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
John P. Herrlin - Societe Generale Cross Asset Research
Brian Singer - Goldman Sachs Group Inc., Research Division
Apache Corporation (APA) 2012 Investor Day June 14, 2012 9:00 AM ET
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 Pitman.
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 of 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 in 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 inventory 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 have 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 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 as we 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 -- whether it's 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 time frame.
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 time frame. 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 -- 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 its 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 outspend 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 2x, 3x, 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 after 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 a 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 (sic)[Cairo]. 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, about 8 billion, 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 play [ph]. 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 got discovered that took him 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?
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 are some key indicators. And 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'd 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 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 million [ph] 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 as 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 through the Fusselman. Very predictable results, we're drilling these wells mainly on 40s, we're testing 20s. And I think there's 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 will 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 can 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 on 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 use [ph] a little acid [ph], 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 are as of the May 25, 2012, strip, these are before tax rate of returns after royalties. At the appendix at the back of your books, there is a -- 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 at 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 drill and complete costs, seeing 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 type 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. Drill 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, is 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 aged 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 aged 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 at 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, it was 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 these flow rates, so these are not absolute open flow rates. The 30-day average is 330 barrels a day. And within 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 is when we 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 the stratigraphy 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, drill 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 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 you 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've 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 generate 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 I can reel off 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 not just 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 think of 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 -- 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 Andrews 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 [ph] 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, and 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 get out on the fringes of these, and 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 cheap. 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 undeveloped. 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 drill 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 is a 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 State #24, a 30-day IP of 170 barrels of oil equivalent a day and an EUR of 156,000 barrels.
Our Yeso type curves. Drill 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 cost 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 [ph] 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 -- and I show it here on the right, depicting it, it's really a vertical well where we're completing multiple zones and frac-ing it. 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 -- you've seen. 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%. 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 40s 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, drill and complete costs of $3.6 million, EURs of 280,000 barrels, 61% liquids, rate of return of 37%. You see these wells are -- fall 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, it's 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'd 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 looked 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 a lot of places 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% but you don't [ph] 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 that because it can create its 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 acquisition, 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 thick, there are hydrocarbons known and proven down below 20,000 feet. I think the deepest wells have gone 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 pay [ph]. 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 stacked pays.
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 is committed to staying within its cash flow, and we got a little too aggressive, had too many rigs running 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, everything's worked 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 front of us. And what you see here is the depiction of, for no better word, lassos in colors around the various -- around our acreage, depicting the various plays that we're currently chasing. And by way of example, the top left, the Granite Wash has the most number of locations. We identified 22,000 locations within the Granite Wash, and 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 overburden, very low permeabilities -- low permeabilities and leads to very, very low drainage area. Historically, it's been spaced 1 well per 640 acres but 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 our 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 that we were counting. We've tried to illustrate 4 horizontal wells in a single vertical well in the southeast 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-feet thick [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 gray [ph] 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 cheaper, use different drillers [ph] 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 south of [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 reading 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 deep. 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 bunch [ph]. 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 drilling 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 quote 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 what 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 that 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 are economic. There are a lot of Tonkawa completions 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 up to 500-plus on this particular map and I think 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 the first time [ph]. 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've spent 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 drilled 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 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 our [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've exceeded 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 the 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 the completions [ph] 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 grah-bin [ph]. 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 50-, 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 91 per completion [ph].
We acquired this block of over 100,000 gross acres and 93,000 net acres, 200 square miles contiguous, 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 were uneconomic. But one well that had been drilled, it was called the Gun [ph] 401, 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 [ph] 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 Bivins Ranch [ph] area that's -- 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 and 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 rest of the block and then merge it with this. We have that acquired now, and we're in the process of perforating [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, assuming 225,000 barrels, which would be, including the horizontal well, which would be the $4.5 million completed 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 hooked up several wells. By now, we're hooking up about one 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 one well, where you would be successful, as we really had very limited [indiscernible]. We've now drilled 8 wells, one well is a dry hole. There was [indiscernible], so we drilled a dry hole, which we wanted to turn into a water-injected well. But after that, I mean, we've had 7 productive wells. We had one 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, but we chased them off location, blundered [ph] that one. And they got about 10% of the prah-fin [ph] end of the formation before they had to 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 control that I 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 zone that carries it. 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." Well, 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 property, 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 engineers and more geologists [ph]. 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 to recruit [indiscernible] right out of school. 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 2042. 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, if that's right. Patrick?
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.
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, I'll just 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 have been some very region-specific programs. These are typically characterized, as you might imagine, aside from [ph] North Americas, places where you can drill a well, put it on production, appraise the production, book the reserves and sometimes even all in the same quarter.
Now these are projects, that I'm going to talk about, as I said, span 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 what you call the project pipeline and add value going forward.
The development 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 they are largely international, these 12 projects. About 7 of those we've taken a final investment decision, these are ongoing, sanctioned by our board going forward. Half of the projects, about 5 of these projects are in Australia. And they run quite a gamut of investment opportunities.
