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Apache Corp. - Analyst/Investor Day

Apache Corporation (APA)

June 14, 2012 9:00 am ET


Patrick Cassidy - Director of Investor Relations

G. Steven Farris - Chairman, Chief Executive Officer and Member of Executive Committee

John Christmann - Vice President

Robert V. Johnston - Region Vice President of Central Region

Rodney J. Eichler - President and Chief Operating Officer

John R. Bedingfield - Vice President of Worldwide Exploration & New Ventures

James L. House - Regional Vice President of Apache North Sea Ltd and Managing Director of Apache North Sea Ltd


Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Joseph Patrick Magner - Macquarie Research

John Malone - Global Hunter Securities, LLC, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Patrick Cassidy

Please take a seat, and we'll get started. Good morning, and thank you for joining us for Apache's 2012 Investor Day. Speaking today, we have: Steve Farris, Chairman and Chief Executive Officer; John Christmann, Region Vice President for the Permian Region; Rob Johnston, Region Vice President for the Central Region; Rod Eichler, our President and Chief Operating Officer; and John Bedingfield, Vice President for Exploration and New Ventures. We also have several other members of the management team for Apache here with us. This includes: Roger Plank, our President and Chief Corporate Officer; Tom Chambers, our Chief Financial Officer; Mike Bahorich, Senior Vice President and Chief Technology Officer; Kregg Olson, Senior Vice President for Corporate Reservoir Engineering; Alfonso Leon, Vice President for Strategy; Bob Dye, Senior Vice President for External Affairs; and numerous other officers, including David French; Anthony Lannie; members of our regional operating groups, Mark Bauer; Janine McArdle from Gas Monetization; John Bedingfield; Michael Bose; Jim House; Tim Wall; Jon Jeppesen; Corey Loegering; Tom Maher; Paul McKinney. And we also have members from our Board of Directors. This includes: Scott Josey; Dr. Randolph Ferlic; Bill Montgomery; and Charles Pittman.

The schedule for today includes a break, following the first 3 presentations that will occur at 10 a.m., resuming at 10:15. The question-and-answer period will follow at the end of the formal presentation before concluding with lunch at noon. Earlier this morning, we posted today's presentation on the company's website at www.apachecorp.com. Today's discussion may contain forward-looking estimates and assumptions. And no assurance can be given that these expectations will be realized. A full disclaimer is located in the presentation pack and on our website. It also includes reference to non-GAAP financial measures, including adjusted earnings and cash flow. Reconciliations of these measures can also be found on our website.

Lastly, I would request for the site audience that cell phone dial tones be turned to vibrate or silent in consideration of the speakers and other audience members. And with that, I'll turn the microphone over to Steve Farris.

G. Steven Farris

Good morning, everyone. I'd especially like to thank those that made it here in person. I also understand we have about 300 on the line listening electronically and looking and flipping through the slides, so welcome to you also. I don't know if you've had a chance to go through -- flip through the pages today. I hope you're impressed with what you see, most of which you haven't seen before. And although it's new to us -- I mean, not new to us, it's going to be new to you.

Actually, before I go through my slides, I want to talk a little bit about the macro overview of what you're going to see in the presentation. And I want to start with what you're going to see today has taken us about 2.5 years to build. Portfolios are always an evolution. But I think we're in a position right now to give you a picture, a coherent picture of what we started about 2.5 years ago.

And frankly, I'm going to give you 2 premises that we started with back in late 2009, and they're going to sound real obvious today. But back in 2009, they weren't so obvious. And the first one was that the maturity curve of gas and maturity curve of oil in the world are 2 different things. And I think they're, at least for the foreseeable future, going to be totally delinked. If you think about it just real simplistic terms, the world uses between 85 million and 90 million barrels a day. And that doesn't sound like too much. But when you stop and think about it on a yearly basis, that's over 30 billion barrels of oil. That's bigger than Prudhoe Bay ever was. That's bigger than all the tertiary in the deepwater Gulf of Mexico that has been surmised to be in the deepwater Gulf of Mexico. So it's a big number. So we've set out over the last 2.5 years to really move our oil prospects and oil inventories up. And I think you're going to see that today. The other thing that I hope you come away with today is that we're now in a position, both from an asset inventory, drilling inventory and also from a financial standpoint to really move the needle in the United States in a prudent financial way. But certainly, we have the inventory to do that and we also have the acreage to do that.

Lastly, what I'd like to say is we are starting to see fruits from our exploration endeavor that we took up about -- at the end of 2009, we decided to start a global exploration outreach. And the purpose was -- is to put together an exploration team, starting in 2010, that would be able to look globally to find opportunities that would really move and impact the needle. And you're going to see some of those today. We're working on some others that we are not at liberty to show you today. But you're going to see 2 or 3 of them that we think really has the potential to have a big impact on Apache in the future.

I'm going to go through my slides pretty quickly. It's really the summary. But the meat of the presentation is what you're going to see after my slides. I'd like to emphasize a couple of things. One is you're only going to see the Anadarko Basin and the Permian and basically our new venture stuff today. We've really skinnied this down to try to show you what we're doing in those 2 areas because it's really what we've built over the last 2.5 years. The other thing is that, that does not deemphasize -- we have a number of Apache Regional Vice Presidents here. We are still a very much a portfolio player. And over the coming months, we're going to showcase those regions every go-forward also.

So with that, I'd like to start with the presentation. This is the key. We're going to talk about -- John Christmann is going to get up and talk about the Permian Basin. We have 35,000 locations, drillable locations that we've identified on our existing acreage. On a risk basis, that's about 3.8 billion barrels of oil equivalent resource potential. Only 6% of it is on the books today. You're also going to see we are -- we have identified about 35 -- 33,000 locations in the Anadarko Basin, over 5 billion barrels of oil resource potential, drillable locations on spots on the map with our working or net revenue interest in it. Two huge plays in North America for this with the coming years for Apache. We're also going to talk and we're going to -- Rod is going to get up and talk a little bit about our project inventory that we've got around the world in terms of projects that we've got coming on over the next several years. And then John Bedingfield is going to get up and talk a little bit about some of the worldwide new ventures.

The first one is going to be Liard. It's a play that we started 2 or 3 years ago. We have 400,000 acres up in British Columbia. We've got 3 wells drilled. I will tell you it's probably the best shale -- gas shale play in the world. We think that we have about 48 Tcf of gas. Certainly, with gas prices struggling right now, we have takeaway issues. But in terms of just resource, with the 1 well we drilled horizontal, we put 6 fracs on it. It's going to go to 18 Bcf of gas, came on at 22 million a day, a tremendous resource.

We've also, over the last 1.5 years, been putting acreage together in Mississippian Lime. We now have 580,000 acres in that play, 100%. Leasing has not caught up to us, so we're done leasing there in terms of costs. We also got a play in the Williston Basin, it's on the western side of the Bakken play. Interestingly, when we've added about 300,000 acres, interestingly, our biggest competitor up there on the west side of us was Exxon. And then we're going to go through some of the stuff we're doing in the Cook Inlet in Kenya.

We've been able to build a lot of strength in this company over the last 10 years -- actually over the last 57 years. This is what our production per share, reserve per share, cash flow per share, earnings per share. We've been able to deliver on what we've said we've been able to do or could do. So what you're going to see is really the current evolution of Apache. We've gone through a lot of life cycles in our company, and the current life cycle is probably the most exciting because it's in front of us. We have an expanded liquids play in North America. We have global exploration. And although we're not going to talk a lot about it today, we have 2 LNG projects. The Wheatstone will come on in 2017, and we're projecting that the Kitimat project will come out at around that same timeframe.

The portfolio may change, but the principles that guide us haven't changed. We're going to be portfolio-balanced, we're going to be rate of return-focused. And when I say rate of return-focused, I'm not talking about just wellhead-focused. I'm talking about total all-in rates of return. And I think if you just look at our performance over the last several years on a cash flow per share or ROE or ROCE, we are either #1 or #2 in our industry over that timeframe. We're going to live within our means, and I'm going to show you what this program looks like in terms of based on today's strip, what kind of excess capital that we have generated even over and above our growth rate. And we're going to be away from the herd. One of the things that I started out talking about was that we really saw it was a good time to be back in the United States. The idea that we are in the last land grab, really if you look back in 2009, it was absurd. We have a tremendous inventory or acreage base in this country. And what our premise was -- is that those that had the financial strength when that acreage came back around would be able to take advantage of it. So that's what some of what you're seeing today.

A lot of people talk about financial strength. The world's going -- it's off speed because everybody's trying to catch up with their debt. And that doesn't matter if it is Greece or Spain or some companies in our sector. What we've learned over many, many years is that you can't continually put on debt and have to spend your cash flow. This is from Goldman Sachs, it's EBITDA for 2011 versus net debt. And you can look on there, many of our peers have 2, 3, 4x the cash flow to -- or the debt to their cash flow. And things haven't gotten much better in 2012. So we find ourselves in a very good position to take advantage of what's in front of us.

This is our guidance. We're sticking with 6% to 12% growth rate. You can see, we really have 2 numbers on there. We have a base. This has no North American gas investment in it. This is only growth off the properties that we think that have liquids. It also has a very small component of our exploration. You can see the 2 regions that really fuel our growth, the Permian Region and the Central Region. And that growth rate in Central is actually the Cordillera acquisition. All of the rest of our regions grow, but certainly our growth over the next 5 years are going to be coming out of those 2 regions.

This is our cash flow to capital. This is based on the strip. And this is how much of our capital we use on a yearly basis in order to hit that 6% to 9%. So you can see, we have tremendous upside from a cash flow standpoint, assuming we get the strip price we have today, to be able to continue to grow above that 6% to 9%.

I want to digress a little bit and talk about Egypt because I will tell you, I took more questions last night. It wasn't about the inventory or the things you're going to see today as much as it was about Egypt. What's happening in Egypt is not what's happening in the rest in that part of the world. It's got the highest population growth in the world. They've got 88 million people. They have a runoff. And I just read this morning that the court upheld that Shafiq, one of the candidates, is going to be the runoff candidate against the Freedom and Justice Party. For those of you who don't know, the gentleman that is running on the Freedom and Justice Party is a U.S. -- graduated from USC and his kids are U.S. citizens.

Not like Syria, it's not like Afghanistan, I can't tell you what's going to happen. But I will tell you that I think what's going to happen is Apache's going to be there for a long time. We continue to grow our production there. We continue to get paid. In fact, I'm going to get on the plane in the morning, will be in Egypt Saturday and Sunday when the elections take place. If you go to Egypt, it's a very easy place to live in. We have 100 expats there. We have about 200 dependents that work and reside in Maadi, which is right outside Egypt. And we really haven't had a hiccup. I will say though that based on that planned scenario, although Egypt is going to grow, it's going to become less and less part of our portfolio. And I will tell you this wasn't on purpose, it is just the inventory that we have in front of us.

What you can see is the biggest growth is going to be on the U.S. onshore, and it's going to be liquids. We're going from 50% liquids in 2011 production to 58% liquids in 2016. And the U.S. onshore goes from 21% of our portfolio to 41% of our portfolio. We think it's a good time to drill wells in the United States today.

These are just a ramp-up of the numbers that you saw on that very first slide. At the end of 2011, we had about 3 billion barrels of equivalent reserves on the books. We have 2 regions, the Central and the Permian, that have resource potential of 5 billion and 3 billion BOE, about 8 million to 9 billion barrels of oil. If you look at Liard and you look at -- and John Bedingfield is going to talk to you a little bit about what we've done in the Vaca Muerta in Argentina, and you can argue about the topsides, but it's real difficult to argue about the subsurface in that play, as you're going to see in a little bit. And then we have a number of new ventures plays, some of which are easy, like the Mississippian Lime, and we're really very confident about what we're doing in the Bakken. And then there are some a little further out like Kenya, which is a truly frontier exploration site. So we have a lot of ways to continue to grow this company over the next 5 years.

It's really the beginning of a new life cycle for us. And I will tell you it's a little bit like the pop star that you have discovered that took in 13 years to get discovered. I mean, we've been working on what you're seeing on this slide for a number of months, actually for about 2.5 years. So we now find ourselves with a very good position in U.S. onshore. We think it's a good time to drill. More equipment available today at more reasonable prices than we've seen in the last 5 years. 1.5 years ago, we couldn't find a frac crew in the Permian Basin, now you've got them running all over you. A lot of things have changed in the last 1.5 years. We have a global exploration group that's now showing fruits. We are in an enviable position on the financial side, and we expect to grow to over 1 million barrels a day by 2016.

And with that, I can be -- before Rod gets up here, we're not going to show all of our regions. So what we thought we'd do is show you a little video. It's about 5 minutes of some of the things we're doing around the world and a little bit about Apache. So could we roll that video?


John Christmann

Good morning. My name is John Christmann. I'm the Regional Vice President for our Permian Region in Midland, Texas. And I'm excited today to walk you through our asset base, show you the progress we made on building a region, and most importantly, outline the growth potential that we see in front of us.

This first slide really lays out our operations. And the purpose of this is to show you we have a very large footprint. Our net production in April crossed the 100,000 net barrels of oil equivalent a day mark. I could tell you that's ahead of schedule. We did not forecast doing that until the third quarter of this year. We are 70% liquids. Our acreage, shown in gold, spans 3.5 million acres gross, 1.6 million net. In 2012, we plan to average 32 drilling rigs. As of this morning, I have 34 running. And 9 of those 34 rigs are on horizontal projects. We plan to drill 760 wells. To give you an idea of our footprint, I've also spotted on this map, in the red star, is our Midland office, the regional office. And the green dots, we've got 5 district offices, and the blue dots, we've got 27 field offices. So we've got 32 field offices in the Permian that gives us quite a backbone and infrastructure of people to grow our assets from. Additionally, there's 2 gas plants, which are the purple diamonds.

This shows you what our some key indicators. And in over the last 2 years, from 2010 when we formed the region to where we are now, our employee count, we're grown from 345 to 792. I can tell you, I think I've got the best people in the business in the basin out there. We now have over 250 people in our Midland office and realize that 2 years ago, we started from scratch. What that's enabled us to do is take our investment ability up from $400 million in 2010 to just under $2 billion in 2012. Our cash flow has grown with our growth in production. In 2010, we've returned $700 million to the corporation. Last year, we spent $1.2 billion and returned $500 million. And this year, we finally got an organization in place where we feel like we can invest our cash flow in the Permian Basin. So we will -- cash flow of $1.9 billion based on the outlook, and we will invest all of that.

Rig count. In 2010, we were running 5 rigs. This morning, I'm running 34, so almost a sevenfold increase over a 2-year period. In terms of horizontal drilling, in 2010, we stepped out and decided we drill 20 horizontal wells, and most of those were on the Central Basin platform. I can tell you today, we've added to that, we're drilling different types of wells. And we expect to drill over 120 horizontals in 2012. Over that time period, our total well count has tripled from 263 to almost 760.

