Sandridge Energy, Inc. (SD)
February 28, 2012 8:00 am ET
Kevin R. White - Senior Vice President of Business Development
Tom L. Ward - Chairman and Chief Executive Officer
Matthew K. Grubb - President and Chief Operating Officer
Todd N. Tipton - Executive Vice President of Exploration
Rodney E. Johnson - Executive Vice President of Reservoir Engineering
David C. Lawler - Executive Vice President of Operations
James D. Bennett - Chief Financial Officer and Executive Vice President
Charles Meade - Johnson Rice & Company, L.L.C.
Kevin R. White
Good morning, and welcome to the SandRidge Analyst Day. We've got a big crowd today. So welcome, and hope everybody enjoys the day, and more importantly, the buckyballs. I want to take a quick second to introduce our Board of Directors. And for the board, if you guys could stay standing up after I call you. We got -- excuse me, Jim J. Brewer; Everett Dobson, you've seen Everett this morning; Bill Gilliland; Dan Jordan, he's right over here; and Roy Oliver. So that's the SandRidge Board of Directors, and welcome to those guys.
I just wanted to go through what the agenda is going to look like today, and you can see the forward-looking statements on the first page there. For the day today, we've got Tom, who's going to lead us off with some introductory comments, and Matt, who will go over high-level operations review. Todd Tipton and Rodney Johnson will go over the Extension Mississippian and the original Mississippian technical overview. Dave Lawler will go through our development plan for 2012. And then after Dave is done, we're going to take a short break at that time. And then finish up the day with Rodney Johnson going over the company's year-end reserves and James Bennett wrapping up with our finance overview.
Another thing I wanted to point out, in your book, we've got guidance for 2012 in the back of the book in the appendix. And we don't have any plans to go over the information specifically today, but if you've questions, feel free to ask about it. And through the course of the presentation today, most of the information that is presented, is presented as SandRidge only, so it's pre our Dynamic acquisition. There'll be some slides through the course of the day where we will have footnoted it and noted when we've included Dynamic's information in some of our numbers. And then in the guidance information that's at the back of the table, we have included Dynamic assuming a close of April 30.
So with that brief overview, we'll let Tom come up and get started.
Tom L. Ward
Thanks, Kev. I was running just a little bit late this morning. I was on the phone with my counterpart in Nigeria, looking a little bit of cheap oil. Just kidding, just kidding, I was just kidding. So a few years ago, as we started looking at the transition of the company from gas to oil, we had some big objectives, how do we move the company forward? But more -- and just the last year, we started to focus down. And whenever I looked at the growth of the Mississippian project, what I kept seeing in our model was that 3 years out, things were really very good for us as long as we could do some transactions to get us there, as long as we could keep our CapEx up at a $1.6 billion to $2 billion range. There were some objectives that we could reach that I thought would be different than most companies were able to achieve. So those objectives were tripling EBITDA, doubling our oil production, having a company that is mature. In my definition, mature is you could have a couple of billion dollars of CapEx that can be funded within cash flow, then you're looking at making acquisitions that would be funded with straight debt and equity. So that's kind of the goal post-2014 as whenever I think of SandRidge as a mature company.
Now keep in mind, we're only 5 years old. And with that 5 years, we had a U-turn in the middle where we moved from a 95% natural gas company to today by PV, we drill basically 94% oil. So it is a very rapid growth we've had, and that we've been able to achieve that in a short amount of time is -- a lot of credit is given to the guys in our organization you'll be hearing from today. I'm going to keep my presentation very short and try to just give the strategic overview of the company, but I want to spend most of the day will be with Matt and Dave, Todd and Rodney and James. And so what I do want to focus on that along with being able to have tripling of EBITDA and doubling of oil production is that we'll continue to make transactions and improve our credit metrics.
There's really not much that's changed for the company post-Dynamic. We still are low-risk, shallow conventional oil. We're really focusing on the 2 best areas from a rate of return perspective in the U.S. And that's the Mid-Continent and the Mississippian play, and the Permian is where we drill all of our wells basically, or onshore looking for shallow conventional oil out of carbonates. The Dynamic transaction doesn't change that. In fact, it just helps us with our growth engine of being the main drilling part of the company in the Mid-Continent.
Much like what we did in the Permian basin in 2009, when we moved into the Permian, it was an out-of-favor area. We looked at places that were being drilled shallow, very shallow oil. Most of the wells that were drilled and still are drilled on the Central Basin Platform are at 4,000 feet or so of vertical wells being drilled. And so what we looked at, it was a way, can we logistically drill 600 to 800 wells a year and can we take something that is known that there's oil in place and make an acquisition, and on around that acquisition, build an oil company. And that's what we did with our -- starting in 2009. When we met right here in March of 2009 and our board was here then, that was a decision point we had to go forward to oil. And oil was at $39.96 and gas was at $4.13, and that was the transitioning date basically 3 years ago today that we looked back and said, we want to change the company. And with that, we had a net investment in our Permian assets of $1.4 billion. It has a PV-10 value of growth of $2.7 billion so a growth in investment of over $1 billion in that time period. We think the Dynamic transaction we just made is like this, not the growth engine of the Permian, but that we went and bought very inexpensive oil in a place that is out-of-favor in the investment public. And so that there was a dislocation in the market just like there was with the Permian assets 3 years ago.
But the main growth area for the company is the Mississippian. For this, we found something that we knew about that others weren't focused on really a few years ago. But starting in 2009 and 2010 with our drilling and basically starting in Alfalfa County, moving to Grant and Woods and now into Comanche County in Kansas. Now you can see the red is where we've drilled, the blue is where others have drilled. We drilled basically half of all the wells in the Mississippian on the horizontal, but the key of the play was done decades before that we got here. And that's the -- there have been 15,000 wells drilled across a very large area, and what were those people looking for? They were looking for very subtle structures. So it's a huge stratigraphic trap, that red area, in the center of the page is the Central Kansas Uplift. There's no Mississippian present there. There's a large stratigraphic trap wrapping around the Central Kansas Uplift with a perfect trap, the Pennsylvanian Unconformity, and the Mississippian is eroding into that Unconformity. So we have newer rocks tipped away from the Central Kansas Uplift and older rocks because of the new rocks have been eroded off as you move towards the Central Kansas Uplift. Rodney and Todd will go into this in great detail, but this is all the same rock as you wrap around from the Nehema Ridge in Central Oklahoma and Central Kansas up to the Los Animas Arch, which is in Eastern Colorado. Those are the 2 structures where the stratigraphic trap is in between, up against the Central Kansas Uplift. The reason that's where your trap is and there's oil in place, the reason it wasn't drilled, is you have to have the ability to move water. And so what our guys will talk about today is the key to the play is this disposal system that we have in place, and what I would call the genius of the idea is that there's oil in place. At high prices, you can move a lot of water and have very high rates of return. And that's what the idea was that gave us the leg up to go put together the acreage.
So what did we do? We spent basically $400 million to buy 2 million acres, around $200 an acre. And we sold 550,000 of that and still -- and created $2.33 billion worth of value. That's through the Mississippian Trust, number one, the joint ventures that we have; and then a second pending royalty trust that James will talk more about. So that leaves us with 1.5 million acres. The implied value of that, 4,236 as we implied $6.35 billion. The resource NAV, so this is an important number, is $23 billion or $15,000 an acre. So whenever I talk about the ability to hold onto more of this acreage and use the Dynamic transaction as a funding mechanism, that's when I talk about the -- being so accretive, the NAV to us. So the Dynamic acquisition complemented the 3-year plan of doubling production, tripling EBITDA and reducing our leverage. So we had a few alternatives that we could've done, I talked about this at the conference call, is we could've -- in moving forward with our plan, we could've just reduced CapEx. We knew if we kept our CapEx as we projected over the next 3 years, we needed some funding. That's always been known. So how are we going to fund it? Well, first of all, you could've reduced CapEx and just not needed the funding. But then we wouldn't have had the growth and -- that we're projecting in our EBITDA, where you could have -- you could've raised debt, just fund it all with debt, but we were already 4x leveraged. So that wouldn't have been -- this wouldn't have been the appropriate time to be adding debt. We could've issued straight equity. I had a lot of people calling to say, you should just issue straight equity, and frankly, with straight equity, you wouldn't have liked that either. And you would have been -- you wouldn't have had 25,000 barrels of oil a day. So that leaves -- the royalty trust is a good idea, so you could've done more royalty trust, but they're actually fairly small in scale. And you have to sell the most proven assets, so around the production that you have, and you're also selling EBITDA at the same time. It's a good structure, but not one that you could -- that I believe you could build the company going forward over the 3-year plan.
And then the one that I had the most questions about is why don't you sell more acreage, and the last slide shows you why. It's that if the Mississippian is as successful as I think it's going to be, every acre we hold onto is worth $15,000 and we won't be able to sell it today for $15,000. So the Dynamic transaction -- well, oh no, I forget that we could do mezz debt. I mean, there's a lot of mezzanine or mezzanine financing, and I don't even put that in 1 of the 6 ways, I don't even to put that in as something we considered. But the other was to do an acquisition of Dynamic, and in all ways, that was accretive to us. And so that's how come that we talk about the Dynamic acquisition and 25,000 barrels a day. And the Gulf of Mexico has not been a place that I necessarily wanted to go and have a growth engine and it's not considered to be a growth engine, but we do believe by spending $200 million a year, we can keep our production flat, and we'll spend more time. And, well, even post this quarter once we get the Dynamic acquisition in place, we'll spend much more time talking about what we're going to do there.
2011 was really the key year for us. This was the year that was -- the difficult year to do all the transactions that we had to do, to have 440 -- $410 million of adjusted cash flow from operations and have a $1.833 billion CapEx budget. It took 7 transactions to be able to make that together and we did that without adding to -- straight equity. We didn't have to issue equity, and we didn't increase our leverage. So that was the transitional year for the company. Now in 2012, all the hard work's already been done. So we basically have SDR left, and then we're -- our funding is done. And actually, we can add leverage in '13 and '14 and still improve our credit metrics. So the way I look at this is that we're -- the Dynamic acquisition was one of the last 2 things we need to do in order to fulfill our 3-year plan. So I'm very pleased to be here, and I can't wait for you guys to be able to look -- especially at our Mississippian area and why we thought that the Extension Mississippian is as good as the original. And Rodney and Todd will spend a lot of time today going into that, and we're very excited to put together the plan. And we'll have -- this year, we'll have 26 rigs averaging in the Mississippian. We'll end the year with 5 of those continuing to move up into the Extension Mississippian. And next year, we should end the year of 2013 at 45 rigs in the Mississippian. So it's -- I think we're going to be bringing in about 100,000 jobs to Oklahoma and Kansas. It's a wonderful play, over the next 3 years, of growth for the company that'll allow us to execute our 3-year plan of tripling EBITDA, doubling our oil production and continue to improve our credit metrics.
So with that, I will turn it over to Matt.
Matthew K. Grubb
Thank you, Tom. And good morning, everybody, and welcome. My name is Matt Grubb, I'm the President and Chief Operating Officer for SandRidge. And I have about a dozen slides to go through before we get to the technical part of the presentation.
And 2011 is a great year for us in many fronts, not only on the -- to strengthen our balance sheet, but also on a performance and production, executing on our drilling program. We currently produce about 67,000 barrels of oil equivalent per day, and that's 16% growth in total production year-over-year, and 60% growth in oil production. In 2011, we produced about 11 8 million barrels of oil. And in 2012, with Dynamic, we expect to produce about 18.2 million barrels of oil, so that continues with our strategy to increase oil production within the company. Proved reserves, adjusted for what we produce, which was 23.4 million barrels of oil equivalent, and what we sold during the year, which was about 123 million barrels of oil equivalent, we were up 122% year-over-year. Our 2012 drilling plan is similar to our 2011, which is focusing on the Mississippian play and also on the Permian. We're just going to drill more Mississippian wells this year. We expect to drill 380 Mississippian wells and 759 wells on the Central Basin Platform. In 2012, production guidance, 54% of oil growth is projected for the year.
We operate primarily in 2 areas, which I believe, right now, are 2 of the best areas for developing oil and gas. The Mid-Continent, which is our Mississippian play, covers northern part of Oklahoma and Western Kansas, and of course, our Permian Basin is primarily in the Central Basin Platform. The West Texas Overthrust is at Piñon Field, which is a dry gas area, and we don't plan any activity there this year. Like last year, we didn't do a whole lot there. And then, of course, the Gulf of Mexico now with the Dynamic acquisition, we expect to spend about $200 million in the Gulf this year. So overall, we should drill about 1139 wells and roughly about 1150 -- 1155 wells with the Gulf of Mexico.
As I've mentioned earlier, current production is about 25 -- I'm sorry, 67 million -- 67,000 barrels equivalent per day with Dynamic, which we're projecting to produce 25,000 barrels. That gives you a pro forma of 92,000 barrels equivalent per day. We are -- pre-Dynamic, we're producing about 57% oil currently. And with Dynamic, we produce about 50% of oil so that's in-line with what we're doing. So we expect to produce probably 55% to 57% oil this year, in 2012.
The CapEx -- I'm sorry, the total production guidance, pre-Dynamic, and I think some people missed this because we announced this with the Repsol JV, is 26.5 million barrels equivalent. And with Dynamic having it 8 months out of this year, we expect to produce 5.8 million barrels of oil equivalent, and that's 25,000 barrels equivalent per day adjusted 3 months, down 10% for hurricanes in July, August and September. And so for the year, our guidance is 32.3 million barrels of oil equivalent. And as far as CapEx guidance, we were looking -- as far as E&P, there's another, there's land, and there's midstream, and oilfield service not in these numbers, but for E&P, which includes primarily drilling and workovers, we're expected to spend $1.35 billion and another $200 million with Dynamic, bringing that to $1.55 billion.
Proved reserves, we ended the year with 471 million barrels of oil equivalent. When we bought Dynamic, the reserves at year end is 62 million barrels of oil equivalent, bringing the total up to 533 million barrels of oil equivalent. Percent of oil, as you can see, most of the value, by value is 96% for SandRidge. The Dynamic reserves, 77% of that value is oil, bringing the total company pro forma to 91% oil by value. And then percent developed, we're right at -- close to 50%, developed reserves at SandRidge. Dynamic is 81%, bringing the pro forma number to 53% developed reserves.
From an FCC PV-10 value, we finished the year 2011 at $6.9 billion. Dynamic's bringing on another $1.8 billion, $1.9 billion NPV10, bringing the total company to 1-- I'm sorry, to $8.77 billion. And then, I'll repeat, these reserves of our production ratio in the Permian and the Mississippian, they're fairly long life, 19 years. As you can expect with the Gulf of Mexico, those will be shorter-life reserves at 6.8 years. So it brings the total company, our R/P ratio, to 15.7 years. From an NAV standpoint, SandRidge is $34.5 billion, the bulk of that, about 2/3 is in the Mississippian play. And the bulk of the -- remaining is in the Permian Basin. Dynamic brings on another $2.5 billion for a total NAV of $37 billion for the company.