No particular order, but they're listed there at the rate at the time 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 Monetization 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 Monetization 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 start of by looking in Australia. Here we have a map of their Northwest Shelf acreage holdings. We have about 8 million gross acres, about 5 million net acres represented in yellow on that map. All of our acreage is concentrated for the most part in Australia it's the Northwest Shelf. It's one of the major gas region provinces in this part of the world. And in fact, the location of the area where gas reserves will be challenging the Middle East for LNG output in the coming decade.
Out here, we represented some of the major infrastructure that already exists 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 the current time between Varanus Island gas processing facility and Devil Creek, we have the ability to handle about 600 million cubic feet of 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'll mention in more detail in about a minute, and the domestic gas plant associated, the Wheatstone LNG project, which are both located in areas there at Onslow, the Northwest Shelf. They will bring up our ability to produce domestic natural gas in Australia to 50% by the time the Wheatstone LNG project is complete. So going 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 are Coniston and Balnaves, which are FPSO-related developments; and 2 gas, Macedon and Julimar-Brunello, which is the subsea component, 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 very high rate gas wells to the onshore gas plant, which is currently under construction, which has a capacity of about 200 million cubic feet of gas per day. At the current time, we have site works underway. Pipelines onshore are complete tying into the Bunbury -- the Dampier to Bunbury natural gas trunkline, which courses into close to Western Australia down to Perth. It's the main supplier of the developed natural gas that we produce 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 our share of the project will be at 49 million cubic feet of gas per day. I think, importantly, as we've seen 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 currently being signed at 2x -- more than 2x our current utilizations.
Coniston, in the same area as Macedon, this is an oil development project. If you recall, we brought online the Van Gogh oilfield 2 years ago. Big initial production of about 35,000 barrels of oil per day. That project paid out in a very short period of time. The project continues to produce from the reservoir, the mother [ph] reservoir, which is providing about 20,000 barrels a day gross production at the present time. Now that oil is a subsea development, which is brought to a turret, detachable turret mooring, anchored to an FPSO, which evacuates the oil.
The Coniston project is a very similar companion piece to Van Gogh. Similar reservoir and striation [ph] structure, which we began drilling exploration and appraisal wells in 2009. Completed our drilling program, have now sanctioned a development program for Coniston, utilizing the Van Gogh facilities and utilizing the same FPSO. So this is a tieback utilizing our Apache-owned and operated FPSO, the Ningaloo Vision. And we anticipate the principal development here to be 7 multilateral producers, a couple of water injectors and a gas injector well for the initial phase. We've awarded many key contracts and are starting to work on the subsea portion of this development. We have 52.5% in-operatorship in this project. We expect the first production in 2014 in the first quarter at a rate 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, principally 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, in our Julimar-Brunello drilling program, we discovered an oil accumulation in the same vicinity at Balnaves in the B20 zone. This will also be a subsea evacuation to 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 that as the oil reserves are completed here, that the associated gas, which we'll be reinjecting into the underlying B10 sand zone, will be then evacuated and used to support as LNG as part of the Wheatstone project.
We expect first production from this project to commence in the first quarter of 2014. We have a 65% working interest in the project, and we expect production initially to come on about 19,500 barrels of oil per day. Very similar to what we see -- have seen to the south at 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 in 2009, Apache began discussions with Chevron for the possibility of entering their Wheatstone LNG project and to be able to monetize the large gas reserves that we had found in the Julimar-Brunello complex in the Northwest Shelf. In the third quarter of 2011, which was the final production [ph] decision at Chevron to proceed on 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 produced out there.
Both of our projects, which will help with the ability to add projects for future developments that Apache might have in this area, to add these Wheatstone trains as well. And of course, we liked that project so much that a short time later in the fourth quarter of 2011 -- or 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, and I'll show you a slide on this specifically in just a few moments, it's designed initially to be one train followed by a second train in a short time period, at 5 million tons per annum, at least 5 million tons per annum on the initial first train, a little over 700 million cubic feet of gas per day. We'll be the operator of the project with a 40% working interest, in order to receive the export license approval for a 20-year project export from the Canadian government, as well as other significant environmental approvals. Certainly, early site work is underway at the project. And this project also has significant expansion potential for the gas, which we have in Northeast B.C. area, as well as western Alberta.
Wheatstone LNG. This is a mammoth project. This is probably our second-largest project currently underway, offshore Australia behind the Gorgon Project, which Chevron also operates. We have a 13% interest in the project. This diagram here shows what the domestic gas plant and the LNG facility will look like at the -- town of Ashburton north on the West Coast. The site work has begun. It begins with the construction of the plant facility, the offshore platform, which will process this gas initially before we pipe it ashore. We expect fabrication to be commenced in the fourth quarter of 2012. We have already placed 80% of the market with 4 Japanese utilities. So all the offtake is taken care of 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. And the first 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 feet of gas per day, net to Apache, and that's for a 20-year production plateau.
Now on the Kitimat side. Kitimat is very similar in the basic components that we see to the Wheatstone LNG. For the location position, it's in the West Coast of British Columbia. But interestingly, this is the same sailing distance to Tokyo as it is from Northwest Shelf in Australia and it's 6 days shorter than sailing to Middle East, the principal suppliers being Cutter [ph]. The principal operation here in Kitimat is to be able to tie into the existing spector [ph] grid system through the domestic grid.