This next slide is a quarter-by-quarter look at our production and our rig count. And what you can see is from 2010, I show you quarter-by-quarter of the growth in rig count, it's the red line, and our production. And what's impressive is after the closing of the 2 transactions in 2010, you can see really from 2011, as we started to get our feet underneath us and get the organization built, we've been able to grow at a very steady rate. The last 3 quarters of 2012 are obviously region outlook numbers.

This slide shows we've got a material position out there. And this information was compiled for us by Tudor, Pickering, Holt. On any of the 4 key metrics we stack up very well. At 34 rigs, we're really only behind Pioneer. Net acres in terms of reported, we're only behind Oxy at 1.6 million acres. We operate 12,000 wells, which puts us just behind Oxy. And then on net production, there's only one other company other than us that's over 101,000 net BOEs a day. If you look down there, there's really only a handful of companies over 50,000 barrels a day. And that I'll make a reference to that in a couple of slides down the road.

Steve hit you with the highlight number in terms of the inventory. We have an inventory of known locations, and these are technically supported spots on maps. I mean, we've got a location for each of these and we've got them identified. But we now have over 34,518 locations, represents a resource potential of 3.8 billion barrels and only 6% of that is booked as proven undeveloped. We break our asset base into 6 key material positions. And I'll walk you through each of these. And then at the end, I'm going to roll all these up and show the impact it has at the regional level.

The Midland vertical is the first one I'm going to talk about. We have 17,816 locations in the Midland vertical program, represents 1.7 billion barrels. The Cline Shale, shown in purple, we have 2,321 locations. It represents 642 million barrels. The Wolfcamp Shale in green is also a subset of the Midland Basin. We have 971 locations there and 347 million barrels. Then we'll move over to the Central Basin platform, where we have almost 10,000 locations and 691 million barrels. And then we'll slide over in Eddy County and talk about the Yeso, where we have almost 1,800 locations, 100 million barrels. And then we'll conclude with the Delaware Basin, which we're excited about as well, where we have 1,800 locations and 284 million barrels.

I'll start with the Midland Basin, and it's in red. And if you look at the strat column on the right, on the vertical wells, we produce everything from the upper Spraberry down through the Fusselman. I've highlighted in 2 colors, the purple, the Lower Cline Shale because I'm going to talk about, and you see on the left of the slide there, in the dashed purple is the Cline Shale fairway we have. I'll talk about it is a subset, and then I'm going to talk about the Wolfcamp Shale, the upper and the middle, is a subset as well. And that fairway is in the dashed green line.

Across the Midland Basin, we control almost 1 million acres. It's been the main area of acreage expansion for us over the last 2 years, and it is continuing as we speak today. I'm going to show you proven impact at Deadwood, where we've taken production up fivefold since we took over operations in January of 2011. And we really have decades of growth ahead of us in terms of verticals as well as horizontals. I also believe there is going to be more horizontal zones highlighted in the future as we go forward.

On the Midland vertical, I'll touch on and kind of give you a feel for the size and scale and scope. I mentioned to you, there's only a handful of companies over 50,000 net BOEs a day. We're producing 36,000 just from our Midland vertical program. We're going to drill 448 wells in 2012. We've got a drilling inventory of almost 18,000 locations. It is our most active area. We have 3,000 feet of productive section, and we're producing everything from Spraberry down to the Fusselman. Very predictable results, we're drilling these wells mainly on 40s, we're testing 20s. And I think is going to be potential to stack horizontals in multiple formations.

I want to highlight a couple of wells just to give you a feel for the types of wells we're drilling right now. The first one is the Hartley 38-9. It's a Wolfcamp and Strawn well in our Deadwood Field at a 30-day IP. And this is a vertical well with 408 barrels a day and an EUR of 641,000 barrels. Another well to point out in our Wilshire Field is the Windham 120-9. It's a Wolfberry well at a 30-day IP of 306 barrels a day and an EUR of 211,000 barrels.

I mentioned Deadwood, and I got a little note this morning that in the last year, we have done our 200th frac. So that would give you an idea of the activity level out there. It's an aggressive growth story for us. Our production is up fivefold. We're now producing over 11,000 barrels of oil a day and 34 million cubic feet of gas. At year end, it was our sixth highest-value field. And I could tell you we did that in a matter of a year through the drill bit, which is pretty darn impressive. I'd also tell you, we see over 6,000 future vertical locations here. And I think all down the road, that Deadwood is only going to become more valuable relative to the corporation. It's a Wolfwood and Fusselman play. By that, we drill all the wells down to the Fusselman. If the Fusselman's there, we yield a little asset, we produce it, the Fusselman flows, and then we will come back later and frac the other Wolfwood zones and comingle. The wells where the Fusselman's not there, we go ahead and frac them day 1 and drill out all the plugs and comingle them. We're running 14 rigs there now. And the primary reason is that we've got a gas plant that we're bringing on. So we're aggressively drilling our program to be able to maximize our infrastructure. And there's upside in the horizontal targets. So I'll show you in a minute, the Lower Cline, we drilled and we are testing 2 other zones.

You're going to see these type curves on each of the 6 areas. And the oil price and gas price commodity prices we're using in as of the May 25, 2012, strip, these are before tax rate returns after royalties. At the appendix at the back of your books, there is details on that strip curve. I'll also tell you that I'm showing you real costs, so these are not development costs. I got a lot of questions last night about development costs at the reception. We're showing you real numbers. Obviously, we think costs will come down as we get in and work them. We also feel like we're in a point right now where service costs are starting to come down as well. So I think there's the ability to improve our costs.

On the stacked verticals, we're running $2 million drilling and complete costs, see an EURs of 144,000 barrels, 82% liquids, and we have a rate of return of 27%. High working interest, 89%. And our current inventory, 13,341 locations, and we only have 5% of those booked as proved and undeveloped. You see the curve on the right, and I will not walk through all of these as you've got them, but they're for 60 months, 5 years. And really, you see a start on these, these wells kind of peak at over 100 barrels a day. I've just showed one that was 400 BOE/D. So there's some tight curves and a lot of wells way above these type curves, these type curves are conservative.

Slide down to Spraberry Vertical, a little cheaper, a little more plain vanilla wells. Drilling and complete cost of $1.4 million, EURs of 127,000 barrels. They have a little different profile to them as you can see from the curve, 68% liquids, but great rate of return, 30%. High working interest, we have about 4,475 locations and 13% of those are booked as proved and undeveloped.

Now we'll talk about first horizontal play, the Cline Shale. And the fairway here is in purple. We have 451,000 gross acres and 334,000 net acres exposed to the Cline Shale, so we've got a big position. Current production in April is 500 barrels of oil equivalent a day. We plan to drill 10 wells in 2012. Our drilling inventory is over 2,321 locations. We see a potential of 642 million barrels. We drilled 4 wells to date. And I'll walk you through those results in just a second. And we're running -- just moved 2 horizontal rigs in for the second half of 2012. The other benefit we've got with all the vertical wells, we've got one of the largest petrophysical databases in the industry. And the other thing is that we've got Cline identified across a lot of our producing assets, which you can see in the gold. And this really augments our vertical program. And you'll see the same thing with the Wolfcamp.

What I've got here is a strat column. And I've highlighted the zones, the horizontal targets in purple in the Lower Cline. And then we've got 2 other zones here, the Deadwood Shale, which is really a Wolfcamp age shale and then the Atoka/Barnett, which are secondary horizontal targets which we are starting to drill. In fact, I've got 2 rigs in the field now. On the right, we've got -- and you see a type log, and you'll see this throughout here, for these unconventionals. It's a gamma ray on the left, and then we've got an organic indicator on the right. But the Lower Cline is a prolific Pennsylvanian age shale. Its average thickness is about 350 feet gross. The things I'll point out here, high porosity, 7% and 3% TOC. We see an OOIP of 23.4 million barrels per section. It's high quality oil of 40 to 45 degree API and 1,400 BTU gas. But the upside in here is in addition to the Cline, we see the Deadwood Shale, which is just above it there. It has the red circle by it. It has thickness of 228 feet and an OOIP of 11.7 million barrels. And then down below that, the Atoka/Barnett has an average thickness of 247 feet, and we have an OOIP of almost 19 million barrels. So we've got a lot of oil in place in 3 stacked shales within this interval.

Touch on the results. The first well I'll point out is the Mack 8-2H, spud last June, had a peak IP of 384 barrels a day. I'll tell you, these wells flow back. And when we think of peak IPs, we're managing the flow rates, so these are not absolute open flow rates. The 30-day average is 330 barrels a day. And in both of those periods, later we go back in, probably 3 months down the road and put pumps in, we'd see these rates come back up. So -- but we see an EUR of 352,000 barrels. That was a 4,400-foot lateral and 10-stage frac.

I'll slide down now and talk about the PhilMac. It's a 6,840-foot lateral, 15-stage frac we drilled, last September, it was only spudded, a peak IP of 400 hundred barrels a day and an EUR of 433,000. What we see here is the ability to increase the EURs with longer laterals, and we've also got a new 3D that's going to be available in August, which is going to help us reduce costs. We'll be able to lay down strategically a little better and not to have to drill as many pilot holes.

Here's the type curve. I want point out again this is current cost. I think these are going to come down. For the Cline Shale, drilling and complete cost of $7.6 million, EUR of 423,000 barrels. These are 87% liquids, a rate of return of 28%, high working interest, 85%. We've got a current inventory of 2,321 locations.

Next, we'll move to the Wolfcamp Shale. And you see the fairway in green, we have 377,000 net acres exposed to the Wolfcamp Shale -- or gross acres, 272,000 net. Our production in April was 500 barrels a day. I can tell you our June month-to-date average is over 2,000 barrels a day net. And we've just brought on 2 more wells. Originally, in 2012, we were planning to drill 4 wells. I've already spud 7 year-to-date. I've got 4 online, 1 completing and 2 drilling, and now we expect to drill 33. And based on the results, that may be a conservative number. We see an inventory of 971 locations and a potential of 347 million barrels. This is an incredible shale. I mean, the Cline, you've got to get back 10% to 11% of your load before you start seeing oil. The Wolfcamp, day 1, these wells come back amazingly with very strong rates. We have robust results, and we've currently moved a third rig in there. I've got 3 rigs running in the Wolfcamp Shale.

The same strat column and type log. I've highlighted the Upper and the Middle Wolfcamp. And 4 of our wells have been drilled in the Upper Wolfcamp, but it's a prolific Permian age shale. It's thick, 1,400 feet, and I'm talking just the Upper and the Middle. We see 2 additional laterals in the Middle as well. If you look on that type curve at the bottom of the Upper Wolfcamp, there's a carbonate stringer in there that's really held the frac in zone. And it's kind of opposite. We used to think shales hold the carbonate -- the fraction zone for the carbonates. But here, it's actually the other way around the way the shale breaks. But we're excited. We're going to be able to stack multiple laterals here. The thing is, in terms of thickness, the other thing that jumps out at is if you look at TOC, 5.4%. We have an OOIP of 106 million barrels per section. This is great quality crude, 40 to 43 gravity, a BTU of 1,470 BTU gas. We've got great NGL leads -- or NGL yields as well. We will be able to stack multiple laterals here.

Talk about the results. And the first 2 wells have been on more than 30 days. The Scott Sugg #1H is our first well. It's kind of down there, there's a pocket of the -- you see our green dots within the fairway. We've really just drilled 4 of them with results on 4 wells on a very small area. But we had a peak IP of 1,255 barrels a day, 30-day average of 726 BOE/D. Once again, these are flowing and we've got them choked back, so those are very controlled flow rates. We see an EUR of 682,000 barrels for the 1 zone. And that's from a 7,300-foot lateral. We used 23 stages on that frac.

Slide down to the Bennie #2H. This well has been on 11 days. It IP-ed similar rates, 1,260 barrels, a 30-day IP of 8 -- or 11-day IP average of 800 barrels a day. We seen an EUR of just under 800,000 barrels on the Bennie #2. That's a 9,300-foot lateral and a 30-stage frac. You look over at the map on the left, it shows our acreage. I've got 3 ovals that kind of show the peer activity. We're positioned extremely well, and we're very excited about the results and are making an impact on our production. And this is one of the reasons we're ahead of schedule.

Our drilling inventory in terms of the economics type curve. Once again, I'm running a real cost, $7.7 million. I think they can come down. We're using an EUR of 600,000, 598,000 barrels and we're assuming a 7,200-foot lateral. Obviously, where we've got the acreage lined up to drill longer laterals, we will and the economics will be better. It's 91% liquids, rate of return of 44%. We've got high working interest, 80%, have a current inventory of 971 locations. And we don't have any of these booked.

Now I'll move over to the Central Basin platform. This is really the heart of the basin. The strat column on the right shows we produce everything from the Yates down through the Ellenburger. We've got 1.75 million gross acres here, 777,000 net. When you look at this, go back to that first or second slide I showed you, we make 57,000 net BOEs a day alone on the Central Basin platform. This, in itself, is also another big business. We're going to drill -- in 2012, we're going to drill 140 wells. We've got an inventory of 9,800 locations, 691 barrels of potential. And this is a strong business. We generated a ton of cash here. We've got tremendous downspacing opportunities. I'll tell you a couple of sidebar stories in a second. And we really have been one of the industry leaders in applying horizontal technology to redevelop several of these zones. And there are multiple horizontal zones. If I go down that list, we've drilled horizontals in the Grayburg, the San Andres, the Upper Clearfork, the Tubb, the Lower Clearfork, the Wichita and the Devonian. So [indiscernible] 7, 8 of those right now, and I think there will be more as we continue to utilize horizontal drilling and learn how to use it in the basin.

To start here, I'm going to really highlight 4 areas. And we've continued to have success on the Central Basin platform. We're targeting bypassed oil zones and adding new reserves. The costs here are lower than our unconventional wells because we can use a little smaller rig. We can get away with a 1,000-horsepower rig here instead of a 1,500-horsepower rig. Plus we've got the benefit of an infrastructure in place. We operate 47 water floods. We've tested -- in 2011, we've tested 6 of those water floods successfully. And in 2012, we're testing these water floods, we've tested 9 additional fields. I'll tell you, 4 stories here. The Slaughter, and you can see I'll start up at the very north end of the shape. I kind of look at it as a T-bone steak. If you think of the region as a T-bone steak, that is our backbone. So it kind of fits for the Central Basin platform. But up on the top there, the Slaughter Field has the CS Dean A-264H, had a 30-day IP of 156 barrels of oil a day and an EUR of 294,000 barrels.

I'll move a little further south to Shafter Lake and Andres County. The Shafter Lake San Andres #612H had a 30-day IP of 295 barrels of oil equivalent a day, has an EUR of 230,000 barrels. I'll move down to TXL South. But before, I want to digress just a minute. I had the luxury of working this property back in 1991 for ARCO. And at that time, we were -- it was producing 1,500 barrels a day and we were drilling 28-acre infill wells. Well, I knew a little something about the field. In 2007, when we bought the properties from Anadarko, TXL South was making 1,500 barrels a day and we're still drilling 20-acre infill wells. Well, today, we still have a lot of 20-acre infill locations, but field's up over 3,000 barrels a day. And it's because we've been horizontally in it. The TXL South -- and actually we've got now, I think, 3 different landing zones within the TXL area. We've got another one we're about to test. The TXL South #5118H had a 30-day IP of 406 barrels a day, has an EUR of 259,000 barrels.