This is our growth chart dating back to September of 2009. In September 2009, the blue line is the total production, oil and gas, and the green line is just oil. And back in September 2009, we're producing about 80% natural gas, 20% oil. Today, we're producing about 57% oil. And so you can see as we set out back in 2009 to transform our company from natural gas to oil, we bought Forest first back in -- and we closed that in December of 2009. Then 7 months later, we bought Arena, bringing our total oil production up from about 15,000 barrels to about 25,000 barrels of oil. And the rest of that, from July of '10 through February 2012, has been grown organically just through drilling in the Forest and the Arena properties, and the little bit of legacy Central Basin Platform makers that we had. So it's been tremendous growth in oil just over the last couple of years.
The Mississippian. The Mississippian has been truly a remarkable play for us. It is truly a vast area of tremendous resources for developing oil and gas. One of the great things about the play is that it's shallow. TVD on this play, true vertical depth, the top of the Miss. is kind of 5,000 to 6,000 feet. It's as shallow as a thick carbonate, on average probably about 300 feet thick. The area that we looked at leasing in here that we -- the envelope that we drawn in here, covers about 17 million acres, and has been proven up through history with nearly 15,000 vertical wells. So what we have left after the JVs that we've done is 1.5 million net acres, and this represents nearly $24 billion of NAV value. There's approximately 7,000 locations to drill here, and this is based on 3 wells per 640 acre section. And we still -- we started the program thinking we would recover 300,000 to 500,000 barrels per well. Our type curve is 456,000 barrels equivalent, and so we're still in that range. We have 380 wells planned for 2012, and the industry to date, combining what we drill and with other companies, there's been about 500 wells, horizontal wells drilled, in this play. The key to this whole play is the ability to move water inexpensively, and I think we are the leader as far as going out and spending money and designing our infrastructure for water disposal. And so you have high oil prices, you have cheap water disposal, that drives a very high rate of return for the Mississippian.
Mississippian production growth has been just as remarkable as the play. We started out in January 2010 with very, very little production for the Miss. In fact, we drilled and completed our first well in late 2009. We averaged 5 rigs in 2010, we averaged 15 rigs in the play in 2011, and we're moving up to 26 rigs, average, in 2012. And so production has gone from nearly nothing in January 2010 to over 21,000 barrels of oil equivalent per day today.
Mississippian economics are very robust. You're looking at 456,000 barrels of oil equivalent, $3.2 million per well. That includes saltwater disposal infrastructure, IP at 375 barrels of oil equivalent per day. The PV-10 on each well is roughly $5.5 million and a 91% rate of return.
So in 2012, we're looking at 380 wells, and net of our JVs, we're looking at about a 62% working interest at the play. As I mentioned, 7,000 locations, that's based on 3 wells per section, so there could be upside to that if we decide to go to 4 wells per section. And you can see the economic is in a type curve even at $60 oil, which is the bulk of the economics in this play is oil. Even at $6 oil, you're at about 40% rate of return, and that the strip today is somewhere north of 90%.
The Permian Basin, the Central Basin Platform, that remains to be a very, very important and core area for SandRidge. We -- again, it's a shallow carbonate drilling that we do there. Most of our drilling in 2012 will be less than 5,000 feet deep in the San Andres formation. About 600 locations of the 759 locations, we plan to drill in 2012 to be San Andres wells. So we have about 225,000 acres on the Central Basin Platform, and we're the most active driller with 13 rigs running. And it does have an NAV value of $7.2 billion. There are multiple play objectives in the Central Basin Platform from the Grayburg/San Andres to the Clear Fork to the Penn., but the bulk of the drilling is in the San Andres play. And today, we are the fifth most active operator on the platform in terms of well count. And you see we're in league with some -- with a pretty good company there. The Central Basin Platform, we have 6 of the major producing fields on the platform, and that has been a very, very good area for SandRidge as far as growing oil production.
The Permian. We look at the Permian as a area of steady growth. Of course, we have some tremendous growth when we acquired Forest and we acquired Arena, but since -- again, since about July 2010, we've grown production from about 25,000 barrels equivalent to about 32,000 barrels equivalent. One of the things we talked about in the Permian Basin was some infrastructure work back in our November call, and these were 28 pressure reduction projects that we're working on. We completed 11 of those before the end of the year. We should complete about another dozen here by the end of this quarter and finish out that project by the end of the second quarter. So everything's going as well as planned there, and we should continue to see production ramping up as we drill.
Permian economics remain very robust. Again, these are low cost vertical wells, all 759 wells we have planned in 2012 are vertical wells. About $643,000 per well, finding about 53 -- I'm sorry, 58,000 barrels of oil equivalent, but with most of that is crude oil. PV-10 per well, you're looking at just slightly under $0.75 million and very high working interest. On average, we're looking at 91% working interest.
If you look at the economics on the Permian at $60 oil, you're looking about 20% rate of return. So we do have a lot of room there on oil price. And at the Strip, we're at roughly, I don't know, 70%, 72% rate of return.
The capital plan for 2012. In the Mid-Continent, before the carried interest from Repsol and from Atinum, the Mid-Continent really, we're going to spend about $900 million, and that includes drilling the horizontal producers, and also, the saltwater disposal system. So that is probably 60% of the total E&P budget. The Permian Basin, we're looking at drilling -- spending about $0.5 billion there. And then offshore, $200 million and then all other areas as you see very little.
So you have a total E&P cost of $1.6 billion. That's before workovers and capitalized G&A, but we do have about $300 million worth of drilling period this year with Repsol and with Atinum, so that would reduce the net impact on the Mid-Continent drilling, would be reduced from $755 million to about $455 million. So when you add back in workovers and G&A, our total E&P budget is $1.55 billion. As you remember, the carry on the drilling total combined with the 2 JVs is right at $1 billion, and we look for that carry to run out in about 3 years. So it is a very aggressive carry program.
With that, I'll now turn it over to Rodney and Todd to go over the technical presentation. Thank you.
Todd N. Tipton
Good morning. Tom talked about 2011 being a pretty critical year. Well, just, our time frame's a little different. We look at this play, what we have done in just the 4 years that we've been working on the Miss., we look at the de-risked -- we've de-risked the original Mississippian area, which is Northern Oklahoma and southern portion of Kansas. As Tom had mentioned, over 500 wells have been drilled there. SandRidge has drilled 250 of those wells, 51 rigs running in the play today.
We've also, in that time frame, moved into Northwest Kansas, extended that resource potential an area that 17 million acres and we're looking at the same type of geology, the same source, the same depositional environment, the same thickness of Mississippian. In fact, as we move into Northwest Kansas, we even have a better reservoir, we feel, than what we had found in Oklahoma.
So 2011, pretty critical year, but for geologists, actually, it was 325 million years ago. So if you look at that area and what is now Oklahoma and Northwest Kansas, it was at that time, shallow, marine setting, great place for that carbonate deposition, not only the limestones, the dolomites and the chert. So that mix lithology that we see deposited over a very large area in what is now Central Oklahoma and Northern Oklahoma and Northwest Kansas.
I'm going to spend a few moments -- usually, I have pointers and I can stand up and wave my hands. So I have to -- it is a little more difficult to do it this way. But this schematic, this illustration, pretty key. And actually, Tom did a very good job describing this without having this illustration in front of him this morning. Geologically, it's almost the perfect storm. The lower part of the Pennsylvanian section, as we go through this illustration, the northern part -- the upper portion, the Pennsylvanian section, is overlain with shales, so it forms an excellent seal over a very large area. Then immediately below that is the Mississippian Unconformity, and we have upwards to 300 to 500 foot thick Mississippian section. Now we target that upper portion of the Mississippian, the best porosity, the best permeability is developed just beneath the Mississippian Unconformity. So that target zone, and you can see it on this illustration, the horizontal wells that we drill in that section targets those porosities just beneath the Unconformity. But we do have overall Mississippian section, as I said, 300 to 500-feet thick. Just below that is our source rock for the area, that's the Woodford Shale. The Woodford Shale underlays that entire area shown on the previous slide. It has -- it's a very rich source rock. In fact, some companies are even looking at that as a reservoir today. But for us, it's pretty key in that source rock, the Anadarko, deep Anadarko basin, was the kitchen that created the oil and gas that we see migrated as far as 350 miles away. We have typed that oil all the way up into Northwest Kansas, and the oil that's being produced in the Northwest Kansas from the Mississippian section is Woodford age oil.
So -- and then just 1500 feet below the Mississippian target is the Arbuckle formation. That is our saltwater disposal. You heard this morning and we'll hear a lot more about the importance of being able to handle the saltwater that's produced with the oil out of the Mississippian. And we happen to have an aquifer in the Arbuckle that is anywhere from 1,000 to 1,500 feet thick. It's a porous dolomite. It will handle all the saltwater that we can put into that formation and generally takes it on a vacuum.
So again, a perfect setting geologically with excellent seal; a stratigraphic trap that covers hundreds of miles; excellent reservoir, especially in the upper portion on any of the benches that we see within the Mississippian; good source rock through the area; and then a great aquifer to put away all the saltwater that we could produce.
We think of that area, that illustration, all the vertical wells drilled, the 15,000 vertical wells drilled, all you're looking at an area the size of a dinner plate as it drills through that Mississipian formation, and often, just produce from the very top of that Mississippian. So you look at its compartmentalization, you have that mixed lithology, carbonate lithologies through that Mississipian section, and if there's a way to access more of those compartments and more of those lithologies, is by drilling your horizontal wells. So this compartmentalization of the Mississippian section is really advantaged with the advent of horizontal drilling. This example is from Northwest Oklahoma, it was work done by the Kansas Geological Survey and putting the story or history of the Mississippian together.
Matt and Tom showed this slide earlier. They usually do a very good job explaining the play. Tom had mentioned, you can see the Central Kansas Uplift. As you move to the south and you move to the west, you're adding more and more section of the Mississipian, a younger section. As it erodes down, you're able to see various benches within the Mississippian. The key, though, is that anywhere in that area, we proved it in the Original Miss. to the south, and we're seeing it with wells that we're drilling in the vertical sense as we move up into Northwest Kansas, is you're able to see the porosity, again, developed right below the Unconformity. So irrespective of which bench geologically you are in, which age bench of the Mississippian you are in, you are able to see the best porosity and permeability developed just below the Unconformity, 50 to 75 feet below the Unconformity. Reiterate, the 14,700 vertical wells drilled, that's within the blue outline. That total map sheet, we're looking at 30,000 Mississippian vertical wells drilled over that entire map area. So an awful lot of data, very good data available, especially in Kansas, with DST information, core information, from all of those wells drilled that gives us an excellent database. And then our 500 horizontal wells gives us a opportunity to look at that in the southern portion, but utilize all that work, all that information as we moved up into Northwest Kansas and why we're so excited about that extension of the play.
This cross-section runs through the entire -- from Northwest Kansas down to Oklahoma and then takes a turn and heads down to the deep Anadarko. The blue is the Mississippian section, and the key from this map, 2 key things: one, it's structurally very, very benign. It's 0.5 degree of dip, you don't run into any problems as you drill in that porosity zone, just underneath the Unconformity. So structure does not play into this at all, its, again, a stratigraphic trap that covers this entire area. And then there's an ice pack map or thickness map over on the right-hand side, with the area that we're -- the total Mississippian area highlighted. And you can see that the play that we're making is anywhere from 200 to 700 foot thick total Mississippian section.
Little bit of history. This is our original Mississippian play area. This is the current day, this is the acreage position that we currently have. It shows not only the SandRidge horizontal wells that have been drilled, it also shows the control, the vertical well control in green and the industry horizontal wells that have been drilled in blue. I'll show you this, this is a snapshot today. But what I want to do now is give you a little bit of the history of SandRidge's activity in the original Miss. play and how does that help us to move into Northwest Kansas.
Okay. So this is the play area, that 6.5 million acres within that purple outline. We go back to -- from the 1970s through the 1980s, the southern portion of that map area, that is the Sooner Trend. That was very developed, very closed-based wells drilling the Mississippian section. The Mississippian section in that area is upwards to 1,000 feet thick, and they would play all the porosity zones that you see within the Mississippian. The issue here is off -- if it got into any water, they would concentrate, try to stay away from the water and concentrate on those porous zones, but they will open a fairly large section. But also, you look at the price of oil at that time, as you moved up to the north, you do see a number of vertical wells that were drilled there, up on the shelf, on the Anadarko Shelf. Those typically targeted small structures. Again, with the premise for the vertical drilling, you had to stay in the upper portion, with your higher oil cuts, better porosity and staying away from water. So -- but an awful lot of development in the 70 -- '70s, '80s and '90s in the Sooner Trend.
So back in 2007, SandRidge participated in horizontal well in Woods County. This was our first entrée. This is the acreage position that we had at that time. Most of the acreage we had was for Mississippian, but vertical Mississippian. And then in the southern area, primarily for gas. So our acreage position at that time, 2007, we test that first horizontal well in the Mississippian, it's pretty good well. As we move ahead to 2009, 2010, where we moved now to the West, and that oval shows now our activity at the end of 2010. We've drilled a number of wells in northern part of Alfalfa County. We've tested a few over in Grant. We're looking at adding that additional acreage. We are now -- we're having the same success in Alfalfa, actually, even better wells horizontal wells in Alfalfa than we had in the original area over in Woods. And we added more and more acreage and began to expand that play. So that's our position at the end of 2010.
So now 2011, Tom also mentioned, a pretty critical year in our development of the play. We've now expanded out to the East, to Grant County all the way out on the East side as far as Noble County, all the way up into Comanche County in Kansas, a number of wells there. That area from Northern Comanche County all the way down to Noble County is 125 miles. You can see our acreage position. We've added a lot more acreage, drilled wells all across that area in the horizontal sense. We've, at that same time, developed our geological model, our reservoir model for the Mississippian, looking at the various benches, geologically, as it plays into that entire area. And you could see a lot of development in Alfalfa County, and again, it all relates back to developing your saltwater infrastructure. So that's why it was such a density of horizontal wells because of the infrastructure we've been able to put into place. While we see that same infrastructure being developed in all of these other areas, the ovals that you see here, as we expand that play. This has a little bit of history to where we are in the original Miss., but also, key as we move up into Northwest Kansas or the Extension area. We look up at Comanche County, those were wells that were drilled in the middle of last year. Our first well, excellent well, the same type of horizontal production and potential that we saw all the way down across the play, but all the way up into that portion of Kansas. So the work we've done, all that data, all that history, understanding the play, first mover in this area to understand the Mississippian. This is the geologic mapping that we've done on the various benches of the Mississippian. To be able to have the understanding, this nomenclature is something that SandRidge had developed, at least down in Oklahoma, and then be able to tie all of that work, that same oval that you see in Oklahoma, looks at those various benches, looks at the reservoirs, and we're able to tie that all the way up, that total map sheet from the southern -- southeast portion all the way up to Northwest Kansas, that's 350 miles. So critical for us to understand the play, map it geologically, look at the benches, look at the carbonate reservoirs in each of those benches and see that what we had found and what we had discovered in Oklahoma is exactly the same as we move up into the Extension area in Kansas. And as we said, all the way up to the Northwest part of Thomas County, where we see the same oil, Woodford oil, in the Mississippian, about 350 miles north. Same reservoir, same rocks, it's a little bit shallower, a little bit cheaper. In fact, the reservoir, in some of the studies, the DST work and core work that we have that Rodney will discuss in a few moments, actually, the reservoir seems to get better even as we move to the Northwest. So the real linchpin to moving into that area was our work in Comanche County, the wells we had drilled in Comanche County, which is, as I move to the next slide -- we come back to this one. We -- again, that zooms into the area that we had developed, shows our acreage position, and the 232 SandRidge wells. And up in that northwest portion of that oval, that is -- those are the wells that we drilled in Comanche County. So that helped us to step into the Northwest Kansas area. As we move up into that area, we have 7500 vertical wells drilled in that area, helped us to put that historical perspective together as far as production out of that Mississippian zone. And so our plans then for next year, as we have over 1 million acres growth up in that northwest portion or Extension area, we look at it now as the total Mississippian play, and our plan to drill our first well in April and 5 rigs through the balance of 2012, and we forecast to drill 50 wells in the extension area in 2012.