To bring gas, principally for Apache's interest in the Horn River Basin south and 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, which is an ice-free, deepwater port facility, which allows us to evacuate LNG across the Pacific to Asian buyers. This will be at oil-linked prices. The process train, which we anticipate to start, will be over 300 million cubic feet of gas, net for Apache, and we have a 40% working interest in the project. We have 2 partners with 30% a piece, EOG and Encana.
We're filling and doing all the work necessary to lead up to FID. And that consists principally of the marketing aspects, to line up our off-rate [ph] customers, the finalization of the FEED cost for the plant construction and the pipeline construction. And of course, including all the necessary approvals and requirements from the B.C. 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 expect, from the time we take FID to be approximately 55 months from FID to the first cargo of LNG. This is a very important project. There are several, I'm sure you have read about, that have since proposed. There are about 3 other projects in the same area. We've had the same general concept all going to a similar areas around Prince Rupert or Kitimat because of the configuration of the shoreline there in evacuating Horn River gas and Montney gas. In our case this is an outstanding opportunity to be able to monetize substantial gas reserves, which we have in this area and which John Bedingfield will talk more about in his subsequent presentation.
The basis for supplying our Kitimat LNG at the present time is our Horn River development. The last few years, Apache has, as well as [ph] its partner in Canada, has actively developing Horn River shale gas opportunities. We have a substantial position here, almost 300,000 gross acres, almost 200,000 net acres. Our Apache 100% 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 net to us, 90 million cubic feet of gas per day, and we share that production 50-50 with Encana.
Overall, this field in production has been ranging between 200 million to 250 million a day gross from the Horn River from the bootlaw [ph] shale section. We have usually [ph] drilled the drill pads. We're about 10 wells per 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, keeping the cost reduced 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 resource 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 rather commanding, 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 these is the Forties Alpha Bridge Linked Satellite Platform, which has certainly been underway, in the planning and development stages for the last 2 years. In fact, we begin to set the jacket in this platform in summer of 2012, with the subsequent installation in the top sides when the weather is available [ph] in the early part of 2013.
Now this is a rather 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, will show you the general field outline of the Forties complex, which is a developed by 5 platforms. The Forties Alpha Bridge Linked Satellite Platform in the past [ph] project will have additional drilling slots, which is our biggest constraint in the Forties right now is the ability to drill more wells.
The dots on that map represent the current inventory of drilling locations, 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 still have the 100 wells in the inventory. This project -- this satellite field platform project will allow us to access different drilling locations, which otherwise you cannot reach our existing Alpha or Echo Platform locations. The sales [ph] 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 House, our country manager, mentioned to me it's really interesting in that slide you have a fast project. He said 2012 and 2013, when we first acquired Forties from BP in 2003. This was the year that decommissioning was the start at Forties. This was the end of it's life, in 2012, 2013. And we were pleased that the work that guys have done in the North Sea and we're a long way from decommissioning. We adding a rather substantial platform in the field this late in its life. Instead of being decommissioned, look at the production [ph], 50,000 barrels a day, net, from the Forties Field. It was quite a ways, and all the hard work that we've done to increase production. I think you know the story, since we took over operations in 2003.
Now moving on to some significant projects in the Gulf of Mexico Deepwater. Now we've been actively drilling [ph] in deepwater since 2010. We currently have about 750,000 lease acres and 148 federal lease blocks, which is shown as the black dots across the map there 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 May [ph] average of 16,000 barrels a day. We'd 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 4,000, 4,500 barrels of oil per day. At this rate, we'll be up about 25,000 barrels a day net by year end of 2012.
Now the 2 big projects which were coming up for 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 of drilling prospects which would be operated by Apache. They're shown there on the screens, Eagles Nest, Backslice, Staurolite, Refugio and Parmer. In Parmer, we have 50% working interest in that well 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 pliocene miocene subsalt oil development in 7,000 feet of water. And that diagram kind of gives you an idea of what the development concept is. This project has been sanctioned by the partners for development. It can consist principally of 6 initial producers, oil producers, which will be tied back to a Spar-type facility.
We expect that the development drilling will commence in the second half of this year, with first production anticipated by the third quarter of 2014. And our share of that production will be about 10,000 barrels a day. The Lucius field is probably a 300 million-barrel oil field, oil accumulation on an equivalent basis, mostly oil. Our share there, our resource there is at over 30 million barrels net to Apache. 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, to develop 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 neighborhood, as you notice on the map there. This is another Middle Miocene oil prepped against salt [ph] as shown there on that purple line.
The Tahiti Discovery and Chevron's fields are about 450 million barrels, just north along the same trend. Anadarko's Caesar and Tonga discovery, their resource probably up to 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 when an appraisal well was drilled early this year. It increased the size of the oil approval [ph] by some 1,500 acres. In the pre-commissioning stage for sanctioning and as we move forward depending on timing of the FID, the likely first production would be in 2016. And our net share of is 200 million-barrel gross field size would be at about 25 million barrels or 10,000 barrels a day equivalent initial production.