And now I'll move over to McElroy. McElroy is one of the very first fields discovered in the Permian Basin, I think in the 1920s. It's a long-time water flood, it's at Grayburg. It's a field that's been producing at 1.5% oil cut for quite some time and it's drilled on 5-acre spacing. We've gone in and laid down horizontals, so we can only do them on a diagonal because of all of the well spots. And we're bringing wells on 10% to 15% oil cut. The North McElroy #3231 is one of those, has a 30-day IP of 300 barrels a day. This is within a field that's only making 2,500 barrels a day, has an EUR of 231,000 barrels. But the learning that you take from this, here we are in the middle of the field. You move to the west of there, there's some standup 80 leasehold that we've taken in 2007, took it for Wolfcamp idea. In 2010, leases were set to expire. We said we'd move over there and try horizontal Grayburg, no water flood support, you're away from the unit. And if you know how units were formed, most of these units were done on reservoir parameters and porosity cutoffs and so forth. So you could have on the fringes of these, I'm telling you, horizontal drilling works. So what we did was we drilled the University Lands 42 #1H. And surprise, surprise, 813 barrel a day IP, an EUR of 226,000 barrels. We have since leased about 20,000 acres south of there, so we've got a total primary play now set up based off of what we've done on these fields. So that's one of the reasons why you continue drilling in these fields.

Our type curves, the vertical wells, cost of $1.5 million are key. We'll continue to have a big vertical program, even as we drill more horizontals. Just through as you've got fields on water flood and CO2 floods, there's patterns to fill out. But a great rate of return, as you can see here, 36%. We've got an inventory of 8,100 locations, only 9% of those are booked as proved and developed. The horizontals' drilling costs -- and these are average. And once again, on all of these type curves, we're kind of averaging our interest across these plays. We've got a drilling and complete cost of $4.2 million, an EUR of 196,000 barrels, 90% liquids, rate of return, 37%. And we've got 1,712 locations, only 9% of those are booked as proved and undeveloped.

The Yeso. In the strat column here, you see the Glorieta Paddock, Blinebry, Tubb is what we call the Yeso, which really Leonard age. Its Clearfork equivalent in Texas, it's the same rock I've just been talking about. This is in Eddy County. We've got 68,000 gross acres, 64,000 net. Current production is about 3,000 barrels of oil equivalent a day. We're going to drill 111 wells in 2012. Our inventory is just under 1,800 locations. It has 108 million barrels of potential. It's a development drilling program on 10-acre spacing. We're running 3 vertical rigs, plan to add 2 horizontals. If you look up on the right side, there's a circled area that's kind of dashed, this horizontal program. We've got a big position up here at Cedar Lake that we've got 60% of. Concho is in there with us at 40%. And the plan there is to develop that horizontally. We've got 112 wells that we see. We plan to drill and develop that over the next 2 years. I'll touch on some of these rates because these are fantastic rates. And you'll see the rate of returns are great, too. The N B Tween St. #24, a 30-day IP of 170 barrels of oil equivalent a day and an EUR of 156,000 barrels.

Our Yeso type curves. Drilling and complete costs from the vertical wells of $1.7 million, EUR of 128,000 barrels, 82% liquids, a 59% rate of return. Working interest average is 50% and our inventory is 1,677 locations. 31% of those are booked as proved and undeveloped. The horizontal wells, these have the costs of $5.5 million, EUR of 328,000 barrels. It's 84% liquids, rate of return of 56%. And we've got an inventory of 112 locations. And only 16% of those are booked as PUD.

The last area, kind of our sixth area but surely not least, is the Delaware Basin. And here, we've got a big footprint. We've got 584,000 acres, 262,000 net. Our current production is 3,000 barrels of oil equivalent a day. We're planning to drill 18 new wells in 2012, and perhaps there, we've got our first Bone Spring horizontal that we're drilling right now. They got an inventory of 1,823 locations. If you look at the strat column on the left, the primary horizontal targets are the Avalon and then the first, second and third Bone Springs. And then the upper portion of the Wolfcamp, maybe a horizontal target as well. You see the red oval, you move down into Wolfbone, and there, you've got a real thick expansive section in the Wolfcamp. We're looking at -- I show it here on the right, depicting it, it's really a vertical well where we're completing multiple zones and frac-ing in. We spent the last 2 years really studying this area very hard, studying our acreage, understanding our acreage positions. We now have 5 wells we plan to drill in the Avalon/Bone Spring this year. The Wolfbone, we'll drill 8. And I've got 5 other wells that will be drilled in some other areas here.

Same curve you're seeing. The Delaware Basin, we've got the targets kind of lined out there, the horizontal targets for the Avalon/Bone Springs. The Avalon, the first Bone Spring, second Bone Spring, and the third Bone Spring. It's a prolific Permian age organic shale and sandstone interval. 3,500 feet of gross thickness with multiple horizontal conventional and unconventional targets. It's good gravity crude, 1,200 BTU gas. We see here, we kind of highlight the Avalon, the first Bone Spring and the third Bone Spring as our primary targets. And then the second Bone Spring and the Wolfcamp Shale is secondary targets. If you look at your key metrics -- I've kind of been showing you these on all the plays. When you stack the OOIP, it's pretty fantastic here. The Avalon Shale, 138 million barrels per section. If you look at the porosity, these are all 500-foot thick sections, porosity of 13%, high TOCs. And then jump down to third Bone Spring, 66.5 million barrels, 480 feet, 10% porosity and a TOC of 1.8%. This is a fantastic horizontal play.

The Wolfbone. And a little bit southeast of there, there's a thick expansive section. It's prolific, organic-rich Bone Spring through the Wolfcamp intervals. You've got shales with carbonate and sand stringers, 2,400 feet of section, average porosity of 6%. So we see an OOIP of 47.5 million barrels per section. Gravity, 40 to 45, GORs in the 1,000 to 2,500 range, 1,500 BTU gas. Initially, these are vertical wells. We're drilling down to 12,000 feet on a 160-acre spacing. But we see the ability to go down to 40,000 feet with these. The vertical wells we're frac-ing were up to 10 stages. I think the big kicker here, too, is as we get in and start drilling some of these wells and learn a little bit more about this expansive section and do some reservoir characterization studies and take some core data, I think we will be laying down horizontal wells in here in addition to the vertical wells.

Our type curves for the Delaware Basin. On the vertical wells, the Wolfbone, drilling and complete costs of $3.6 million, EURs of 280,000 barrels, 61% liquids, rate of return of 37%. You see these wells are falling in line with all of our other plays. Working interest of 64% and an inventory of 1,419 locations, only 2% of these are booked. The horizontal wells, the Avalon/Bone Spring, we've run an average cost of $6.6 million, EUR of 313,000 barrels, 74% liquids, rate of return of 30%, higher working interest, 88%. And our current inventory of 404 locations, only 3 of those -- or 3% of those are booked as PUDs.

So now you roll them all up. And I mentioned I've got 6 material plays in the basin. Here you can see the impact. And if you look on the bottom, over the next 5 years, I show rig count. And I can tell you today, I'm running 34 rigs, is what we've kind of gotten dialed in for our 2013 estimate. So that's probably conservative. So we think by living within cash flow within the Permian, we can grow at 13%. And that's with a modest rig increase compared to what we've done over the last 2 years. So there's no doubt in my mind that we can do that. And I think as we continue to shift to the horizontal program, there's upside to the growth numbers.

My last slide. And I really like this. And I don't know if it's being out here in West Texas, where it's middle of a drought and it's hot and dry, looking at a nice, cool iceberg in the water. So when you look across our acreage position, 3.5 million acres, we were managing these assets from a location away from Midland. One can argue, you probably could see what you could see above the water. A year ago, when I got up here, and actually in May of 2011, we've started to put people on the ground, studying our assets more. We've come up with 5,000 locations. Obviously, today, we've got more teams working. I tell you, the more we work these assets, the more excited we get. Everything is working technically, and there are more and more horizontal candidates coming at us from all different directions. So today, we see 34,518 locations.

When you look at that, we do know there's a lot behind us and there's a lot underneath us. And with what horizontal drilling is going to bring to the basin, there is a tremendous amount of more opportunity in front of us, and we're excited about what we've got. So thank you very much for your time. I think that concludes my piece.

Robert V. Johnston

Good morning. My name is Rob Johnston. And I'd like to repeat Steve's gratitude for you joining us here today or on the telephone. Next Friday, I celebrate my 30th year with Apache. It's the only job I've ever had after college. And I began my career in the Central Region, what we now call the Central Region. And when I started in '82, the office had been there for 27 years. Five years earlier, we had -- Apache had acquired a huge block of acreage in the Western Anadarko Basin, really what's now the foundation for our region. And at that time, we had a very active drilling program among the wells we were drilling through the Granite Wash.

14 years later, when I transferred to Egypt, the region had drilled hundreds, if not thousands, of wells, among them, 150 Granite Wash wells. And I say this because it's hard for me to imagine that there's another company out there with the breadth of knowledge and experience that Apache's had in the Granite Wash. A lot of things have changed since 1982, but a lot of things are still the same. Clearly, horizontal drilling has absolutely changed the landscape. But the fundamentals of good geology and good engineering are still the same, and that's what you need to build a good well. So I'm going to walk you through our production in our -- here we go.

The map in front of you is a graphical indication of what the region looks like today. Our acreage is shown in yellow. On the right side of the map where it says Anadarko Basin, we have almost 2 million gross acres, a little over half that net. The North Block acquisition that I referred to looks exactly like that, it was just a little not quite as dense. The acreage in the Anadarko Basin, unlike what we see in Permian or other sites [ph] overseas, is not unitized, it's just an absolute checkerboard of ownership. You can go from one section, where you might have 100%, to another section adjacent to you that you have 2%, and then a few sections with nothing, and then one where you have 50% [indiscernible] operate. So to a large extent, it's a bit of a chess game as well, where you score where you drill.

The acreage to the west, where it's labeled Canyon Wash, is something that we picked up a couple of years ago. It's a contiguous block of 200 square miles. And we'll talk about that as well. Today, the region is producing about 59,000 barrels of oil equivalent a day, and that would include the Cordillera asset that we picked up a couple of months ago. We are currently operating 23 rigs with 25 -- excuse me, with 2 additional rigs coming I'll talk about. And we actually trace our legacy. This is where Apache has been for 57 years. So we think, and particularly with horizontal drilling, we're really poised to move forward. Horizontal drilling, just a little note, I'm sure most of you are already aware. But it has absolutely changed the way we do business. It used to be the 150 Granite Wash wells that Apache has drilled over the years were all confined to very limited sweet spots with higher porosities and higher permeabilities. What we found with horizontal drilling is because it can create it's own permeability, some of the best locations and the best acreages is not in those sweet spots, but away from it. And that's really what most of the Cordillera acreage is.

This is an illustration of the Anadarko Basin. It extends from Central Oklahoma to the center portion of the West Texas Panhandle. It's an asymmetric basin. But what's very key to the Anadarko is that it's deep. And deep means there are hydrocarbons known and proven down below 20,000 feet. I think the deepest wells have done about 8,000 feet deeper than. The advantage in having a basin like this is that you are able to stack up a lot of [indiscernible]. The vertical wells that we've drilled over the years typically have 3 or 4 zones, and oftentimes, historically you complete at the bottom and work your way up. More recently, we've comingled, but it gives you an opportunity and exposure at any -- almost any given site to multiple stack pace [ph].

This slide illustrates the transition from horizontal -- from vertical drilling to horizontal that the region has gone through. And we've absolutely changed the way we do business in the last few years. You can see that on the left there are 2 charts. The chart on the left represents the number of drilling rigs operated and the chart on the right represents production. On the left, what you'll see is that from -- really for the company's history, up until the end of 2008, when the market really fell, what we were drilling was exclusively vertical wells. And there, for a period of time, we actually -- at one point actually dropped all rigs in the middle of 2009. But when we picked back up again, we did it with horizontal wells. We started off with -- our first well was drilled -- first horizontal was drilled in 2008 -- or excuse me, 2009. We actually drilled a couple of them early on, several years earlier but no real extent. And what you'll see is that there's a bit of a decline in 2011. What happened is that Apache was committed to staying within its cash flow, and we got a little too aggressive, had too many rigs and ran out of -- just outside of our capital. But this year, we've started up slowly only because we had dropped rigs, had to add them again. But we're back at, not quite full speed, I guess, because we're actually bringing 2 more rigs in within a month. But we're currently at 23 horizontal drilling rigs, so 23 rigs, 1 vertical. And I'll talk about that area where we've got the vertical well is operating.

But the chart on the right really illustrates the results. The production from all of our vertical wells is displayed in gray. And you can see that it continually declines until a little bit in 2012, and that's resulting from a vertical program I'll show you. But the green is amazing. We're actually -- we're on the higher portion of that curve today. And I really anticipate -- I'd like to think that we're going to outrun this before the year is out. So it's really been an unbelievable transition. And so far, every thing's looked awfully well.

As a result of horizontal drilling, Apache recognized that there's so much more opportunity that we hadn't quantified, that all the regions, ours included, undertook a pretty extensive effort to try to quantify what's in progress. And what you see here is the depiction of, for no better word, lassos around our various -- around our acreage, depicting the various plays that we're currently chasing. And by way of example, the top left, the Granite Wash had the most number of locations. We identified 22,000 locations within the Granite Wash, with a total of almost 33,000 locations across the region. So what I'm going to show today are 5 of those formations in a little bit more detail that make up about 80-plus percent of those locations.

The idea of 33,000 locations sounds like a bold statement and probably difficult to feel until you look at the details. The Anadarko Basin is deep and it's very tight, a lot of local burden, very low permeabilities -- low permeabilities and has at least a very, very low granite area. Historically, it's been spaced 1 well per 640 acres that we learned early on that, that wasn't adequate to drain the sections. Throughout the '80s and '90s, the name of the game was infill drilling. We drilled an awful lot of vertical wells on properties throughout that period of time. The section on the -- what you'll see on this particular map on the bottom left is an actual section we were counting. We've tried to illustrate 4 horizontal wells in a single vertical well at this quarter. The single vertical well in the southeast, a preexisting well, is actually producing from a deep objective. We drilled these 4 wells into a middle Granite Wash formation that was an average of about 50-foot deep [ph]. The wells were drilled down to the top of the Granite Wash, which in this case was about 12,900 feet, and then laterally almost 4,000 feet. And then it was just a coincidence that each of these wells was frac-ed in 13 stages along the length of the well, so every 350 meters.

