilcorp's pretty significant. We talked about that 1-year lag time of building that inventory, we're just getting started, just getting started. Additionally, when you look at the reserves, this is interesting, as you compared the reserve split, now they're almost equally split between those -- between the 2 pieces, the Legacy and the Hilcorp. So what we're seeing is, we're seeing some of the new projects, we're seeing from the Hilcorp property as significant reserve side. As we talked about it earlier, we're continuing to grow this inventory and we're excited about it.

So let's talk a little bit about the type of plays. When we talk about this 2P, what did you think about that? How risky are those prospects? What kind of prospects are you drilling? We're basically at them in 3 different buckets. The first one is added plays. An added play is very simply that, if you may think about oil and water, oil and water don't mix, oil seeks the higher ground, right? And so when we go back in our fields, we're looking for that plays up dipped at the last well drilled that has enough reserves. We can go execute on that. And that's basically you can get a PUD for that. That's how lower risk, that type of project is and we have numerous ones we've executed on in the Anglo-Suisse acquisition and then in our Legacy fields. But also, we're already starting to identify those within our Hilcorp assets. So those are the type of projects that we're drilling.

Secondly, By-Passed Pay. When we think about By-Passed Pay, I mean it's By-Passed Pay. It's paid as on logs. It's identified. The question is, has it ever been drilled by another well and if you decide that if you can confirm that it hasn't, then that's an easily booked reserve.

And the last but not least, fault blocks, new fault blocks or fault extensions, where we're just taking the field with the new reprocessed data, with our teams collaborating, they're finding new fault blocks or extending the field out in the direction that hasn't been identified before. So very, very low-risk opportunities. And a lot of times, we'll find most -- a lot of these all in the same wellbore. If you look at the cartoon on the bottom, this is the West Delta area and we've actually found all 3 of these just within the West Delta area. And when you drill upon Salt Domes like you see on the panel on the far left there, West Delta 29, the salt there is in white. We typically have stacked pay sands in our wellbores. All of our fields are salt supported, our stacked pays, numerous stacked pays within the field. And so when we're drilling an added play, we're probably drilling through some By-Passed Pay as well. And so you'll see that here in just a few moments. So we've actually de-risk our prospects because we typically drilling through stacked pays. That's why we're able achieve such a high success rate.

So let's just take a look back at the time, which we bought Anglo-Suisse. This is the West Delta 28, 29, 27 area. This is the one we operate. And this is what the field look like from the guy when we got it. You can see, if you look at the West Delta 29 in the far left, you'll notice there's a lot, a lot of wells there. That's the Eastern flank of the West Delta 30 Salt Dome and then you see West Delta 28 and 27, a lot of wells drilled out here. This field has been around since 1955. So this is a 50-year-old field. What could be possibly left in all the pay sands that they discovered. Well, there was actually quite a lot. When we bought this, the rate, production rate was 2,300 barrels of oil equivalent a day and the PV value of the field was $120 million. Within the last 12 to 14 months, we have executed on 19 drills for sidetracks. So when we talked about putting things not to get them, this is a prospect but as a portfolio and then our ability to execute, this is a great example of that 19 wells in about 14 months. That success rate is about 95%. Our current production rate has gone from he 2,300 barrels a day we talked about a moment ago. Now it's up to 7,800 barrels of oil equivalent a day. And our PV value has gone from $120 million up to $435 million. And the good news is, is that this execution we've done is just the start for the field. We've got, as you can see by the green triangles, we've got additional prospects that we are currently reviewing and putting into our queue. This is an ongoing process. They're still coming up with ideas. And so we're very excited about our ability to execute within our newly acquired fields at Hilcorp just like we have here.

This is a great picture of the West Delta area and I think it's a great example. Chad's team's ability to get out when they get the portfolio of ideas together. We collaborate on the projects that they can go out and execute. That's got 3 wells working in this field at one-time. This is how you drill 19 wells in 12 months. So in the foreground, this is the West Delta 29 area. That's the seafloor well that we're drilling. That platform is just underneath that large jack up. There's a platform that Chad's team went out modified, and we'll talk about that in just a moment. In the background left, that's the West Delta 28 #18 well. That's a successful well. then the West Delta 27 B-4 in the back right. That is a new platform we set. We'll talk about that in a few minutes as well. And then last but not least, that's a work -- a lift boat, way in the back at West Delta 27. They're hooking up our newly successful C-1 well. So this is how we execute when we get to our portfolio, collaborate, innovate and we build the company.

So now let's talk about how we do that. Let's take some specific examples within the field. We've talked about the teams getting set. They start to get the new data in, they begin to look for ideas, they begin to collaborate and they found 3 prospects in the West Delta 29 Salt Dome area that they thought would be a great opportunity to go drill off the "H" platform. They also found a work over. So we begin to collaborate with Chad's group. So look, we've got this portfolio of ideas. We would love to drill those off the "H" platform so we went and visit with Chad about the "H" platform. He has some concerns. Chad, you want to talk to him about how we got around that?

Chad E. Williams

Yes, because of the design of that "H" platform, you could only access it with an independent leg rig. We know that those are long lead, plus at that time, they were much more expensive than a mat-supported rig. So we spent about $900,000 to modify that "H" platform to be able to accommodate one of the mat rigs that we already had under contract. So we had control over. We moved that mat rig on location. We spent 108 days on that location and a savings of about $50,000 a day versus that independent rig -- and independent leg rig, and we saved almost about $5.5 million by making that little $900,000 investment to modify that platform. Plus we brought production on probably between 6, 7 months earlier, so.

Andre J. Broussard

And that's really our culture, the identification, the collaboration, the innovation and then as you've seen the execution. So let's just give you an example, one of the wells we drilled off of that platform, this is the H-3 well, and I was just kind of give you some color schemes you'll be familiar because you'll see these on the rest of the slides. Where you see purple that's salt. And so that's a Salt Dome you see on the cross-section on the left and also on the map on the right. Additionally, when you see the dark green, that's perspective oil on the map. When you see a light green on the map, that is produced oil. That's oil that's been produced out. And then the tan lines, you see those are faults that also help create seals along with the salt. Those in tan on the map. So we drilled the H-3 well. The H-2 well, you can see where it's located on the cross-section is the highest well. So it's an added opportunity that we drilled. We got the new seismic data and we found there was plenty of space between the last well drilled, which was drilled 40 years ago, went off production in 1977 that the F-5 while you see in the middle of a cross-section. That F-5 went off production 1977. So it's just fields or reservoirs that has been sitting idle for 40 years. So the guys got the seismic data in, we began to collaborate, saw those up dip potential that well. That well came on, make an 800 barrels of oil a day.

We talked about that they had drilled 3 wells -- 3 sidetracks off that "H platform. We took that inactive platform. They've been sitting there. It was ready for being -- ready to be removed. Drilled 3 sidetracks of the deal work over. The IP of those 3 wells was 2,600 barrels of oil a day. So this is how we begin to increase our production rates within our field.

Additionally, we talked about our fields who always had stack pays. We found 6 new behind pipe zones that we also added as we drilled those 3 wells. So not only did we have the added play but we have this By-Passed pays, other pays down deep. This is what our new Hilcorp fields look like as well. So this is why we're excited when we start thinking about the inventory build that we've got going on. That we can repeat these type of projects over and over and over again and this is how we're going to continue to grow our company just within the field pays of our properties.

Let's give you another example. This is moving over the West Delta 27. So we're moving a little bit east. We're getting off of the Salt Dome and we did some reprocessing of West Delta 27 as well. That was a nice MC sand field out here. The MC sand, a log you see in the bottom right. The field off of the A platform, 4 wells have been drilled off that A platform. You see highlighted with the red square there. Four wells drilled and that and that one did accumulation, produced about 4.1 million barrels non-pressured, very inexpensive wells to drill. Also there was another, along that same fault, another field just to the north in our West Delta 26 area, that had 9 wells drilled in it and had found 3.6 million barrels. Our guys begin to look at this area and thinking that there was probably ability to extend this field to the north. The problem was on the A platform, we've done so much work and so much work have been done in the past that we have no really slots left to go drill off that A platform. So now we're kind of in a conundrum, how do we execute off of these new ideas that the team has. So once again our collaboration with Chad. We start talking about Chad, "How do we execute?" How do we develop this field?" And Chad, you want to talk about what we did out here?

Chad E. Williams

Well, out here it's a little bit different. We've thought about how can we get production to the tank quick as the easiest way. So we went out and we preset the B platform. Since Andre had already identified 5 or 6 projects, a couple of those being PUDs, we're able to de-risk that a little bit. So we spent about $1.4 million to install the cased on in the well slots. Once we drilled and successfully lobbed that first well, we were able to come in while the rig was on location and set the platform simultaneously. So we worked together with drilling and our facility groups set that platform and we actually have that first well on production while we were drilling that second and third well. So again, that production acceleration. So by the time we got done with that fifth well on that platform, we had 4 wells on production. Again, accelerating that -- our sense of urgency are getting that first production online.

Andre J. Broussard

And it sounds a little aggressive, but I think it goes back to our ability to see our prospects with the new seismic data, understand what we have, if you feel comfortable enough to go out and set a platform prior to drilling the well. I don't know how many times out in my life of being in the Gulf of Mexico, I've seen a platform set ahead of a drill well, ahead of a test. It's very unusual but that's the kind of accomplish we have in our data and our ability to execute out in the field. So what do we find? Well, we found the field extended to the north in 2 separate little compartments of 4 wells, found that MC sand and those are the 4 wells you see up here on the top. Those 4 wells are all full to bay. So we're not really sure how big they are yet. They could be big -- also bigger than we were able to book but they're all new reserve ads. Those 4 wells combined over 2,000 barrels of oil a day and, like I said, new reserve and so that was a great outcome within the West Delta 27 field. So this is how we've been able to execute out in the Anglo-Suisse property.

So how do we take this type of process going forward? What are the type of prospects we have in inventory that are going to continue to grow our company through 2013, 2014, 2015? How do we do that? We do the same type of thing we've done here. We continue to do it here. And we do it, at Ship Shoal 208. We do it at South Pass 78. We do it at South Marsh Island. We do it in our Legacy fields. We continue to drill these type of prospects.

So let me walk through these different type of plays, I'll walk you some of the Legacy fields, as well as through some of our new Hilcorp opportunities we've already identified. I think it will give you a flavor for the type of activity we have coming forward. The risk profile of that activity and its ability to grow not only production but also grow organically our reserves as well. So this is going back to Legacy field. This is the South, I'm sorry, the South Tim 26 area. And this field has been around since 1966. A lot of wells drilled 173 wells drilled out here. Off of about 5 platforms and the keys on. It's produced over 184 million barrels of oil equivalent. So you can see the platform as a highlighted there in blue. You can see the density of the well pattern. We're getting ready as to set an "H" platform ahead of drilling, just like the B platform, out here. Again so this is a great example of our team's ability to collaborate, to identify and collaborate and then to innovate. And so what happened was our team begin to look at the new 3D reprocessed data we had over South Tim 26 because we reprocessed all of our fields, even the old ones, and came up with a number of active opportunities within the field pays. And so we need to find a way to execute on these and then we're also looking at the reprocessed data.

We begun looking at below the fuel pays and some of the 3P opportunities that we had out here and we say, "You know what? We've got that opportunity as well." So we have, not only a prospect, but a portfolio of prospects in South Tim that we wanted to find the most efficient way to execute on. And so once again that means we're collaborating with Chad from the get-go.

And so, Chad, do you want to tell them a little bit about what we did out here to get this H platform.