So if you look at the wrap-up of our development projects, I mean there is the opportunity of some 200,000 barrels of oil per day. This is one of the project pipeline. This is the result of discoveries we've made in the areas we showed you in the last 2 years, maybe 10 years ago in a case of Australia at the time it takes to bring some of these projects to monetization level. And I think you can see from the list of the 12 projects that are currently underway and many others, which will be entering that pipeline, they're very material. They're sizable. They're very viable, 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. With 2 trains at Wheatstone and initially 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 equivalent 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 major facilities, especially LNG. The more you can add to subsequent trains and LNG, we do sure like [ph] the cost of these common facilities and amortization costs get better and better economics going forward. And we intend to expand that project pipeline, and you can see from the demonstration here, we have the ability, as I think, Steve had mentioned, to operate effectively from exploration phase whether it's in North America or international locations. It doesn't matter [ph] the size of the project, be it deepwater development, onshore gas plant construction or even LNG -- 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 can talk about our exploration and new ventures program, just to deal and generate the kinds of projects that will now be in the next 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 in 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 indeed what it is that we're actually doing within the organization. And I'll illustrate that with a series of examples, which I hope you'll agree 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 materially impact Apache's shareholder value. In other words, things of scope and scale, things that matter financially.
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 the opportunity. 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 where others are either not looking or have missed opportunities. And coupled with that is, of course, the willingness and courage to act. So all the strutting in the world is never going to bring about [ph] the oil, 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, it' really in our DNA, I suppose, is that we've got to temper our enthusiasm, by the economics and commercial realities of the world. So what that means is not every great idea is something that -- it may be great geologically, but may be commercially not 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.
You've heard the theme of balance. Exploration's no 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 basins. So we've got to try 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.
One of the things I do need to say, and I want to make sure everyone understands it, this effort is additive, actually. This is not a replacement for the exploration activities Apache has always done within this region. 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 metrics of success is the generation of new Apache regions. So we see some of those, you'll know that we've actually been successful.
Like I said, we've been doing this for a little over 2 years. I got here in February 2010. The first order of business was to build an organization. So we actually hand selected a number of really high caliber exploration professionals across the industry. We had a core group of key Apache folk, a sort of ultra [ph] 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. This is a group of highly dedicated, passionate men and women who know their business. Group of G&G, geologists and geophysicists, engineers, commericial and business folks. And of course we give credit to our hard working admin staff as well. Along 2010 in through last year, basically it was figure out where we want to go, figure out how to get what we want to get and how to do it. And that's what we've done. We've actually built, I think, a reasonable portfolio of opportunities, and I'll go through those to a certain extent. Now this year is going to be a fine year, if we actually get the test wells or actually drill wells. We should drill somewhere between 15 to 19 wells this year. Exploration wells. Some of these that we'll be drilling will be frontier basin, some of it in the almost appraisal wells. But as I said, I think a really exciting time right now. So down the end of the year, we'll see how things panned out and next year will be very interesting.
All right. A lot of people do exploration. Apache is not one of the companies you immediately think of as a global exploration company. We certainly do have a global reach, everyone recognizes that. But one of the things I think is important is what differentiates us from some of our peers is our exploration organization is by backstopped [ph] by a tremendously capable organization, great depth in terms of skills and abilities across a broad range of industry disciplines. That's really important. That's something a lot of companies don't have. And I think most people would certainly agree that Apache has a rock-solid record of development, our ability to commercialize assets is probably second to none. We have sufficient cash flow to fund these growth projects without undo strain. 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 is the same story you've heard from other folks, is our focus on shareholder value, growing shareholder value. So we've got to do this efficiently.
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 New Zealand, other than to say that it's a frontier unconventional oil play. We've got a lot of work to do, to figure out exactly what we're going to do there. But I will talk about the others to a certain extent. This morning someone asked me, what are your exploration teams? And the answer to that is, we actually have 3 exploration teams that we're pursuing. We are pursuing a deepwater theme globally. Deepwater as many of you know is more of a catch-all phrase, it doesn't mean anything specific. I was asked specifically about the plays and such, we're pursuing them. I can't really talk about that right now, because we're in the sort of sensitive stages of the negotiation and paper [ph] opportunity capture. Suffice it to say that we do have a deepwater theme. Deepwater has delivered most of the oil, discovery of oil in the last decade or so. We also have an unconventional resource theme, which is typified by some of the things that we do see, in fact almost everything in the Americas will be our resource play.
And the other theme that we have is one that, I kind of struggle with the right term, but it's effectively a neglected basin or a technology theme. Basins that have considerable potential that can be unlocked with the application of technology. And a good example that is the Cook Inlet program up in Alaska.
This is an interesting slide, I think it kind of sums up kind of where we are after 2 years in terms of exploration. And I'm not going to read this slide to you, but you can see here that these numbers here is that we have exposure to a tremendous upside in terms of potential resource. Some of the stopped that's been discovered, although not booked, and some of these yet to be discovered, but we -- our resources assessment I thing is quite reasonable, and based on, in many respects on quite a bit of fact [ph]. Bottom line here, is I don't know that 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 could basically increase our proven reserves up to fivefold. And that's a pretty nice bit of inventory to be sitting on. This is all organic growth, pretty impressive [indiscernible] around the world.