I'll bring up Rodney to discuss a little bit more of the play and the excitement that we have to move in the Extension area.
Rodney E. Johnson
I've tried to joke that I'm a reservoir engineer and you probably wouldn't think it is funny, so I'll just try and stick to the data. The first slide, really, as we look at the Miss. as a play for just -- for SandRidge -- tough start. Tom's back there just "aaah." Really, when we look at the play, there's a lot of excellent oil plays across the U.S. There's a lot of in-place oil still left in the ground and a lot of places that you can go and try and find reserves. The unique thing about this play in particular is that it's shallow, it's carbonate, and it has a lot of vertical history with it. So the uniqueness of this play is we think it has less risk than some of the other plays in the U.S., and then the second thing, it's even harder to put together an acreage position in some of these plays. A lot of these plays s are held by production or they're very expensive for an entrance. And when you think about what we've been able to do in the last 2 or 3 years, we've put together a 2 million-acre play with $400 million, and that's amazing for an entrance cost into a resource play, that we think you'll hear a lot more about in the future.
One of the things we'd like to spend a little bit of time today, Todd went through a lot of the geological history and talked to you about some of the concepts and what we've studied across the play. I'm going to take a few minutes just to kind of take you through a simplistic model of the play. And forgive me for the simplicity of it. But if you remember back to that slide Todd showed you, the original part of the play in the Miss. was in the Sooner Trend. And that Sooner Trend was say 500 to 1,000 feet thick. But as a carbonate reservoir system, it's broken into compartments, as Todd was talking about. And one of the, call it, misnomers about the play is these compartments are isolated cases of oil, gas and water mixtures. So when you hear people talking about up on structure or not on structure, really what we're talking about -- let's see if I can use this simplistic model. Think about a 500 to 1,000 foot thick reservoir and think about 100-storey building with each 10-foot interval as a compartment. And when you think about that, each of those floors in that 100-storey building can have a different mix of oil, gas and water. And as they started in the Sooner Trend with this nice, thick robust package of 500 to 1,000 foot thick, what they were able to do is look down -- up and down that interval and cherry pick where they wanted to perforate and produce. So 30, 40 years ago, what they were searching for was 100% oil, and so they've looked up and down that package and with 500 to 1,000 feet of thickness, they were able to isolate the better reservoir qualities and produce that. Now as I move north out of that -- and another thing to keep in mind is when you look at that Sooner Trend, you're not going to see isolated cases of drilling, what you're going to see is a bulk of drilling across the entire play.
Back to the original concept, they weren't drilling structures. They drilled that as a bulk play and they were looking for that 1,000 feet and then isolating somewhere up and down that interval, looking for the best oil saturations. As they move north out of the Sooner Trend, the pay thickness got less. So you went from 1,000 feet of thickness to maybe 300 to 400 feet of thickness. So less chance to isolate and cherry pick that interval. And then also, what happened was the oil saturations in general got a little bit less. So what happened is they start to perforate some of those intervals, they get water and then walk away. Then the next logical choice was to move around structures, and we're using structures in a very benign sense. Really, what we're talking about are 10 to 20 feet of relief in a 300-foot interval. So maybe they moved up 10 feet, they get a little bit better oil saturation, and generally, what they did is they perforated that top interval because as Todd talked about, that top interval is where the best reservoir quality rock is. And it has to do with the Unconformity, so what they do is they perforate that top interval, looking for the best oil saturation, and in any given compartment across that region, they could get a good result or a not-so-good result. And as we studied the play, what we really saw was it wasn't really related to the structure as it was related to the compartments and that differences in oil and gas and water saturations through this compartments. Long story short, it makes a great horizontal play. If you're able to then go horizontal in that play, what you were doing with 1,000 foot of vertical interval, you're now doing with 4,000 foot of lateral interval. And you're not only doing it with a 4,000-foot lateral, but you're also connecting up all of that different compartmentalization, and what we're seeing is you're getting a varying -- we're going to show you some statistics in the after -- in the second session on histogram of the statistics, and what we see as variability, but overall, the economics are excellent by being able to go horizontally in that interval.
So it gives you just a little bit of background on the kind of the reservoir model that we're talking about. And then the second thing is you have to be willing to deal with the water, okay. Because of the less oil saturation in that entire interval as we move north, you have to be willing to deal with the water, and what Dave's going to spend a lot of time talking about is how we have built the systems to cheaply dispose of that water and deal with that water system. So the concept is fairly easy, but we want to distinguish what we're doing from a reservoir modeling perspective from trying to chase structures or do any of that. We are definitely not chasing structures. We are not chasing even good vertical performance, because classically, what you see in a vertical performance -- and we'll show you plenty of examples here in a minute, what you'd classically see on a vertical performance is not indicative of what you'll get from the lateral performance. Because of the compartmentalization and the ability to go horizontally, we're seeing much better performance horizontally. We've offset literally dry holes, dry holes from DSTs, dry holes from production, and found some of the best horizontal wells. And that has to do with the compartmentalization and ability to go horizontal and connect up that reservoir system.
We're going to show you a little bit of data. I think we've shown this one before. This is our original study of the vertical performance, and what we're really using the vertical performance to do is to give us an idea of the producibility of the reservoir. What we've found is the statistics around the vertical performance is indicative, in general, across the region. But as we said, what Todd's been able to do in his group, is they'd mapped this across a very large region, and then we've seen vertical performance across a large region. And I think we showed this to you last time, we're just giving you a refresher course. But generally, when you average out all of this production, particularly across Woods, Alfalfa and Grant, where we've done most the horizontal drilling, you get about 66,000 barrels equivalent oil production. And we're going to use that as relative reference as we talk about the new area up to the northwest.
And then you also have varying degrees of gas performance across the region. And the other thing I will say as we've connected up these compartments horizontally, we're seeing variations in gas/oil ratio from well to well, but generally, it's coming right back to the type curve expected outcome. And that has to do with statistically averaging in a very large data sampling set and then going out and drilling horizontally in that same area, and we'll talk a little bit about that as we go forward.
Now, if you move into the Northwest Kansas part of the region, what you're going to see is the same geological environment, the same structural environment. There are only a couple of key differences we'd like to get across is it's a little bit shallower, okay, so it's about 1,000 feet shallower than what we saw in the original area, and what that translates into is less cost. And I'll hit a couple other economic criteria here. The other economic criteria that you see that dramatically helps this part of the play is because it hasn't been actively explored horizontally, we were able to go out there and across a very large area, we were able to go out there and take leases at 85% net royalty. So we're up about 5% in royalty across this region, and those 2 components, about 10% less expected drilling cost and the 85% NRI, dramatically helps the economic expected outcome for this area. Besides that, what we saw -- and we'll spend a little bit of time for here in a minute, is we're going to tell you -- show you some information on reservoir quality and also performance, and we believe they go hand-in-hand. And what you're really looking at here is if you go through all of this data, you're going to see that numbers of Ness, 94,000 barrels; Hodgeman, 102; Gray, 67, average. And we're talking hundreds of wells, thousands of wells up here. 87,000 in Finney; Haskell, 59. You go across this whole region, Kiowa, 130. Even moving as far north up in the Gove County of almost 60,000 barrels for 200 wells. So when you look at this, what you're seeing is a better overall average vertical performance from the reservoir. And we believe that will translate into better horizontal performance on average as we move into this region. Now one of the things you are going to notice is as you move out of Ford and Edwards and start to move farther north, you're going to notice that Hodgeman and Ness and some of the counties to the far north aren't reporting gas. And one of the things, one of the unknowns that we spent a lot of time researching is this question about the gas as you move farther north. What we found, really, talking to operators and researching a little bit and another thing Todd mentioned is the DST information. One of the things about Kansas that they did as small operators is they use DST information as an exploratory tool. So there were literally thousands of DSTs across this whole region, but the interesting thing -- and when you study the DST information, I'll show you here in a minute, when you study and look at that DST information, you're going to find that there's gas, oil reported across this whole region, recoveries of gas. And so we were left with a question of well, why in the world isn't there reported gas production? And as we researched it, we talked to operators, there is a significant amount. We don't know the quantity of flared invented gas as you move north. And the other interesting thing is while you have major pipelines across this region, what you don't have is gathering infrastructure. As you move out of the -- and I'm a little hamstrung as Todd is without the pointer concept, but as you move out of Stephens' and Stewart County to the Southwest, that's where Hugoton is. Significant gas infrastructure exists down in that region, so you move up into Finney, towards Gray, there's remnants of gas infrastructure. But the further you move north, there's literally no gas-gathering infrastructure that exist. So we don't know, and the other thing you have to keep in mind is Kansas is a different operating environment. It's mom-and-pop operators who literally were out here drilling 5 wells a year, 6 wells a year. And we're going for high oil saturations, and they would literally -- and when you review the DST's information here in a minute, you're going to find that if they found any hint of water, they did not want to deal with setting up disposal systems, disposal wells, they would walk away. So literally, you'd have hundreds of feet of oil recovery in the DST information. If they showed any water, they classically would walk away.
So what we have is a different environment. And when you think about gas infrastructure, those aren't the kind of guys that are going to invest heavily in building gas infrastructure 20 years ago to get modest recovery on gas. So we still believe that there will be gas recovered from this region. But as you move north, there is a lack of known gas reported.
Now on the oil side -- which, keep in mind, oil drives are economics. And the oil recovery has been excellent. If you look at the 3-county area where we drilled the most horizontal wells, Woods, Alfalfa and Grant, there's 1,400 wells that have an average oil recovery of 66,000 barrels vertically. As you move into northwest Kansas, that 14-county area I just showed you, has an average of 4,000 wells and a recovery of 86,000 barrels. That's roughly a 30% better oil recovery vertically than we saw in the original area where we've got our 456,000 barrel equivalent type curve.
What we did is we ran sensitivities, what ifs on oil recovery, et cetera, and particularly, what we looked at is a 10% up oil recovery. It would say what if we get half the gas as we move into that region. And effectively, with 10% less cost, a better royalty, a 10% up in oil recovery and half the gas, our rate of return outcome on a sensitivity analysis is actually better for that region than the original area that we're getting the 91% rate of return on. So conceptionally, what we see is the opportunity is that the northwest extension area could actually end up better economically advantaged than what we're drilling today. So we're very excited to move into that region.
We also did a sensitivity analysis of what happens if you don't get gas, what if you get modest gas or 0 gas. And our 91% rate of return drops to 80% rate of return. The gas -- in today's gas environment, the gas does not drive the economics of this play. So that's another thing to keep in mind as you look at this play.
Told you I was going to tell you a little about reservoir quality. When you look at this area and you compare it, and we've given you some offset wells -- again, it's hard to point from this direction. If you look at the core from well A and well B, those are 2 of the wells in the -- call it, the centralized location of our horizontal drilling today. And by the way, some of those wells were offset dry holes in the very same sections.
We've got well A -- if you look at the porosity and perm region that it's in, it's generally -- we call it good rock today when you compare it against some of the other plays in U.S. But generally, it's what we historically would have called tight rock. It's a 2% to 4% porosity cross plotted, and it's 0.1 to 0.01 millidarcys. It's not nanodarcys, but it's still pretty low on the millidarcy range. Now keep in mind, that's the core recovery that we saw out of 2 wells, directly offsetting 2 wells horizontally that have come in extremely well. So 749,000 barrel equivalent offset and 1 million-barrel equivalent horizontal offset that we just drilled.
So that's where the reservoir quality for the 2 cores we have taken to date comes, offsetting our horizontal drilling. But then as you move into northwest Kansas, which you're going to see, is they're -- all of those colored dots in the center of the page, those were taken by the Kansas Geological Society when they were actually studying horizontal drilling in the area -- very active group up there. They were actually, 10, 20 years ago, trying to propose horizontal drilling to the drilling community and get them to do something because they saw, as Todd pointed out, the compartmentalization and ability to come back into this region horizontally and recover additional oil.
So they took all this core data and what they found, if you cross plot that and get a vision for it, the average of that is more like 10% to 12% porosity and maybe a millidarcy of permeability in the center of that location. Then we gave you one more core example out in Finney County with the Maune B#1 well and that cross plots 10-plus millidarcys and 8% -- or a 10% porosity. So we're in the order -- on the order of magnitude, greater in reservoir quality as we move up into this northwest Kansas kind of region from all the data we've been able to collect.
And then -- and we believe that's reflected in the vertical performance. But keep in mind, the models that operators have utilized were the same models that they utilized in the original drilling area. They would try and drill around little structures. They would try and get 100% oil saturations. And they were definitely afraid of any water, and they would stay away from any water.
Now the thing I haven't told you is that when you really study the detail -- the data in detail, you're going to find excellent vertical performers -- performance in both the original area and the northwest expansion area off those structures. They have absolutely nothing to do with structures.
And that -- primarily, that what happened is, just give you an example, an operator goes out there trying to find a structure, they don't find the structure but they run a DST information. And what they end up with is they end up with high oil saturations, no evidence of water so they go ahead and actually complete the well. When they complete the well, they get an excellent response. So those are the examples that we find in both areas that you do not have to be on structure to even find high oil saturations, but you'd have to be willing to explore that methodology.
The next slide takes you through a little bit of the DST information that we've collected. We've given you -- trust me, we've given you like 5 examples here but there are literally thousands of DSTs taken across northwest Kansas and recorded as part of the Kansas Geological Society.
Interestingly enough, we've given you a couple examples to the southeast in the Original Miss area where you see recoveries of 30 to 98 feet of slightly gas cut mud tested and plugged. That's in a section where we drilled a 1.9 million barrel horizontal offset. So that's the kind of DST information to the south.
And then to the southwest there a little bit, you'll see the DST information recovered 600 feet of oil and gas cut mud in the pipe, yet dry holes, so they walked away from it. We offset that with 1 million barrel horizontal well.
As you start to move north, what you're going to find is excellent DST information, 310 feet of oil, 62 feet of gas cut oil and they walked away from it, dry hole. And that's one of the areas where one of the original wells drilled in the 1990s horizontally was drilled, and they recovered 122,000 barrels of oil out of horizontal well.