Chad E. Williams

Kind of the same story that we had at West Delta. Again, the only way to access the wells on our F platform was through an independent leg rig, which, again, is long lead, a little bit higher of a costs. A little different though. We also have 1,000 barrels a day of production currently on that F platform so by moving an independent rig there and working on 3 or 4 wells, that created a bunch of down time and lost production. So we looked at different ways. So we thought that we could install an H platform, which, for about $4.5 million, we can go out install that, tie it back to our existing infrastructure, to be able to accelerate that. That would eliminate the production downtime that we have off of our F platform as well as make a safer, simpler wells to drill for our drilling departments. So --

Andre J. Broussard

Right. And so the type of prospects we're looking to drill off that H platform are low-risk prospect. This is the O RD Sand. This is the most prolific reservoir within the South Tim, 26 field. It's produced over 75 million barrels of oil. It's a very complex reservoir. It had not only a lateral compartmentalization but also has a vertical compartmentalization. So there's a lot of science that has to go in understanding these reservoirs. Additionally, it has a gas cap. You can see that on the map. That's the red at the top of the structure, far part of the map, far north part of the map. Then you go to an oil rim and then you go into the water. And so what we're attempting to do here is to produce that oil. The government doesn't allow us to produce that gas cap, because it reduces the efficiency of the reservoir. And additionally, we want to get that high-priced commodity oil out of there. And so where is that oil? The good news is this field has been around for a long time and has a lot of well control. So we matched that well-control with the seismic data and we looked for the best places to go drill for that oil rim, if you will, within this reservoir, and so we identified 2 locations. Additionally, though, what we discovered was, just like in most of our fields, there's stacked events, stacked pays all throughout this field. So we begin to look at the O RDs, wait a minute, we can go take this whole section, this logs section you see on the right. We have an opportunity to access a lot of those pays in an up-dip attic position. So that's how we begin to determine where the H platform goes. We begin to look at what's the most opportune place, optimized place, to set that platform.

So on the seismic line here, the section that you see in blue, on the middle and off to the right, that is the current field pays. You can see those brighter events, darker reds, darker blacks in there, that's some of the field pays in there. The little black squares on the top of the seismic line with all the black lines coming down, that's our historical well-control out here. The new platform is the one that's in gold. And you can see we've got about 3 wells, we plan to drill off of that platform as well. And you'll notice one of them goes down into the red section, below the blue on the seismic line, and that's the deeper section. That's part of our 3P story we'll talk about shortly, that we're also going to be able to drill also the H platform. So once again, the identification, the collaboration and the innovation allows us to be optimized, our well work, our field work out in these fields and creates great margins for us.

Staying at South Tim 26, I'm going to show you an example of a combination of field extension and an attic play opportunity. This is a -- and bypass pay opportunity. This is South Tim 26 G-2 Sidetrack1. The G-2 of Sidetrack original or the G-2 original hold in G-1 were drilled to the M Sand. You can see in the upper left there, the G-1, the G-2 logs found a beautiful oil and gas sand there that well, those 2 wells together have produced about 1 million barrels of oil and about half a BCF of gas. As the team got the new seismic data and they began to map this area out, they realized that along the same fault trap, the trap that -- the fault that traps the hydrocarbons, just to the west of that, there was a similar trap, just sink-line [ph] separated, valley [ph] separated those 2 and looked like a great opportunity to go drill that M Sand in an untested area within the field. And remember, this field has been around for 50 years. So the new data is helping us unlock some of these opportunities even within the field. So this G-2 Sidetrack, well, just in that M Sand has about 340,000 barrels of potential. That's, once again, going to be a reserve add for the field and be a great potential rate for us and we drilled it off of a platform. So we're able to hook it up very, very quickly.

In addition to that, South Tim 26 is just 1 pay sand after another. And so you can see the type log on the right. You can see the M Sand in the middle, that portion of the log on the left, that's our primary target. We've got sands above and below that all the way down to the P. Once again, South Tim 26, on the flank of the salt dome, lots of stacked pays, lot of them -- most of them oil. And so we're going to not only drill that M Sand, which is closer to the top of the section we're going to drill, but also we're going to go test all of those sands. So in addition to the field extension, we have potential for bypass and attic plays within this 1 wellbore. And once again, this is the way you de-risk wellbores as you give yourselves more opportunities to find hydrocarbons. And so this is how we've been able to enjoy a 90% type success rate within our fields.

Now let me spend a little bit of time looking at some of our new opportunities on our newly acquired blocks. This is the Ship Shoal 208 area. It's a large salt dome. Once again salt dome is stacked pays. The map on the upper right is kind of the whole complex. You can see the purple salt dome with the pay all around the dome on the east and the west. The map on the left is an insert of the northeast side of that salt dome for the Bul 1-6 Sand. And our team, we talked about our teams being inquisitive and asking questions. Any time you look at somebody else's map and somebody else's work, it's an interpretation. And so an interpretation is what it is. It's an interpretation of what you think is there. So our guys they'll always begin to unlock all that information, go back, peel through all the data, correlate the logs again, look at the seismic data to try to determine whether that's, in fact, the case. Well in this Bul 1-6 Sand, you'll notice that the green color is a light green and so when we acquired this field, it had been interpreted that this Bul 1-6 Sand had been produced out in this fault block on the northeast side of this dome. Our guys began to look at the logs and they begin to see if there maybe some discrepancies. So what the interpretation was, you can see the cross-section right here on the map here, you'll notice that there's a TP15 Sand and then the Bul 1-6 Sand is located here. Well the B-1 well, actually, drilled through to both those sands, produced both those sands but then those J well drilled up at the top of the structure that the interpretation was that TP15 and that Bul 1-6 Sand, they had in fact become one sand. And so this J-7 well have actually produced out all the Bul 1-6. Therefore, nothing left in that fault block.

But our geologists start to look in the logs and it goes, wait a minute, I think the correlation doesn't look right between that B-1 and the J-7. So we began to look at all the logs in the area and began to reinterpret this section. And so this interpretations on the bottom cross-section, he said, that the J-7 well stopped short of the Bul 1-6 and, in fact, the J-7 well had never seen the Bul 1-6 Sand at all. And so, he said, he went to geophysicist's on the part of his team right next door and said, "Hey, can you look at the seismic data and determine whether or not this J-7 well have actually drilled an attic potential on the Bul 1-6. And this is the geophysical interpretation. Here's the J-7 well and you can see the Bul 1-6 Sand, which you see circled in yellow, was never reached by that wellbore. It was never reached. So he said, wait a minute, there's up-dip attic potential here. So now all of a sudden the map becomes dark green instead of light green. In addition to that, when we -- this actually occurred while we were in the data room. So prior to the act of the acquisition.

So then we processed the data. We were talking about our ability to reprocess data quickly, computing speed gone up, costs gone down. So we've reprocessed it. This is an inversion reprocessing technique and, basically, what it does is it marries some of the well-controlled we have in our logs to the seismic data and it gives the seismic data a little bit more structural, I'm sorry, geological, what makes the seismic look more like the logs. And so once again, this helped confirm our story. Here's the TP15 Sand, the Bul 1 and the J-7 well. You can see the J-7 stopped short of this event, which is the Bul 1-6, and so we realized that these 2 did not come together as that original interpretation has suggested. But in fact, they were separate. So we'll be drilling that, that's an up-dip attic, low-risk PUD type opportunity and within the Ship Shoal area, right out off the bat.

So let's take a look at a few of the bypassed pays opportunities that we have within our portfolio. This is also in the Ship Shoal 208 area. This is on the western side of the salt dome. It's off the flank a little bit. You can see up here that it's away from the salt dome. It's this little fault block right in here. This is the blown-up section of it. So over here you'll see that, that's the section blown up to here. And you'll notice that there's 4 wells that have been drilled into that 1 little fault block. But once again, the reason 4 wells were drilled out here was because there was numerous stacked oil pays within this 1 fault block. So we do multiple wells to try to efficiently produce that oil out. We begin to look at that and we realized that some of the well issues that we had in there and some of the production that was out there, maybe there was a way to more efficiently produce that oil. So we will actually going to drill, what you see up here is the L-6 rigs and new drill L-6 location on the map. And so we put together a technical review of this with Chad's group. Chad's group's always involved in our technical reviews and to take a look at this drilling opportunity in what we might do to help more efficiently produce the oil out of this multiple stacked sands, and you can see all the multiple pays on the cross-section there. Chad's actually going to talk a little bit more about this in the operations group, because it's a great story about our ability to collaborate and innovate. So I'll leave the rest of the story to him, suffice to say it's a great opportunity here.

And then moving over to East Bay. Let's look at the few East Bay opportunities. Gary mentioned East Bay a little bit earlier. This is a 60-year-old field, has a 100 field pays. It's produced over 1 billion barrels of oil equivalent and it covers 50 square miles. It's a huge field. When you think about the production life of this and all the production history. You think about all the sands. You think about all of the wells that are drilled and you start looking at all that data, you go, how do you manage all of that data? Well you have to have a team. This is the reason why we set the team's up the way we do. Geologists, geophysicists, reservoir engineer collaborating, looking at this data and seeing where the disconnects are, to the well we thought was going to produce 500,000 barrels, only produced 100,000 barrels. We ask the question, why? Does the new data unlock that? Give us the answer why. So we have this inquisitive thing that goes on and collaborative thing that goes on within our geoscience team to help unlock this and we're continuing to unlock new reserves within our field pays in East Bay, in South Tim. It's really amazing. And so let me give you a couple of examples of some of the bypassed pays that we have out here at East Bay. This is our #310 where you can see on the cross-section, it's the second log from the right on the section. This well has the N4b sand up running it. If you'll notice the log to the further right, doesn't have that sand. But as you move to the west, down to the left, you'll see each one of those logs has that N4b upper sand. This well -- this reservoir was last produced in 1982. So it's, what? 30, 40, 30 years old and had been produced yet, the top wells, the added portion of those wells, the ones that are structurally up-dip, which are -- I'm sorry, which are these here, these wells were never produced. We believe there's about 325,000 barrels that were left behind in this zone. We're just going to do a work over here. Very expensive operation to go out there and produce these reserves.

Additionally, when we looked at the 310 well and the sands above and below it, because, once again, that 310 well has stacked pays. We found numerous other sands that had been bypassed within that wellbore, because they're thin like this one. We find thin pays like this that produce 300,000, 400,000, 500,000 barrels of oil and so we're very excited about this type of opportunities and they're all over East Bay, they're all over South Tim and so we continued to execute on these.

Here's another great story about the collaboration about asking questions and about busting some of the conventional wisdom. If you just take a real quick look at the production history here, you probably just bypassed this and you wouldn't spend any time with it, but our guys were pretty tenacious. And so let me give you a little bit of a story about the Q sand. This is a fault block that the #19 well. It was drilled in 1959. Drilled to Q sand, found oil from top to bottom in it and was quickly put on production. About a year later, the #21 well was drilled way down, you can see on the cross-section there, it found oil in the Q Sand but also found a water contact. So we had a nice reservoir with oil in it, had a water contact and they began to produce that. Well in 1973, the #37 well was drilled and you can see it was produced pretty far up-dip, not quite as high as the 19, but it's produced pretty far up-dip or drilled up-dip deep, drilled through to the Q Sand. It was completely wet. So when you look at this, you go okay, so we've had about 12, 13 years of production. The #19 has been doing a great job of pulling the 500,000 barrels that's produced out of the ground and, of course, the water is climbing up the structure, taking it's place, and so when you drill the 37 well, you see a very efficient reservoir moving the water up the structure.