All right well I'm going to start off now by talking some of these projects. Liard, I believe Rod alluded to a little bit earlier. I believe Steve talked about it and clearly this is a gas project. It's the only gas project that I'm going to talk about today. It is located at the northeastern British Columbia, and like all gas projects it is challenged by gas prices. I think what's really incredible here is recognition of this resource. This is, in my view, certainly in my estimation, the best shale gas reservoir in the world, certainly from a performance perspective. And I'll talk about that a little bit more. We have a commanding position up here, with over 400,000 acres in the heart [ph] of play. If you look at the in-place numbers, 210 trillion cubic feet of gas, is a staggering number. Shrinking that with [ph] package et cetera, we wind up within [ph] 48,000 [ph] 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 the zone [ph] on this. This is a huge resource for the future.
Steve alluded to earlier, we did drill a well, we drilled 3 wells, frankly. One of them is a fairly short horizontal, which tested over 21 million a day, out of 6 fracs and on a per frac basis, one of the most prolific wells I think I've ever seen it in this sort of play. I'll talk a little bit more about that later.
All right I'm not going to get through all these words, just wanted to say that Liard compares very favorably to other resource plays that you may have heard about. Liard, this is probably the first time we've every talked about Liard publicly. This is all new stuff, no one has ever seen this before outside of Apache this whole time. The things that make Liard special -- I'm going to use a pointer, my apologies for those of you online, but things that are most important are thickness, we have tremendous age [ph] in this reservoir. Pressures are great and the other thing that's really important here is that this reservoir is more than 90% quartz [ph]. In other words, we don't have much play [ph]. The vein of most resource plays is, goes towards heterogeneity. And you don't see that here, this is a fairly homogenous reservoir. As a consequence, we have tremendous vertical lateral continuity. What this means is, in your reservoir engineering background, this acts kind of like a tank, and that's pretty impressive, I haven't seen too many of these in the world.
Looking at a little cross-section here, this cross section runs about 15 miles north to south. North is actually on the left-hand side of the cross-section. Now the colors here, the red, the degree of red represents gas saturation. I think what you can see from this 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 off to the -- on the left-hand side of the section, the Apache, the 86S [ph] well, that gets out into the deeper part of the basin. And you can see our net pay is huge, over a thousand feet of net pay. These are pretty decent porosities for a shale gas reservoir and, as I said, pretty impressive rates off a single frac on this particular well. Moving to the right-hand side of the cross-section, the D34 well. That's a pilot well that you're actually looking at there. We actually then did a short horizontal on this one and we'll talk a little bit about but we learned. And by the way, all 3 of these wells are currently on production, into a little sales [ph] pipeline that kind of run through the heart of the aperture [ph].
The D34 well, once again this is a profile view of the lateral. You can see that they did a really good job staying in the zone. We did 6 fracs on this well, fairly short lateral 3,000 [ph] feet. Our 30-day IP was over 21 million a day, and at $3.6 million cubic feet of gas per day 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, my time in the industry, this is probably the best shale gas reservoir in the world at this time. So I say we -- others may surpass us but I haven't seen much that would suggest that so far.
All right. Our development model. Once again, not to suggest that we're going to rush to development. But I think the idea, what I wanted you to take away from, is the efficiency of this reservoir and how these wells will actually deliver. The development model, once again based on our -- a simulation based on our hu-shong [ph] well. We probably drill 7,000-foot, 8,000-foot laterals, frac spacing, 400 feet. You can read all this stuff. But what's really staggering to me is that these wells should deliver somewhere between 60 to 70 billion [ph] cubic feet of sales [ph] gas per wellbore. That is exceptional. What you can see here is that the pad drilling concept, which we know well how to do. Basically if you do the math on this, what this means is that each pad should deliver somewhere in the order of 800 billion cubic feet of gas. That's a huge number, very, very efficient way to get gas out of the ground. I won't go through all of the other numbers here other than to say, if you do the math it certainly does come up to 650 [ph] billion cubic feet of gas in terms of deliverable reserves of resource. We have a high net interest in this. High net working interest 100% working interest, high revenue interest.
Where we are right now frankly is we'd like to have higher gas prices, like everyone else in the industry and we need about $2.57 to make this thing effectively. But as I said, that's a domestic price. Looking at it perhaps a different way is we said these wells are already connected. There were some infrastructure in place, these wells are connected to the domestic market, if you will. Also there's an option perhaps if it makes sense that's it also be exposed to LNG prices, perhaps at some point in the future. But any rate, once again, I'm not going to jump into the development on this right away, it's a tremendous resource and it certainly is something of significance in scale that will matter to Apache in the future. And what we're doing now here is we're drilling ten-year wells to hold the acreage together, so in the next couple of years we will drill the wells that we have to drill to hold the acreage. But we should be in reasonably good shape in the event that we have a clear path to [indiscernible].
All right, moving further south, but also within our own unconventional resource is the Vaca Muerta shale. The map that you're seeing here is the brown color represents the working basin, which is located in West Central Argentina. The black line here represents the simplified [ph] purity outline of the Vaca Muerta Shale. The industry news about this play, YPF, for example, has talked quite a bit about the oil project they have down in Argentina and if you look at about the center of that map, you see the ellipse there that shows where the YPF activities are located. Now Apache has over 900,000 net acres of the Vaca Muerta, with about half of that in the liquids window. Our assessment at this point is about 800 billion barrels at this rate, we think this could potentially be a world class shale play and I'll talk about that a little bit more. Our activities down here we're certainly transitioning to the drilling for oil in this play, and I think this year it's going to be very, very interesting as we make our work program. Just for the record, Apache's been in Argentina for quite some time, and certainly lead in Neuquén and unconventional gas development. We are also one of the top producers of gas, as well. And as you can see here, the gas prices are actually quite favorable.