But what this illustrates is that a penetration into a 50-foot sand like that, whether you penetrate it vertically and frac it once or penetrate it horizontally and frac it every 350 feet or so, still achieves about the same drainage area. In this case, it's about 10 to 15 acres. And the chart on the right represents the 4 horizontal wells in columns from right to left. And in the rows, what you could see is the typical drainage area per stage and then the EUR per stage. So what we show is that, typically, with a vertical well in the Anadarko Basin, you might have 2, 3 or 4 stacked intervals. But those stacked intervals are basically going to be something on the order of 70,000 barrels of oil equivalent each, stringing a bead of about 13 has absolutely changed our ability out here. When you consider that Apache has about 3,000 sections across the Anadarko basin, if you just assume in this case typically 4 wells per formation per section, you only get to -- need to have about 2.5, a little over 2.5 zones per completion, you've already exceeded the 30,000 number. So it sounds bold, but it's quite tenable.

Before we talk about each one of these formations in detail, what I want to show you is a great card in the Granite Wash. We actually drilled our first Granite Wash well in 2009. Before the year was out, we drilled a couple more wells. We didn't include that on here because we really got up and running in the following year. But what you can see is that in 2010 and so forth, we drilled 27 wells, following year, 36. So far, this year, we've drilled 29. We anticipate drilling at least 79 before the year is out. But what you can see is that the cost went up from 2010 until 2011, and mostly that was a function of the industry costs just went up. Now as John mentioned, costs are coming down a little bit. But what you can see is that our cost, the fact that we've lowered -- for $1 million we saved over the wells is really more a function of the learning curve. We've figured out -- or we're figuring out and the industry as a whole is the same way, we're figuring out how to drill these a little bit better, drill it faster, drill it deeper, [indiscernible] and put more efficient fracture stimulations on.

So below that, obviously, the EURs are going up, along that, the percentage of liquids and the rates of return. So things are really looking up. And I am absolutely convinced that we will continue to get better at what we do. We've already seen it in certain areas where we've been very active, we've pulled down the cost even more than this general average. So with that in mind, keep in mind, that on the wells that we've drilled so far this year, we are at 57% rate of return.

Now this is the first of the 5 formations I'll show you. This is the Granite Wash. And on the right, on the bottom right, is the type log. And this is actually Apache well in section 23 [indiscernible]. And what you can see is that this is a representation that starts at about 10,000 feet and goes down to about 16,000 feet. And if you aren't familiar with really open hole well logs, then what you can see that stacked all the way down that hole are a number of different formations, starting with the Tonkawa and going down to Atoka Wash. And we've drilled considerably deeper than this, but I'm just really limiting this to the formations we're talking about today. And so the Granite Wash is really a compositional term, it's not an age term. It just describes the clastics that we're looking at. And then in our case, in the Anadarko Basin, the Granite Wash, for the most part, is a Pennsylvanian sand that runs basically from 13,000 feet. So that's the type log. And every slide I show you is going to look just like this one, so we won't have to go through each one in detail.

But what we're showing inside the lasso of the Granite Wash, as it's been mapped by us -- and there are many, many Granite Wash sands, and we've mapped them all, but this is just an aggregate [indiscernible]. Inside that lasso is over 700,000 acres and about half that is net. The current production from the Granite Wash wells that Apache has drilled is 33,000 barrels of oil equivalent a day. As I mentioned, we've got 79 locations. But on this, we had almost 22,000 Granite Wash locations identified. And you can see, if you look at the map on the left, the darker green -- it's really hard to see. The darker green dots, not the large lime green, but the little ones, those are actually locations that each of these teams have gone through and have identified one-by-one. To put this asset evaluation together, we had more than a dozen teams generate more than 28 various isopachs among 12 formations. And then one-by-one, location-by-location, spot these. And that's what those are.

The map on the left, again it just shows the generalized Granite Wash. In 2010, when we started doing Granite Wash, we popped all over the place. Not just Granite Wash, we tried to drill as many different formations as we could. I think to date, we've targeted about -- in the team for the number of formations we've targeted. And amazingly, they all work. We tried to drill as many geographically different locations in as many stratigraphically different intervals as we could because we're just in sort of an exploratory mode. And so that's what we're showing on this particular map. You'll see 4 different Granite Wash formations targeted, several couple right up by the Oklahoma border on the Texas side, one farther west, and then one on the Oklahoma side. But what you see is that these 30-day rates -- from where everything we're going to go today is on a 30-day IP, an average of the first month, because these do start declining, so we capture that decline. But what you're going to see is that these things are averaging -- and these are some of the better wells, but they're anywhere from 2,500 barrels of oil equivalent a day to 4,500. And as you saw a moment ago, year-to-date, we're over 1 million barrels oil equivalent per well. So as I mentioned, we've got 13 rigs running and more coming.

If we look in detail about a particular zone, and what we're looking at here is just a Granite Wash C map. On the right, you'll see an interval isopach of the Granite Wash C in red. You'll see the locations that are currently identified for our 2012 drilling program. In green, the wells that we've drilled already year-to-date. On the left is a type curve, which was an aggregate of many type curves across the Granite Wash, across the basin. So it's difficult in some of these to quantify. But this is an aggregate type curve. Below that are economics for a single well, like very similar to John shared. And so drilling and completing, the average is about $8.9 million. Now this varies because in Oklahoma, it's deeper. And as you move to the West and in Texas, it gets a little shallower. But we're showing here about 793,000 barrels MBOE. But that again is an aggregate of the resource, not to be confused with our current inventory. So what you'll see is we're 48% liquids. And I won't go through every slide like this. But the rate of return on this program is 44%, not to be confused with an ROR [ph] that's already higher.

Now for somebody like me that grew up drilling wells, vertical wells in the Anadarko Basin, the Tonkawa astounds me. Because as you can see on the type log on the right, it's shallow. At 10,000 feet, it can't be considered shallow, but shallow for the Anadarko Basin. But every well we drill going through Tonkawa, and every time we drill through the Tonkawa, you've got an oil shale and a gas shale. But there are only a handful of vertical producers in the Anadarko Basin that's turning off [ph]. There are a lot of Tonkawa completions [ph] and they're awful. But turn this sideways, and this is one of the best formations we have. Inside of the lasso, on the map on the left, we have over 600,000 acres within the Tonkawa, about half of that net. The current production from our Tonkawa wells and the program is just -- it's really in its infancy, is about 7,000 barrels of oil equivalent per day. We have right now -- today, we have 4 drilling rigs actively drilling Tonkawa in various locations in the basin. As you can see, we have a huge footprint here. We plan on drilling at least 54 by the end of the year, and we've got almost 2,800 identified. I guess, the other thing I should probably draw your attention to are the actual results. If you look at text box is what you can see is that we have anywhere from 300 barrels of oil a day equivalent to 500-plus on this particular map and extremely strong EURs.

If you look at the typical decline curve, typically a Tonkawa well is about $5 million. Again, we're using 251,000 barrels here. But for our program, it's about 20,000 barrels of oil above that. The map on the right displays our current inventory and the wells drilled to date, as well as -- it's a little more snapshot, it's about maybe 250 square miles located on the Oklahoma side. So what you can see once again are some extremely strong IPs, 1 well actually tested for more than 1,000 barrels of oil equivalent. But again, strong program. On the 2,700 locations, 2,800 locations, we're looking at about 26% rate of return at current price.

The Marmaton is a little harder -- it's very broad. This extends -- on the map on the upper left, what you'll see is it extends all the way from the shallow portion of the shale in Ochiltree and Hemphill Counties, all the way down to Oklahoma. Now this is -- the Marmaton is actually a member of the Granite Wash. It's an overpressured member in Oklahoma. And then when you move up on to the northwestern portion, where we spend a lot of time drilling shallower wells, it's acts like the Cleveland. So it extends really from about 10,000 feet all the way down to almost 14,000 feet. To date, we drilled -- Marmaton, we're currently drilling 2. And I don't recall the number that we've drill to date, but it's just a handful. It is, as I said, in the northwest, it's almost entirely oil. For example, the Weinette had 1,000 barrels a day IP and 500 BOE/D out of Pletcher. But as you move down to the southeast, you can see that Skyy, it also -- you're getting -- you're picking up a lot more gas, but it's huge wells, so huge EURs.

If you look at the curve on that, we're currently using -- and again, recognize that this is extending all the way from the shelf down to the deep portion of the basin. But we're looking on average of about 350,000 barrels of oil equivalent, so amounts to about a $5 million well. And again, cheaper in the northwest, more expensive in the southeast. But it's a play that we're extremely happy with, and we've had some tremendous results. One of the things we're trying to do right now is try to get our arms -- and I think there's a lot of upsides here in the deeper portion of the basin to try to get our costs even lower than [indiscernible].

Cleveland is very similar to Marmaton, slightly shallower. It is up in the far northwest, where Apache -- and on the map that you're seeing, we've had -- we've drilled a number of Cleveland wells over the last few years, probably the last 2.5 years, horizontal. So we've had some tremendous results. We've actually had several wells that's exceed 1,000 barrels a day initially and averaged close to that for the first month of production. Inside the lasso, we have 0.5 million acres. From those wells that we have drilled to date, we're currently producing 2,000 barrels of oil a day. We have 35 on new inventory. We've got 2 Cleveland wells that are currently drilling right now today. And we have something on the order of 200 million barrels of oil equivalent booked -- or not booked rather but identified.

If you look at the economics, again this is something that we're on a type curve, we're using 229,000 barrels, which is probably right with the cost for it. Hopefully, we can get that cost down. We've had -- on the actual successes, you could see on the right, anywhere from 400 to 700 barrels of oil a day equivalent initially. But we've actually had really some of the better completions in our area within [indiscernible] of our peers.

The last formation that I'm going to talk about is Canyon Wash. This, if you remember the first slide I showed that had the acreage outside of the Anadarko Basin, about 50 miles to the west, and that's what this is. This is located in, let's call, the Whittenburg Basin and is a small [indiscernible]. To the northeast, it's really bound by 2 faults, one to the northeast, one to the southwest. On the northeast side of our acreage is the huge Brownsville and Panhandle fields, shallow gas. Immediately south of -- and the fault is not represented on this map, but immediately south, it comes back up structure, and there were a couple of 50s, 52-barrel -- or excuse me, 52 well fields immediately south of it, that had done an average of about 150,000 barrels of oil -- 150,000, 160,000 barrels of oil EUR from the Canyon sand, which was producing at about [indiscernible].

We acquired this block of over 100,000 gross acres and 93,000 net acres, 200 square miles, in about not quite 2 years ago. When we acquired it, there had been 21 penetrations throughout this block, which works out to a well every 7,000 acres. I mean, there were very, very few penetrations. And there had been a number of dry holes, several that weren't economic. But 1 well that had been drilled, it was called [indiscernible], an oil drill, it had an IP -- initial first rate of over 700 barrels a day. And it was performing just like those 2 fields to the south that we're going to do, about 150,000, 160,000 barrels. So based on the fact that these don't come in singles, Apache and the board acquired the entire block. We have an average of 73.5% working interest through that original block. And then we have since picked up a pretty sizable amount of contiguous acreage adjacent to it. We now have 141,000 gross acres. And as I mentioned, there are -- the primary target right now is the Canyon sands. But if you move up about not quite 1,000 feet, there's another zone that we have yet to actually test, but we drilled through it obviously several times now. And it's a carbonate to the Canyon line. And we are really, really eager to test that, but I want to test it horizontally. We have a horizontal rig scheduled to arrive in this area. We call this the [indiscernible] area that's on where it is. But we have a horizontal rig scheduled to arrive in about 2 weeks. So we'll start that development program very soon.

If we zoom into the map on the right or if we zoom into a smaller area in around where most of the drilling to date is taking place, and part of that was that there was an existing 3D that covers the area that we're looking at here. Early on, after the first success, we moved forward with a 244 square mile 3D to cover the entire west of the block and then merge it with this. We have that acquired now, and we're in the process of pumping [ph].

But this has been an absolute amazing story to me. As you can see on the left, the type curve that we used for the resource, assume 225,000 barrels, which would be, including the horizontal well, which would be the $4.5 million well cost. Still, it's almost black oil. We -- on average, these are on -- we are seeing something on the order of 300 Mcf a day. We just completed the pipeline 4 days ago, and we've put up several wells. By now, we're looking at about 1 well a day. But what's amazing about this story is that Apache is now -- when we acquired this, the economic model that we used was 1 well, where you would be successful, as we really had very limited [indiscernible]. We've now drilled 8 wells, 1 well is a dry hole. There was [indiscernible], so we drilled a dry hole, which we can keep on training as a water-injected well. But after that, I mean, we've had 7 productive wells. We had 1 well that doesn't quite have a 30-day rate on it, it's actually been slowing for the last 3 weeks, it's still flowing 700 barrels of oil per day.

And that's an amazing story in itself because as we were drilling the well, the service company that we were using to fracture simulate the well -- and I won't say who they are, so you can chase them off location. [indiscernible] And they got about 10% of the [indiscernible] end of the formation before that shut down. And so they leave, and we think -- we try to produce the well. And for the better part of a week, it was just water, I mean, a lot of water. And then the water began to dry up. And now it's almost no water, it's almost black oil. And again, as I said, it's been producing about 700 barrels a day for the last 3 weeks. Prior to that, the other 6 wells that we drilled had an average 30-day rate of 685 barrels a day. So yes, I mean, this thing -- maybe the shoe is going to drop, but so far it's just been astounding, and I absolutely cannot wait. We now have enough controls to think we can start a horizontal development program. So with 700 barrels a day from an unfrac-ed vertical well, really eager to see what a horizontal well does. So we recognize an awful lot of potential here. And as I said, I'd like to think that the Canyon line is ultimately going to be the better formation.

My last slide almost speaks for itself. This is our production curve over the next 5 years. And it's broken out clearly by formation. We think the Granite Wash is going to be the [indiscernible]. But on the bottom, what you can see are the average number of drilling rigs employed during the year. And this is over the course of the year. So what you're seeing is if you look at 2012, you're saying, "Well, 18 wells, well, we've already got 23 and a couple more coming wells." That was because we've started the year a little slower. And so over the course of the year, we are saying 18. I really hope that number increases. I can almost guarantee that the 24 that we've plugged in for next year is going to increase because that's just the kind of the nature of the business. Every year, our plan is this and we typically are able to continue to come to work and improve it and get a little bit better and either drill wells cheaper or drill more. But what you can see is that from the beginning of 2011 until today, we've already picked up 20,000 barrels of oil equivalent. And we project that by the end of 5 years, we'll have 160,000 horizontal production from where we began. I'll also say that we've been able to do that as a result of increasing our activity level with Cordillera properties. Because these properties is laid right on top of our other properties, the efficiency is so amazing. I mean, that was one of the reasons we really like it, it was literally in our backyard. But we've increased our staff, not even 50%. We're still staffing up in certain disciplines. I'd like to have more drilling, engineer, support and technology. But it's really astounding.

And I leave you with Apache has -- about 10 years, maybe 11 years ago, we started to probably [indiscernible], and it's really been very successful. I mean, we now recruit engineers and geologists and we even started [indiscernible]. And I can only assume -- I mean, these kids are really brilliant, better than we were. And I'd like to think that 30 years from now, some of those kids are still going to be here. And I can't imagine what technology we might have available to us in 2040. But I feel confident that we have the staff and we have the opportunity to carry us through to that time. So with that, thanks very much. I appreciate it. And I think we're ready for a break. Patrick?