Well that was a great story, great. That's conventional. That's the way we see most reservoirs behave but we had a bust. In 2010, the 21 sidetracks 3 well was drilled and it was actually drilling for a deeper objective but it had to drill through the Q Sand. And when they drilled through the Q Sand, they actually found oil on the log and they -- so then the question started happening, how do you get oil after the water has moved past all of the reservoir? How do you get oil down-dip of a wet well that was drilled in 1973? So they began to question, is the log right? What's going on out here? Do we have some kind of strange reservoir that we don't understand? So they say, what do we do to resolve this. So what we did was we run a pulsed neutron log, PN log, and it's something that we do as a matter of course, in each one of our fields. As a matter of fact, Chad will tell you when we acquired Anglo-Suisse properties. It's one of the first things we do is go out and run PN logs. And what a PN log is, is basically is a case hold [ph] log. So once you put your production tubing and stuff in the hole, you run this log and it reads water, it reads chlorine. So it will -- and you can run this log over and over through time in the wellbore and it can give you a reading of where the water is in any given reservoir. So you can know, quite quickly, whether you've had a reservoir produced out or not, whether the water level is moving up in that reservoir. And so we ran that PN log in the 37 well up-dip the end of the 19, that was originally wet when it was drilled and it was full of oil. So you can see that on the screen there, the little log on the right on the 37 there is the PN log. And so there are guys who go, now, what do we have? And so it became obvious that what had happened was the #19 well, when it was producing, it actually coned the water. So it was like a straw, pulling very hard on that oil and it was creating a pressure sink and oil -- water locally was being pulled into that wellbore. And so what happened was, when the 37 was drilled next to it, it looked like it was wet. It got caught up in that pressure sink. But once those wells went off production, the 19 well went off production in the 1980s, the oil began and the water began to find a common contact level. And so when we went back and ran these logs, we found a reservoir, they have not been efficiently drained and we're going to drill this well here shortly. This has got -- a nice reserve add. You can see it's got a PV-20. It adds about $1.7 million to us. So this is a function of really asking questions and being collaborative as a team that you can't do a lot when you're in this big companies because they operate in silos. Reservoir and Geo group over here. Geology group over here. Geophysicist group over here. Our guys sit right next to each other in the team. So they're constantly bouncing information off each other and trying to come up with ideas.

Let's go over and look at one of our newly acquired fields bypassed pay opportunities. This is South Pass 78. It was, again, a Hilcorp acquisition. It's also a very large field discovered in 1978. So it's 30-plus years old. It's got multiple sands, self supported just like all of our other fields, stacked pays. This had a 5 platform set out there, very large platforms, 237 wells drilled out there, and a cumulative production to date of 241 million barrels of oil equivalent.

So we put a team on this, began to reprocess the seismic and the guys, when they begin to look at the logs out here, they said, "You know what, these wells all have lots and lots of stacked pay in here. We need to understand what's been produced in these wellbores and what hasn't." So they went through each one of the wellbores and say, "What sands have not been produced?" And when they were done, they came up with 133 individual wellbores that did not -- that had sands that had not been produced. As a matter of fact, most of those 133 had multiple sands that had not been produced. So then the question is, "Okay, well, will it be produced by a wellbore nearby and what's left?" And so once again, we said well, this is a great opportunity for us to go run that PNL program. So we went out and did a test of 7 of those wells, and so we went, did a few off the B platform, and a few off the D platform. You can see that on the map on the upper left there. And they went around 7 PNLs within that -- in those 7 -- in the wells. And you can look on the log on the right. This is the B25 well and you see it, once again, numerous, numerous stacked sands, stacked pays and the PN log is on the right. And when they were finished running this program out of these 7 wells. They found 9 booked sands. They confirmed those. They were still booked. We'll confirm they have pay in them, but not only that, they found 20 additional pay sands that were not on the books that had not been produced. And so now we're on the road to understanding how to best execute on those. So once again, we start off with an idea, we create a portfolio, we collaborate with Chad on how to best execute on those and then we go execute. And so what we're doing out here now is we're getting ready to start a work-over program on the B -- is it the B platform? On the B platform. We're going to kick those off here very, very shortly and we're already beginning to develop sidetrack opportunities as well. So just think about this, think about the West Delta program where we start off with PNLs. We spent some time understanding the field and drilled 19 wells in 12 months. We've done 7 of 133 wells, PNL program. And we've already got multiple opportunities out here to continue to add production and also add reserved growth. And we're just getting started. So we're very excited about the South Pass area. This is an area that we believe is going to really begin to contribute as we get into 2014, '15 and '16 and has great, great potential, just within those field pays.

Another type of bypassed pay is low contrast pay. You may heard a little bit about this. And what is low contrast pay? Well it's basically pay we can't see. We run a log and we can't recognize the fact that it's pay. And so the log on the right is a great example. You'll notice the P4 Sand. That's a great example of a classic-looking oil response. You've got the yellow as the sand indicator. That yellow, when it moves, gets thicker to the -- move towards the left, great indication of sand. The track on the right is green, when it moves to the right, great indicator of oil, love to see that, makes it real easy for us, the scientists, to understand that speck. However, when they drill this well, they had some indications on the middle logs that there was a potential hydrocarbons just above that P4 Sand but when you look at that log you don't see the same type of classic response just above that sand that you do in the sand itself, and so they began to -- we shot sidewalk [ph] course in that to test to see was there hydrocarbons there. It was chock of block full of hydrocarbons. The problem was, just like our seismic data, as it's evolved through time, creates great and great ability to resolve data. These logs are the same. Well, a lot of these logs couldn't resolve the thinly bedded sands and shales that are within this member here, that are full hydrocarbons but you can't resolve them on the logs. So how do we go about testing that? Additionally, sometimes the mineralogy within the sand can suppress those log readings. And so we can't see it, we believe this has tremendous potential within our fields. In each one of our fields, we see opportunities like this that we think we need to go spend some time understanding and then maybe execute on those. So what do we believe about low-contrast pays. One, they're underdeveloped, because people don't recognize them, that makes it very easy. Secondly, the reason that they're underdeveloped, we think, is because most people when they look at that sand like the P4 Sand you see on this log, they go, that's going to give me a great rate. Let's go produce that. They look at the section above and they go, I don't know what's going to give me. So we believe a lot of this is bypass for higher rate. We believe it's commercial. We've seen it some of it -- well, I'll give you an example in just a moment about why we believe this is commercial.

We also are taking a look at some of the completion techniques that we know are being implemented in the resource plays and going, do they have application here? Because the resource play is about being able to extract the hydrocarbons of out of these very, very tight rocks. And so we think that we need to look at and understand that as well going forward. And last but not least, we believe there's significant resource potential here within this section.

So here's a great example of why we believe there's a lot of bypassed, low-contrast pay. This is a well that was drilled in 1996 in East Bay and they drilled through the N4 sand, beautiful classic-looking sand, drilled deeper, found the N4a and N4b and N4c section, very low contrast looking, doesn't look very clean, looks like it wouldn't give much rate. They looked at the N4 sand and said, let's produce that. And they did, they went straight to it. They did not complete either the N4a, the N4b or the N4c, and you can understand why. But however, we understand now that the N4c is quite a good producer. This is part of our East Bay field and you can see those 4 logs on the top, the N4c, once again, not a very good looking log. It looks low contrast. Those 4 wells have combined to make over 1.6 million barrels of oil, produced over 300,000 each. What's amazing about this is this has been sitting around for about 17 years and our guys got in here, began to tear this field apart and knew of some new focus and realized that there's an up-dip attic potential within this N4c sand and we also believe this has got numerous fault block implications throughout the field that we're going to continue to execute on. So we're very excited about opportunities like this. Bypass is pay. Very low-risk. And we see this in our old fields. We see it in our new fields. So we're going to begin to spend some time with that.

And then last but not least, just want to talk to you a little bit about enhanced recovery. It's one thing to build a fine bypassed pay, but it's another thing if you can say, "You know what, can I get a little more out of that reservoir? Is there ability for me to extract more from that reservoir?" And so to that end, we've been looking at new types of technologies to try to unlock some of this recovery and efficiency, and we're beginning to look at dumpflood technology, dumpflood technology simply says that I've got a reservoir that I believe can have enhanced efficiencies and so I'm going to take a well and go down-dip in that wellbore that's producing that reservoir and I'd go drill a well and I complete in a water sand above that reservoir, that's got more pressures than the reservoir does. And I complete that sand and allow that water in that sand to flow naturally down into the reservoir. And you can imagine, as it flows into that reservoir, it begins to increase the pressure within that reservoir. And as it increases the pressure in that reservoir, it pushes the oil up towards the producing well, creating greater efficiencies. And so we've got couple of opportunities like that and one of those is within our new field, the Ship Shoal 208 area. This is the Ship Shoal 209 on the northeast side of the salt dome and this well is -- the K-2 well has produced about 1.6 million barrels of oil to date. The recovery efficiency has been about 22%, we know that because the original oil in place is estimated to be about 7.3 and so we believe that we can increase that ultimate recovery by 35% to 50%, which would increase our reserves in that 1 well by about 1 million to 2 million barrels. We've got opportunities like this in East Bay and South Tim and so we're excited about these.

So we kind of look back over, this is just kind of a smattering of the 58 we talked about that are all within our field pays. They're all very low contrast, whether they'd be attic, they'd be bypass pays or they'd be low contrast pays, we believe we've got numerous opportunities out here that we're executing on that and we'll continue to execute on.

And so just to kind of sum up the 2P, what I hope you take away from this is number 1 is the 77 million barrels is really just the tip of the iceberg. We've got a very solid inventory, much like the inventory we execute on last year, we'll execute on this year and in the years coming, that inventory is deep, it covers multiple years of opportunities and if you look at that 2P of 16 million barrels of our legacy that's booked, you look at the 2P that's going to be booked from Hilcorp and you look at the 50 million barrels of oil equivalent that we believe is in inventory and that number is growing. We believe that basically doubles the size of our 2P. It gives another 70-plus million barrels in very low-risk, easy to execute on, quick turnaround type projects that we believe can double our company quite quickly.

And then the good news is that's not it. We want to come back in a few minutes and talk to you about that 3P story. But first, we'll take a 10 minute break. Then we'll have Chad come up, talk about operations and how we're doing this efficiently and effectively. And I'll come back for a few minutes to talk about 3P.

Gary C. Hanna

It's 10:30.

Andre J. Broussard

At 10:30, so about 10:40, Gary?

Gary C. Hanna

Yes. No, it's only 10:20.

Andre J. Broussard

10:20, so we're going to be back about 10:30? Thank you very much for your time. I appreciate it.

[Break]

Gary C. Hanna

Okay. Welcome back. I want to introduce Chad Williams, who'll talk a little bit about our operational side of the business. So Chad Williams.

Chad E. Williams

Hey, welcome back, everybody. You just heard Andre speak about our reserve adds, growing our 2P reserved base and building our inventory. And that alone should get you guys excited about EPL. I know the reason that I'm excited is, is my primary job is to convert those 2P reserves into production and to continuously execute on that inventory and to do it in the safest, most economical way possible. So I'm going to briefly talk about how we handle our growth from project recognition to putting oil in the tank.

Our approach is simple. It's very involved, but I think it's very simple also. First, Andre's and my team's goals are the same. They are identifying the right projects, maturing and planning those, executing, hooking them up and getting that oil and gas to sales in that safest, most economical way that we can. We do this through an integrated approach, and the team's collaboration that you've heard today that we talked about is a must for us to be successful.