All right. The Vaca Muerta shale has all the earmarks of a world class play, once again, just kind of going through the check list here. It's got great thickness, good pressures in this part of the play that we are pursuing. And, although variable, we have very good quartz [ph] carbonate percentage. In others words low clay [ph] we have good carrier beds [ph] with some [ph] or more clay-ridden [ph] sections. Overall, this is a very attractive play. It's thick, pressured and it's relatively shallow, which is the near the middle of our play.
Now this is -- there's been a lot of oil and gas activity in Argentina over the years -- a decade. And there's over 360 Vaca Muerta penetration on Apache's acreage. We've looked at all those, I think we have good petrophysical [ph] logs and analysis that were 230 some odd wells. So what I'm trying to say is we understand the play is reasonably well constrained and I think we're in the process, with a bit more information, but in anticipation hopefully of a development decision sometime next year.
One of the things that is great about this play is the lateral continuity and thickness of it. It's very predictable. And we also have great oil saturations throughout this. By the way, this section runs about 50 miles down here in the Southern part of our concession. You can see good carrier beds and the lighter colors, the lighter the green the 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 collecting more information. We have a way of getting to that information. To do entry [ph] completions on these pre-existing wells, about more performance information out of those. We'll also drill 5 wells, 2 vertical and 3 horizontal wells to better understand the performance characteristics of this play. And with the new wells, we'll be able to collect some really -- pull some data, the types of data we really want to help the public better understand the play. So right now, I guess what I mean to say is our technical study is more or less complete and we're kind of going into the exploration or the execution phase of this program. Very exciting time for us in Argentina.
We do have one well as we completion of the PVG [ph] 39. Is got a 30-day IP, about 118 barrels of oil per day and that actually produces gas as well,so if you do that on BOE basis, that's about 127 [ph] barrels of oil per day. That's vertical well, that's not too bad. I think collecting [ph] information and stimulating it, which we do, we know how to do this pretty well, which is not to say this is a final design but looking at 30,000-foot [ph] lateral and fracs, we reckon we could get 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 on our acreage and about almost 800 million barrels. So very substantial play potential as from a technical perspective, this looks very, very attractive. And as I said, we'll be doing some additional data collection this year, testing and hopefully making some development decisions.
Now for something -- moving back up to U.S. This is something that you guys have never seen before. We have never talked about this. No one outside of the Apache, and only a relatively small group of folks within Apache, were aware that Apache has filled [ph] a position in the Mississippian Lime play in Kansas. And I think this is -- the reason we're talking about this today is because the landgrab is over and we have pretty much finished our leasing activities. But we've been able to achieve first-mover advantage in this play. We've picked up over 580,000 net acres, there are stacked pays. You guys probably guys know this play as well as I do. But I think one of the things that really spectacular here is we've managed to beat industry to the punch. We have very low entry cost. I don't know exactly what our costs were but I can tell you, we've got great terms in our leases, 8- to 10-year leases, acre [ph] royalties, that sort of thing. So we have lots of time on these leases. I will say our acreage cost was less than 200,000 acre for this one. But as I say, we think we did a pretty good job of identification and capturing this opportunity. And now, frankly, we're surrounded by industry, a lot of the well-known players in this play are certainly are adjacent to us. Put this next up. I don't think everyone can actually see this on the screen but there are little circles and little squares, little red circles and little 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. So industry is moving into this play. And we feel pretty excited about our position here. I will say that we see a number of stacked plays and I'll go into that in a little bit more detail here in a series of slides. So we have broken this out into chunks, if you will. And you can see from map -- inset map at the bottom. All the green here represents historical production. A lot of this, as we've see, the oil is here, there's no doubt about that. So there's no question that the oil is present. Now no one's been doing horizontals up here, so this is where you're going to see some effort 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 lift [ph] column or strat 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 tide [ph] oil. It's good porous limestone. On top of that, we have a Cherokee section, which is more, solisiplastic [ph], 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 amenable to horizontal drilling. We have a number of opportunities there that I'll talk about a bit more.
All right kind of once again, I'm not going to get too deeply into geology right here, I don't really have the time for it. I just want to say that within the Mississippian Lime proper play out 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 does -- a lot of oil in this section. It tends to inch out of the -- basically not inch out so much as be truncated by the Mississippian component [ph] as you move to the east, a bit on to the central Kansas, Southwest. So we see quite a bit of oil in this section. Once again, literally hundreds and hundreds of pre-existing wellbores, vertical wellbores that provide us with quite a bit of control. And so what we have yet to do, of course, is do all the sweet spot mapping. And I think that, that is in progress and of course 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, it actually is a more solisiplastic [ph] play, with series of deltas, we believe. Or river [ph] system, fluvial systems, feeding off the Central Kansas platform from the Northeast to the Southwest. A bit more restricted in nature but very, very attractive, very sweet, where you find it. Once again, our play fairway here is in counts [ph] is about 230,000 acres with about 1,400 location.