Patrick Cassidy

We are slightly ahead of schedule. But we'll go ahead and take a break right now for both the webcast audience and the audience here. We'll resume the presentations at 10:15. Thank you.


Patrick Cassidy

Please be seated, and we'll continue our presentation. Our next speaker is Rod Eichler, our Chief Operating Officer, and he'll give you a review of our ongoing project work Thank you.

Rodney J. Eichler

Thank you, Patrick. Good morning. Well, us start off by giving you a brief overview of some of the major development projects, our infrastructure projects that we have ongoing at Apache. These are typically the very large projects, what we've seen this morning and then some very region-specific programs. These are typically characterized, as you might imagine, side from North Americas, especially where you can drill a well, put it on production, appraise the production, put the reserves and sometimes even on the same quarter.

Now these are projects that we'll talk about, as I said, multiple areas, multiple years, a lot of international type opportunities and opportunities that have been -- largely have been developed, have been discovered. They're ready to be put in to what you call project pipeline and add value going forward.

The de novo projects here, there are 12 of these. They are mostly projects in which they are typically over $100 million of capital exposure net to us. And you can see these are largely international, these 12 projects. About 7 of those have taken a final investment decision, which are ongoing, sanctioned by our board going forward. Half of the project, about 5 of these projects are in Australia. And they run quite a gamut of investment opportunities.

Now these opportunities that are in order, but they're listed there at different rate at the of first production. But I'm going to cover some of these in more detail in the course of this presentation. And these include projects that are oil projects, like the Forties Alpha Satellite Platform, Coniston and Balnaves in Australia, Lucius and Heidelberg in the deepwater Gulf of Mexico; large gas and oscillation projects in Australia such as Macedon, Hydra in Egypt, the Varanus Island Compression and the Greater East Spar projects in Australia; and of course, finally, the large gas condensation projects, Wheatstone and Kitimat LNG.

So we've got over 200,000 barrels of oil equivalent per day coming onstream from identified projects over the next 4 to 5 years.

We move forward by looking in Australia. Here we have a map of Northwest Shelf. We have about 8 million gross acres, about 5 million net acres represented in yellow on that map. All of our acreage is concentrated the most part of Australia is the Northwest Shelf. It's one of the major gas region provinces in this part of the world. And in fact, it's location in the area where gas reserves will be challenging, the Middle East for LNG output in the coming decade.

Out here, we represent some of the major infrastructure that already exist in the Northwest Shelf. This includes the Varanus Island hub and Devil Creek gas plant, which we just inaugurated in the first quarter this year. Now at this time between Varanus Island gas processing and Devil Creek, we have the ability to handle about 600 million cubic feet gas per day through those 2 facilities. And at the present time, we handle about 30% of Western Australia's domestic gas demand.

The subsequent projects, which include the Macedon gas plant, associated Macedon development project, which I mentioned in about a minute, and the domestic gas plant associated, the Wheatstone LNG, which are both located in areas that are on the Northwest Shelf, it will bring up our ability to produce domestic natural gas in Australia to 50% by the time we sell and these projects are complete. So from 30% to 50% is supplied in Western Australia's markets largely to industrial consumers, principally the miners of the very mineral-rich robust areas of Western Australia.

The major development projects currently underway out here, we sanctioned some 8 development projects in Australia in the last 5 years, 4 of which are shown here in the map. Two oil, which is Coniston and Balnaves, which are FPSO-related developments; and 2 gas, Macedon and Julimar, which is the subsea, which supports the Wheatstone LNG. And for reference, I've shown the location of the Wheatstone central processing platform, which would be constructed beginning next year. It's a key component for processing gas for delivery to the LNG plant onshore.

This is the Macedon project. This is a project operated by BHPB, which we have about a 29% working interest. This is about a 75-kilometer tieback from the Macedon shallow gas field. These are high rate gas wells to the onshore gas plant, which is currently under construction, which have a capacity of about 200 million cubic feet of gas per day. At the current time, the site works underway. Pipelines onshore are complete tying into the Bunbury -- the Dampier to Bunbury natural gas pipeline, which courses into close to Western Australia down to Perth. It's a main supplier of developed natural gas that we produced in the Northwest Shelf.

And we expect that the commissioning on this project will begin in the first quarter of 2013, and first production of gas commencing in second quarter of 2013. Net production of the onshore project will be 49 million cubic feet of gas per day. I think, importantly, we see a significant price movement for domestic pricing in Western Australia with increase of gas supplies in Western Australia. In fact, here at Macedon, as well as other areas, but mostly Australia operating area, we see domestic gas contracts certainly being signed at 2x -- more than 2x at current utilizations.

Coniston, in with the same area as Macedon, this is an oil development project. If you recall, we brought online the Van Gogh oilfield 2 years ago. This is a production of about 35,000 barrels of oil per day. That probably would paid up in a every short period of time. The project continues to produce from the original reservoir, which is providing about 20,000 barrels of gross production at the present time. Now that oil is a subsea development, which is brought currently, anchored at FPSO.

The Coniston project is very similar companion piece to Van Gogh. Similar reservoir and construction which we began drilling exploration and appraisal wells in 2009, completed our drilling program and have now sanctioned a development program for Coniston, utilizing the Van Gogh facility and utilizing the same FPSO. This is that tieback utilizing our Apache-owned and operated FPSO, the Ningaloo Vision. And this states the project development here to be 7 multilateral producers, a couple of water injections and a gas injector well for the initial phase. We're awarded key contracts that are selling north on the subsea post this development. We have 52.operatorship in this project. We expect the first production in 2014 in the first quarter at a record of about 11,300 barrels of oil per day. This is an oil project.

Balnaves, just north and near our Julimar-Brunello LNG gas supporting field, is also an FPSO development of principal oil and a small amount associated gas. And you see the diagram there, we're producing oil from the B20 sand. We're very fortunate, of course, of our Julimar-Brunello drilling program, we discovered an oil accumulation in the sand at Balnaves in the B20 zone. This will also a subsea evacuation through an FPSO, the Armada Claire, which we have contracted for this project. Now we've done most of the installation work and in the final stages of award. And we expect the estimate of oil reserves and the associated gas, which will be reinjecting in the other line, B10 sand zone, will begin evacuating the use to support as LNG for the Wheatstone project.

We expect first production from this project to commence in the first quarter of 2014. We had 65% working interest in projects, and we expect production initially to come on about 19,500 barrels of oil per day versus from what we see at the south in the Van Gogh and the Coniston complex.

Of course, LNG. LNG is the big thing in Australia. It's the big thing for Apache. Beginning 2009, Apache began discussions with Chevron for the possibility of entering their Wheatstone LNG project and be able to monetize the large gas reserves that we have found in the Julimar-Brunello complex in the Northwest Shelf. The third quarter of 2011 which is the final production decision at Chevron to proceed at a project to build 2 trains of about 8.9 million tons per annum capacity, which is about 1.2 Bcf per day output. We have a 13% working interest in the project. We expect the first production and the first cargo of LNG to be delivered beginning in 2016. And of course, this project has significant expansion potential, there's a lot of more gas to be commissioned out there.

I'll go through our projects, which help rebuild ad projects of the future developments that Apache might add in this area to add the Wheatstone as well. And of course, we like that project so much the short time later in the fourth quarter of 2011. 2009 we had also announced our intention to move forward with the Kitimat LNG project. It's the first greenfield LNG export project proposed in Canada, also to be able to supply LNG to the Asian markets.

This project is specifically him a initially to be one train followed by a second drain in the short time period, at 5 million tons per annum, at least 5 million tons per annum on the initial first train string, over 700 million cubic feet gas per day. We'll be operating the project with a 40% working interest. In the Northern Sea, their export license approval for some of the project exports from the Canadian government, as well as other significant environmental approvals. Certainly, early sites and work is underway at the project. And this project has significant expansion potential for the gas, which we have in Northeast D.C. area, as well as Alberta.

Wheatstone LNG. This is a mammoth project. This is probably our second-largest project currently underway. We've got Offshore Australia behind the Gorgon Project, that Chevron also operates. We have a 13% interest in the project. This diagram here shows what the domestic gas frac and the LNG facility will look like at the location north of the West Coast. At the site, work has begun. It begins with the construction of the plant facility, the offshore platform, which will process this gas initially before offshore. We expect fabrication to be commenced in the fourth quarter of 2012. We already placed 80% of the market with 4 Japanese utilities. So the offtake is taken care for the project, and we're moving forward with the development.

We anticipate the first dom gas production for this project to begin in 2018. The LNG delivery would be in late 2016. Our net production for the project is 39,000 barrels of oil equivalent per day, which really stacks up to be about 7,000 barrels of condensate per day, over 300 million cubic gas per day net to Apache and that's for a 20-year production plateau.

Now the Kitimat side. Kitimat is very similar in the basic components that we see in Wheatstone LNG. For the location position, it's in the West Coast of British Columbia. But interestingly, this is the same difference in Tokyo as it is for Northwest Shelf in Australia and it's 6 days shorter than sailing to Middle East. The principal supplier is being cluttered. The visible operation here in Kitimat is to be able to tie into the existing spectral grid system through the invested rig.

The green gas, especially for Apache's interest in the Horn River Basin south and purchased in interest and the south in Fort Nelson to Summit Lake and we'll construct 480-kilometer pipeline across the Rockies for the last portion of the pipeline to the town of Kitimat at the upper end of the Douglas channel., This is ice-free, heat-more facility, which allows us to evacuate LNG across the Pacific to Asian buyers. This is the equivalent prices. The process train, which we anticipate to start via 300 million cubic feet of gas lift and a 40% working for the project. We have 2 partners with 30% a piece, these EOG and Encana.

We're filling and doing all the work necessarily to lead up to FID. And that consists principally of the marketing aspects, the line of our customers, the finalization of the FEED cost for the plant construction and the pipeline construction. Of course, including all the necessary approvals and requirements from the BC government and the First Nations that are occupying the lands both in the location of the plant, as well as the pipeline rights-of-way.

So we skip from the time we take FID to be approximately 55 months from FID through the first cargo LNG. This is a very important project. There are several, I'm sure you have read about, and that since proposed for about 3 other projects in the same area. We've had the same general concept although in Kitimat because of the configuration of the shoreline there in evacuating Horn River gas and Monte gas. In our case this is an outstanding opportunity for Kitimat to be able to monetize substantial gas reserves, which you have in this area, which within will talk about in the presentation.

The basis for supplying our Kitimat LNG at the present time is our Horn River development. The last few years, Apache has also partnered in Canada to actively developing Horn River shale gas opportunity. We have a substantial position here, almost 300,000 gross acres, almost 200,00 net acres. Our Apache lands are shown there in yellow. The green are the partial interest of the Apache's partner lands. We've done this by having production established at 7 drill pads from which we drilled some 79 producing wells. They currently produce nat gas, 90 million cubic feet of gas per day, and they share that production collection 50-50 with Encana.

Overall, this fee in production has been ranging between 200 million to 250 million gross from the Horn River from the shale section. We have drilled pads. We're about 10 wells for pad in the current development scheme, which is very efficient way of handling your environmental footprint, and that's utilization of the facilities most efficient manner in the cost reducing of in this area.

We have about 912 potential locations that have been identified on this acreage block. If you exploit the 9.2 Tcf of net recoverable resources identified in this play, that's 9.2 net Tcf to Apache. That will be probably exported by virtue of some 50 drilling pads, local well pads, which are depicted by the black boxes on this map. So you see the size and the scope of this acreage position is under command, and we've got the dominant position in the central part of the Horn River Basin, the sweet spot, if you will, for this development to support the LNG project at Kitimat.

Now I'd like to talk about some of the larger oil projects. The first one of this is the Forties Alpha Satellite Platform, which is certainly underway, the planning and development stages for the last 2 years. In fact, we begin to construct the jacket in this platform in summer of 2012, with the subsequent slate in the top side when the weather is bearable in the early part of 2013.

Now this is a very large structure and provides additional utilities and power capability for the existing Alpha Platform, as well as provide very valuable 18 drilling slots. Now the map on the right hand of the slide, let me show you, it's general field outline of the Forties complex, which is a developed by 5 platforms. The Forties Alpha Satellite Platform in the past project will have additional drilling slots, which is our biggest constraint in the Forties right now is the ability to build more wells.

The dots on that map represent the current inventory and drilling location, about 100 wells. So it's about 100 wells every year no matter if we drill 30 wells a year on average in Forties and we start put the 100 wells in the inventory. This project is a satellite field platform project and will allow us to access different drilling locations, which otherwise you cannot reach our existing Alpha or Echo Platform locations. The sales of that is about 16 million barrels of oil equivalent once it's in drilling production and drilling opportunities begin in 2013 and 2014.

I think it's interesting, our first oil production is expected late in 2013. During the coffee break, Jim, mentioned to me it's really interesting in that slide you have a fast project. He said 2012 and 2013, we're the first to grab Forties in 2003. This was the year that decommissioning was the start at Forties. This was in the like 2012, 2013. And we were pleased that the work that guys have done in the in North Sea and we're a long way from decommissioning. We adding a rather substantial platform in the field this late in this life. Instead of being decommissioned, look at the accretion, 50,000 barrels a day from the Forties Field. It was the ways and all the hard work that we've done this increased production. I think you know the story, like 2 of our operations in 2003.

Now moving on to some significant projects in the Gulf of Mexico Deepwater. Now we've been actively drilling in deepwater since 2010. We currently have about 750,000 gross acres and 148 blocks, which is shown as the black dots across the map here in Deepwater Gulf of Mexico. We have presently are producing in the Gulf of Mexico about 16,000 barrels net a day from the producing properties shown there in the gold stars. We have 2 projects which we brought on, Wide Berth in April this year; Mandy, which came on just last week.

So our current production is at average 16,000 barrels a day. Weed be up to 20,000 barrels a day probably this month production. And you can see that by year end, we'll be adding the Bushwood production. There shown on this slide in the late third quarter. There's 4,500 barrels of oil per day. At this rate, we'll be up about 25,000 barrels a day net by year end 2012.

Now 2 big projects which were coming up in development are the Lucius project and the Heidelberg Project, both of these are operated by Anadarko. And you can see there that as we move forward, about 20,000 barrels a day coming on in 2014 and 2016, just from these 2 projects alone. Additionally, we have a number drilling prospects which would be operated by Apache. They're showing there on the screens, Eagles Nest, Backslice, Staurolite, Refugio and Parmer. In Parmer, we have 50% risk to that while that is currently drilling.

Lucius is a subsea development principally located at Keathley Canyon in 874, 875 blocks. We have 11.7% interest operated by Anadarko. This is a standard Class C monitoring subsea oil development in 7,000 feet of water. And that diagram gives you an idea of what the development concept is. This project has been sanctioned by the partners for development. They consist principally of 6 initial producers, oil producers, which are tied back to the Spar-5 facility.