The operation group learns about a new well or a prospect almost from the beginning. Our well intervention group begins at that point figuring what platform, what well, what kind of rig do we need to make that well work as efficient as possible.

At that same time, our facility and production group look at how we're going to hook that well up. What kind of production is going to be impacted by moving a rig on a particular platform, what potential back pressure problems is that new well going to cause and then how does that potential impact the compression of the entire field? Well, we start solving those problems as early as we can.

All these planning and permitting start at the earliest possible time. Sometimes we might have our facility hook up permits actually get submitted to the BSEE before our well work permits go in because we know that those take a little bit longer to get approved. At this point, we can prioritize those projects based on rate, reserve impact, taking into account capital efficiencies that we can gain by doing so.

And cost accountability goes hand-in-hand with this execution. We can save a few dollars in each of our projects and by managing these efficiencies, we might be able to execute on another work over a sidetrack that wasn't in the original plan to begin with. And then that just adds the production and cash flow to our bottom line.

And of course and most importantly, we -- keeping in mind that safety and environmental compliance -- environmental and regulatory compliance is our #1 priority. You'll see in a couple of slides just how important and how focused we are on this.

On the graph, you'll see -- that you've seen before is we've come from an $11 million CapEx program in 2009 to a $300 million program in 2013. Our EBITDAX has grown from $102 million to approximately $500 million over that same time frame. We currently manage 311 active wells associated with 167 major platforms, as well as a very active well work program, which includes 60 to 70 drilling workover coil tubing and through-tubing wireline jobs to over 100 P&A wells and countless production and facility projects. This growth -- this work that we've done has resulted in our oil sales up over 260% since 2009, and we've seen our run times increase as well as our LOE get reduced.

How do we handle this growth? How do we handle this growth? Again, pretty simple, a focused approach. We focus on 3 priorities and in this order: safety, environmental and regulatory compliance and then thirdly, execution. Our 3-year OSHA recordable incident rate is 1.14, which is a 15% improvement over last year. Our environmental and regulatory compliance is industry-leading. Our 3-year INC/component ratio is 0.033, which is almost 35% less than the industry average of 0.047. This is so important to us that our board has created an EH&S committee at that board level to help us drive to better performance.

And third, our priority is execution. We focus on shortening that time between project recognition and getting that oil and gas to sales. And we do it with that strong sense of urgency, keeping in mind capital efficiencies and cost control.

It's a collaborative effort between all the groups, as Andre had mentioned. It's us getting in front of these projects with permitting, facilities, all to be able to execute more efficiently. I began with it as a pretty simple approach. We work safe, we work within the regulations and then we execute well. And by focusing on these priorities, we add value to our company. We believe that safe operations are more efficient. It's a fundamental belief that we have in our company.

Here's a map showing our footprint of our operated core fields. The blue shaded fields, Ship Shoal -- South Pass 78, Ship Shoal 208 and South Marsh Island 239 as the newly acquired Hilcorp properties. As you can see, these new fields are relatively close to each other, to our other core fields, and this is important because we can share our resources. The water depths are close enough that you can use the same drilling and workover rigs and the same lift boats in these fields. This allows us to have a greater flexibility in our ability to high grade these projects. We're able to share people, such as mechanics, electricians, construction crews, between these fields and then we also share boats and utility boats -- our crew boats and utility boats, all to make these operations more efficient. We look to ways to optimize our people and our equipment, and this is how we drive our costs down.

Results for the acquisition to date. We've driven down the LOE by almost 9% since the Hilcorp purchase, and we're not done yet. That's a $511,000 a month cost savings, which equates to over $6 million a year in savings, which drops right to the profitability of the company. And if you recall, we reduced the Anglo-Suisse operating costs by almost 13%.

We did this in both cases by attacking logistics. This is one of our largest cost drivers in LOE and by focusing on it, we not only save the dollars, we also improve our efficiencies. Reducing the number of boat and helicopter runs makes us plan better. We eliminated a helicopter and changed vendors for those helicopter services. We reduced or changed out our boats for purpose boats, all netting us a better value.

We also changed the culture by infusing EPL leadership into these new fields. We switch the fields to a 14 and 14 crew change that not only reduced the number of boat and helicopter runs, but it made -- also made us more safer and more efficient. We focus on people because that's another large cost driver in LOE. We are able to unman 3 platforms. We, by -- and then thus removing unnecessary risk exposure, and then we redistributed 7 people to our main core fields.

Lastly, we focus on contract services, and probably the most important one in there is that we reduced or eliminated rental equipment and replaced it with company-owned equipment. Our expertise is here, in this part of the Central Gulf, and I think you can see that in these results.

Part of the LOE cost savings comes from good facility investments. The graph on the right there shows our run time of our East Bay compressors basically, in 2010, at 91% to where we are today at about 99%. We invested $13 million in overhauling our 6 East Bay compressors. We increased our run time by 8%. This equates to roughly 240 barrels of oil per day and $175 million in revenue over this long life field.

Our repair costs significantly dropped. We don't have problems with cooling fans and cooling tubes. Our head and cylinder repairs dropped, and we rarely have to replace our turbines anymore. Since acquiring the South Pass 78 field, we've identified that we can increase the run time out there by almost 4% also, and this will equate to about -- this equates to about 70 barrels of oil per day and about $46 million in revenue over the long life field.

The next couple of slides, we're going to show a little bit more detail about our newer core fields. We'll first look at Ship Shoal 208. It's 100% operated and about 100 foot of water. We currently have 3 rig operations underway on EPL-generated prospects. Just to reemphasize our sense of urgency, we acquired this property in November of 2012, just 6 months ago. It's just a great collaborative effort that shows that we can exploit these fields in this part of the Central Gulf.

In addition to the rig activities, we have facility work underway, so we can be out in front of all this production that should be coming our way. I've included a pipeline and a facility map to help demonstrate that this field was originally built to handle 30,000 barrels of oil per day. This shows that we have options at getting this production to sales. You'll remember, that's our objective is getting that oil and gas to sales.

Next, we'll go to South Pass 78, a 66.6% operated field and 190 foot of water. As you've seen just recently with that 7 well pulsed neutron log program, which had great results, and knowing that we've got existing back pressure of issues already out there and anticipating this feature well work, we've already begun the process and permitting process to install a new 3,300-horsepower compressor on our B platform.

Those white buildings that you see just to the left of the heliport there will be removed, and that's where our new compressor will be added. It will not only lower the back pressure on the B platform wells, increasing that production by 200 to 300 barrels a day, but it will also increase our compression capacity for our upcoming work.

This field was originally set up to handle over 20,000 barrels of oil per day. And as you can see, there's few pipelines interconnecting there with the platforms. So we'll be able to handle this production growth and the well work that's coming down the road.

Last but not least, is South Marsh Island 239, an EPL operated and on average about a 92% working interest located in about 20 feet of water. Great story here is that during the due diligence process, we identified a broken company-owned compressor with 2 rental compressors on location. And we saw that the wells were produced against the higher than normal back pressure. Our production and facility guys started the permitting process and a repair plan to fix that, and we're able to fix our company-owned compressor and then remove one of the rentals less -- thus lowering the LOE.

So by the end of December, less than 2 months after the closing, we executed on that plan and lowered the field back pressure and increased production out there at South Marsh Island 239 by 200 barrels of oil per day, and as well as we increased our capacity for the field. And again, you'll see the pipeline and facility map, there's plenty of infrastructure out there for us for the upcoming well work.

Our 2013 CapEx program is at $300 million. As you can see in the rig schedule, we're currently showing 6 rig operations. That's not correct. Actually, we have 7 rig operations going on this morning. We picked up a 7th smaller workover rig late last week that we weren't able to get into the slides, but that just shows how we can accelerate a couple of work overs in East Bay. But here's a perfect example of how EPL's sense of urgency to be able to take advantage of a situation where a less expensive rig becomes available.

So we not only save a few dollars, we're able to accelerate some production out in our East Bay field. And it's this sense of urgency that makes me very proud of our technical and operational people to be able to handle this quick changes to the plan as well as maintain our outstanding safety and regulatory results. Also to note that this schedule does not include our bread-and-butter work, which is our through-tubing, nor does it include our non-operated work. Besides being very active in West Delta and now at Ship Shoal 208, you can see that our rig schedule for 2014 is starting to fill out, which makes us very excited in trying to get out in front of this upcoming well work.

You can also see that we're using the same rigs on a consistent basis. This gives us not only control of those rigs, but it helps us drive our efficiencies, cost savings and makes our operation safer. The rig crews have been with us for sometime now. So they know what to expect out there, and we know what to expect from them.

Here's another really good example of our sense of urgency and team collaboration. As Andre mentioned earlier, the technical teams were introducing this L-6 prospect to our operational teams. As Andre's team went through the presentation represented by this cartoon, my group noticed 2 other workover opportunities that jumped right out at us. If this L-6 well is successful, then we'll be able to accelerate those 2 workovers.

Workover plans have already been permitted, put together to perform this workover. So as soon as we see this L-6 log, we'll be able to start that program in motion, which we already have a snubber out there in the Ship Shoal as we speak. So this is just one of the examples of something that we see quite often when our teams get together. We went in to discuss one well, and we came out of the meeting with 2 or 3 other opportunities for us to be able to go out there and execute on.

Changing subjects to P&A. We believe that our expertise in abandonment is a competitive advantage. This is a core discipline for us, and we focus on our already low ARO. This focus allows us to understand the liabilities we are gaining while we are assessing quality acquisitions. Our focus in execution on eliminating idle iron is a proactive approach we believe increases the value of our field. It also reduces our operating costs and reduces our exposure to safety and environmental risks.

So in conclusion, our key to success so far and our ability to grow the company is our people and the way that we collaborate together. We have common goals. We plan for success and execute with a high sense of urgency to shorten that time that it takes goal from project recognition to putting oil in the tank. We do that by focusing on our priorities of keeping people safe, protecting the environment, complying with the regulations and efficient execution.

Thank you for your time. And with that, I'm going to turn it over back over to Andre to discuss what's coming down the road.

Andre J. Broussard

Thanks, Chad. We talked a little bit earlier about last year, we began to execute on the West Delta area. About the same time as we began to get excited about what we're seeing in the West Delta area and about the ability to execute on 2P and grow our company organically, we said, since this model is working real well, the [indiscernible] model is working really well, we need to understand more about our own fields, not just in the section that we're comfortable with, but also let's take a little bit deeper and see what's there.

So to that end, we began -- we hired a regional expert to begin to look at the whole oil corridor that's out there and say, "What's below the field pay? What's below 12,000 to 20,000 feet?" And so last year, we came on board and began to tie in all the well control. So the things I'm going to show you today are tied to well control. They're tied regionally, so we're going east, take a look at the logs from the Deepwater out into -- onto the land, east to west, tying that information in together. He works in conjunction with the teams. The teams were so busy finding 2P projects that what he does is he just leads them to the section that could be prospective below their fields, and then they began to develop the prospect.

So today, we're going to talk to you a little bit about that 2P, 3P section. We believe it's a 3P section -- excuse me, we believe that's a significant resource add to us as we go forward. As Chad mentioned earlier, it's what we see down the road. So it's a little bit longer term view for us as we begin to develop the set of properties and prospects, but we're excited about what we're seeing.