And then you move all the way to the far north, and you're going to still see 400 feet of very gassy oil, 124 feet of gas cut oil and 240 feet of oil and gas cut water. Guess what? They walked away from it.
So you these examples -- and we're just giving you 3 or 4 examples to kind of show you the kind of data that we've looked at. We've looked at literally thousands of this data up here in this region to get an idea of what happened.
The other interesting thing as we moved in to try and study northwest Kansas is that in the 1990s, the Kansas Geological Society did all this extensive reservoir work characterization and geological work to try and convince the producing community to actually go out and drill horizontal wells. They actually -- it's interesting, they had to go to Canada to get a Canadian group to come down and drill those wells. The Kansas operators weren't that interested, as best we can tell by looking at the history, to go drill horizontally. They were primarily small shops drilling vertical wells, trying to go for a high oil saturations. They had no interest in expensive horizontal technology or the possibilities of getting water.
Now they drilled -- 8 of those were drilled in the 1990s, 2 were more recent in age in the -- like the last 10 years. We've given you the location of those identified in blue on the map. And generally, what we found was they were mostly all-drilled, short-lateral average lengths of less than 2,000 feet, open-hole completions and no fracture stimulation. And still out of that group, 4 out of the 10 still cum'd about 100,000 barrels each.
So if you think about it, what we're doing today versus what they tried and what they were really trying to do conceptionally was a little different, too. They were trying to go back into these old fields and drill interior to these oil fields, up on structure, on these modest structures and find undepleted compartments. And really, what it did is confirmed the fact that you can drill very tight spacing. Several of these wells, they drilled interior to 40-acre or 20-acre wells and got these 100,000 barrel outcomes.
So conceptionally, they drilled around existing production with high oil cuts to produce undepleted compartments, and were very successful at it, but it never caught wind with the Kansas operators. And now we've come back in with the concept of actually going in and regardless of the water production drilling, 4,000-foot laterals, cementing liners and frac-ing these wells and connecting up a lot more of that contact area.
The next slide, we just you what's happening in the original area since we last talked. There was -- we were one of the lone voices talking about the Mississippian. There's a lot of activity that's gone on in the last year. Shell has entered the play. Chesapeake has moved in with more rigs and are ramping up now as we speak. Range has talked a lot about the play. You see Devon coming in from the south, and then we have a whole myriad of small operators that are entering the play.
I will say, when you think about the play conceptionally and -- David's is going to spend some time talking about this. When you think about the play, we've got about 50% of the wells that are producing, about 50% of the rigs running in the play. And we're the only operator that has the extensive saltwater disposal infrastructure that allows the play to have the robust economics that we see moving into the future, at least to this date.
One of the things I will say, interesting about what's going on right now is we talked a little bit about spacing, and we've talked about 3 wells per section or 4 wells per section, seems to be kind of out there in the industry of discussion for spacing. Right now, what we've done is we've drilled 38 pairs of wells -- and see if I can explain this without diagrams and charts. I usually have a better ability. We haven't really done 3 wells in any 1 given section. But since we were drilling out here and setting up the sections for future horizontal drilling on tight spacing, we drilled our first well up against the lease line on one side, and we drilled wells up against the lease line on the other side. And we set our patterns up such that we could drill 4 wells per section, if we decide to. And with that in mind, you have to drill your first 2 wells close to the lease line that would allow you to drill 4 wells in the section.
So effectively, what you end up with is we've got 38 pairs of wells that have been drilled within 160 acres of each other. And as part of our year-end process, we studied those 38 pairs of wells with our consultant, either us or our consultants, on any impact or any interference in those wells' performance. So our initial understanding is we've got 38 wells that have been drilled to date that show no impact from interference on 160-acre spacing, which will be 4 wells per section. But as you note in all of our data, we're still only counting 3 wells per section in our NAV runs, et cetera. So we still see a lot of opportunity to increase that NAV value in that reserve booking potential, up substantially from where we are today.
With that said, Chesapeake has announced that they -- well, announced that permitted approximately 7 to 9 sections, and it permitted 4 wells per section in those 7 to 9 sections. We're interested to see -- right now, it's not a top priority for us to study that. We're out holding our acreage position and do things we need to do business-wise, but it is interesting to watch in the next year. We're going to be very interested to see how those 4 wells per section come out, and I think we'll get data on 7 of those 9 sections, if they truly do drill it. So partners are looking at drilling the 4 wells per section, and it is a significant upside to us if that works out.
And with that, I will turn it over to David.
David C. Lawler
All right. Thank you, Rodney, and good morning, everyone. I'm Dave Lawler. I'm the EVP of Operations. And for my part of the presentation today, I'll be going through the 2012 program.
Before I dive into the metrics themselves, wanted to spend a little bit of time about -- with you on what we're looking at and ways we can lower costs and increase returns. So as Rodney has talked about, we have a type curve that's fairly established. So at this point, it's incumbent upon us to see how we can take our operation to the next level.
And one thing that the company has done exceptionally well is the planning process for this. Let's think about using some technical jargon, but I'll just go ahead and walk you through it. But the essence of the way that we've looked at this project is much like a megastructure or like a large dam project. We have something called front-end engineering. And part of that front-end engineering process is where you stand back from the problem or the project and you look at what could be the major problems, how can we solve these in advance. That process was alive and well at SandRidge 3 years ago as we started migrating into this play, and what you'll see is some pretty phenomenal results about how this process works. So again, it's called front-end engineering, and we'll talk about it a little bit more as we go through the presentation today.
The next piece that we're looking at, obviously, is we have to keep up with our critical infrastructure. So many of the plays in the U.S. today do not have the adequate infrastructure systems in place. That isn't really the case here in the Miss. We're ready to go. We've kept up with gas export, oil export, and of course, saltwater disposal.
And then the other thing that we're looking at is just how do we implement best practices and the latest technology, how can we make those things that perhaps even the industry has perfected work for us in the Mississippian.
And in any time you look at a multibillion-dollar project, you want to have the best companies in the service industry working with you. And we have secured 3 or 4 of those companies to join us, and these are world-class companies that can help us take our operation to the next level. So when we think about our themes to lower cost and what we're trying to do to increase returns, these are kind of the 4 strategic themes that we're working on. And hopefully, it will be reflected in our presentation today.
Okay, so just by the numbers. The Miss play itself, we're looking at 380 wells gross. And 330 of those wells are in the gray area. That's what we'd call the Original Mississippian. And about 50 wells are going to be the -- in the extension area in northwestern Kansas. Now from this point forward, we'll probably be talking about the play as one grouping, so you probably won't see a whole lot more detail about the original and the extension. But again, 380 wells across the vast acreage position.
Now the $3.2 million, that's the drill complete and also the portion of the saltwater line that we need or produced water line to each wellbore. That's the number in terms of the development and the operation that we're focusing on to try to get down, obviously, as low as possible.
High level, we've got 21 rigs working in the play today. At the end of this week, we'll have 22, and we hope to exit the year at 32. A couple of people have asked me, do you have the rigs secured? We've got 30 of the rigs already under contract, so they'll arrive throughout the year. So there's no real risk to not reaching that 32-rig program by the end of '12. In terms of total CapEx with the carry, we plan to spend $457 million in the play.
On the produced water disposal piece, and this is what we keep of kind alluding to in some of the context of our presentation today. We plan to drill about 57 gross wells, and that'll be about 105 -- or $135 million in net CapEx. And again, this is a front-loaded system that we think will actually enable the play to be highly successful, and it'll actually have a cumulative value effect. And again, it gets back to that front-end engineering that we think will be apparent as we proceed.
Okay, so this is what the typical system looks like. It's high-capacity design. So again, we've got significant volume of water moving through the system, and it's multidirectional flow. So as you can see, the blue lines represent our SWD system. And depending on if we have a problem at a particular SWD, we can redirect the entire network to the SWDs that happen to be online. What makes this nice is as we continue to drill along those lines, then we have direct access to the system. So if you'll note, the squares that are green is our acreage position where we drilled horizontal wells.
You can see there's a significant number of sections that -- or along there that's more of the peach color, where we have wells planned in the future. So you can envision the synergy that's going to take place once we're able to line up a rig program and then just consistently walk through the development of these wells. At the end of this year, we expect to have 108 produced water or produced water disposal wells online and part of this vast system.
So if you think about this in terms of our competitive position -- and you have to drill enough wells that you actually reach the statistical mean so that you do realize that type curve performance, but then you also have to have an infrastructure that can support the water that's produced. So just as an example, if you do not have this system, you're probably paying about $2 per barrel to truck water. So you see a significant NPV impact if this SWD system isn't in place. So it isn't like you can go out and drill 5, 6, 7 wells and make those work for you efficiently. And again, we're adding about 4 wells per month and about 20 miles of pipeline per month.
Okay. Now where this system really starts to become beneficial, again, is as you get closer and you start drilling the higher-density programs. So one system that we've been using is this produced water frac tank. It's a mobile system. And we started using it this fall, and we frac-ed 27 wells to date. Now if you can think back to the earlier slide, we have this massive trunk system, and you bring in this portable tank and you set it down on that trunk system that's carrying to produce water. So instead of having significant number of 400 barrel frac tanks on location, you now have this massive swimming pool-like object that you're doing the frac operations out of.
And what's interesting about this, we did a 7-well test using this tank system and we saved about $408,000 or about $58,000 per well. And so the way this works is you rollout the hose from this tank, similar to a firehose, you go directly to your frac pad and you conduct the operations. Tanks hold anywhere from 20,000 to 45,000 barrels, and so you have this significant volume of water that's there for your utilization.
Now the way that this saves you money is, as you know, fresh water sources are hot topic across the United States. We're moving so much water right down near the drilling location that we can fill this up so we have no fresh water source cost. We don't have transportation. We don't have pit construction, and we don't have water transfer. So if you follow the industry for a while, you know that water transfer companies carry a very high premium, and we found something very interesting. Once we've started using this, the cost for the water transfer dropped almost immediately. So when you bring in the competition, suddenly water transfer is now very close to what this tank system provides. So what we've seen is the benefit of competition in the area. But also just a more efficient operation.
One of the thing that's a positive here, since it is produced water, it's about 80 degrees. And so you don't have to have a lot of cost, expenditure, heating the water, avoiding freezing in the winter months. So what I wouldn't want you to do is plug in the savings of $58,000 for every well. The key here is that you have to be within the network. But as we continue to grow, I think you can imagine that the system is so large there'll be a significant number of these tanks along the line. So on a good percentage of our wells, we think that this will be a key savings for us. And again, it gets back to that front-end engineering and how do you continue to leverage your system to your benefit.
Okay, moving on to the gas-gathering piece. As Rodney had mentioned, this area, historically, has had a lot of gas production. We deal primarily with Atlas. Atlas lays the line to each location, and we typically can flow gas from the well right after our completion operations. So there's no real delay or problem getting our gas to market. Atlas has a gas-processing facility in Waynoka, Oklahoma. It's capacity is around 250 million a day. They're in the process of expanding that by another 200 million, and so that'll be in operation in Q3 of this year. So again, we continue to maintain and stay just ahead of our pace and our needs for natural gas.
We got this map that we have here, kind of shows how the trunk system works. So we typically have a 4-inch line out to the individual wells and then it emerges with an 8-inch system and then to a 12-inch trunk line. So again, the infrastructure's in place. It is a positive that Atlas is moving forward with the additional capacity though, because we are starting to bump up against their limits.
In terms of oil gathering, most of the oil in this area is gathered with trucks. But we have had a couple of positive things happening here just recently. We just signed a 10-year purchasing contract with Plains Marketing, which is effective March 1. And they've converted a 6-inch NGL line to crude oil-only service, and that's the red line that you see there in the center of the chart. This will provide an additional 13,000 barrels of oil a day of takeaway capacity. It goes directly to Cushing. And then later in the year, we will secure another 17,000 barrels of capacity, which gives us a total export of around 30,000 barrels per day. Both of those lines will end up at Cushing, and you see the system there highlighted with the green dash.
Okay. So that addresses our capacity, our front-end engineering, but then it's also incumbent upon us to increase our performance day to day. And so what we really started looking at since we drilled a fair number of wells, what were the key factors that made us successful on some of the faster wells. So we basically did a study, started at the bit phase, went back through the directional motors, the BHA design and the drill string itself. And we started implementing some industry knowledge that we had gathered that was out there. We made it fit for purpose for us, and so we started improving what kind of motors we used, our bit designs, our bit selections and parameter optimizations.
And to date, we've seen some impressive results, really put a lot of this into motion around the October timeframe. And what we're seeing now, the teams are routinely drilling wells, spud to rig release around, on average, 20 days. So we saw a drop from a consistent average of about 23 days per well to 21 in November of last year and then 19 in December, and then we just registered right at 20 for January. So we think we've taken 3 days off the drilling curve. This is something that we think is going to save us quite a bit going forward. And again, we're continually trying to optimize each and every process in the drilling operation.
Okay. One other thing that's still embryonic, but we have confidence that it will work its way into our system, has to do with our completion program. So our current design is to drill horizontally about 4,500 feet, run a production liner and then cement the liner, and then go through what's called a perf-and-plug cement job. It is 24-hour operation. And when I talked a little bit about the premium contractors that we're working with, we have secured 2 of the largest companies in the world to help us with our fracs, and the operation is moving very, very quickly. We can typically -- we'll be able to easily frac 30 wells a month without a problem, and the system is highly efficient at this point.
But what we're testing and how we think we can improve our cycle times going forward and decrease our well cost is with the system that is out there in the industry, but it's an open-hole packer system. And this is where you don't actually cement the well, but you run the production liner in the hole with open-hole packers that are placed at evenly spaced on the liner itself. And then you have frac sleeves that open, and you frac through the frac sleeves between the packer sets. And so this particular operation can save about $150,000 to $200,000. We conducted our first test, excuse me, in January, and that particular well is flowing above type curve, about 200%. And naturally, there's a fair number of our wells that flow above type curves, so we're not trying to claim any EUR credit here at this point. We're consistent -- or we're thinking that it's probably an EUR-neutral technology. But over time, obviously, that may have an impact on EUR as well.
The key here is there's usually an extra amount of time to prep the hole in terms of reaming, so we're trying to optimize that procedure. But the reason why you save the money primarily is that you can significantly decrease the amount of time that the hole completion spread is on your rig -- or on your well site. So we think that if we can combine a conservative $150,000 per well, plus $50,000 to $100,000 on rig time savings, then we're up around $250,000 savings. And then if we can utilize our tank system, we can get another $50,000. So you can see how we're starting to stack up the savings for the play. Now the thing I do want to warn you about is not to apply that to every single well in the play. But we do think that different portions and different areas will be able to benefit from these programs. So that's kind of the effort that we're trying to put in place.
Moving on to the Central Basin Platform. So as Matt had mentioned, we're drilling 759 wells gross. 600 of those will be in the Fuhrman-Mascho area and 159 wells will be spread out across the rest of the CBP. Most of the wells this year will be focused on the San Andres, the Shell, San Andres and Fuhrman-Mascho. 20% will be Clear Fork, and there will be a few other zones in there as well as we conduct the program. Total expenditure is about $643,000 per well, and we will maintain about a 12-rig average throughout the year, with $479 million total spend.