We expect the development drilling will commence in the second half of this year, with first production anticipated by the third quarter of 2014. Last year, we got production of about 10,000 barrels a day. The Lucius field is probably a 300 million-barrel oil field accumulation on an equivalent basis, mostly oil. Our share there, our resource there is at over 30 million barrels initial production. And we have significant exploration opportunity in the area with additional leases we have offsetting this field location.

Heidelberg is the newest field for development. It's currently being evaluated by the partners, a development plan in the pre-FEED stage. We've not sanctioned development yet. We have a 12.5% interest in Heidelberg, principally located in a 5-block unit in Green Canyon 859 and 860. This is a really great area as you noticed on the map there. This is another Middle Miocene oil prepped against itself as shown there on that purple line.

The Tahiti Discovery and Chevron's fields are about 450 million barrels, just north along the same trends. Anadarko's Caesar and Tonga discovery, their resource of about 400 million barrels. That is along 10 miles to the north. Heidelberg, we've already identified net oil pay at 200 feet. We've extended it down dip by some 700 feet. The first well was drilled early this year. It increased the size of the oil field by some 1,500 acres. In the pre-commissioning stage for sanction and I think we moved forward depending on timing of the FID, the likely first production would be in 2016 or next year and is 200 million-barrel and the gross FEED size would be at about 25 million barrels or 10,000 billion barrels of oil equivalent initial production.

So if you look at the wrap-up of our development projects, I mean there is the opportunities of some 200,000 barrels of oil per day. This is one of the project pipeline. This is the result of discoveries we made in the areas we showed you in the last 2 years, maybe 10 years ago in a face of Australia at the time it takes for these projects through monetization level. And I think you can see from the list of the 12 projects that are currently underway and many others, which are the Internet pipeline, they're very material. They're sizable. They're very visible projects and provide significant growth in the next 4 years and beyond.

In fact, beginning in 2016, 2017 time frame, we'll begin to see the impact of LNG coming onstream. The 2 trains at Wheatstone and this one train at Kitimat, we're looking at 90,000 barrels of oil equivalent per day beginning at probably 2017. The second train at Kitimat will bring that production up to 140,000 barrels of oil per day probably in 2018 depending on the timing of FID of this project.

These are substantial infrastructure projects, which provide significant growth and cash flow in the case of LNG for over 20-year production plateaus and marketing arrangements.

And we have substantial expansion opportunities associated with these majors facilities, especially LNG. The more you can add to subsequent trains and LNG, we sure do see the cost of this common facilities and amortization costs get better and better economics going forward. And we certainly expand that project pipeline, and you can see from the demonstration here, we have the ability, I think, as Steve had mentioned, to operate effectively from exploration phase in North America or international locations. It made together the size of the project be it deepwater development, onshore gas plant construction for LNG and construction opportunities to be able to monetize the success of our exploration program.

I think now, I'd like to turn it over to John Bedingfield, who's going to talk about our exploration and new ventures program, just to deal and generate the kinds of projects that will now be in the ventures list of our project inventories going forward. John?

John R. Bedingfield

Good morning, and thank you for sticking around. All right. Well, for the benefit of those who are online and those of you I didn't get a chance to meet last night, my name is John Bedingfield. I'm the Vice President for Exploration and New Ventures for Apache. By way of introduction, I've been with Apache for about 14 years, previously serving as the Region Exploration Manager in Egypt and then the Region Vice President for Australia region before I took this job on February 2010.

Steve asked me to take this job to build a worldwide exploration organization and to really provide a new engine for growth in terms of delivering shareholder value. So what I'm going to do today is talk a bit about that, what it is that we intend to do and what it is that we're actually doing within the organization. And I'll illustrate with a series of examples, which I hope you'd agree as we demonstrate that we're on the right track.

So the mission of exploration is the same as every other business unit in Apache, and that is to deliver shareholder value. We do it by looking and identifying and capturing large-scale resource opportunities that have the benefits to certainly impact Apache's shareholder value. In other words, things of scope and scale, things that matter potentially.

In order to do this style of operation successfully, you need to do several things pretty well. The first one is you got to kind of think big. In other words, you've got to visualize what you're thinking. We have guys that do that very well. The first thing you have to do is actually be prepared to lead. By that, I don't mean people so much as I mean leading the industry. You've got to basically look for areas or look in places that others are not looking or have missed opportunities. And coupled with that is, of course, the willingness and courage to actually. So all the strutting in the world is never going to bring that, you've got to be able to identify where you want to go and then get there, and then basically act on your vision.

The other thing that's important too is really in our DNA. We've got to temper our enthusiasm, the economics and social realities of the world. So what that means is not every great idea is something that is maybe great geologically, but maybe not a viable. So we temper all that and basically, we look for those places where we think we can work well and make money. I'll just be showing you some examples of that a little bit later on in the presentation.

The third thing is balance. Explorations are different. We have a balanced approach with what we're doing. We certainly are looking at frontier basins. We're also looking at sort of new plays in more mature basis. So we've got to have a range of opportunities of the higher risk and more modest risks of exploration plays instead of jumping straight at the big one.

What we're pretty good -- I want to make sure everyone understands this, this effort is additive, actually. This is not a replacement for the exploration activities. Apache has always done within this reason. So what we're looking to do is identify new plays, new opportunities and in some cases. make bolt-on to existing regions, activities. I believe it's kind of exciting and maybe one of the more visible interest is the generation of new Apache regions. So we see some of those in Apache.

From so we've been doing this a little over 2 years. I got here in February 2010. The first off business organization. So we actually had selected a number of really high caliber exploration professionals across the industry. We had a core group of Apache element in 2010, we actually built an organization that I think is one of the best business I've ever had the privilege working with it. This is a group of highly dedicated, passionate men and women who business TNG, jealous in geophysics, engineers and this. And get that integrated of our as well. Hot the 2010 into last year, basically it was everyone to go, we got how to get built environment want to get and I think and that's actually built I think our reason for portfolio of opportunities that goes through the circumstance. Now this year is going to be a fine year, magic get the past actually drill wells. Drill somewhere between 15 to 19 wells this year. Exploration wells. Some of these will be drilling in the basin, some of it in the almost appraisal wells that but. But as I said, really exciting time right now. So down the end of the year, we'll see how things panned out and the.

All right. A lot of people do exploration. Apache is not illegally thing at global expiration company. We certainly do have a global reach everyone recognize that. Well, one of the things I think is important is differentiates us from some of our peers is our exploration organization is by a tremendous capable organization, great that in terms of scale to build these a broad range of industry discipline. That's really important. That's a lot of companies don't have. And I think most people would certainly agree that Apache has a rock-solid record of the elements, a great do asset is probably second to none. Sufficient cash flow to fund these growth projects without strength. I think that really the message here is that if we find it, we can develop it. I think that's really what's important.

And really another way of saying this essential you heard from other folks on shareholder value, growing shareholder value. So we've got to do this vision.

All right. I'm going to talk about, I've got the 7 projects. I'm going to talk about 6 of them. I'm not going to talk about Harder than to say that the frontier oil play. We've got a lot of work to do, but I will talk about the others. This morning someone asked me, what are your exploration teams? and the answer to that is, we actually have 3 exploration teams that are doing. We are pursuing a deepwater thing globally. The border is more of a cash of phrase than anything just event of ask specifically about the place and sets pursuing. I can't really talk about that right now, but those are in the soda of Central Station of the negotiation opportunity. Suffice it to say that we do have a deepwater thing, a deepwater oil discovery of oil in the last decade or so. We also have a resource play which is by some of the things that we do see on the an American us will be our resource play.

And the other theme that we have is one that's kind of struggle with the right term, but it's typically a neglected basin or a technology theme. It' basin that have considerable potential that can be unlocked with the application of technology. And a good example that is program up in Alaska.

This is an interesting slide, I think it kind of sums up kind of where we are after 10 years in terms of exploration. And I'm going to read this slide to you, but you can see here that these numbers here is that we have exposure to tremendous upside in terms of potential of resource. Some of the stopped that's been discovered, although not booked, and some of these yet to be discovered, but we are resources I thing is based on. Bottom line here, is I don't know what I would stake my life on any specific number. Obviously, some things are going to work better, some things are going to be worse. But overall, I think from a ballpark perspective, we have access to an inventory that is basically increase our proven reserves up by. And that's a pretty nice sitting on. This is all organic growth, pretty impressive [indiscernible]

All right well I'm going to start of now by talking some of these projects. Liard, I believe are brought a little bit earlier, Steve talked about it and clearly this is a gas project. It's the only gas project that I'm going to talk about. It is located at the northeastern British Columbia, it is gas prospect gas prices. I think what's really here is recognition of this resource. This is, in my view, certainly in my estimation, the best shale gas reservoir in the world sort of from a performance perspective. And I'll talked about that a little bit more. We have a command a position of here. We have about 400,000 acres of play. If you look at the interface numbers, the hundred then trillion dollars cubic feet of gas, staggering number. Shrinking every, we have lineup with FIN 48, doesn't cubic feet of gas, that's the staggering number as well. This is a very large resource for Apache, not suggesting that we're going to be dumping into that. This is a huge resource for the future.

Steve alluded to earlier, we did 3 wells, frankly. One of them is a fairly short horizontal. It's tested over 21 million a day, out of 6 racks and on a per frac basis, one of the most prolific wells and I think I've ever seen it in that sort of play. I'm talking I little bit more about that later.

All right I'm not going to get through all this, just wanted to say that Liard compares very to other resource place that you may have heard about. Liard probably about Liard. This is no one have ever seen this before outside of Apache this whole time. That things that make Liard special, my apologies for those of you online, but things that are most important thickness, we have tremendous Asia in those reservoir. Pressures are great and the other thing that's really important here is that this reservoir is more than 90% in other words, we don't have much. The vein of much resource plays is, we don't see that. This is a fairly homogenous, some consequent we have tremendous vertical lateral continuity. What this means is your engineering background, this acts kind of like, and that's pretty impressive in the world.

Looking at a little cross-section here, this cross section around 50 miles north this outcome. North is actually on the left-hand side of the cross-section. Now about, the red the degree of red represents gas. I think what you see from the cross section is once again as I said before, great lateral continuity in this reservoir section. And also, I think what's important as you move up to the on the left-hand side we've actually Apache, that's gets back to the deeper part of the base in. Our net is huge hundred thousand feet. For our shale gas reservoir and have pretty impressive on the single on the well. Moving to the right-hand side of the cross-section, the Peter to for L. That's a pilot well develop, we actually in a short horizontal on this and I'm going to talk a little bit about but we on that. And by the way, all 3 of these wells currently on production and pipeline kind of run through the heart of the.

The P34 well, once again this is a profile view of the lateral. You can see it's a good job staying in the zone. We did 6 fracs on this well, fairly short 2,000 feet. Our 30-day IP was over 21 million a day, and at $3.6 million cubic feet of gas pretty per frac, that's about twice as good as the Haynesville in terms of gas per frac. This is a reservoir that forms really, really well as I said from everything I know what I've seen so far, our timing the industry, this is probably the best shale gas reservoir in the world at this time. So I say we make others that I haven't seen much suggest that so far.

All right. Our development model. Was against Russia the development but I think the idea what I want to take away from is the efficiency of this reservoir and wells will actually develop. The development model, once again based on our, that we probably drill 7,000-, 8,000-foot laterals frac spacing, 400 feet. It's really staggering for me that this well should deliver somewhere between 60 to 70 billion cubic feet of gas per wellbore. That is such. As you see the pad drilling concept, which we know well how to do. Basically you can do that math on this. But this means is that somewhere in the order of 800 billion cubic feet of gas. That's a huge number, very, very efficient way to get gas off the ground. I won't go through all of the other numbers here other than say to do the math it's basically at the duties 650 billion cubic feet in terms of gas deliverable reserves of resource. We have a high net interest in this. High net working interest [indiscernible]

We're right now frankly is higher gas prices and we need about $2.57 effectively. But as I said, that's domestic fracs. Looking at it different way is we said these wells are already connected. There were some infrastructure laid over the wells connected to the domestic market, if you will. Also there's an option perhaps if it makes sense that's also algebra is, is perhaps at some point. But then once again, I'm going to GAAP into the development on this right away, it's a tremendous resource and it certainly is something that significant in scale as you imagine Apache the future. And what we're doing now here is we've had doing wells to hold acreage together, so that's something we will drill the wells if we have to drill 40-acre. But we should be in good shape [indiscernible] to develop

All right, moving further south, also within our own commission resource is the Vaca Muerta surprises say that. The map that you're seeing here is the brown color represents the working basin, which is located about West Central Argentina. The back line here represents the Central pretty outline of the Vaca Muerta Shale. The industry news about this play, YPF, for example, this is a but a bit about oil project have it down in Argentina and if you look any ability reticent of that crap, you see Alistair that shows where the YPF activities are located. Now Apache asked over 900,000 net acres of the Hummer the, with about half of that in the liquids window. Our assessment at this point is about 800 billion barrels at this rate, I think this is a shale play and I'm talking about that. Our activities down here were transition to the drilling this play, and I think this year it's going to be very, very interesting as we make our work program. This right here, the Apache and certain feet and Neuquén and, we produce gas development we also that as well. And as you can see here, the gas prices actually priced.

All right. The Vaca Muerta shale has all the earmarks of a him or to, once again, the great thickness, good pressures in this part of the play that we are pursuing. And at the, we have we have very good carbonate percentage. The slow with some part will place. Overall, this is a very attractive rate. It's fake, pressured and it's relatively shallow which is the middle of our.

Now this is done a lot of oil and gas activity in Argentina over the years in a decade. And there's 360 Vaca Muerta penetration on APA's acreage. This was a good all those and we've announced that were 230 some odd. So we're trying to say is we understand the play recently, while constrain commanding we think we're in the process it more information of the anticipation hopefully of decision sometime next year.

One of the things that is play is that lateral on continuity and thickness of it. It's very predictable. And we also have great well saturations throughout this. By the way, this section runs 50 miles down here in the Southern part of our compression. You can see a carrier beds and the lighter colors, the lighter to green higher oil saturation. So very good saturation. It's a very good play for us.

Our work program for this year is basically consists of information We have a getting to that information To do and Rick completions on these pre-existing wells, about more how to go. We're also to acquired wells, 2 vertical and Frito-Lay down the wells to better understand the performance characteristics of the play. And with the new wells, we'll be able to actually pull some data, the types of data we do want public better understand. So right now, I guess what to say is our technical study is more or less kind of good into the exploration for the execution phase of this program. Very exciting time for us in Argentina.

We do have one well as we completion of the PVG 39. Is got a 30-day IP, about 118 barrels of oil per day and that actually produces gas velocity if you do that on BOE basis, that's about 147 barrels of oil per day. That's vertical well, that's. I think information in stimulating it which we do is, looking at this is condensates design but looking at the bottom of the site. 30,000-foot lateral fracs, we reckon week it did bit about 330,000 barrels of oil equivalent per day, about 84% of that being oil. When you look at this thing, there's at least 2,500 locations already identified and our acreage and about almost 800 billion barrels. So very substantial play potential as spec perspective, Lake this looks very, very attractive. And the lever be doing some additional data collection this year, testing and develop [indiscernible].