I think it's important to note that when you think about the type of fields that we have, that most of our fields are salt related. So there's -- we talked about the vertical stacking of hydrocarbons along the salt flanks and along the top of the salt. And there's no reason for us to believe that as we look deeper, that's not going to continue, because salt is a great hydrocarbon migration pathway. It's also a great field for hydrocarbon. So that's why people have always been interested in salt domes, and we're very, very fortunate that we have the prime real estate within this oil window to be able to execute on.

So when we're looking at what's happening in the shelf right now, we believe there's a new technological evolution that's creating a new renaissance, if you will, of a deeper exploration along the shelf and we believe there's a lot of resources there. And we feel -- and as we talked about earlier, we believe these big fields just keep getting bigger. And we believe technology is a big driver in that as we continue to see things better, we're able to size them and we're able to derisk them. And so to that end, we'll be able to go drill them and exploit the opportunities that are out there.

We also believe that regional understanding is the key and that the leasehold, once again, is the key, owning those leases. And it's important to note over the last couple of years, we've been involved in those Central Gulf lease sales. And so what we've been doing over the last couple of years is shoring up our acreage position around our key fields because we're beginning to see some significant potential sitting along the flanks of these salt features along our core assets.

So let's just take a step back and look historically of all the number of wells that have been drilled in that oil corridor in the Gulf of Mexico. As you heard Gary say, this is where [indiscernible] 80% of the oil production's been produced out of the shelf, sitting right here in this window that you see. And you can see the number of wells, all the wells on that map are -- the black dots of wells, you can see the dense patterns. You can actually look at some of the rings of wells, those are the salt domes.

The maps along the fringes of the major map are all of our key assets, all of our key fields. So you can see the well control within those fields. So this has been an area that's been very highly drilled, a lot of dense well control. But when you get to 12,000 -- the wells that we drilled deeper than 12,500, you can see that the density begins to drop significantly, not only in the whole area, but also within our field pays. You can see that it changes dramatically.

If you go down to 15,000 feet, look at the change from all the wells deeper than 12,500 to 15,000 is almost very -- there's no -- hardly any wells that have been drilled that deep, not only in the area but also within our fields. Then when you get to 17,000 feet you can see there's really not much there.

So the question is, what's kept people from drilling deeper out here in the Gulf of Mexico? Well, a lot of the reason is because they hit pressure in the well and they would stop. They get to a pressure point and say, "We're going to set a pipe. It's going to be more expensive, technological hindrances. We stop drilling." Additionally, a lot of people, when they got to this pressure section, saw a -- gotten to a shale section thought, "We've gotten to the prospective end of the geologic world." So they quit drilling, and you can see that on the seismic line. The blue section is the section where most of the fields within this well window are located, and you can see very few wells go deeper.

However, there's always a few wild cats out there and took a little bit deeper and those are the type of wells that we're tying into on a regional framework because some of those wells drill into the red section, going through the gray shale area, into the red section, in the middle of Miocene in this case and found sands. And so we tie in to those sands regionally, and we began to tie that into our fields and see where the prospective section might be.

So over the last 5 years, what's happened, wells completed that are below 17,000? You can see going from onshore to offshore within this oil corridor, there've been a number of wells in the last 5 years that have been completed. Most of these wells have been drilled based on the reprocess, the 3D data we talked about. So as they've begun to do the reprocessing in these 3D data sets, they've begun to see some things a little bit deeper in less complex geologic settings, be able to resolve those features and drilling them has been success. We believe this is just the tip of what's getting ready to happen on the shelf as we begin to resolve these deeper sections more and more.

And what's happening is that the technological shift we talked about seismically, we've gone from 2D to 3D to reprocessed 3D and all the algorithms and competing capacity we've had. As we begin to look deeper, people are going, "Well, okay, do we need -- can we continue to build resolution with the data we have? Or should we now, with this new technology, go out and reshoot the data and create even greater resolution?" And that's what we're going to see happen.

So going from the 2D to 3D to reprocessing, we're now moving into a new phase of actual azimuth acquisition, using wide azimuth surveys. And you've maybe heard a little bit about wide azimuth surveys. It's been a tool that's been around deepwater for about 10 years, and they use it for the same reason we would use it and that is to resolve deep complex features, especially along salt flanks and below salt, being able to image those deeper structures. When you think about the deepwater, you think about the cost of a well, $100 million, $150 million to drill the well to go out and choose a new seismic 10 years ago at $140,000, $240,000 of block. That was not a big deal. But that's cost prohibitive for us on the shelf that we're drilling $20 million wells.

So what's happened over the last 10 years is the adoption of wide azimuth surveys has been incorporated within the deepwater. All the seismic vendors are shooting wide azimuth. All the deepwater seismic vendors that are out there playing are shooting these data sets. They've pretty much covered a lot of the nonproducing and exploratory areas of the Deepwater.

But now what we're beginning to see is beginning to see moving from the Deepwater, you see the red polygon there, on to the shelf. And there are 3 surveys right now that are currently being shot on the shelf. The one on the far right around the main pass area, aqua area, is a proprietary data shot being shot by Apache. That's, I think, $100 million survey, significant investment.

Additionally, Chevron is shooting around our South Tim area right now, wide azimuth survey, all with the purpose of being able to understand this deeper section, the complexity of that deeper section to resolve it, see it, size it and derisk it. So what we're seeing over the last couple of years now is this adoption or this intrigue into this new reprocessing or new acquisition opportunities on to the shelf.

Additionally, what we're beginning to see now is the kind of the widespread adoption. These are highlighted in the green polygons or the proposed wide azimuth shoots by various seismic vendors along the shelf.

So this technological evolution, this new ability to acquire data to resolve deeper, complex geologic features is beginning to march quickly onshore. And this is why those few wells we showed you that were completed below 17,000 feet with reprocessed data, we believe that the drilling activity in this deeper section is going to start to ramp up over the next few years as the adoption of wide azimuth survey takes place on the shelf. And the reason they can do that is because, we talked about it earlier, the cost per block is continuing to come down as we continue to create greater resolution through time with the new reprocessing technology.

If you look at that graph in the middle, it's very telling. This -- you look back to the 2004, if you bought bulk wide azimuth survey out in the Deepwater, cost you about $140,000 a block, if you bought in bulk. Today, that number is about $40,000. So I wouldn't say [ph] you're reaching a price point that's feasible on the shelf for drilling a $20 million well. You go out there and shoot wide azimuth survey over your fields and help resolve some of these deeper salt supported fields that we have.

So what is different about wide azimuth survey? Well it's about not only the source or the types of sources they use, but also about how they record it. So this is a great example of a wide azimuth survey. You can see that there's 2 boats that are shooting a source down into the sub-surface. Previously technology, 3D, typically use one boat as a source, maybe one cable right behind it. Now they use multiple boats, multiple cables. They've increased the cable length, and that allows them to really begin to appear [ph] below that salt, around that salt and come back and record that data. And that is helping them to better resolve the subsurface around and underneath the salt domes.

And so as we talked about, those are the types of plays that we're beginning to see below our section. That's 12,000 to 20,000 feet. This is not a Davy Jones type play. This isn't 34,000, 35,000 feet. We're talking about conventional type drilling, $20 million well cost, very common practice along the shelf that we're going to implement.

So what kind of uplift does it give you? Wide azimuth, as we talked about, really begins to resolve that data in and around salt and below salt. So the slide on the left -- or the picture on the left, conventional prestack depth migration. So this is the 3D data set, and you can see below the salt, salt highlighted in pink, you can see that the salt is highly resolved.

But below the salt, the pictures now on gray and a couple of ovals areas there and show you some of the areas of entry. When you go to the wide azimuth, you can see that the quality of the data, the continuity of the data dramatically increases. And this is what every geoscientist is looking for: the ability to see, to size, so you can derisk these prospects. And so we believe this type of wide azimuth technology has great application along some of our complex salt features on the shelf.

And so what are we doing now to unlock some of these deeper 3P that we believe is going to be the driver to double, triple our company going forward. Well, first of all, we talked about 2012, we hired a regional expert. We bought a regional 3D data to help him tie well control in to seismic. We already had a vast 2D data set that you had access to, so we've been using that to tie in these deeper sections. We also bought an interpreted 2D data that helps him get tied in, which goes across the Gulf. So he's allowed to really get tied in. And then we're tying this back into our core assets and saying, "Well, these deeper sections, how do they fit into the prospectivity around our fields?"

This year, we're continuing that work. We're also doing -- using some targeted reprocessing to help resolve some of the less complex features around our deeper potential, and we're continuing to build -- starting to build that portfolio. And then going forward, that portfolio will continue to get built. We will begin to take a look at wide azimuth as wide azimuth becomes available on the shelf. We'll begin to look at that data to see the quality, the uplift on some of the projects that are being shot now.

The good news about our data, our 300,000-plus acres of leasehold in the Gulf of Mexico, lion share of that is held by production. We talked about the long life of our fields. So we have the luxury of being able to look at this data, begin to figure out the uplift, the quality of the uplift, what our investments should be in it, where we should invest in it and how do we tweak it, if you will, to get the best result for the type of geological complexities that we have within these fields. So this is what we're going to be -- do going forward, and then we'll begin -- you'll see us begin to test some of these concepts, especially some of those concepts that we can resolve and derisk using our reprocessed data and we have some of those in-house.

So let me give an example of some of the deep potential that's already been drilled out in the Gulf and in fact, it's our field. We talked about the South Tim 26 field. It's one of our major assets, 184 million barrels. It's been around for about 40-plus years. And in 2004, about 40 years after the field was discovered, one of the geoscientists at EPL had -- saw an opportunity along the flank of the salt in South Tim 41. He saw 1 amplitude anomaly down deep, thought it might be a place to go test a well.

And so he drilled the deep well, down about 17,000, 18,000 feet, drilled the well and found 2 pretty surprising things. Number one, was that not only was it a one pay sand but there was a series of stack pays out there. Not only were the stack pay sands out there but down deep at 17,000 feet, there was oil. Typically, we think the deeper we get, the more gassy we get, but we're finding out that that's not necessarily always true.

And so we drilled the F-1 well South Tim 41. You can see the log here on the right. This RT sand, drilled down almost 17,000 feet, had a thick oil sand that came on production 2,000 and plus barrels of oil a day with associated gas. And this discovery in South Tim 41 ended up being 26 million barrels of oil equivalent, off the flank of a field that had been around for 40 years. And you can see on the seismic line that where that field sits relative to South Tim. You've seen the seismic line before, so that gold platform on the top of the seismic line off to the left there, that's our newly -- going to be newly installed ace platform here at the end of the year. And so that's our South Tim 26 field.

You can see when you go across the seismic line, that blue section, that's our field pays. South Tim 41 found some of those South Tim 26 field pays in it, but it also found deeper section. And so now we have deeper potential below our 40-year old South Tim 26 field. So when you look at the next slide, you'll see that one of the H platform wells we're going to drill is going to go down into that red section, which ties back to some of the pays we saw in South Tim 41. Some of them oil. And we believe we have a great opportunity to find significant reserves sitting under a field that's been around for quite some time.

Now as we talked about, when we get to newly reprocessed data in, we've got an expert who does our regional work. So we -- those guys work together. The teams and the regional expert work together. And so we started looking at what we saw in that South Tim 41 and 26 areas and said, "Can we take this information that we have and let's start moving it, thus putting a geologic framework across the area?"

And so this is a long seismic line that goes -- travels many miles through the South Tim area, and we begin to see similar opportunities within that blue section that were along the trend and we said, "You know what? These are very interesting." So you can see the white ovals starting in the middle, and going off to the right, we have 3 ovals. Those are newly acquired blocks within EPL shop that are prospective in the same section that the South Tim 26 and 41 is. And so we'd like to show you one of those.