One challenge that we've had in the Permian -- Fuhrman-Mascho field is a significant producer, has been for many, many years. But with that -- at this point, it's getting a little bit difficult for us to get the wellbore in the exact bottom hole location to honor the spacing for each well. So what we're seeing is that due to roads, existing pads, tanks, electric stations, things like that, we've been having to drill higher number of wells than we would like directionally. That's probably going to be about half. But what that does, it adds about $35,000 in cost to those wells. So we've put in a program to try and offset some of those costs, and so this year will be the first year that we've conducted our directional drilling operations from a central command center.
So the way this would work is a little bit like an air traffic control tower. Instead of having 5 directional drillers, one on each well, we have one central directional location where the surveys are called in and each well is steered with just a single person. To date, we've saved about $6,000 per well or $17,000 (sic) [17%], so it doesn't completely offset that increase but it certainly helps.
And then the other thing that we've done, we've seen some frac companies free up equipment here over the last 6 months or so. We've gone out with an aggressive bidding program and brought in 2 premium service providers to work with us. And as a result of that, we've been able to decrease our frac costs by about 20%. So we're down about -- we're still down a little bit having to drill the wells directionally, but we've been able to capture back about $20,000 or $25,000 just in some programs to keep that program under control. And as Rodney had mentioned, we're still looking at 70% rate of return, so still very strong, robust economic machine working for us in the Permian.
This next slide, Matt had talked a little bit about our debottlenecking project. What we have is about a 28 project -- 28 discrete projects to lower the pressure in the field. So while there's not a lot of gas associated with the field, there is enough that the historical infrastructure is challenged somewhat to keep the pressures down. And even small amounts of pressure will impact the Permian wellbore. So we started the work in September of 2011. We've completed -- or we will complete 20 of 28 projects by the end of Q1. And to date, we've seen about a 500-barrel response from these projects.
So if you look at the chart on the lower left, you can see the impact of really how these projects work. The dash lines shows the decline curve of wells that were online before 2011, okay. So this is not the new well program. These wells were operational and active at the start of 2011. And so as we start to put these projects into effect and lower the pressure in the field, what you see then is a dramatic change in their decline portfolio -- or profile. So what you see at this point, just from these first 4 projects is you see about a 400 barrel per day production gain versus the expected decline. So we -- again, we think this'll be a very profitable project for us and relieve some of the pressure in the field. So these are the kind of things that we're doing each day to stay on top of our business.
It's not a dramatic picture, but what you can see here in the lower right, this isn't just basically a massive header system. So these types of headers you'll see all over the field, and it's hundreds of miles of pipeline collecting the gas off these wellbores so we can then free
flow the oil and bring that oil out with a pump jack. So again, it's a project for us that we think will be very accretive in 2012.
All right. So just to summarize our themes. We still have some critical planning and some front-end engineering to do as we look forward into the northwestern Oklahoma play. But our core assets, so far, is working very well. The company took some early action to set up efficiencies and create value for us going forward. As Tom said, it's kind of the genius of the play, and it certainly is. It's working very well. And then we're also going to stay on target and on pace with our infrastructure needs, and the systems are in place to do that. And we will also be implementing key technologies like the open hole packer system, like the portable tank systems and in best practices, which as you saw, have led to improved drilling performance. We'll also continue to work with our premium service providers. Due to the scale of the project, it is very, very large, and we're working with some of the best companies in the world to help us.
So that finishes up my piece of the development. And at this point, I think we planned on taking a 15-minute break before we started the Reserve Review. So we look forward to seeing you in just a minute.
Rodney E. Johnson
Can I wait for everybody to settle here for just a second? All right. I'll guess we'll go ahead and get started. I won't go through and read all the metrics, increases, et cetera for you. But you can see, we had a very good year: our replacement ratio, our proved reserve replacement, 303%, increases in SEC value, NAV resource value. And we'll spend -- I've had some questions back in the corner on the resource value. We'll spend some time talking about how that's calculated, and we'll go through a little bit of that in detail. And we'll talk just a little bit about where we are in our reserve booking process, what we're seeing in numbers and kind of the look as we looked at it year-end 2011.
2011. One of the things that you'll see as we go through the numbers -- let me just talk a little bit about Permian. Permian was a year of development. So when you look -- when you think about Permian and you think about last year end, primarily what we had at last year end was -- I believe we talked to you here last year about booking our 5-acre infill drilling at -- in the San Andres. So last year end, we booked a considerable amount of reserves to that San Andres program. And this year, we effectively drilled those proven locations. As we look towards the future, we still have a significant amount of 5-acre potential and growth that we can look at in the Permian, and we'll be talking about that in a little bit.
And then as you think about the Miss, we are just now starting to get that, call it, scalability to the Miss program. So this year, we didn't book a substantial amount of extensions. Well, we did book some. You can expect to see, as we drill out in the Miss program, that you'll see movement into the proven category kind as we move forward.
When you think about our booking methodology in the Miss and you think about where the industry is, we're -- I would characterize us as using the more traditional methodology of booking. If you think about our Miss program, classically, we're still using the one direct offset in any given direction for our proven locations. We have not gone to a statistical booking potential on a resource value-based methodology. And in reasonable sense, we're probably -- and we'll talk about b factors. I know everybody gets excited when we talk about b factors. But we'll talk a little bit about b factors and kind of go through some of that analysis.
But reasonably, this year end, we were in the Miss at 1.5 b factor. Last year end, we were at a 1.5 but we showed you a lot of data from the vertical information that suggested 2.5 was the real outcome. We actually saw evidence of the 2 this year. When you think about progression in understanding a play, we're probably another year away from conceptionally proving that concept of a 2 b factor in a proven relationship. And then maybe another year out before you would even think about having enough statistical data to think about a resource kind of PMRS booking potential in the Miss. Until then, we'll continue to use the traditional methodology of one direct offset on the east/west side of a horizontal well. And I know that's different than some of the bookings in some of the other plays.
The other thing, if you noticed, we're showing a proved developed finding cost of $19.66. Here, in a minute, I'm going to show you about 6 different methodologies to calculate the finding cost, and please, feel free to use whichever one you think is more appropriate.
Talk a little bit about our reserve movement through the year. We've given you a waterfall, both on an MMBoe basis and a PV-10 basis. As you can see, generally speaking, we took out the divestiture so that you have a pro forma starting place, 23 million barrels of production and then 37 million barrels of negative revisions. And we have -- we are now using the very strict interpretation of extension versus revision. In other words, we went as far as even behind pipes and existing wells. If they were new to the reserve booking for year end, they go into the extension category. So the revisions are truly revisions to previous estimates or an entity that existed in our reserve reported last year end.
But primarily, that was associated with our Piñon gas field. 29 million barrels of that was associated with the Piñon gas field, and 22 of it was associated with pricing revisions. This is a lot less painful than 2 years ago when we stood before you and talked about gas reserves and gas pricing. I believe we told you at $3.87, I think it was $3.87, we actually wrote off our gas reserves. And we told you, they start coming back on in the $4 range. And then at last year end, when we had prices of $4.38, our gas reserves were primarily back on the books, all of them, again, a little bit of fluctuation.
We're still using the PV-10 rule, not the PV-0. So we aren't allowing our gas reserves to stay on the books if they have $1 of positive revenue. We use the PV-10 rule. They have to make that criteria to stay on the books. And in this particular case, 22 million of our reserves, primarily PUDs, failed the criteria at year end at the $4.8 -- $4.12 mark. I will say, they will continue to be challenged as we look forward to this year as we see it, natural gas prices of where they are.
Good and bad about the new rules, we got the benefit of the 12-year averaging with the new rules this year end, which is $4.12. If you actually go back and do the math, the 12/31 price was actually $3. So had we had to live with -- had the industry had to live with the previous rules, it would've been a very tough year end for a lot of companies.
But when you look at our asset base, the interesting thing when you move to the right column of this is while we wrote off those reserves that had very little impact in value to our company, mainly because they don't have a lot of positive PV value at those price ranges. Our company has now transformed into this oil company, and we're much more driven by oil prices than natural gas prices. And so what you note over on the revision side of the page is while we had 37 million barrels of negative value or negative reserve, we gained $1.9 billion in positive revisions in value. And that's primarily associated with the fact that we went from $75.96 oil prices to $92.71 oil prices. So while you saw this change in reserves, based on the gas reserves in the Piñon Field, they had very little impact on value. And the price movement in oil was the one that gained us all the value on the revision component. Then we had 106 million barrels of extensions and $1.8 billion movement in adding those reserves to our books over value because they are primarily oil reserves as we look at it.
I will say a couple points on the rules. We've moved another year forward. The one advantage we have from doing a couple of royalty trust, and we're now on our third royalty trust, and also just normal bookings is we had an opportunity through comments to kind of get an insight of what the SEC is working on and thinking about. And the interesting thing is while they seem to have opened up the rules for much broader reserve bookings, they are spending a lot of time focused on the 5-year rule, both on how vintage your reserves are and how fast you develop them. And I will tell you, since we did, 2 years ago, have the event with the economics on our gas reserves, we are pretty well vintaged within 2 years on all of our reserves. So we aren't anywhere near the 5-year rule on vintage. And then the second thing is we developed all of our PUD reserves within 3 years using our current budget models. So under both of those rules, we -- our reserves are very clean. The only issue we have, as we look forward to 2012, is just what happens with natural gas prices and what impact it might have on a reserve quantity, not a reserve value component.
If you move to the next slide, we just give you a pie chart showing you the delta -- I mean, the breakout of where our reserves and value are. And that gives you a little bit of idea that while WTO still has a reserve quantity of 103, its value is relatively small in the context of our $6.9 billion SEC run. Mid-Continent continues to grow and will continue to grow as we develop more reserves and expand out. Permian is still a very big piece. So when you look at those 2 components, a large percentage of our reserve value is driven by oil properties now. The other thing we identify in that page for you is 96% of our reserves are third-party engineered, 81% of those by Netherland Sewell and 16% by Lee Keeling. And those are engineered, not audited. So all of our reserves are independently engineered as we look ahead.
The next slide shows you a little bit of every breakouts you can imagine. 33% of our reserves are Mid-Continent. 57% of our value is Permian. And then another interesting move up is we actually have more of our reserves in the proved developed category this year, 56% of our value and 49% of our reserves.
The next slide shows you our movement historically from oil mix in reserve quantity and revenue. 80% -- and I'll let that sink in a little bit because you won't see these slides a lot in today's marketplace. But 80% -- almost 80% of our revenue in our reserve report comes from oil, okay. And that means we're much heavily -- much more heavily weighted towards oil price than natural gas prices as we look forward to the future.
The next slide, we also showed you -- broke out by what we call oil properties or gas properties. What that means is the Miss well is an oil property. And when we drill an oil well, that's a -- a Mississippian would be considered an oil well, but it still has some gas revenue associated with it. And what it shows is that our drilling and by property type, we're 96% weighted towards oil properties. That's a pretty significant slide when we talk about where we are in transition from 3, 4 years ago, where we were primarily drilling natural gas wells to where we're primarily drilling oil wells today. Well, 100% of drilling oil wells.
If you look at the next slide, we gave you all the different types with revisions, excluding revisions. We will say -- I will say, the proved developed finding cost methodology of $19.66 and $24.61, we see that as maybe more insight into what you're really finding with the drill bit. The interesting thing about the other finding cost methodologies is depending upon how companies book a wave of PUD reserves into the reserve books, you can get a skewing of what you're really finding with your drill bit. This is really -- the proved developed finding cost is really the conversion of reserves into the proved developed category, and it gives you an insight into how much money you spent and what you actually got for it.
And interestingly enough, the other comment we've seen recently from the SEC is a tendency to have more disclosure around this specific item, which is how much money did you spend developing proven developed reserves and where are your revisions and how much revision did you see into the proved developed category. So we've given you -- really, $19.66 is a very respectable number for drilling oil properties especially.
The next slide, we show -- as we mentioned before, when you look at our 10-K, all of our reserves are consolidated and include the trust values. So we do a consolidated report and report that in our 10-K. You will see a note, at the bottom -- on our 10-K for our reserves that identifies there are trust ownerships in those numbers. What we've broken out here for you is the third-party ownership value of those trusts. So what we don't own of those trust, third-party ownership is 26 million barrels and $935 million. And this breaks out what that value would be, 444 million barrels and almost $6 billion without that ownership.
Then if you move to the Mid-Continent slide. Obviously, we had an incredible proved reserve replacement as we ramp up that program and start to add more proven reserves into the mix. Increase in value is tremendous, increase in net resource value; 50% of our proved developed reserve value and 73% oil revenue; and then $14.86 finding cost.
When you move to the Miss, I know there's a lot of interest in the community around type curves, what's happening to our reserves. If you look at this slide, what you're going to find is no perceptible notation and revisions on quantity. And then when you look over on the value, we actually saw a bump up because of that oil price change, and then you saw a significant increase in proven value from the extensions we booked through the drilling process. And again, as I've mentioned, we're drilling more -- we're booking more the traditional methodology, so it's one offset away from our proved-producing location.
The next slide, we're going to spend some time on this one. We've given you the old curve, the new curve, and we'll talk a little bit about -- primarily the changes to that curve are essentially it's the same oil recovery that we had in our original type curve, and we've gone up on gas. And let me -- the phrase I like to throw out for you is the most significant engineering non-adjustment was to the Miss curve. If you think about where we were last year end, we had 37 wells in our type curve. This year end, we had 145 wells in the consultant type curve. And that move up in statistics alone, not only was it a move up in statistical number but it was a move up in, call it, distribution.
We drilled across a very wide area. I think Todd's quoted some numbers of the distance that we drilled across. And I'll show you a map in a little bit, I think, of how far that distance was from Comanche County, all the way to the far southeast of the play development. And what we're seeing is the curve is holding up extremely well considering the statistics that we had at last year end. I would say the non-movement of this curve was very remarkable item for this year end. Now the move up from 409 to 456 was primarily gas. And last year end, I'm going to -- I'll show you the plot we showed you last year end, which is we did a study on gas-oil ratio across the play and we showed that the vertical wells had a tendency to go from about 5 -- range of 5,000 to 10,000 GOR up to about 17,000 GOR to 20,000 GOR over their life, over a 30-year life.
At the time, we didn't have enough history on the horizontal wells to book that inclining GOR ratio. And this year end, we had enough history. We're effectively the same GOR starting place as we were last year end. It's just we booked the increasing GOR instead of a constant GOR this year end. So the increase in gas-oil ratio is really over the life, not the initial point, and that's the key to understand. And what that means is, really, from an economic perspective, I will tell you, the other remarkable thing is the 409 curve and the 456 curve, because the rest is in natural gas and its primarily towards the end of the life, had very little impact on rate of return. They're pretty much the exact same economic outcome that we had last year end, when you look at them and compare to each other.