Now for something -- moving back up to U.S. This is something that you guys have we've never seen before. We have never talked about this. No one outside of the Apache. I know we're relatively small but [indiscernible] Apache where were in Apache that has still the provision in Mississippian Lime play in Kansas. And I think this is -- the reason we're talking about this today since the landgrab is over and we are assuming that we finished our leasing activities. But we've been able to achieve first-mover advantage in this play. We've secured over 580,000 net acres, the stack phase. You guys probably guys know this play as well as I do. But I think one of the things that really impacted this year, is we've managed to beat industry with a punch. We've very entry cost. I don't know exactly what our cost were but I can tell you, we've got But great terms in our leases, 8- to 10-year leases, acre royalties, that sort of thing. So we have lots of time on these basins. I will say a ridge cost us less than 200,000 acre for this one. But as I say, we think we did a pretty good job of simplification and [indiscernible] the opportunity. And now, frankly, we're surrounded by industry as lot of us the well-known players in this play are certainly are adjacent to this. Put this next up. I don't think everyone can actually see this on the screen but there are little circles and little squares, red circles and red squares. What that represents is industry activity in this area. So I believe there's 150-some odd drilling rigs currently active in this area, with over 200 locations. Our industry is moving this play. And we feel pretty excited about our position here. I will say that we see number stack plays and go into that in a little bit more detail here in a series of slides. So we have broken this out into chunks. [indiscernible] And you can see from map -- incept map at the bottom. All the green here represents oil historical production. A lot of this say, we're staying here. The oil is here, nothing bad about that. So there's no question that the oil. Now if everyone's been doing horizontal stuff here, so this is really great. You're going to see [indiscernible] starting as early as next month so, and I'll talk about that in a little bit more detail later.

Now this is a little column, this right column. Basically, it's sort of a schematic to represent the play. So we have the Mississippian Lime play proper, which is a series of [indiscernible] stacked and [indiscernible] stacked carbonate units, oil saturated with good porosity. This is not a tad oil. It forms limestone. On top of that, we have a Cherokee section, which is more, plastic, a little bit more restricted in distribution, it's also quite interesting. Above that, we have the upper Penn section. Once again, quite a bit of oil in this section. And as I said I think this is very amiable to horizontal drilling. We have a number of opportunities there that I'll talk on a bit more.

All right kind of once again, I'm going to into geology right here, I don't know really know the punch for it. I just want to say that within the Mississippian Lime proper play up line, we have about over 400,000 acres, 100% working interest. Once again, net revenue interest here is about 87%. So high equity and a good location.

I talked about the play activity in this area, and we'll cross-section that on here. It actually shows the oil saturation within the Mississippian. It's does -- a lot of oil in this section. It tends to inch out of the inch out, basically inch out so much of the truncated of the Mississippian base as you look to the east, bid on to the central [indiscernible], South West. So we see quite a bit of oil in this section. Once again, hundreds of hundreds of pre-existing well bars, vertical well bars that provide us with quite a bit of control. And so what we have yet to do, of course, is drill all the sweet spots. And I think that, that isn't progress and we'll also be drilling some wells next month to further our understanding.

The next play I want to talk about, the Cherokee. Once again, an established play. We see the Cherokee as being actually a north, It's actually a more sophisticated play, with series of deltas, we believe. We believe our system feeding of the Central Kansas platform from the Northeast to the Southwest. A bit more restricted than Miocene but very, very attractive, very sweet, where you find it. Once again, our play fairway here is in constant is about 230,000 acres of that 1,400 location.

Certainly, [indiscernible] the last big topic, if you will, of our 15 plays is the Upper Penn play. Once again, all saturated limestones as is classic cycle systems. We are working hard to develop our signal framework to better understand this play to basically target the best portions of this play. We have over 500,000 acres in this play with 3,300 locations.

Looking at the economics. Obviously, we -- we call this the valuation economics. These are not based on Apache activity at this time. What this is, is an analysis of contract or offset operator results. As we've done the analysis obviously with carefully selected wells and have looked very hard at performance. And basically, the Mississippian, I think these are probably consistent with what the industry has proven so far. It's about the level of 300-some-odd thousand barrels per well. These plays all offer spectacular rates of return. Mostly because potential tests in production are quite high but also the drilling and production are quite low. And so the oil per well is very attractive. So great return on these plays and, as I said, with [indiscernible] policy in terms of PNC. But -- I won't read all this stuff here, but say 320,000 barrels for the Mississippian, we have about 212,000 barrels for the Cherokee and again, Upper Penn at about 265,000 barrels. So in aggregate, this adds up to about a few billion barrels of recoverable resource -- of net recoverable resource. Once again, making sure that's not reserves and that number has been change. This is what the exposure is from me. We think this is pretty special. This is a real chance of being material and actually move the needle for Apache.

All right. Another play I want to talk about is once again this is the first time we talk about this. It's basically where we're chasing Bakken and Three Forks is in Williston Basin. We've, once again, managed achieve a first mover status and have over 300,000 acres -- net acres secured at the Daniels County in Montana. What can I say? It's good to be there first. We get low entry costs. And right now, we are done, basically, the leasing is. Some will trickle in the big leasing is done, and we're surrounded by some of the traditional Bakken players you should recognize. And so the other thing I wanted to point out is not shown here, not labeled on the field. Just for reference, if you will, this big group of wells down to the south and east, right in here is the Elm cubic [ph] here, another 1 billion barrels of oil from the Bakken. Not just to point out, [indiscernible] only has oil in the Bakken, there's no Three Forks in that location. The red dots here represent where industry is currently drilling and what you can see here is that industry is moving in this direction and certainly up in Canada has been quite active in Canada as well. What really brought us to this point was good for fundamentals. We recognize an area that has not been viewed as attractive by industry as others, but as fairly mature. We've got great reservoir and we've got about 35 wells on or near our acreage, all of which are oil saturated. So this is an area we're moving quickly to make a real difference. And we are starting to certainly we saw competition lead in this place, pretty well locked right now.

In total, we see that 1,900 locations for Bakken and Three Forks, which yields an EUR of about 1 billion barrels. So once again, a very material resource for Apache here in the U.S.

Now going through just looking at the pipe log here. One of the things that's a little bit different here, upper parts of the Bakken, we've only got about 7,500 feet, which is important. Net debt reduces our drilling cost, down from $10 million in the Bakken to about $7.5 million, $7.2 million in this part of the play. Once again, although we're focusing on the middle Bakken and the Three Forks, there are a number of other play throughout this whole section. The Madison section above us, Lodge Pole and others, that also has plenty of oil in it. We haven't even -- got to the evaluation on that yet. And blow in the Devonian, or the Devonian plays, the Birdbear, for example, and Charles also has oil play as well.

This -- basically, to let you know that we are actually in front of Montana Oil and Gas Commission today. We're asking temporary station here and basically, I know it's something like a chunk here in the corner of the slide. Basically, the -- one pad should be able to hold about 4 square miles, we'll basically drill 16 wells, 8 Bakken and 8 Three Forks wells. Basically, 10,000 foot laterals at the plant. Obviously that will be adjusted off the market as we collect more information. But once again, a pretty efficient way to drain is to significant large resource.

Looking at the cross-sections, runs rants about 45, 50 miles to the heart of the Apache acreage. Once again, as in the Vaca Muerta, the lighter coverage represents higher oil saturation. The 2 gray bands or the gray band at the top and the one sort of in the upper middle is -- represents the 2 Bakken shales. They are mature in this area. We grew them in time and effort into that. So clearly and having now generating hydrocarbons. We've had great saturation in our reservoirs. And the reservoirs here, they're a little bit stealthier. It actually has slightly better across this than we've seen else where and the phases are quite amenable to very good production rate. So we're pretty excited about that. Clearly, we'll land wells in the middle Bakken and we'll also probably around the top of Three Forks [indiscernible] indication.

As you move further west, you do get out of the Bakken pressure shale. You get out of the play. So the shales become less mature as you move to the west and then the rest of it is also to grade a little bit as well. So you get out of the play, not much for the west and for every yard now. So we do think this is a great location, very similar to based on position to the partial Rough Rider field I believe on the Eastman side, and also a little bit to the south, although our [indiscernible] in this part of play is significantly larger than a handful of [indiscernible].

Looking at the economics. Once again, spectacular rates of return, that speaks to the reality as best. But what's important here, I think, for us is the PNC costs are about $7.5 million per well. And that's important. As I said before, it's shallower cost a little bit less and we get considerable amounts of oil out of these plays. Once again, the bulk of the oil as we have currently evaluated is in the middle Bakken but Three Forks being a very attractive sort of our secondary target, another target. As you guys well know, the Three Forks is also being commercialized [indiscernible] as in other parts of the Bakken play. We're very excited about this. Once again, we'll start growing in July and we have plans to grow 5 wells this year. We won't stop at 5 wells but hopefully, will get done this year. Hopefully, get a couple completed as well.

All right. Moving to further north, Alaska the -- specifically the Cook Inlet. We've talked about this before. This other in before. But we did a pretty good division here. We have access to over 1 million net acres. This is a basin and that is proven basin. it's got very oil potential. You can read these slides but industry -- the heyday for the Cook Inlet was back in the 1950s and '60s, and about 1.4 billion barrels of oil was discovered. And then Prudhoe Bay was discovered and everybody left. Cook Inlet, when you go up there, it's kind of like going back into Bakken. Inside it's like an oil museum, kind of how I'd describe it. It's interesting, but things are just been frozen for 40-plus years. So it feels like there's only a handful fielded and discovered out here. It feels like distribution is strongly suggested that there's at least another 1.3 to 1.4 billion barrels of oil yet to be discovered in this basin. And at the -- we've been over this with -- and we've looked at every well in this basin numerous times and our trap analysis for this area, it tells us that every single trap we've drilled in this basin has hydrocarbons. It does not mean it's a commercial but every trap has got hydrocarbons. So really, at that point, it becomes an exercise in trap definition and basically risking investment. And so this was a play that is ever made for 3D seismic. The only 3Ds up here had been effectively development scale 3Ds. Typically, they would be from a design perspective, insufficient to image some of the structural complexities that we see in the basin. As I said, we actually believe that [indiscernible] analysis, the 3D is going to be key to unlocking this basin's potential. We feel like we're in a very good position to capitalize on the opportunity. We do intend to spud a well. Hopefully, we'll fit 2 wells, [indiscernible] another well this year, probably starting in August time frame. We have a rig and we're working through the permitting process first.

We also, as you guys know, we are acquiring a large scale 3D in this basin. We believe that's that key as I said before. Today, we are acquired about 130 square miles. Got to put that in context. We actually started in late November of last year, did about 30 days of acquisition kind of shake out the operational business and see where our problems were. And [indiscernible] fixed and then we started that back up again in March of this year. So this 130 square miles, most of that was acquired since March of this year. And most of you know that the key imaging factor on seismic is not dynamite or [indiscernible] the daylight. And so we're moving into long daylight hours now up in Alaska. And we expect to get somewhere in the order of 3 400 square miles for this year. That's out of 1,000 square miles program. It should last over 3 years. So we'll be shooting seismic and concurrent with beginning to drill some of our exploration wells. This is a, once again, we think is a pretty exciting play.

The early results from our 3D had been very, very encouraging. What I've done here is I've taken a bit of our 3D. Is about the chunk of seismic or map I should say. I've rotated in -- kind of moved it around so hopefully [indiscernible] I would know where it is. I wish I had taken the scale bar off, not that -- yes. But anyway, what we see here, what's in 20 square miles, we can identify 8 leads on this. It's never been identified before and we view this as being somewhat typical of what we expect to see from a frac density standpoint. This is a lot higher frac density than we actually anticipated. So you can do some simple math here and come up with sort of [indiscernible] constant about this. It's probably wrong but the implication is, of course, it's going to be much higher than we had originally anticipated.

The other thing to keep in mind here is that we have fields in the Cook Inlet that -- but the surface area of only 800 acres 100 million barrels. So these are complex plays. You got a lot of the stack plays, big columns. And so we believe that this 3D is going to, as I said, unlock the potential of the Cook Inlet basin and lead to what I view is a very high degree of profitability. So we view this as -- I'm very excited about getting this wells drilled this year.

All right. Moving from Cook Inlet now to the Indian Ocean. Kenya, which is a good example of our deepwater -- or this happens to be a frontier play. We've talked about this before, and I think we've seen a lot of comments in downsizing. I want to be kind of be able to be careful about what I say here. We do see this is a very high potential block. And the first well we will drill on this is the Mbawa well, which we'll spud in August. The rig will be handed over by the end of July and so we should spud shortly thereafter, but it depends probably as from engineers here. The prospect for drilling has basically a mean value of about 280-some-odd million barrels, 300 million barrels. I want to be careful is that this -- what you're seeing here on the map, this little green outline. Little green outline with the 2 boxes in the Mbawa box points to. That actually is a combination on the much larger 40,000-acre closure. The 40,000-acre closure we believe from a perministic [ph] perspective, it has about 780 million barrels of potential growth. We -- as I said, we'll drill this first well. And we'll see where we go. But if you look at the upside on this, it's a pretty good size running around the block as opposed to it's a real thing of Web. We are the operator with 50% and, as I said before, lots of running room, lots of opportunity to do follow up on. Yes, so even encouragement, if I should say.

Starting in August, this is the first well in Kenya offshore. It's been drilled on 3D data. It's big size and data. We actually see some potential DHIs. I won't call them DHIs simply because they aren't calibrated at this point, but they certainly are somewhat encouraging. And I'll talk a little bit of why we think about this is an oil play and everyone has a gas in the area. So to the south, in the basin industry very successful in finding just literally lots of TCF of gas in Tertiary Delta system. We're actually targeting spacious spuds with Jurassic charge system. We even think this important. we're in the level basin, there's different basins, different history even in the Garguma [ph]. If you do your plate reconstructions, what you'll find is that Madagascar fits very nicely into this part of Kenya, which -- where it originated prior to the breakup of Datwana [ph] 150 million years ago. For those of you who might know something about Madagascar, along the northern shore, there's about $30 billion of oil, heavy oil, but it's heavy because it's been exhumed and biodegraded. If you do your quiet reconstructions, that fits very nicely with our block position in the Mbawa basin. The other thing I will say is that the Madagascar oils have been type to the cool sort of sal rock, Jurassic salt rock. Now there are no wells in our block, so we can't say it depends on the equivalents there. But from the offset wells in the area, we also -- we actually do believe that it's there and if it is there, it certainly is going to be mature for oil at this time. So we think it's a high risk, it's frontier. It answer both about that but it certainly has a good play chance and from a prospect perspective, we think it looks fairly attractive.