Certainly, above that, the last big trunk, if you will, of our 15 plays is the Upper Pennsylvanian play. Once again, oil saturated limestones as is classic cycle systems. We are working hard to develop our sequence 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 ourselves, we've carefully selected the 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 a little over 300-some-odd thousand barrels per well. These plays all offer spectacular rates of return. Mostly because potential tests is obviously quite high, but also the drilling costs and production are quite low. And so the oil per well is very attractive. So great rates of return on these plays and, as I said, with relatively low cost in terms of P&C. 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 [ph] at about 265,000 barrels. So in aggregate, this adds up to about a 2 billion barrels of recoverable -- of net recoverable resource. Once again, making sure that's not reserves and that number may change. This is what the exposure is from a regional potential. 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, which, once again this is the first time we've talked about this. It's basically where we're chasing Bakken and Three Forks up in the Williston Basin. We've, once again, have managed to achieve a first mover status and have over 300,000 acres -- net acres secured up in Daniels County in Montana. What can I say? It's good to be there first. We got low entry costs. And right now, we are done, basically, the leasing is. Some will trickle in but 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 Coulee field here, another 1 billion [ph] barrels of oil from the Bakken. Now just to point out, Elm Coulee 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 trawling [ph] fundamentals. We recognize an area that has not been viewed as attractive by industry as others, it's thermally [ph] 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 where moving quickly could make a real difference. And we are starting to -- certainly we saw competition lead in this place, it's pretty well locked right now.
In total, we see about 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 type 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. That reduces our drilling cost, down from $10 million in the Bakken to about $7.5 million, or $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 plays 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 gotten to the evaluation on that yet. And below in the Devonian, or the Devonian plays, the Birdbear, for example, which 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 [ph] unit and basically, I know it's something like a chunk here in the lower right-hand 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 this will be adjusted and optimized as we collect more information. But once again, a pretty efficient way to drain this significantly large resource.
Looking at the cross-sections, runs about 45, 50 miles to the heart of the Apache acreage. Once again, as in the Vaca Muerta, the lighter colors represent 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 put a lot of time and effort into that. So clearly mature, definitely in the oil window now generating hydrocarbons. We have great saturation in our reservoirs. And the reservoirs here, they're a little bit healthier [ph]. It actually has slightly better porosity than we've seen else where and the phases [ph] 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 land wells 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 reservoir is also to grade [ph] a little bit as well. So you get out of the play, not much further west than where we are now. So we do think this is a great location, very similar from a basinal [ph] position to the partial Rough Rider field I believe on the Eastern side, and also a little bit to Elm Coulee in the south, although our [indiscernible] in this part of play is significantly larger than Elm Coulee.
Looking at the economics. Once again, spectacular rates of return, subject to reality I suppose. But what's important here, I think, for us is the P&C costs are about $7.5 million per well. And that's important. As I said before, because we're shallower the costs are 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 it 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 drilling in July and we have plans to drill 5 wells this year. We won't stop at 5 wells but hopefully, what will get done this year. Hopefully, get a couple completed as well.
All right. Moving to further north, to Alaska the -- specifically the Cook Inlet. We've talked about this before. Other folks have talked about the Cook Inlet before. But we sit [ph] in a pretty good position there. We have access to over 1 million net acres. This is a basin that is a proven basin. It's got very low [ph] 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 time, it's like an oil museum is kind of how I'd describe it. It's interesting, but things have just been frozen for 40-plus years. So it feels like there's only a handful fields have been 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 indeed, 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 tailor 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, that 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, I hope we spud another well this year, probably starting in August time frame. We have a rig and we're working through the permitting process of course.
We also, as you guys know, we are acquiring a large scale 3D in this basin. We believe that's the key as I said before. To date, we have 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 we found some and we fixed those and then we started 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 limiting factor on seismic is not dynamite or [indiscernible] so much as it is daylight. And so we're moving into long daylight hours now up in Alaska. And we expect to get somewhere in the order of 300 to 400 square miles acquired [ph] this year. That's out of 1,000 square mile program. It should last over the next 3 years. So we'll be shooting seismic and concurrent with that, 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 have been very, very encouraging. What I've done here is I've taken a bit of our 3D. This is about a 20-square-mile chunk of seismic or map I should say. I've rotated in -- kind of moved it around so hopefully no one will know where it is. I wish I had taken the scale bar off. 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 leads we might see assume that constant [ph] 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 -- with a 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 would view is a very high degree of repeatability. So we view this as -- I'm very excited about getting these 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 the industry abut sizing. 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, whatever the transit time is from Tanzania to here. The prospect for drilling has basically a mean value of about 280-some-odd million barrels, 200 million to 300 million barrels. Why I want to be careful here is that this -- what you're seeing here on the map, this little green outline. Little green outline with the 2 boxes [ph] 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 deterministic [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 sized, a lot of running room on the block is the real thing I want to leave you with. 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, I should say.