This is in South Tim. This is a block we've recently acquired and it looks very, very similar. So we're always looking for analogues in our business. That's how we derisk, right. And this is one that looks very, very similar to the South Tim 26, 41 field that we have just to the north.

So once again, seismic line you can see the -- in the purple and pink is the salt feature, and you can see those dark red and black events that are right along the edge of that purple feature. Those are the pay sands and the salt dome field just north of our prospect. A beautiful section within that, beautiful section of pays within that blue section.

When you go off the structure just like you do with the South Tim 41 field, you go off to the right, you can see that we're going to drill a proposed well on a buried fault just like we did at South Tim 41. We're utilizing the newly reprocessed 3D data to resolve the amplitudes out here and the anomalies that we see in this prospective section. And once again, we see multiple stacked events like we couldn't see in 41 when we drilled it, but we could later on when we got the reprocessed data. We can now here, and we've derisked this prospect.

So this is one we'll probably drill next year. As a matter of fact, we're in the process -- the regulatory permitting process right now where we'll drill this well, and this has the potential to be about the size of South Tim 41. So a very nice looking prospect with a very similar setup to our currently producing fields using the reprocessed data, tying it regionally with our geologic framework, and we've got more like that.

This is also a newly acquired block that is salt supported, has numerous pay sands. There you can see the pays on top of the salt highlighted in oval, that's lateral oval and all the wellbores that were drilled into it. When you go along the purple salt there on the side, you see the elongated up-and-down oval. Those series of amplitudes, those dark red and black events, those are all pay sands within there.

What's new is the section below it, we didn't see this. Also, when you get to that red section below it, there's a series of stack anomalies like that ones you see just above it, that are just stacked a little bit deeper. We're talking that 15,000 to 20,000 feet. So we're not talking ultra deep, very reasonable well cost with great upside potential.

Not only that, when you go off to the right and you see that buried fault just like you saw at South Tim 41, just like you saw at the prospect I showed you on the last slide, you have another set of just like this with a beautiful amplitude on a buried fault, actually a series of amplitudes. All these have a great upside potential that we're going to execute on the years coming forward. So we believe this is what drives our company as we head out in 2 to 3 to 5 years going forward.

This is our East Bay field. This is one of my favorite slides in the show because this is a -- we talked about it earlier. This is a 1 billion barrel field. It's been around for 60 years. And if you look at the blue section, which is the field pays and you compare it to all the section that's below that's really never been adequately tested, you go, oh wow, there's a lot of section out here that really hasn't been resolved properly with the seismic data that even with the reprocessing efforts that had been out here to resolve the actual shape of that salt you see in purple, still not accurate.

So when you start thinking about where wide azimuth might have application within EPL shop, this is one of those places. Our regional expert got in here and he started looking at the well loss comparing it to the seismic section and go, there's some discontinuity, some mismatches here that don't make sense that need to be resolved. And so not only do we have potential along the salt flank, you see the oval on the salt flank at about 12,000 to 17,000 feet, but we have a significant structure, we believe, sitting below the East Bay field below the salt. So when we look at something like this, we go, there's -- we think there's a lot of potential still to unlock at East Bay.

This is another one of our fields that we own, not to tell you which one it is today, still working this through, but we've got though -- as you see in the blue section, we've got a number of wells that we drilled into that blue section field pays. This is a 6,000 to 10,000-foot section in the field pays, but just below that section, 12,000 to 20,000 feet is the Middle Miocene section that we tied back to the well control with sands, and we see numerous structures and amplitudes that are sitting in within this section, some of them fault trap, some of them 4-way closures that we're really excited about and we're continuing to resolve this. And we believe this has great potential for us in this core asset of ours.

Let's move on to another one -- a really -- recently acquired blocks. This block was actually acquired for shallow -- an opportunity of 6,000, 7,000-foot opportunity, 2 pay sands, been a prolific oil producer in the region. We used our regional 3D seismic data to identify this. We derisked it by taking some derivative products. You can see the Gather on the upper right there. That Gather, if you remember the Gathers, the technological slide we've shown in the 2P, whenever we have a Gather panel and the color is bright from left to right, that's typically a hydrocarbon indicator. This has a classic hydrocarbon indicator response. It looks like the fields around us. So once again we use technology to derisk. We use analogues to derisk. And so this is a -- very excited about this prospect. Got this in shop, the regional expert began to take a look at this, and say, "Well, what's deeper?" And so the -- once again, the prospect that we're going to drill in that blue section at the top, you can see where the wells have been drilled, but very, very few wells, if any, drilled deep. But if you look where that -- the white oval is in the red section, once again Middle Miocene, 12,000 to 20,000 feet. Numerous amplitudes, structural features that we're quite, quite excited about. That we're beginning to resolve now. And then if you look at this slide, too, you'll also notice, the structure goes all the way down to the salt. I mean, when you start getting down to the salt, that's pretty deep stuff. Well, we've got planned opportunities in that 12,000 to 20,000-foot range.

Now to finish up this morning talking about another prospect. This is off of one our -- this is off of our newly acquired blocks. This is a great opportunity of a salt flank test like the other ones we showed you. This one is quite unique because we've actually got offset production analogue just across the sink line. You see that the -- that well up on the upright on the map is the B2 well drilled by another company at a block to the northeast, and Tex X Sand produced -- that field produced 845,000 barrels of 56 BCF of gas. You can see the log on the side, about 200 feet of pages on this 1 sand. And this also has stacked pay potential out here. And you move to the south, into the west, along that fault, you can see the star on the bottom right of the map, that's our proposed location to begin -- to develop this prospect. Now pretty excited about it. Once again, stack pays alongside of salt. This is that prospect here on the seismic line. Beautiful salt feature, and you can see in that blue section, numerous stacked amplitudes out of the field pays that are good -- prolific producers for this field, but when you get off the flanks, you can look off to the right of the salt, you see the red line going down, that's our proposed well location into the red section, numerous amplitudes on buried faults deep along the salt flank. This is a great geologic setting for finding hydrocarbons, and we're really excited about this prospect as well. So this is just kind of a look at some of the prospects we have and as deep at 3P. You're going to see us do a spattering of tests out here as we begin to resolve some of these on the reprocessed 3P. We believe this is -- this set of properties has a longer-term view, but when you combine this with a 77 million barrels, and you add the 2P that we've already executed on, the 2P that we've got in front of us and that inventory is growing, that could potentially double the company, then you look at the section below us, that we believe has just as much upside potential as anything we've looked at within the field pays, this has the ability to really significantly change the face of our company, and we're just getting started. And so we're excited about this and I hope you get a sense of the opportunity and upside that we have within our inventory.

So with that, I'm going to turn it back over to Gary. Thank you so much for your time, and I'll be able to answer questions here in just a few minutes.

Gary C. Hanna

Well, as you can imagine, our shop we've got 20 guys just like Andre and you wonder why I just want to go to work every day. So it's a buzz all around. And I can assure you on the 3P, we've shown you what we can. It's the tip of the tip. We've got a lot of things going on. We will not be discussing. They're proprietary, and it's just a very exciting time for our company. Just kind of -- a couple of slides here, then we'll get to the Q&A section. Just some key takeaways I want to make sure stuck today: continued focus on our basin, continued focus on capital efficiency. It's just a promise we make. T.J. said earlier, we -- honestly, we don't know another way to do it. So I assure you, that's how we will continue to run our company going forward. And that 2P, that historic-producing horizon, we have a lot of running room. We have a lot of inventory for years to come. We could go years and not do another acquisition and continue to grow our company at the pace we've done it. The 3P that we look at is really just the icing on top of it. And if you're looking for something that could revolutionize the company in 3 to 5 years, that's the play we think is coming at us. We don't think we're out there waving at windmills, we're seeing a couple of very strong competitors in Apache and Chevron taking the same thing on. So we think we're on the right track and that's going to be -- it's going to be an interesting ride. Again, that integrated approach is important to us. We talk a lot about the efficiency. We think we do that well and we think we do it safely. That's just the big takeaway. So a great lookout for us over the next 3 to 5 years.

Just a couple of slides on making a case for owning EPL versus some of the other plays. We've made some headway over the last, really, 12 months in catching up to our peers. Our peers being the typical basket, the 21 Stone, [indiscernible], et cetera. We've caught up to them, which is great. It's a nice to do that but we, as a basket of companies and particularly ourselves, we still traded at a discount to NAV. We certainly trade at a discount to oil and gas shales. We've had this slide in before, it always surprises a little bit on the multiples on the gas shale side but obviously, we've got some work to do. We think where we are today, we've so much transcended up our peers. We think that we need to be going out and looking at some of these basins and start to educate, if you will, and the investment community, we feel like in a certain ways, we're blazing a trail through the world's misconceptions about our basin. And we need to change that thinking in order to bring our company and our stock behind it to raise that multiple up and try to get some expansion there. So it's a little of what we're trying to do today.

This is kind of the first shot at doing that, if you will. These are new slides to us. [indiscernible] let's go and look at the oil shales. We took the basket of Bakken, the Eagle Ford, Utica. Took the best players we could find in those plays, did the same thing in the gas shales, put them up against our peer's lists. Let's go compete. Let's go make an argument why our basins every bit as good as those basins. We've got to get people over the idea that we're gassy, and a treadmill and we all spend our cash, all those things are simply not true. So if you look at this production, I was -- we hadn't run this before, I was really surprised. If you look at the best of the oil shales, we're simply oilier by production in our basin. Our cash margins are significantly better. Our R/Ps are very competitive. Again, I'll make the argument that our economic lives on the average of our key 7 fields is over 20 years. And then you look at our cost structures on our well costs are very, very similar, $6 million, $7 million to $10 million on average. We get into these deeper wells, we're going to run a little bit more, those will be $15 million to $20 million type wells, but we'll tend to sell interest down. We're drilling 90% wells for a $7.5 million. We're going to take 100% of those and do them all day. We'll get a little bit deeper, we'll start to sell those and hedge or bets, we'll do deals, we'll swap acreage, we'll obviously, spread those bets out on the deeper side and you know us, we're just conservative by nature and that's how we're going to do it.

I just think it's a fascinating comparison. I think where we go from here is to start compare our inventory against those inventories. The perception that we have the same kind of repeatability that they have, and not only that we have the repeatability left to right, east to west, but we have much more of that north and south. When you really start to look at our company, what we have in the horizontal opportunities at all of these different depths, I think that it's something that no other basin can offer you today. The only exception, that might be Deepwater, and that's just a completely different profile. Okay.

That's the mission. So a very targeted approach, great real estate, guys talked about resource plays and then into the heart of that basin, we're in a key acreage positions in our quarterly block, again we'll stay focused, we'll stay operationally consistent and safe. And again, if we haven't mentioned, we've got some technical expertise and I'm very, very happy with the folks we have on our shop.

With that, we'll take some questions, we've got, I think, the room till noon. We'll use every minute of it, if we can. When you have a question, if you would, maybe state your name and your company. This is in a webcast, we should be able to come back later and listen to this as well other people. I think Anthony [ph] has a microphone. With that, if you'll state your name, your company, we'll start taking questions. Thanks.

Question-and-Answer Session

Dan McSpirit - BMO Capital Markets U.S.

Dan McSpirit, BMO. Any update on the Hilcorp 2P estimates, any early read you can share with us today maybe on it?