Let me show you a little bit of that. Once again, Mbawa, 40,000-acre closure. Talk about that catching sleep from this -- the top seismic slice there were we're catching sort of a simple confirmation because it's out. To move look closely on the slide, but we do see evidence of [indiscernible] we think it's the last slide there we described to being a little bit of gas.

Below that is a potentially a second black spot, a little bit sketchier, which we -- I mean it could be another contact or it could be some other biogenetic effect, but it could also be, let's say, an oil water contact. So we actually see some good upside in this block and so, as I said, we'll be drilling the well here in August and hopefully, that's 50, 60 days later, we'll have something here to look forward to.

The other thing, and as I mentioned before, we do have some pretty good running room. And this is a slice on the bottom. It's high prospect related. It's something we just have identified off of brand-new 3D in the area. And what we see is it is slightly older, although still targeting cretaceous sandstones, which actually is a little bit older than Mbawa itself. It has good access to charge and pretty good side. I mean, we push on about a 220 million barrels of mean, we have an upside of over 0.5 billion barrels. So we've got a follow-up opportunity that we're compares to our best in Mbawa.

All right just to kind of wrap up what I've been talking about here. Without going too pretty deep into it is that, as I mentioned, we have basin. we are going preserve acreage in the drilling. Kenya wells, we're actually doing one right now. Mississippian Lime in the Bakken plays, we will begin our drilling exploration in the appraisal drilling in July. Now that program will run through the end of the year. And soon if successful, we'll continue onto 2013. Our development plan is really is not like one day we'll be doing exploration, the next day development. Development will slow to become sort of principal activity in each plays maybe not so slowly. And so we'll see that accelerate as quickly as we can. You guys have seen what we do in the region so you can imagine how this might go.

Vaca Muerte, I mentioned that hopefully reach a development decision sometime early next year. Cook Inlet, pretty excited about that, ongoing seismic, some exploration drilling starting in the end of this year and flow into the next couple of years, with development to follow perhaps next years with some ifs.

And Kenya well, I'll say will be drilling the Mbawa well next month or in August. And successful or we have some plenty of time to consider doing appraisal wells or other exploration wells in the block.

So with that, and all the time were doing is, of course, we're continuing to fill our opportunities funnel with others. But I hope, you would agree to be high-quality exploration opportunities, projects, as I said, space for future reserve and production growth. And with that, that's the end of my presentation. Thank you.

G. Steven Farris

Well, to close, number one, I hope you get a picture of what -- of why we're showing you this today and why we haven't be able to last 2.5 years. It's really taken us about 2.5 years to put all this together. We think we're right now in a position to be able to show you a real picture of where we're going over the next 5 years. The one thing I would say is there's very little upside in these programs to fund to exploration plays, which you saw today. And we're going to stand by being 6% to 12% production growth over the next 5 years. As you can see from -- oh I don't have that slide we have the cash flow based on today's trip. We have the cash flow to be able to take advantage of some of the things that we're going on the exploration side or to accelerate even further some of the steps were doing in the Anadarko basin and the Permian basin. So we've got -- as I said in the release this morning it's time for Apache to drill wells, which is what you're going to see over the next several years. I'm really not going to go through all those again. You've seen them a number of times. We're very financially strong. We have tremendous inventory. And hopefully, when we come back here 2 or 3 years from now, all this will come to fruition. So thank you very much. I think we have questions and answers now, Patrick?

Patrick Cassidy

All right, it's question-and-answer time now. I have 2 of my colleagues here with microphones. If you do have a question, please go to Bethany [ph] and Jessie [ph] and she'll hand you the microphone or you can come up here and ask your question from this line. Thank you.

Question-and-Answer Session

G. Steven Farris

We've got one gentleman there who would like the microphone.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

It's Doug Leggate from Bank of America. First of all, I think you should be congratulated for falling into depths of the inventory that you have, but it does present I did bit of a dilemma. Your multiple is trading on one of the lowest in the sector. You've got extraordinary building inventory. How do you see the balance between optimizing the value of the inventory versus where your share price is trading? That's my first question. My second question, I guess related to that, you said in the press release, it's time for Apache to drill wells. What does that mean in terms of your...

G. Steven Farris

That's what I just said here.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

You said in the press release it's now time for Apache to start drilling wells. What does that mean for your acquisition appetite and to that, and then perhaps your appetite for monetizing or high grading the portfolio that you've built up over the last several years?

G. Steven Farris

I'll try to remember those and Roger Plank is here, and Rod Eichler is here. They might want to chime in also. I've said for years, we don't make acquisitions for the decline curve. We make acquisitions because it brings us opportunity. And if you look at the Permian Basin, the Permian Basin didn't go together based on what we did with BP, frankly. Permian Basin we've been building since 1991. Where we find ourselves today, given what's going on in the markets, what's going on with respect to our asset base today, we don't have to make acquisitions anymore. In fact, I can never say never, but I will tell you, it would be very out of character for Apache to make anything of any large acquisition. Now bolt-on acquisition with one some of the stuff we're doing and I'm not talking about large. We always do that, everybody in our industry does that. But in terms of being able to find new areas to be in, we've really transitioned that over the last 2.5 years to not be buying it is to be going discovering it. Some of the steps you saw that John Bedingfield put out there. So I don't really think for certainly not in our talk plans to make acquisitions over the next several years. We have plenty of inventory. In terms of acceleration, I think that was your question or stock price versus -- hopefully, what we've been able to unveil here in the last 3 or 4 hours, give some people some confidence that we do have the inventory and the where withal, both financially from an asset base, to continue to grow this company with drill bit. And that's what we're about.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Maybe just to get out a point of clarification, Steve, because I know I ramble on my question, but you're stock price is extraordinarily undervalued, at lest in our perception relative to your asset opportunity. So where do you draw the line between we're going to drill wells as opposed to we're going to buy back our shares?

G. Steven Farris

Yes. I'll be more honest to do. I think it is very much more important for this company to share growth on the top line than it is to shrink them. And what I'd like in it -- everybody points to one company when they talk about share buyback, and that's ExxonMobil. If you can name another company our there that's been successful buying their stock back, at least in our industry, I wouldn't know who it would be. And I would argue that ExxonMobil is in a different position than anybody else in our industry. If you look at our peers, our next peer is half their size. So they have made a business, a strategy out of buying stock back. We have no downstream. We have no chemical business. We have -- all we are is oil and gas produced, and we are subject to the big vagaries of oil and gas prices. And regrettably, when the prices are really high, yu have a lot of cash flow. And generally, that's when your stock price is up. And when your stock price is down, it's generally when commodity price is down. So it doesn't give you an awful lot of leeway to turn around and buy your stock back. Should we drill, not drill well from the Permian Basin or the Anadarko Basin or the Williston Basin or the Mississippian Lime and buy our stock back? I don't think so. I think one thing that we have said is that if we're going to run our company to being an A-rated company, which is one of the very few, we're going to stay within our cash flow. This time at our size to look annually at our dividends, and you saw us increase our dividends back in February, and we're going to make an annual review of our dividend policy every February. I can never say we are -- think it's -- we are hit the vagaries of commodity price. But having everything else being equal, you're going to see our dividend policy continue to move forward in the next year and the years after that.

Joseph Patrick Magner - Macquarie Research

Joe Magner of Macquarie. NGL prices have softened recently. Concern is starting to build about a potential supply overhanging, given how much -- how many different plays are being this year in North America. Can you just remind us how your volumes are marketed currently and what their plan is going forward in terms of future marketing opportunities?

G. Steven Farris

Yes. And I had that question a number of times and I will tell you whether it's in the commodity being the crude oil price or the natural gas price, we would like to think that we set prices. The fact of the matter is, we don't. We're all price taker in all those different commodities besides NGL. I mean obviously, what you're seeing is as real pool out of NGL because the transition from and the suffering from having $2.30 gas to looking for liquids. So that's really no doubt that we've got a getting to be blip of NGL. And I'm going to answer that the same way I do about why there's WGI and why there's a Brent price. Over time, economics builds a hole. One of the things that we saw with rigs is and with frac crews if everybody and their little brother thought they could make great amounts of money and still the frac crews. I don't know how many private equity guys, I'm not -- I'm going to get back to your question, but I want to talk about the market a little bit. And what happened is you have bunch of people go out there and build frac spreads and say, "God, I'm going to put them in the Permian Basin and make $1 million." We got more frac spreads than we can spend, which is the same thing that's happened to the NGL. But what happens is, is if the industry contracts and expands, because they're always be a margin. And I'm there's an awful lot of work going on with NGLs right now, in Oklahoma, Texas Panhandle, take away capacity across that states, the same thing has happened in the Permian Basin. It always depends on your time horizon. For us, our high -- time of horizons are long. If you're looking at 90 days, we're going to suffer on NGL price. Over the next several years, we will -- there will be infrastructure and uses for that NGL.

John Malone - Global Hunter Securities, LLC, Research Division

Steve, John Malone from Global Hunter. Just 2 asset-specific questions. The first one in the North Sea in the mobile assets, the barrel of getting rid of your well recently. Have you learned anything from that in terms of are other compartments that could be that prolific and do you think you can see sort about a 40-type scenario there? And the second question is for Kitimat. Can you give us some sense of how lining of customers is going there and how timing is looking?

G. Steven Farris

The first question is barrel, and I -- Jim House who runs our region is here with us today and you might ask him more details about that. We have a number of prospects of barrel, especial barrel out there. Jim?

James L. House

You want to take me a crack at this?

G. Steven Farris

You bet.

James L. House

First and foremost, is it's early. We are shipping a 3D survey this summer. The first one has been acquired over the barrel fields since 1997. And the answer is, yes, we did find out this that well. We found a fault block with a reservoir that's not original as we are pressure, which is obviously a fungus. What I have found is that many of the professionals at ExxonMobil had a lot of great ideas, but they were running up against reservoir, simulations and engineering-type challenges and they're having a hard time getting them across the line where they will mature prospects. We're finding a lot of neat opportunities, and now we're putting together. Steve is going to see them next week. But we think we'll be able to support at least another rig line, if not 2, across the barrels. And we see another 40s type opportunity to add value in the North Sea.

G. Steven Farris

I think you said you had 40 or 50 million barrels that you could...

James L. House


Unknown Analyst

Over here. Kerling, stock bin. You emphasize a portfolio approach with activities. Today, you've highlighted a lot of unconventional plays, much more so than in the past. So I've got a couple of questions. One, are your resource indifferent than as to the opportunity, conventional versus unconventional from your portfolio management perspective? And two, as you get more unconventional, are you adequately staffed? In recent years, you built up your employee headcounts via acquisition and also development activity, should we expect your headcount to continue to increase with more conventional activity?

G. Steven Farris

The question is I think capital allocation between unconventional and conventional. And frankly, there's a number of ways that I have to answer that. One is repeatable. If you look at what we've got in the Permian Basin or in the Anadarko basin, or what I think we're going to have in the Mississippian Lime and the Bakken, we're going to have repeatable plays. And those plays or those conventional assets will have to compete with us. Having said that, I can't tell you enough and I don't know when it's going to happen, or if it's a little bit like frac spreads. We never want to be a one portfolio, because that is over time what you learn is those things that you didn't pay for, you're going to bite you. One of the reasons why you have so much shale still available out there, number one is because we have better technology. The other one is, they're marginal plays. The difference is, in a conventional plays, we've got high rates of return but the repeatability is different. So we're going to have to balance our capital program so that we make sure we feed both of those. I will tell you certainly we continue to see strip prices on the prices. You're going to see us drill wells in the Anadarko Basin or the Permian Basin. You're going to see us drill more wells in the United States. Just because without repeatability and the rates of return. That's not to say we're not going to have programs in other regions, they just have to compete with that repeatability question that you got in the United States. In terms of staffing, we're pretty well staffed just right now. I mean John, equipment in the Permian Basin could use a few more folks. We just moved a number of Apaches out to the Permian here in the last 6 months. But we're pretty well staffed. And as we -- that's an incremental staff, that's not we got to grow to 100,000. That just happens over time.

Brian Singer - Goldman Sachs Group Inc., Research Division

Steve, Brian Singer, Goldman Sachs. There had been a number of big and small companies that they've tried to ramp up and they step-change in liquids growth that often times, that it takes a little bit longer than expected and can be more expensive than expected at least in the initial execution phase. Oftentimes, they try to do in production facilities and midstream availability. Can you talk about how you think about your midstream infrastructure needs, particularly in the Permian and the Mid-Continent, whether there are anything to the critical path that we should be focused on in the milestone?

G. Steven Farris

Permian Basin needs to take away capacity on their own side for sure and some other comments. I will tell, you what in terms of -- infrastructure is a separate question as to whether or not you can ramp up your activity level. Anadarko Basin, before we split off the Permian Basin with 1.5 rigs. So there -- if you remember, when we opened our Midland office in 2010, before that it was run out in Central Region. So in terms of being able to do that physically, that's not going to be an issue. In terms of doing that in the Permian Basin, I think what you saw from John's presentation in the -- I mean ramping up from where we are, the ramp-up was hard that just to hear. The next step is going to be easy for us, honestly, because we've already set since 2010, ramping up from 5 rigs to 34 rigs. So that ramp-up, that's start to small business and trying make to it something. Once you make it something, the add-on is pretty easy. In the Anadarko Basin, we are working on adding infrastructure out there, really more from the standpoint that not giving away some of our value to what we're doing right now as opposed to is there enough infrastructure out there to do that. I know from NGL side there's a pipeline plan, in fact, they're supposed to be out in 2013 some of that takeaway capacity. But incrementally, I don't see that as being a real hindrance to us, honestly. John Christmann, do you have a comment?

John Christmann

What I would say is on a project by project basis like Deadwood that we've developed from a JV, built a plant and product great solution to get NGLs out on the rail car to Eunice, Louisiana, where they could be taken care of. So obviously, in these areas, we'll have some move and plan our things and we kind of got to stay ahead of our inventory. But that's the benefit we have of having all these 6 plays is you don't want a 2-year time period, you can plan this and then ramp this up. So I think you'll see that dialed into the forward-looking numbers we gave. So and on the employee side, Steve hit the nail on the head. Going from 0 to where we are today kind of getting established was the key, but we've got our great team in place. I think adding incrementally and we showed a pretty conservative ramp and recount going forward. And I think there's upside to be able to take that out if the prices hold.

G. Steven Farris

Well, we appreciate. We don't want to belabor the point. I think there's a lunch planned, is that right? We have regional VPs. Each one of those lunch tables I think so if you have a specific question with respect to one of the regions that we're in, you're welcome to pick out that person. Thank you very much. I can't say enough. Thank you for traveling to Houston. We hope you got what you were looking for. It's kind of like I keep going back to the overnight success that's taken 13 years to get. What you're seeing today is 2.5 years of an awful lot of work by an awful lot of people. So thank you very much. Have a good day. Thanks a lot.

Patrick Cassidy

We have our lunch planned, in the forest room. It's down the hall, on the other side of the foyer that you entered into. There are tables hosted by each of the regional VPs and other officers and we hope you can join us for lunch. Thank you.

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