The other thing you'll note is the b factor. What we saw, if you look in that plot, the black curve is the new consulting curve, and the match is the red dash line through that and the green was last year end. And the only real perceptible change to that curve is we're seeing a little bit higher IPs and a tiny bit steeper decline. I quote that as tiny because it's 56 versus 63, and then you can see how they blend back onto the same type curve.
And as I've mentioned before, b factors, really both us and the consultant, identified the fact that, really, we're starting to see the influence of a higher b factor in our data, it's just where we are and understanding when we can move that into the proven category. And right now, we would say we're probably another 6 months to a year out before we discuss whether a 2 is actually going to be applicable or not. But we do see that character bending more towards a 2, at least, than we saw last year end.
And keep in mind, the b factor discussion in the U.S. is always interesting to me. You need a couple of years of good, solid statistical data to really define the b factor. I can fit any b factor in a range of b factors through 6 to 12 months of data. Once you get a number of wells producing out over, say, 24 months of good, solid data, you can start to see the true character of that b factor. But we see the tendency is going up by all accounts, as we look at it.
The next slide shows the distribution. The one thing we talked about last year end was that we do see a statistical range of outcomes. As we -- as I talked about earlier, as you drill horizontally and connect that multiple compartments in a varying reservoir, carbonate reservoir system, you're going to get statistical outcomes different from well to well. But what we're seeing is range-wise, across the whole play, we're seeing excellent wells across the whole play and no difference in the statistical outcome from, say, what people would like to try and hone down to is, well, do you have a core area. The answer to that is no. We do not see any identified core area in our data today.
What we do see is well-to-well varying performance, and that's reflected in this lognormal distribution. But what we do see is in that statistical outcome is the lognormal distribution fits extremely well, and the statistics are working extremely well for us. If you notice, there's 144 -- last year end, if I had shown you this, there were 37 wells. The same distribution, same lognormal distribution, but you would have had a lot of gaps in that curve in trying to understand where the actual outcome would be. This year end, we've got a solid database and it's looking extremely good.
This is that curve I was talking about on the GOR. The purple line -- wish I could kind of point to that, but the purple line, squiggling line at the top of that rising curve is the vertical performance study that we did in the Alfalfa area for all the wells drilled in 1980 to 1990 to study this concept of what happens to the GOR over time. And we saw this trend. You'll find it in last year's presentation. We identify this trend, but our consultants went ahead and put a solid, flat, constant GOR over 30 years. That's the gold line. The blue line is effectively the new projection. It starts at the same point. A lot of concern over our gas-oil ratio, whether we're getting a lot more gas or oil initially. It starts at the exact same gas-oil ratio but just rises over 30 years to get that extra gas in the numbers. So it gives you an idea of what's happening there.
We've shown this one. While we see this increasing IP over time, we believe we're working on -- Dave's group is working on some excellent ideas on improving contact area to the reservoir, how we do our fracs, what's happening. We're just showing you a trend analysis of what's happening from where we were with our original 409 curve. And these are first 30-day averages, okay. So these aren't 24-hour tests. These are the averages of the first 30 days. The 409 curve was 244. And if you look at all the drilling program to date, we've seen a steady trend up to 312. And I think we showed you that 2011 was 302. So we continue to see that rise in our initial IPs as we move forward in time.
When you look at -- I won't go through all of these for you, but generally speaking, the Permian had also very good metrics. From a reserve perspective, as I mentioned, we were primarily development drilling in 2011. And I'll talk about some of the reserves upside here in a minute.
But primarily, this -- you won't see a lot of a reserve movement when you're drilling infill wells on 5-acre spacing that are already booked. You're not going to be adding a lot of additional PUDs to that concept. But I will talk about some of the additional upside as we move forward into '12 and '13 here in a minute.
But generally, very good metrics as we look forward to our reserves in the Permian. A lot of emphasis on our type curve. We published our new type curve prior to the Analyst Day, and it got a lot of emphasis in the press. And I'm going to spend some time walking through the changes of the type curve and exactly what is going on. We don't see a negative impact in any of our numbers, but I'll go through in excruciating detail the Permian type curves, so you get a concept of what the changes are.
If you'll look at besides Permian gas reserves, we did have a 7 million-barrel revision in the Parker Minerals Clear Fork area, and I'll go through that in detail. But generally, we're not talking about a failure in the Parker Minerals. If you remember, when we were talking about the Parker Minerals area, it was one of our original legacy areas of drilling at Clear Fork. And we took an area where we've drilled 4 -- 6 sections away from what was originally defined as the core area 3 years ago. We've expanded that out to the south. And as we have expanded out, we had a 100,000-barrel type curve. And as we infilled down to 10-acre spacing and drilled the exterior of that fill, guess what, it didn't turn out to be 100,000, it looks like it's more like 80,000. Still extremely robust economics, but it ended up with being a negative revision.
Now on the offset of that, we booked -- we are finding in the exact same field, we've been out testing op [open] hole completions in the San Andres and had a very good successful recompletion program that's not on our books. So offsetting some of that change in the Parker Minerals, you'll see a note up here that the San Andres Parker Minerals, we added 3.2 million barrels to reserve for that op hole zone potential that we're having very good success in.
So the Permian continues to be an area of multi-pay target reserve potential, and we continued to see those kind of reserve movements because of it. But we're giving you all the detail here so you can understand that. And then again, what we saw, slight negative revision on total reserves. We saw a large increase in value, and that was primarily from the move in oil prices.
When you look at the Permian, think of it as this multitarget, shallow target with a lot of remaining oil in place, but they are relatively small targets. And when we have to drill a lot of wells, and what we showed you last year in was a type curve representing a 2011 proposed drilling. And that's -- and then we changed that to forecast 2012. And that's where a lot of the concern came from, and we'll talk about that here in a minute.
The one thing we do see is we still see a lot of positive movement and ability to continue to get additional reserves out of the Permian Basin. It's a lot of in-place reserves that haven't been tapped, and we will continue to work this very hard. And I think you'll continue to see reserve movement along those lines. The one thing we don't talk about a lot is a lot of companies are experimenting with horizontal drilling out here, and we're monitoring that activity as it moves forward to see if it's applicable in some of our areas.
This is the Parker Minerals area. As I mentioned, again without a pointer, the -- really, what we're looking at is we extended that field to the south, about 6 sections and had very excellent results. Where they ended the field years ago was not the economic extent of the field, just where they started having less results.
And what we did this year in, as I said, is we moved down from 100,000-barrel type curve in the Parker Minerals Clear Fork to an 80,000. And that's -- it's still a very robust economics, but it was built into some of those numbers that you saw last year in for the projected drilling, and that equated to 7 million barrels in negative revisions.
But with that, we are also, as we expanded out to the edge of the field, we are also booking additional reserves, and that's the 2.5 million barrels. And then the op hole recompletion was 3.2 million. Guess what, that netted us about a 1% downward revision in the Parker Minerals area. So virtually, no change to the Parker Minerals proved reserves as you look at it.
Then, we move to the Fuhrman-Mascho area where we're doing the bulk of the drilling. Next year, we're planning to drill about 80% of our wells there, about 600 wells. To date, we've drilled 1,400 wells since 2004, with a legacy drilling and our drilling, and that's the type curve. The type curve has effectively changed to 0 from last year end. The only change we made to the type curve was effectively, I believe we talked about 5 acres, 10 acres. We had a different booking for 5 acres and 10 acres last year end. This year end, when the consultants reviewed it, they said we don't see any substantial difference between the 2 curves. We can't differentiate a 5-acre well from a 10-acre well, and we're going to spread the reserve booking across a one-type curve, and that came out to the exact same reserve average per well that we had with the old-type curves.
So there was no real reserve change at all, other than we have adopted a single well-type curve for the whole region reaches now. And that type curve is demonstrated from 2011 drilling. We drilled almost 500 wells last year. And we give you both slides, which is a daily rate and then a cumulative rate over time. It's much harder to hide on a cumulative plot of how the type curve performs over time using that methodology.
So San Andres, drilling 5 acres has been extremely successful for us, and we believe will continue to be extremely successful for us. And that is where we launched our Permian Trust in 2011, was around the San Andres drilling on a 5-acre spacing.
If you look at the next slide, really what I'm talking about is that yellow acreage to the south and to the north, as we expand out in 2012 and drill some exterior wells, we have developed -- we still have the ability to add substantial proven reserves to our Fuhrman-Mascho project. It's just that as we've been extensively drilling 5-acre infill wells, if you don't do some of that expansion drilling, you're not going to add a lot of booking. So as we look forward to 2012 and '13, we still have a lot of opportunity to book additional 5 acre and have a lot of reserve growth in this area. It's just that last year, we primarily were focused on drilling those infill wells.
We did add about 3.4 million barrels of proved extensions even with that in the exterior areas as we drilled out some of those, but there's still a lot of potential that exists.
Type curves. A lot of emphasis on our type curve movement. We did move down from our type curve from last year end to this year end, but this is not reflective of our proven reserves. This is reflective, how to put this, this is the weighted average mix of our anticipated drilling program for 2012, as it was our weighted average mix of our drilling program for 2011 last year when we showed it to you. The change is, we went from about 60% drilling Clear Fork wells, et al to drilling about 80% projected drilling San Andres wells -- I'm sorry, 60% San Andres wells last year to 80% forecasted for this year. And what that does is it moves your CapEx down and it moves your reserve average down and it slightly moved your rate of return down. But there were some conclusions drawn that there must be something wrong that the reserves are moving down. Well, if you change the mix of wells you're drilling on average, depending upon which mix you're drilling, the numbers are going to move.
What didn't seem to be picked up was the CapEx also moved down, and that's because drilling in San Andres well costs you less than drilling a Clear Fork well. So while you're getting -- it's this CapEx efficiency number that should be looked at and the rate of return, and that's what I'll go through. Still a very robust program.
And I will say, when we -- because of some of that concern, we were trying to give the emphasis on 2012 drilling so that people could model and look at the forecast more appropriately because everybody seemed to be focused on that next year, but I'm also getting quite a few questions on what does that mean to the NAV value, what does that mean to the forecast of the rest of the property set. And if you do the mix of the rest of the property set, the rate of return is almost exactly the same as this type curve today. And the San Andres program is almost the same rate of return as this type curve that exists today.
So basically, our inventory of properties between the Clear Fork and the San Andres have -- call it stabilized, right about the same region in this type curve. So when you think of NAV modeling or you think of modeling the rest of our locations, this is an approximate methodology. It's still complicated to try and build in to give you a single type curve that represents 7,600 potential locations in a simplified form, but this is one of the best methodologies we've come up with without giving you 14 different type curves across different areas, et cetera.
So we did put this slide together for you so that you could understand the changes in the type curve. The original one from last year end was showing like a 90% -- in the 90% rate of return. One of the things that happened was if you move down just because the Parker Minerals reduction and expected outcome, that would move you down to an 81% rate of return. And then as Dave talked about, there's a slight increase in capital required from the 5-acre directional drilling and that's the change that moves you to the 70% rate of return.
No change in the San Andres type curve, no change in the expected outcome. Primarily, it's that Parker Minerals didn't turn out to be a 200% rate of return. It turned out to be 100% rate of return kind of project. And that moved that average down from 99% to 81%, and then it further moved you down by a slight increase in CapEx.
So when we think of the Permian pro forma and the Permian type curve, there is no indication of anything that's bad happening or dramatic happening in the type curve. And then the mix of properties changed from 61% San Andres to 81% San Andres as we move into the forecast, as we -- there was also a comment, I think I saw about the LOE. One of the things we did identify, that was with taxes. I think it was $17.30 with taxes. If you compare it to last year end with taxes, the number last year end would have been $18.15. So the total LOE actually went down from year-over-year. So that was also a misnomer in the data that I saw out in the public.
Talk a little bit about NAV and resource value. I got a couple of questions at the break. Let me talk a little bit about the modeling concept first. This is not taking every one of those type curves and running at today's prices as if it was drilled today. This is taking every one of our locations that we have proposed as a PUD and oil resource location and drilling it out effectively over 15 years.
And let me just give you a couple numbers. The Miss is developed within 12 years. The Permian is basically -- the 7,600 locations for the Permian is developed within about 7 years. And then the gas assets are scheduled out in years 13 through 15. An interesting thing about the current strip. If you look at the current strip, one of the things that were being hindered on, I'll call it hindered, in looking at the value, NAV value on this slide, is it's a backward dated oil curve.
We start at $97 and that oil price drops to $91 and then we're projecting that out flat at $91. So a bigger impact of this NAV value that you see on this page would be running this with an increasing oil price instead of a decreasing oil price. It would have significant impact to this overall NAV value, more so than some of the other changes that we might talk about on gas prices or some of those other issues. Even with that, we saw an NAV increase of 77%.
And I think I've mentioned it's 3 wells. We're classically identifying the Miss as 3 wells per section, not the 4 wells that's perspective as we talked about.
We gave you the breakout by acreage and total resources. You will note the Mid-Continent has 1.6 million instead of the 1.5 million. Mid-Continent also includes some Sahara gas acreage that we still maintain. It doesn't have a lot of value, but there are some acres that are still associated with that and some locations. You'll notice that the location count is slightly higher.
We gave you the breakout by oil and gas. I won't go through that in detail, just for your information purposes.
And then finally, we give you a pro forma with Sandridge and with Dynamic. And keep in mind, it still includes the Royalty Trust, so we haven't pro forma-ed it out the third-party interest in the royalty trust. But we did give you the increases, 28% up improvement value, proved develop actually goes up from 56% to 64%. And then finally, you will see, instead of us being 26 and -- I mean a higher percent in Mid-Continent and Permian, the Gulf of Mexico does come up from 1% to 22% of our portfolio on a proven basis.
With that, I think I will turn it over to James.
James D. Bennett
Thanks, Rodney. I will wrap up with the financial overview and then we'll take some Q&As. So in terms of the finance section, it's really the oil assets of the companies put together over the last few years really set us up for what we're able to do in '11.
We were able to monetize all the significant amount of assets that we put together over the last few years in terms of with the Permian acquisitions, with the acreage acquisitions in the Mississippi and really set us up to accomplish what we did in '11. And that put us in a position where we're in a stronger position, credit profile wise. We're able to pay down debt. And the Dynamic acquisition, which I'll get into, was really part of that 3-year strategy.
In terms of what we accomplished in '11, we're able to raise about $2 billion of capital. Starting off with $400 million in cash flow from operations and $1.8 billion capital budget, we think that was a pretty lofty goal, but we accomplished it. We did that through 2 royalty trusts. We're the first public company to execute a royalty trust. We raised $900 million through the trusts. We sold $600 million through asset sales of the noncore assets and then $500 million upfront cash proceeds from 2 joint ventures, both in the Mississippi.
At the same time, we took our leverage down from 4.5x to 4x and then pro forma Dynamic further down at 3.3x. We ended the year with $1 billion of liquidity, nothing drawn on our $800 million credit facility and $200 million of cash. And then we capped the year with 4 quarters of sequential quarter-over-quarter EBITDA growth. First quarter was $148 million. In the fourth quarter, we ended with $175 million. So feel good about what we accomplished in '11, and this is, as Tom said, it was really a year of transformation for us in monetizing the assets and setting us up to do the things that we were able to do last year.