Starting in August, this is the first well in Kenya offshore. It's been drilled on 3D data. It's good quality seismic 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 when everyone is finding gas in the area. So to the south, in the Rovuma basin, industry's been very successful in finding just literally lots of TCF of gas in Tertiary Delta system. We're actually targeting cretaceous sands with Jurassic charge system. The reason we think this important. We're in the Lamu basin, there's different basins, different history than in the Rovuma. If you do your plate reconstructions, what you'll find is that Madagascar fits very nicely into this part of Kenya, which -- where it actually 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 barrels of oil in place. It's heavy oil, but it's heavy because it's been exhumed and biodegraded. If you do your plate reconstructions, what you find is it fits very nicely with our block position in the Lamu basin. The other thing I will say is that the Madagascar oils have been typed back to the Karu [ph] source rock, Jurassic source rock. Now there are no wells in our block, so we can't say it definitively that the Karu [ph] is there. But from the offset wells in the area, we actually do believe that the Karu [ph] is 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 play. No ifs, ands or buts 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. Talked about that, you can see it from this -- the top seismic slice there were we're testing sort of a central confirmation to the south. It's a little difficult to see on the slide, but we do see evidence of a pretty good flat spot there, we think it's the last slide there we described to being a little bit of gas.
Below that is a potentially a second flat 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 about 50 or 60 days later, we'll have something good to report.
The other thing, and as I mentioned before, we do have some pretty good running room. And this is a little seismic slice on the bottom. It's of the tie [ph] 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 feature itself. It has good access to charge and pretty good size. 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 deep into it is that, as I mentioned, Liard basin, we are going to preserve acreage in the drilling. Kenya wells, we're actually drilling one right now. Mississippian Lime in the Bakken plays, we will begin our drilling, exploration and appraisal drilling, in July. Now that program will run through the end of the year. And, assuming success, we'll continue on into 2013. Our development plan, it really is not like one day we'll be doing exploration, the next day development. Development will slowly become sort of the principal activity in these 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 toward the end of this year and drilling into the next couple of years, with development to follow perhaps as early as next year with some ifs.
And Kenya well, I'll say will be drilling the Mbawa well next month or in August. And successful or with encouragement we have plenty of time to consider drilling 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, that hopefully will set the stage 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 shown it to you over the 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 this programs for some of the 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 strip. We have the cash flow to be able to take advantage of some of the things that we're doing on the exploration side or to accelerate even further some of the stuff 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?
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 or Jessie [ph] and she'll hand you the microphone or you can come up here and ask your question from this mic. Thank you.
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 drilling 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 as to be going discovering it. Some of the stuff you saw that John Bedingfield put out there. So I don't really think, or it's certainly not in our thought 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 wherewithal, 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 rambled on my question, but you're stock price is extraordinarily undervalued, at least 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 real honest with you. 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 liken it to, 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 their stock back. We have no downstream. We have no chemical business. We have -- all we are is oil and gas producers, and we are subject to the vagaries of oil and gas prices. And regrettably, when the prices are really high, you 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 wells 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, being an A-rated company, which is one of the very few, we're going to stay within our cash flow. There's 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 at 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. Concerns are starting to build about a potential supply overhang, given how much -- how many liquids-rich plays are being pursued this year in North America. Can you just remind us how your volumes are marketed currently and what your plan is going forward in terms of future marketing opportunities?
G. Steven Farris
Yes. And I've 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 glut of NGL because of the transition from, and the suffering from having $2.30 gas to looking for liquids. So there's absolutely no doubt that we've got what's getting to be glut of NGL. And I'm going to answer that the same way I do about why there's WTI and why there's a Brent price. Over time, economics fills the hole. One of the things that we saw with rigs is, and with frac crews, is everybody and their little brother thought they could make great amounts of money and fill the frac spread. 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 the industry contracts and expands to fit that, because there will 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 state, the same thing has happened in the Permian Basin. It always depends on your time horizon. For us, our high -- time 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 data [ph] from getting a really good well. 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 up 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
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 some new things with that well. We found a fault block with a reservoir that's not -- still had original reservoir pressure, which is obviously a bonus. 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 were 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
John P. Herrlin - Societe Generale Cross Asset Research
Over here. Herrlin, SocGen. You emphasize a portfolio approach with your [ph] 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 you resource-indifferent 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 unconventional 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 could 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 that. 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-trick pony, because that is over time what you learn is those things that you didn't were going to bite you are 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 play, 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 of the 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 up 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 go out and hire 1000 people." 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-changes in liquids growth that've often found, that it takes a little bit longer than expected and can be more expensive than expected at least in the initial execution phase. Oftentimes, that's had to do with production facilities and midstream availability. Can you talk about how you think about your midstream and 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 as key milestones?
G. Steven Farris
Permian Basin needs to take away capacity on their oil side for sure and some of it's coming. 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 was running 25 rigs. So there -- if you remember, when we opened our Midland office in 2010, before that it was run out of 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 to get to here. The next step is going to be the easy part, honestly, because we've already set since 2010, ramping up from 5 rigs to 34 rigs. So that ramp-up, that's starting a 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 the NGL side there's pipelines planned, 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?
What I would say is on a project by project basis like Deadwood that we've developed from a JV, built a plant and put out a 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 to 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 on 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 a great team in place. I think adding incrementally and we showed a pretty conservative ramp and rig count going forward. And I think there's upside to be able to take that up 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. At 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.
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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