Gary C. Hanna

Not an early -- yes, not an early read. Can everybody hear this, okay? I will repeat the questions if -- yes, okay. Not so much an early read, we don't have this tremendous expectations for Netherlands, Sewell 2P report any more than -- if you look at how conservative it is on our base assets, we don't expect them all of a sudden to come up with some giant number on the Hilcorp side. You see some of our estimates, we used 10 million to 15 million barrels, that's pretty consistent with where we are on our based stuff. For us to get that 2P, build those packages, get to Netherlands, Sewell, educate them is going to be a process that's going to take some time. From a timing standpoint, I think we're, at best, we're probably looking at late-summer, T.J.?

Tiffany J. Thom

That's right. And really, something that we've been talking about, summertime being the target, I think we're on track. Whether that's going to be late or not, who knows? It's a little bit of a push but also, we want quality, so...

Gary C. Hanna

Yes, you can only push those fellows so hard and you want that quality work. At the same time, you remember, we took all the Hilcorp assets, turn those back over on our -- on the 1P to NSAI as well, so they're doing that in parallel at the same time. So I mean, we fill the [indiscernible]

Dan McSpirit - BMO Capital Markets U.S.

And will that estimate be exclusive to 2P or will there be a 3P reserve revision as well?

Gary C. Hanna

We do not have them working on 3P. We do that internal.

Tiffany J. Thom

That's right.

Stephen F. Berman - Canaccord Genuity, Research Division

Steve Berman, Canaccord Genuity. Just one clarification, Gary, on the 3P deeper program you said about $15 million to $20 million of costs and you said you would sell interest down, I just saw 1 slide that had a $20 million drilling costs, $30 million to drill and complete, so is $15 million to $20 million just the drilling of the dry haul cost?

Tiffany J. Thom

Dry haul. Yes, and look it's got a range. Some of these, it's just going to depend on how deep we go. Correct, Andre? It's pretty...

Andre J. Broussard

Yes, that's correct.

Tiffany J. Thom

It's a pretty blanket statement, but true.

Andre J. Broussard

Yes.

Gary C. Hanna

Yes.

Tiffany J. Thom

All right. And how many strings in the pipe and it depends on where we are within the section. As you get across the different sections in the Gulf, some of that stuff comes up a little bit shallower and then you traverse over to the west and goes a little bit deeper, so it just going to depend.

Stephen F. Berman - Canaccord Genuity, Research Division

And what's the time line on the surveys being shot by Apache and, I think, Shell was the other one?

Gary C. Hanna

Yes, that's actually Chevron. I think the Chevron's done.

Tiffany J. Thom

Yes.

Gary C. Hanna

Well, we're hoping to see at least samples of that line in the next -- he hates the idea.

Andre J. Broussard

Yes, hopefully, soon.

Gary C. Hanna

And hopefully, soon.

Andre J. Broussard

Real soon.

Tiffany J. Thom

Yes, that's right.

Gary C. Hanna

Yes.

Andre J. Broussard

They're actually in the processing shop right now with that. And it looks like they've probably been in the water just for a short period of time with the Apache, one out of main pass.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. And last one for me. On the acquisition front, your views on oil versus gas, we're in a better gas environment than they were, I think, Hilcorp was kind of a mix between oil and gas. So what's your view today there on...

Gary C. Hanna

Well, if you go back to Hilcorp, it's 50-50 oil and gas. We looked at the metrics of that when we acquired it. All-in, on a Boe basis, $14 and something a Boe. We said, "Let's just take the gas and give it 0 value." It's $25 a barrel. If you give it a $1, $1.50, I think a sub-$1.20 on the oil. So that's kind of how we look at it, Steve. Depending on the environment, obviously, we went on. We hedged some of that gas. We're not afraid of that gas. I think on a very gassy acquisition, it's still very hard to make that compete. It's always a mix of how that competes from in -- but go ahead.

W. Mac Jensen

Yes, well, I know we just added that. As you recall, we're buying these properties on an attractive borrower just on approved basis, but the real reason to buy them is to increase the production and the reserves. And at today's prices, unless you have a crystal ball, we just don't see ourselves doing a lot of gas-related projects. So that makes it hard to execute our plan by buying a lot of gas.

Tiffany J. Thom

And just keep in mind, where we're hunting, where we're looking for new assets, new leasehold, we're in the oily section of the basin.

Gary C. Hanna

It tends to be oily.

Tiffany J. Thom

Just tends to be.

Gary C. Hanna

We have a fair inventory, early deep inventory of gas projects on the shelf. And I can assure you, if it turns around and those can compete in our -- in the way we structure our capital programs, we're just very disciplined, everything competes for capital in our shop. That's an evergreen process. And so we move our program all the time. You need a significant price increase in one of those to compete with these well projects.

Andre J. Broussard

Yes, and I might add as well that when you look at the -- our focus of our teams when we -- whether we're in the beta room, looking at an acquisition or whether we've got it acquired and then we got a job, our focus is on those oil prospects. So the inventory that we're developing, the things we're looking for. When we're looking for upside in a beta room, that is all about can you grow the oil side of that business? Because we -- that's where we're focused on. And so when we see -- do these acquisitions because we believe there's a lot of oil upside in these fields.

Gary C. Hanna

Did that help? Okay.

Raymond J. Deacon - Brean Capital LLC, Research Division

Ray Deacon, Brean Capital. I was trying to reconcile the number of projects versus the 50 million barrels of upside the -- it seems like if you do the math, you're somewhere between 800,000 and 850,000 Boe's per project and that would be higher than most of the projects you've kind of shown in here between 200,000 and 500,000. And I guess, should I read into that you're -- you see more upside in future projects or is that skewed by some big reserve adds maybe?

Andre J. Broussard

I'm think -- when you kind of look at the pie chart to the bottom, you see that, I think, it was beginning to unlock some of the opportunities within the Hilcorp assets. We're beginning to see some bigger reserve potentials in those. And that's why you're seeing that split. So yes, we are seeing some -- actually, some bigger opportunities within the 2P section in the Hilcorp properties.

Tiffany J. Thom

Yes, there's definitely a smatter increase in that technical term a lot of 1 million to 2 million barrels type prospects within that initial look at Hilcorp.

Gary C. Hanna

Ace [ph], do you see a fair amount of discussion and a show about West Delta, and we chose that because of the operated nature of what we've been able to do with that field and that is the best analog we have for the 3 other fields within Hilcorp. So we talk about Hilcorp kind of being ASOP on steer prices, but it's what use on our shop and it's absolutely true.

Unknown Analyst

We heard a lot about acquisitions, what would be divested that's another way of asking, what are your lowest-return properties that you would consider divesting over time to further high grade the asset portfolio.

Gary C. Hanna

Yes, a fair question. Any time that you're going to acquire a company, you're going to get a pieces of things 10% non-opt out and high [indiscernible], and I can go on about just examples of things that aren't core to you. We have our share of those as well. Again, if you look at the 7 core fields, it's 95% of the value of our company, over 95% of the revenue of our company, right, maybe even more. And so we have a spattering of those things that are just not core to us. It's not to say, they're not good prospects, but as a non-opt, small owner, there's not much a way for me to drive it, right? And it's not worth our focus to go over and look at something that doesn't have the economic impact. So we're always looking to ways to perhaps monetize those for sale -- sell them or trade them in order to maintain that focus on our core. Focus, focus, focus. I can't say it enough, but there are things that are just simply not core to us that we would divest at, so the recent deal at Bay Marchand. That wasn't really something that was on the market. Chevron came to us. We thought the price was very, very good. And again, a non-opt, something we couldn't drive and made a lot of sense to us to do that.

Unknown Analyst

And then just a follow-up, can you sketch for us what the M&A market looks like today? And how clean are those packages from a liability point of view, from an ARO point of view?

Gary C. Hanna

Mac, you want to take the first shot at it?

W. Mac Jensen

Yes, certainly. Well, I would say that's -- the acquisition market today is different than it has been a little bit for the past few years. When we first started going on this, we saw a lot of other companies exiting the Gulf and so the sheer number of transactions or possible transaction was very high actually for a relatively small area. A lot of those we didn't care to own and so what we see now is the absolute number of transactions has come down, but the number of transactions that we think, at this point, appear to fit our criteria, actually has grown from our line sight over the next 12 months or so. So we're cautiously optimistic that we'll find something after due diligence has been done that will fit our criteria and hopefully, that we'll be able to make a deal with a seller.

Tiffany J. Thom

And there's always a reason for caution, Mac?

W. Mac Jensen

Yes. The advertisement doesn't always fit reality after we take a look at it.

Gary C. Hanna

Are you making that?

W. Mac Jensen

So I can't say that for sure that we'll do one of these. We may look at -- and we looked at 100 million. As I said before, we looked at 100 million Boe. I mean, we really looked at them, not just the other onside, I looked at it for 30 seconds and said, "No, thanks." So you never know until you get in there.

Gary C. Hanna

You have to do the work, get to the ARO section of your question, it a component of what we look at. Does it have operations? So an upside potential and there's a book -- click off, these boxes, ARO is certainly one of those. We're not afraid of asset return allegation, we think we execute on that well, but it's not something we seek out. We're not going to run away from it, but if you take that Hilcorp, for instance, had a very low ARO. Obviously, that's in the plus column. If it's a little heavy on the ARO, there has to be some really compelling reason to overcome that for us to take that on and have the kind of flow with it.

Tiffany J. Thom

That's going to be upside right, Gary?

Gary C. Hanna

That's all an upside. It's all kind of the balance of value. Again, we get that ARO and we figure, as long as you're going to have to do it and everybody does, you might as well be good at it. You might as well be efficient.

W. Mac Jensen

I'd like to say that Chad and his team have already proven they're very good at it. They don't need anymore practice.

Chad E. Williams

No, we're taking off this.

Gary C. Hanna

We've flowed over 150 wells, over the last 3 years. It's going to be impressive. Any more questions? We've got plenty of time.

Unknown Analyst

Doug Busbyshells [ph], Benbrook Management [ph]. How competitive have the previous M&A transactions that you completed in, in terms of how others looking at it? And what sets you apart from your ability to analyze the data ahead of being comfortable with going forward with it? And is it coming down to discipline on pricing, if you're comfortable with it, but there's a certain level, which you're only going to be willing to pay before you truly understand what you're buying?

Gary C. Hanna

Yes, we'll answer that backwards. We'll do all of the due diligence necessary to get comfortable with our pricing -- of the acquisition. And there's always a pressure point when you say, no, you just won't do it. That's a mixed bag. Typically, we're buying PDP. I mean, we're may be...

Tiffany J. Thom

Well, yes. I mean, look, nothing works unless we buy it right.

Gary C. Hanna

Yes, that's the first thing.

Tiffany J. Thom

That's the first thing.

Gary C. Hanna

Of course, buy them right, get the cost cut, get your studying done, execute well. That's the process of going through it. It's always, there's some competitive aspect to every deal that you do in some way shape or form. So I won't say there's not competition, there's just not a lot of it.

Tiffany J. Thom

Right.