Objectives for '12. Fully funded $1.85 billion capital program. That will be funded with -- we ended the year again with cash on our balance sheet of about $200 million. I'll go through a waterfall chart here, but we -- proceeds from the Repsol joint venture, some proceeds from some royalty trust units we sold week. That combined with our pending royalty trust and a fully undrawn revolver easily funds us for '12. So we have '12 fully funded. We will complete that deal, the pending trust, we can't talk about it in great detail because it's still under registration. We do expect to realize proceeds for that early in the second quarter of about $500 million.
Close Dynamic, that will happen also in April. We'll receive the Dynamic audit about late March and we'll close about 30 days after that. We'll also here in the next month or 2 be entering into a new credit facility. Our facility doesn't mature until 2014, but we thought it's prudent to go ahead and extend that, probably extend it out 5 years, and we think we'll take the borrowing base from $790 million now to right around the $1 billion range. Again, that will close some time in April as well.
And we'll continue to hedge this year. As you know over the last several years, we've been an active hedger in terms of the oil market. If we can lock in these kind of returns in $100 oil, we think it's very prudent to do that. As long as we're not seeing service cost increase and protects our balance sheet, and we think it's one of the risks that we have in this business being price takers is commodity prices, so if we can hedge that risk and take it off the table, we're going to continue to do that and you'd seen this hedge out into '14.
In terms of the Dynamic acquisition, Tom talked about the 6 different things we could have done to bridge our funding gap and really get us to our 3-year plan, everything from selling acreage, taking on more debt, issuing common equity, doing more royalty trust. This to us was the most accretive way to get there and de-risk the company the best way. It's accretive on all -- from a cash flow and earnings measures. And some people have asked how is it accretive on an NAV and NAV can be a tricky thing. But one way to think about it is had we not done something like this, we probably would have sold or joint ventured maybe up to 0.5 million acres in the Miss. And if you look at Rodney's NAV model, the $23 billion, 1.5 million acres, it's about $15 -- I'm sorry, $15,000 an acre. So $0.5 billion, 500,000 acres, a little over $7 million, $7 billion of NAV. So by us doing Dynamic, we don't have to sell 0.5 million of acres in the Miss. We can keep 250,000 of those only sell 250,000. So for us, we think of it as NAV accretive and earnings and cash flow accretive. At the same time, deleverage us, takes our leverage from over 4x to about 3.3x and still maintain strong liquidity. We still have $1 billion liquidity right now.
Capitalization. In terms of where we've come the last 4 quarters, we ended the year with $2.9 billion of net debt. December 31, right now, we're at $2.6 billion of debt. Again, that was because of successful capital raising we had last year. We took our leverage from 4.5x down to 4x. Pro forma Dynamic further takes it down to 3.3x. Another measure we look at a lot, debt to production, $47,000 per flowing barrel down to $40,000, then down to $37,000 again with the Dynamic acquisition. So again, de-risk the business and puts us in a better position balance sheet wise.
In terms of our capital structure, a very solid capital structure. Only $350 million of maturities over the next 4 years. Those are the floaters due in 2014. Those are called on that 101 on April on par. $765 million of converts. We start to be able to mandatorily convert those in 2014. And our long bond right now, the $900 million is trading right at par at about 7.5%. So I feel very good about our capital structure and our lack of near-term maturities. And as you remember earlier, in '11, we refinanced our 2015 bonds and pushed that maturity out to 2021.
In terms of our credit facility, it's $790 million borrowing base right now. This is the one we anticipate amending and extending probably in April. Pushed it out 5 years and increased the borrowing base to right around $1 billion. So we have a group of 25 banks and Bank of America is the lead on this.
Our measures over the last few years, so what we've been able to do with and without Dynamic, we've grown our oil production. You can see up to the top right, and it's really this transition of oil that set the company up where it is now. So on the left, our EBITDA has been relatively flat. A lot of that is due to high gas hedges that we had in 2009 and 2010. Those hedges are rolling off. We've made the transition to oil. Oil comprises more than 50% of our production now and, as Tom said, about 80% of our revenues.
And on the bottom right, you see our debt measures continue to improve those. One of the goals we did lay out last year was to improve our credit profile. We didn't think being 4.5x levered was prudent and we've done that over the last year through the combination of the capital raises that I'll go over on this page and the Dynamic acquisition.
So this is what we laid out on the top of the page in '11 that we wanted to accomplish. So an EBITDA goal of about $700 million, these are actual numbers we showed you guys last year. Cash flow of a little over $400 million and $1.8 billion capital plan.
So we were able to fully fund the last years with the transactions we did. And what that confidence in our capital raising was we saw we had success with the royalty trust, we were able to do another Permian Trust. That really allowed us to increase our drilling plan. In August, we announced that. That allowed us to start drilling up in the Kansas and really see the extension Miss. So had we not had the success in capital raising, had we not gone out and increase our CapEx budget in August and acquired the additional Mississippian extension, we wouldn't be in the position we're in today.
So again, 2011 is really a transformative year in terms of setting us up to accomplish what we did. And in '12, similarly, we're in a much better position, still have a funding gap. But as you can see with the year-end cash, Repsol cash and unit sales, our pending trust, we've basically got the '12 gap fully funded. Well, we may have very small draw under our $1 billion revolver, but we're fully funded for '12.
In terms of our hedges. As we said earlier, we're an active hedger. We'll continue to hedge. We have about 82% of our combined production with Dynamic hedged, just over $99 in terms of swap and a small amount of collars as well. The small amount of gas hedges and collars. We're hedging out into '14 now. Again for us, if we can lock in either between 70% and 90% return to these prices, we think it's prudent to do that and you'll see us continue to hedge.
Joint venture. These 2 summary pages on Atinum and the Repsol joint ventures. You guys have seen this before, but we put a summary in here for you. And this was one that was -- the Atinum was announced in August and closed in September, $500 million, 50% cash upfront, 50% in the form of carrying. This value at the Miss at about $4,400 an acre based on 113,000 acres.
And in the second, Repsol announced in December, closed in January, $1 billion, $250 million cash upfront, $750 million carried. We think we'll use over 3 years as well in that value. That was 114,000 acres in the Original Miss and 250,000 extension valued at about $2,750 an acre.
That's actually the end of our prepared remarks. There's a guidance section in the back. It's identical to the guidance that we put out in our earnings release last week. I'll just note a couple things on that. As Kevin said, that assumes closing of Dynamic on April 30. So SandRidge standalone for the first quarter through end of April, the contribution Dynamic May 1 there forward. As you're looking at -- although we don't give our quarterly guidance, as you're looking at the first quarter, I would point you towards the guidance that we have in our last 2 presentations, Goldman and Crédit Suisse, to look at SandRidge on a standalone basis before the impact of Dynamic.
And with that, I think we'll have Tom and Matt come up and open it up to questions.
Tom L. Ward
I'll sit here or stand here, and then as we -- as you ask questions, I'll direct out to who might be able to answer them better than me. So, yes?
Two questions, Tom, up on the Kansas Horizontal Miss. First, just on the water facilities up there, I think when Matt and some of the guys were talking, obviously it's evident that you've already had the more water facilities in the Alfalfa than some of the areas. As you move up there, are there already plans in place to start the infrastructure in some of those plans or if you can just comment how aggressively you'll start building that out?
Tom L. Ward
That really addresses what Dave Lawler was talking about is that we look at 18-square mile areas where we do the pre-engineering. So whenever we look at a new area to go to like when we moved to Comanche County, the first thing we do is to go drill a saltwater disposal well and be prepared for the system. And then you start drilling wells around that. So as we move into the extension area, the Mississippian, yes, we will have -- not all areas so we would put a saltwater disposals in first. But usually, we'll move in and be prepared to have everything in place to start drilling around.
Then just a follow-up, as far as -- you've always said I think that upfront about having more gas as you move to the west, just if you could comment a little bit about the overall economics despite having more overall gas in those wells.
Tom L. Ward
Actually, we're -- we've been surprised with the amount of gas we're seeing across the whole play. East to west, our GORs haven't really changed any at all. So as you're noticing in our type curve, the amount of gas we're finding is more than we expected. And so that just goes back to we're seeing more gas across the play than what we anticipated because the vertical wells in the east didn't have as much gas as to the west, but we're finding as much gas whenever we drill wells.
If I could just pick up on those 2 questions a little more. So given the need for planning ahead for the saltwater disposal system, would you be thinking about entering the extension Miss more as a step at a time, kind of domino from the current position, or would you think about trying to de-risk the play by going and building out some infrastructure further north, so that you've kind of book ended the play and shown some of the results? And then as far as the gas production and how that's increasing, I just want to make sure I understand it. It sounds like the production is not from the new wells you're drilling, but a lower decline rate on the gas from the older wells you've drilled. And so further out in time, we get more production from legacy wells. Is that the way it's working?
Tom L. Ward
Well, it's both. So what we're seeing is, over time, the gas, the GOR increases, I think it goes -- we start just out over 50% of oil and then over time, by the end of the life of the well, you're producing majority of gas. But we're also seeing more gas than we anticipated in the first 30 day IP than what we anticipated 2 years ago or even at the end of 2010. So there is more gas in the system than we first anticipated and we're seeing an increase in GOR at the end of the well, so the first part of the well. To answer your first part of the question, I don't -- we will step out, just like we've done in Alfalfa and Grant and Woods and Comanche and have areas that we start to drill around the disposal system. We'll have some good wells and some bad wells. The area was really de-risked up to 30 years ago -- a lot of the vertical wells were drilled. And you know you have the same geological model in place as you wrap around Kansas as we have in Oklahoma. So as long as we're willing to move forward with a type of drilling program like we have, we might -- our first well might not be very good, but that still will show. There's oil in place, and as long as we're willing to move water, we'll be able to have, in my opinion, a successful operation.
A couple of questions. You touched on this a little bit, but in the extensional area alone, what kind of leasing activity by others are you seeing? And also you touched on the higher NRI's in the extensional area versus the original. What other different leasing terms are there, the extensional versus the original, if you could touch on that a little bit?
Tom L. Ward
Sure. The terms were basically the same. We took mainly 3-year leases with 2-year options. There were some that were slightly more than that, but you have a 5-year period of time. We have higher net revenue interest, so the 85% versus the 80% in the original that we started with. And we do see now other parties coming in and buying in the play, but we're effectively through leasing. So we don't keep up with who's buying where across the play. We do have some plans, and in fact, we increased our budget as we drill wells that are showing better areas within townships then we do try to high grade those acreage positions as we drill some of our better wells.
Tom, if you could, talk a little bit about the cost expectations per well in the Mississippian for 2012. I know David did a good job explaining the potential savings. Do you have any of that built into the budget or is it just basically the $3 million per well that you've been seeing, if you could explain that a little bit.
Tom L. Ward
Sure. When we bring in a new rig, just the first few wells that we operate with that new rig will be just less efficient than the rigs that have been there and drilling. And I think that the real rate of return increase over the life of the play is not going to be how much more oil and gas we find, it's going to be how much lower we spend, how much lower we cut costs, how much we can increase the cost savings. And so that's where Dave's team is really focused on. I think we do a decent job of getting out oil and gas with the basic stimulation that we have. There's decent primary porosity and permeability, and so we're not trying to create a lot of gas out of a shale where you can just keep spending more money and try to get more optimum recovery. I think what we're seeing is that we'll be able to at least drain 4 wells per section efficiently with a small frac but where we could really change the rate of return is. What if we could not have to line a well in cement and we could do more of a Packers Plus system or what if we can save $58,000 a well by using produced water. And every time if you're spending $3 million, you can save $25,000 here or there, you can have a real effect over the cost -- life of the project. And that's what we start to focus on now. I think we have a fairly good understanding about what the reservoir -- excuse me, what the reservoir will give us.
Given how important water is, are you seeing any differences or expect any differences for water production in Northern Kansas versus in sort of Alfalfa-Grant? Those areas, and also do you see any differences in expectations in AFEs between the two plays given it's all shallower as you go up?
Tom L. Ward
Yes. Again, all we'll plan to do is hopefully over time by having a shallower wells, you'll spend less money. We don't anticipate that in our current budget, but that should be the same for everything we do including water wells. So it's just on the margin. It's not we won't have tremendous savings, but we could save a couple of hundred thousand dollars over time by drilling 1,000 feet less, so that does make a big difference. As far as producing more water, we don't anticipate that. We think it's the same rock in the same type of play, and that you can know the effect -- you can expect to have 90% to 95% water cut. So all we're doing is moving a tremendous amount of water that has a slight oil cut to it.
I'm happy to let other people talk too, not they'll try. Charles? I can repeat the question.
Charles Meade - Johnson Rice & Company, L.L.C.
[indiscernible] Is that [indiscernible] or is that -- what are your plans going forward?
Tom L. Ward
What are our plans going forward with the Piñon Field? We'll sell it. I don't exactly when, but our plans have changed. So just think back in time. The Piñon Field was a great acquisition for us in 2006. In fact, I based the whole company around the Piñon Field because it was a great reservoir. And the reason that it was a great reservoir is it was producing 7 Bcf average per well at 6,000 feet deep. And the reason that it wasn't developed more in time, so I need to understand how come very smart people before me didn't do things is, because the CO2. You couldn't -- until gas got up to a high enough price, you couldn't drill a well even though it made 7 Bcf per well average, which is a better reservoir than any gas reservoir I'd ever drilled in my career. You couldn't go drill those wells and strip out half or over to 60% CO2 unless you had a plant there and you have a high enough methane price in order to make it work. So that worked incredibly well. And in fact, it's still incredible that we can have a PV-10 in the Piñon Field at $4 gas or just over $4 gas when we're giving away 60% of our reservoir. So the field is good. Now what -- the question mark is that now that you have the opportunity to drill 100% rate of return oil wells at $100-plus, do we ever believe that the ratio will get back to a point that it's 6:1, and I don't, at least in my -- what my short career is left. I just don't see that happening. In fact, gas is down another $0.08 today. And frankly, the Piñon Field doesn't mean much to the company anymore. That doesn't mean it's not a great reservoir and that somebody won't drill it. I fully believe that all the obligations with delivering CO2 to our partner and making methane out of the Piñon Field will be met. It just won't happen at today's price. And I firmly believe that you won't have $2.40 gas forever because I don't think the industry can make money anywhere close to this. And that's maybe just the difference of opinion that I have with some of my peers and how come we don't go in some of the other plays. But somebody will buy that field. I just don't know when.
Just on the Piñon. It looks like about half of the undeveloped acreage expires this year. Is there a big cost to extend that or do you have options to extend that?
Tom L. Ward
All the Piñon is HBP. In the West Texas Overthrust, we'll lose all of our acreage and we don't plan to keep it.
That's just Piñon?
Tom L. Ward
Yes. The Piñon Field is basically -- is all held by production. And so, Rodney am I right on that about saying the right -- yes, all the acreage. We had -- one time, we have 550,000 acres across the West Texas Overthrust, and that will expire over time. Now keep in mind we have proprietary seismic that does show structures at some -- we actually found gas out on those structures. It's just that we don't see ourselves buying the leases back or I don't know what we'll do with the seismic over time. But it is a very structurally controlled play that will be difficult to drill without our proprietary seismic.