Gary C. Hanna

Where you might get onshore and have 10 or 15 guys banging for a play, we typically have 1 or 2. On the ASOP deal, for instance, our key competitor there was the -- is this existing management team that wanted to buy that. Well, that presents some set of problems. They don't show you any data. That's the starter, okay? So we had to get things in different ways publicly available information that just weren't forthcoming. So when we exited that, we had 1 PUD. That's all we knew about the asset when we closed besides the PDP. So we had to educate ourselves and start flatfooted there. This was a different kind of an acquisition here. We were able to do a lot of work on the front and right up to the closing. So we already have the 3D in-house. They were very forthcoming, fantastic data room. We could really do that homework and nail those numbers down. But we still had competition on that. I think, there was a limited number of people invited to the room. I think that's a big key. And that's mainly because of the reliability aspect of dealing in the federal water in the Gulf of Mexico. You can't ever escape that liability. Okay? You sell it, 15, 20 years later the company it owns goes bankrupt. They're going to go back to the next owner. And if he's gone, the one before that. If he's gone, the one before that. All right? It all ends up with a guy with -- holding a bond. Look at that magic eyes, but ones never been called in the history of the Gulf of Mexico, so when I come back with a bond guy, you know why. But you can't escape that liability, so you always want to look for a high-quality buyer. It's so important in the Gulf of Mexico, and we think we always want to be one of those 1 or 2 or 3 guys. These are good companies. I'm not saying they're not good companies, they are. But if you look at some of our other peers, they Stone, they're just not in the acquisition mode, right? This is a different model. It's that simple. That hit all the points? There's multiple pieces, I'm just trying to get them all.

Unknown Analyst

Have you considered, based on your product array now with oil and gas reserves today, how that's changed, how that's expected to change going forward and what that might be for free cash flow generation taking out here...

Gary C. Hanna

All right. Good questions.

Tiffany J. Thom

Yes, I think it will certainly stay healthy. I mean, obviously, we're in another transition as we start ramping up production on the Hilcorp side. So you asked what natural decline is, well, we're not. We're in a growth phase. So obviously, we're going to see it increase. But the basic answer is most of our field areas are hyperbolic. If you layer on downtime, and you look at the natural decline of these fields, we give it a conservative 15-or-so percent on the oil, and maybe 20% on the offset. That's pretty shallow. And as you look at gas, we don't differentiate. I have a strong belief I think all of us sitting up, particularly Andre on design side as well, and in practice what Chad have seen day in and day out, gas wells just decline very rapidly. We're no different, 30%, 40% sometimes upwards above that. Frankly, right now our gas is holding in there, but doesn't really matter that it's doing that. It's only providing about 5% of our revenue. In terms of going out further, could it -- I think, again, the answer is we're not going to see -- we're going to be able to overcome that decline pretty easily with the type of execution we've been talking about. And in terms of fee cash flow, as I indicated, I'm very comfortable with continued hedging programs, protecting that downside risk, looking at our assets and always thinking about the right way to produce them, execute. We're going to see that free cash flow generation that's self fulfilling than macros bringing on spades on these assets, continue to bring home, I think, that free cash flow from 3 years to come.

Gary C. Hanna

Correct. Remember we replaced 187% of our production last year? And that was all kind of tied together. 77 million Europe company will roll off to that 8 million barrels as your equivalent. [indiscernible] declines. Anymore questions? Yes, ma'am?

Unknown Analyst

Outlook for the borrowing base?

Gary C. Hanna

Outlook for the borrowing base?

Tiffany J. Thom

We obviously, have abnormal phases, semi-annual determinations, sort of right in the middle one. We simply just don't -- we don't push the borrowing base, so we're very comfortable even if as we look at it today, what our objective is, is not to be so concerned about what the barren base level is, which is quite healthy $425 million, but you pay 50 bps on the unused piece. So what we're looking at is actually using our cash that we're generating to go ahead and pay that revolver down, and all that's doing is providing liquidity. As we look out further, I think, obviously, as we look at acquisitions and a reason to kind of increase that borrowing base, we would do that.

Gary C. Hanna

It's a good Question.

Unknown Analyst

On the bypass opportunities, are you finding that you're getting smaller and smaller over time, or is it your expectation that you'll get smaller over time.

Gary C. Hanna

Our short answer is no but, Andre, go ahead.

Andre J. Broussard

Once again, each bypass pay, you look at each one and say, "This is economic." So first of all, it's got to bue economic. That's always a key factor. Bypass pays -- it's hard to know whether they're getting smaller or not because they've been bypassed for so long, so -- but we've got -- if I understand your question correctly, we've seen a lot of good-quality bypass pay opportunities. I mean, even going back in East Bay. We showed you a couple of those today, so I think we're still seeing quite robust type of bypassed pay opportunities within the field. I think we've got a lot more to uncover. I think, especially when you look at that South Pass 78 we showed you today and all the evaluation work we have going forward, I think that's going to be a great story for us.

Gary C. Hanna

I think one of the interesting things for me that we're doing that you saw in the show was a low contrast pay and what that could mean to the company. You look at that as really bypassed, and we've got some things going on there already, South Pass.

Tiffany J. Thom

Absolutely.

Gary C. Hanna

49 would be an example if you go back to Energy XXI show. They'll have a nice slide in there on -- they operate that. I think we don't, but have -- Sara [ph]?

Tiffany J. Thom

Roughly.

Gary C. Hanna

So -- which is a low-contrast pay. It's making, in fact, 22 million cubic feet of gas today on 3 rig completions. That's a real.

Unknown Analyst

Some of those acquisitions, are you only -- looking forward, are you only looking at similar acquisitions like you've had in the past with reserves? Are you also looking at potential acquisitions with entire companies, like some other publicly traded companies?

Gary C. Hanna

I think that -- then I'll let Mac answer this as well. We're somewhat indifferent of the vehicle, and we're looking at all kinds of things. So it doesn't matter to us as far as how the transaction get done. I will say that we are limiting our acquisitions to our basin. And I'll make it clear that could go right on the shore tubes as you look South Louisiana, our onshore. Geologically, it's identical. It's the same thing. So for us to say we'll never go onshore, it's -- that's just not true. I mean, we would. But we think we have a lot of running room in our basin. We think we can increase our benefits of scale in our basin, so we're going to stay focused for know where we are. We'll see how it goes in time.

Unknown Analyst

Is your metric like years of return of capital of anything like that you'd consider as primary?

Gary C. Hanna

Well, there's been probably a half a dozen key -- yes, there's a lot of metrics, but that certainly one of them. But go ahead, Mac.

W. Mac Jensen

Well, as far as metrics, we never value an acquisition based on a benchmark because that benchmark is, in the end, meaningless. So based upon the reserves that hold it up. We've been able to buy assets that I think has a very attractive RRR on the prudent reserves. Well, the idea that we'll be able to increase the reserves and production after that and achieve is a very superior return, that's the way we look at the acquisitions. Another thing is the assets that we're looking for are quality assets. They're very attractive even so -- and many times, the first criteria is we'll -- how can we create a situation, is sometimes an overused term. But how do I create a win-win situation such as if they want to sell as the asset, and we can do it in a way that works well for them and works well for us, and I think I gave you a few examples during my presentation, but when we can find that dynamic, that's when we're successful in an acquisition.

Gary C. Hanna

We have one back. Yes?

Unknown Analyst

Gary, Garyson [ph]. As you all have more success in a 2P program, running 2P improves, I mean, do you foresee a change in how reserve auditors look at 2P as [indiscernible] bypass today, and start doing business with us? Is there an opportunity for that [indiscernible]

Gary C. Hanna

That's an interesting question.

Tiffany J. Thom

We start with they're conservative by nature. And yes, I think there's always the ability to see things get pushed a little bit, but our objective, in many times, I don't know if we've said it clearly enough is by the time we can bring it to the auditor, these guys are already talking about drilling it. So in many cases, we're proving it. And so we're going to get a book of proves. So to a certain degree, a little bit of hold category is really all we're talking about.

Gary C. Hanna

Yes, it's -- it'll be -- that would be tough. That would be hard, just given their nature. The reserve guys pretty much have a setup so we'll never be wrong. And that's why you have Clayton [ph].

Tiffany J. Thom

No, and that's not a bad thing. That's why we believe we should be considered -- consider that 2P a little bit more of proved-like number.

Gary C. Hanna

Correct. Yes, sir.

Unknown Analyst

Can I ask you about your strategy?

Gary C. Hanna

Yes. Is that your question? I didn't catch it. What is our strategy?

Unknown Analyst

Well, in general terms, how do you look at that? Is there a certain percentage you'd look to add to your or [indiscernible] in the future or...

Gary C. Hanna

There is. I mean, we will -- generally, we'll look at it -- want to be about 50% hedged. That's kind of a ballpark rule that we use. We decided to hedge a little heavier following the Hilcorp deal because we did have some credit exposure. Just want to make sure that we lock in those economics also. We went up to 62-or-so percent we always have to be mindful of, obviously, deliverability risk, and kind of weather issues that we will -- until the today we got to deliver those barrels. We'd be -- when we have a little bit of debt like we did, although it's driven down, we'll be a little more aggressive in hedging. Where is the price? At the certain price level, we might be a little more aggressive. For the longest time, we haven't been hedged in gas. We didn't think there was much downside to gas. Why hedge? So it was driven by the price of the commodity itself. We've recently put a few gas hedges on after the Hilcorp acquisition because we thought, "What the heck?" We think they just kind of gave it to us. We might as well lock in some economics. So it's price driven. Okay? Yes, sir?

Unknown Analyst

As you're looking into 2014 and beyond, what percentage of your CapEx budget are you willing to risk on the chasing of some new properties?

Gary C. Hanna

I think that I don't really know the answer to it yet because I -- it's hard to say what is that amount, how much, what is it all relative to what we have at the time, what does asset base look like at the time, how much success have we had with our us spattering, if you will, on the early success of -- there's a lot of variables in there. I think that for our size and where we're going, and you're going to see our capital programs continue to increase every year, see our top line continue to drive way up as well. That will makes some sense to start to expose dollars, to 25 million-barrel finds, it makes a lot of sense for us, especially if we can sell some of those down, spread our bets out and do it in a smart way. So a little high-risk profile but much larger. So it would -- I don't think you'll ever see us where -- yes, we're going to spend 75% of our capital, looking at those types of deals, but I can see a point in time where it would be a fairly material amount of money. So that's hard to look out that far a bit -- I can see a fairly material dollar amount being allocated to looking at those types of plays.

Tiffany J. Thom

And then clearly '14 would be really early for...

Gary C. Hanna

That, that's -- yes, we really think '15, '16, that's when you really start to cut on that play. Yes?

Unknown Analyst

Can you just comment on leverage going forward. Clearly, if you use a lot of cash flow paying down debt of your term loan, you are in the acquisition market, you see an opportunity, where can you possibly see leverage taking up to [indiscernible] even before you start to possibly bringing back down debt?

Gary C. Hanna

Yes, well, I mean, just kind of answering that when we close till -- at the highest leverage we'd ever been at 1.6. I mean, it's still pretty conservative number. But it's kind of getting up there towards the tips of where we're comfortable as a company and as a management team. If we wanted to do a $550 million transaction today, it would be much, much easier to do than it was 6 months ago or 6 months prior to that, or 6 months prior to that. So you could a $500 million deal today T.J. and really -- it's going to...

Tiffany J. Thom

Look, we're back at an underlevered position, projections are, I think, solid. And obviously, our desires is to always come in and out of transaction in as good a shape as we can.

Gary C. Hanna

As strong as you entered.

Tiffany J. Thom

Or a very, very quick line of sight to bring it back down. And it goes back to the earlier question, are we going to really deviate from buying proved reserves, buying production and the answer is, we're in the higher the basin we're 80% of production in the Gulf of Mexico on the oil side is coming from most of these assets have cash flow. And so, it's just -- again, it's not self-fulfilling deals, so...

Gary C. Hanna

All right. Did that answer it? Okay. I think that's it. Well, thank you, all again. We really appreciate your time. Thank you.

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