Yes, Tom, following up on the well cost question in the Miss. On Slide 53, it shows the improving drill speeds, days from spud rig release dropping from 23 to 19. We're about 20 in January. What are the best rigs drilling? What is their spud to rig release?
Tom L. Ward
David C. Lawler
Tom L. Ward
Let me answer it for you. Dave says that we've seen spud rig to release in 14 days. That's our best.
So you're saying it sounds like with improving spud to rig release and the efficiencies on the salt water disposal, you might be able to eventually target maybe well cost around $2.8 million, maybe $2.6 million in the future after you get to the peak rig count of 45 in 2013-2014. Does that sound...
Tom L. Ward
Well, I can say this that whenever we have 3 rigs, I believe it was 3 rigs working in one township in Alfalfa County, we were seeing $2.5 million per well. And so that's how come I came out and had the slide that said we think we'll go to $2.5 million per well over time, and then we started bringing in all the new rigs and we started drilling new areas with different kinds of rock and our well cost went up. And so that's how come we keep our efficiency number at $3 million, even though I believe over time that we are doing all the right things to lower cost. Here's one.
Do you think you're going to keep all the water handling, the requirements in-house? Or do you think you'll outsource it to one of the MLPs at some point?
Tom L. Ward
We've had offers to do, to outsource our water disposal. I think, over time, as somebody else should own the system, what we don't want to do is give up control of how we drill our program, to let somebody else dictate to us how the water would be handled. But I think there are lower cost -- I mean, that would give us a lower rate of return of drilling a well, and it is going to be a major expense for us in the future. So James, won't you...
James D. Bennett
Yes, we've looked, I think, at some point, you'll see whether it's MLPs or other infrastructure guys come in and own some of these assets. We've been approached by -- it's still early in the play. We're spending saltwater disposal capital out ahead of drilling the wells and it's something we want to maintain control of. I think once you get an area that's up and developed, it's in a more, very mature development stage. I think then you'll see it an opportune time to harbor some of those assets, whether it's the saltwater disposal or even electrical structure.
Just a follow-up on that. In order to hold all this acreage by production in 5 years, don't you kind of need the MLPs to come in or can you handle it yourself?
James D. Bennett
We can handle that ourselves. It's built into our plan. It is HBP and everything I think in 5 years.
Matthew K. Grubb
Just from an acreage standpoint, holding -- we can hold with the rig program that we anticipate wrapping up, we can hold our acreage for 5 years. In fact, that's probably a conservative. And that actually in Kansas, as we drill more and more in Kansas in the coming years, we can hold 1,280 acres per well. Right now, we're basing all our math on 640 acres per well, which is what we're doing in Oklahoma. So as far as holding acreage, that shouldn't be a problem.
Matt, this is for you as well. The $20 PD fine and cost, do you think that's a good assumption to use for 2012's capital program?
Matthew K. Grubb
The 2012 program is very much like the 2011 program, and that are the bulk of our drillings in the Permian and the Mississippian. So yes, I think that's probably a good assumption.
Okay. And just secondly, of the 1.5 million acres in the Mississippian, how much is Kansas versus the core?
Matthew K. Grubb
About probably 2/3 of it is in Kansas.
You referred to type curves by your consultants. Is that the same as your reserve engineers? And who are your reserve engineers and who are your consultants? And do they all work on the same areas? Can you just discuss that for a second?
Matthew K. Grubb
Yes, the bulk of our reserves are done by Netherland Sewell, probably 90% is done by Netherland Sewell. And we have maybe 5% by Lee Keeling & Associates. And what's the -- one more, Rodney? Was it -- and that remaining 3% to 5% were done in-house.
And then Netherland Sewell does all that type curves as well, so they're your consultants and your reservoir engineers, it's the same thing?
Matthew K. Grubb
Yes, it's the same thing. They put our type curves together. They do our reserves, working with our in-house engineers. But yes, I mean, all our -- 95%, 96% of our reserves are done through third-party consultants.
Okay. You mentioned that you're going to let the West Texas Overthrust acreage expire. So the cost of that acreage still in unproved properties or has that already been written off or will be expense as it expires?
Matthew K. Grubb
You know how we work that?
James D. Bennett
Yes. Part of it has been written off through the full cost pool. There could be some of it that's still in [indiscernible] full cost company. It's all in one pool and it's all tested together. So it's all part of our full cost pool that we test every quarter. So it's in there, but it gets tested every quarter. And if it's impaired, it will be written off.
[indiscernible] category that is part of the full cost.
James D. Bennett
Some of it will be, yes. Some small amount will be, yes.
Tom L. Ward
For the scope of that, we average about $175 an acre over the whole West Texas Overthrust when we bought it. Any other questions? I've got a couple online.
In Northwestern Kansas, it doesn't have gas [indiscernible].
Tom L. Ward
Matt, if Northwest Kansas Texas doesn't have gas, did you hear it?
Matthew K. Grubb
Yes, the question was if Northwest Kansas doesn't have gas, will that affect LOE and how do we lift fluid out of the wells. Is that correct, Kevin?
Matthew K. Grubb
Yes. So there's a -- first of all, I can't imagine the Northwest Kansas having 0 gas. What we've learned is we drilled some wells up in Northwest, in the very northwestern part of Comanche County, offsetting wells that didn't report any gas production and we made some pretty good gas volumes. So even you make 100 Mcf a day, once you get your gas lift system loaded up, it recycles the gas and it's a closed system and all you're really burning is fuel to run the compressor. So it doesn't take much gas to gas that. However, if there's absolutely 0 gas, then I think it depends on the volume of total fluid that you make. We would have to probably build power out there as we've done in Oklahoma and run subcons or depending on -- if there's less fluid, we may just run big pumping units. But there's ways to lift fluid out of the ground without gas lift.
Okay. I'm going to combine of couple questions here. Why wouldn't you sell Mississippian acreage and give the company a pristine balance sheet to prepare for any future event like '08, number one. And then number two, could you go into more detail about how the Dynamic acquisition is accretive from an NAV perspective?
Tom L. Ward
Sure. Well, I think that as an investor in the company, as looking after the fiduciary of all our shareholders, I would argue that having a pristine balance sheet or no debt versus selling an asset that's worth $15,000 an acre wouldn't be the best thing or wouldn't be something that our shareholders would want us to do. As a management team, it's not something that's high on our priorities. Now what we would like to do is to continue over time to improve our credit metrics. And you have to keep in mind how we got here was that we had a gas company that had to go to an oil company and so it didn't just -- wasn't made from heaven. We had to get there, and so we end up having a less-than-pristine balance sheet not because it was our will to do so, but because that was kind of the hand that was dealt to us, that I dealt to us. And so it wasn't -- and so it's been hard. It's been a couple of hard years to get where we are today. But frankly, now looking forward, we can continue to add debt and still have our credit metrics be going down to what I consider pretty pristine. I don't know if somebody wants to be under 2x levered on a debt-to-EBITDA ratio, but it's not a big goal of mine. And then if you look at Dynamic versus the other alternatives or just the one alternative of selling acreage, the way I look at that is that if every acre you drill is worth $15,000 an acre, why wouldn't you want to hold as much of that as you can? And so if you believe what Rodney said, is that it's a fairly proven area that has vertical production and we know that we've offset wells in Oklahoma. In fact, one of our very best wells in Kansas, actually in Barber County, Kansas, we drilled a well that was offsetting a well that vertically that produced no gas and made 5,000 barrels of oil and the well came on at $3 million a day gas and over 1,000 barrels of oil a day in the first 30 days. Well, that gives me enough of an idea anyway that I can make an assumption that something else can happen in other area if it's exact same rock as you move around into the western side of Kansas. So I mean, our goal for the near term is to own as much acreage as we can. But frankly, we did sell some, and that was to make sure we can get to where we are today.
James D. Bennett
I might add one thing to the balance sheet while we've been caught onto pristine certainly improved a lot and we've paid out $300 million in debt the last year. We've got no maturities over the next -- or $350 million of maturities over the next 4 years, and we have $1 billion of liquidity. So we think while I wouldn't we call our debt-to-EBITDA pristine, we're at 3.3x now. We think that's a pretty reasonable place to be if you can compare it to where we were a year ago. I think Kevin, you had a second part, which was the NAV accretion?
Yes, yes. How could be accretive from an NAV perspective?
James D. Bennett
NAV can be a tricky measure, but one way to think about it, I mention how Dynamic allows us to keep -- Tom will talk about the 200,000 to 250,000 at least acres of the Miss and not sell it. If you value it to $15,000 an acre, that's -- it's almost $4 billion, $3.8 billion of value. But our NAV, if you just take the 34.5 in our presentation on 506 million of shares, that should be right around $68 a share. So on NAV number, a big number, throw it out there and back off a little bit of debt, so maybe it's a little less than that. With Dynamic, with the additional shares, I think it will get you down to about $63, $64 a share. So it's really big numbers, and I don't know if we're smart enough to say it should be exactly $63 or $68 a share, I don't think there's much difference there. I think this allows us to get to that number and execute it with a lot of greater confidence.
Tom L. Ward
I just love it when he talks like that.
Once the Dynamic deal closes, we think it can post your rates at Dynamic rates?
James D. Bennett
The Longmont is 7.5% right now. I could see it threatening a little bit with -- maybe with the Royalty Trust that's pending and selling some other units and bringing in a little more liquidity. So yes, maybe a little bit better. I don't think it's going to be change difference. I don't think it will have something -- so we're not going to be investment grade tomorrow.
On the gas guiding capacity and the Mississippian, you talked about -- somebody mentioned we were bumping up against gas capacity limits in certain parts of the play. And obviously, you're having there some expansion plans for the year. How much head room do you have, how much risk is there that the gas handling could affect production over the course of 2012?
Tom L. Ward
Yes, I don't see any capacity, gas capacity limitations in 2012, Atlas is putting another process plant into their Waynoka plant area and doubled their processing capacity from 200 million to 400 million. Right now, the existing plant is full from the standpoint but they're still process low BTU gas. But low BTU gas actually pipeline quality, so what they do is they continue to allocate or move the low BTU gas upstream to pipeline and process our richer gas, which is more like 10.50 or 11.50 BTU. It's largely better for them on a processing doing so they have the ability to continue to displace the low BTU gas with our gas in addition to put a new plant. As far as pipe, they have plenty of pipe in the ground to move the gas and remove. There is 16-inch or 24-inch line that's going on right now which should be open up in operation over the next few months. It mostly run across Alfalfa County to the plant. And so while they do there is put in a compressor stations where you need them to keep the system de-bottleneck and they've done a pretty good job on putting us in compression. So for '12, drilling 380 wells, which probably 270, 280 are going to be in Oklahoma, and the 100 and Kansas, we're actually in good shape.
I have a question on the Mississippian wells and it's helpful when you give quite a bit of data on the conference presentation last month as well., or right around this month. You gave some impressive big wells in the Mississippian and looking very good. Have you seen the median of the wells trend upwards directionally of you like the mean as well, or is there more drilling with the means working up?
Matthew K. Grubb
Yes, I don't know. To be honest with you, if the median has been trending with the mean, what we are seeing is with most players, this Mississippian is still -- we're still very early in the play. And one of the reasons that this industry uses what they call the Swanson Mean, if that's about P 35 on the distribution curve. Once you've start developing the play, and you know where the best areas in they play are, that's where you tend to gravitate rigs to drilling, and that's why it's better than P 50 typically. Our Swanson Mean has actually moved up over time. And so the Swanson Mean right now, if I remember correctly, is around probably 500,000 barrels. Our type curve is around 456,000 which is kind of P 50 type number, which is a very good distribution on the play.
James, what with a target balance sheet look like in the 2014, 2015 timeframe?
James D. Bennett
I think as Tom said, we target improving credit metrics. So if you want to think of our debt-to-EBITDA, I would think it's something around, something between 2.5 and 3x, something in the 3x zip code.
And what is our outlook for NGO pricing out of the Miss?
Tom L. Ward
I'll let Matt take the NGO question. Actually, we plan to continue that's -- to evaluate processing and determine in different parts of the play if we want to process or not. We're very comfortable with Atlas as being our partner. They've done a fabulous job of getting out ahead of us. And so the most important thing is having capacity, as the question was brought up. So we want to have partners in place that we don't have to spend the midstream costs of getting pipe in place, and that we can deliver our gas so we can produce our oil. And that's the key to the play. If we would've tried to wait 18 months and build the processing plant just so we could strip off a few liquids, it wouldn't have made sense for us in 2010, and it doesn't really make sense for us today. So as far as marketing NGLs, is that what the question is, or is it what the content is?
Yes, it's actually just what the outlook for the pricing is out of the Miss, what's the current market and our outlook going forward?
Tom L. Ward
I never think about it. I don't -- it's not relevant to really the play. I could give you a long, winded answer about what my thoughts are on the NGO market, but it really wouldn't -- it would just bore people. So I'm going to say, it's not relevant to the play. But it does help us, the NGLs and the gas stream, keep us at about NYMEX flat, and I think that's what we're modeling. And so we don't pay basis virtually to get our gas to market. And also -- and think about the balance sheet going forward. What we're really trying to do is to build a company that can get to a point that we can be a mature company. As I said in the opening remarks, the goal of the company isn't to always be in a position to where we're looking for ways to have -- to narrow or to have a funding gap. The goal of the company is to be able to be in a size that's meaningful. So spending -- you can give a range, maybe $1.8 billion to $2.2 billion a year. We could argue about what that amount should be. But to be a company of size and then to be able to fund all your drilling within cash flow and look around for opportunities to make acquisitions. So I still think that in our lifetime going forward that some of the best deals will be ahead of us as we continue to drill high growth areas within cash flow and then look for ways opportunistically to buy assets. That's what the goal of the company is post 2014. I can repeat it if you want.
I think on the Dynamic acquisition, [indiscernible] You mentioned there might be other [indiscernible]
Tom L. Ward
If we -- I did mention on the Dynamic call and Matt and James and I talked about it that the goal of the company is to make other acquisitions. So we paid what could be considered a fair price or what I still think is an inexpensive cheap oil price to get Dynamic, that's really to get that team. And the offers that were given us for our Gulf of Mexico properties were just insanely cheap in my opinion. So if people are willing to sell assets for 1.5x to 2.5x cash flow, I think we'll be buyers. I think it's a great model. I think it's an out-of-favor asset for whatever reason people don't want to produce water in 300 -- or don't want to produce oil in 300 feet of water, that doesn't make sense. And it's really driven by the thought that people don't like the area or this perceived risk that I don't see is there. And so as long as there's some dislocation in the market and people or companies are willing to sell their assets at what I consider to be excellent prices, we could add to our position. I think we could do that, and still -- all still will be within the same credit metrics we're talking about and do it with that. I'm speaking for James on that. We haven't talked about this. Anything else?
Okay. Well thank you. We did our best to get through in the 3 hours. I hope we're close. And I appreciate, as always, you making the trip here. And everybody on the webcast, thank you for attending.
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