Welcome to the Sixth Annual SandRidge Investor/Analyst Day. We are glad to have such a big crowd here today. I am just going to do real quick brief introduction. Also at the lawyer’s request, actually always read the forward-looking information. Also, we do sponsor three public trusts, SandRidge, Mississippian Trust I and II and SandRidge Permian Trust and today we will not really cover anything related to those trusts. This will just all be on SandRidge, the [C]-Corporation. Just to outline for the day today, most of the day is going to be spent with our technical executives here, doing a deep dive into our assets and we’ll save the questions for the end of the day. I believe we have a break about halfway through, I think it’s after Dave Lawler’s presentation. And with that just brief introduction, I'll introduce Tom Ward.

Sorry, running a little bit late, I was back to talking to Aubrey about Board seat; just kidding, just kidding. Okay, our operating regions have changed a bit over the years. We now have three operating regions that we are active in, still active in the Permian, even after the sale. We are most active in the Mississippian, where we have, that's the area that is the growth interest for the company and then in the Gulf of Mexico we had the acquisition last year of Dynamic, that continues to exceed our expectations and then lastly we still have our gas asset in the West Texas Overthrust. So if you were to be here six years ago as Kevin mentioned, you would have had a company that was focused only in the West Texas Overthrust and a 100% natural gas. So moving forward overtime what we've done is the most dramatic shift to oil of any public company. Our corporate objectives are, I'll keep my part of the presentation very brief, because I want you to make sure that you see our deep management team and all the work that’s going on and especially in the Mississippian project where we're the premier operator to our corporate objectives and we want to continue to perform as the premier operator in the Mississippian. I think that by the end of today, you will know that we have the best drilling team, the best completion team, the lowest LOE and the best operations in the Mississippian. Our second goal is to invest in high rates return projects. The Mississippian is a very high rate return project. We had to overcome the issue of saltwater and we've done that successfully now. Last year was a big year for us to build out saltwater disposal.…

Thanks Tom and my name is Matt Grubb; I am President and Chief Operating Officer. We have a 128 page presentation for you today and I think there will be seven presenters including Kevin. So there is a lot of information to go over, but there is really only four themes, four takeaways from this. One is the Mississippian type curve. I think that type curve has moved around some, but we always talk about this play being in the range of 300,000 to 500,000 barrels equivalent and we can stay in that range. I think it’s a very, very good play, a large area to drill. Two is the Mississippian economics, you know we are still talking even with the type curve moved at year end, we are still talking 50% rate of return. Third is the progression we are making on costs. We've done a really good job operationally of driving costs down. At the beginning of Q1 of ’12 we were about $3.6 million per well and we finished the year about $3.1 million of wells. So that's a 14% reduction in costs. Then also our balance sheet, you know from a liquidity standpoint, we just sold the Permian basin, so we are well funded to execute on this very large play for next couple of years. So I think with those four things you can get comfortable with those things and walk away from here understanding all those and I think you see a really good opportunity here for SandRidge and where we are at today. So in the Mississippian, we grew the production by 131% from Q4 of 2011 to Q4, 2012. So we finished 2011 producing about 15,000 to 16,000 barrels equivalent per day. We finished 2012 at about 36,000 barrels equivalent per day.…

Thanks Matt. Just one little housekeeping item that you want me mentioned, we got a few questions there is Wi-Fi network here in SandRidge gas and the password is sandridge all lower case. So there’s been a few questions asking for that. Let me first tell what we did in 2012, what we accomplished. We started 2012 with LTM EBITDA by $650 million, one penny per share, earnings little over dollar, cash flow per share. $1 billion of liquidity and the Miss was producing about 15,500 BOE per day. So if we think about where we are now contrast last time with where we are now. Now we are about 36,000 Boe per day, LTM EBITDA about 1.1 billion, little under $1.70 per share of cash flow, and 2.5 billion of liquidity. So in terms of the capitalization, the funding, the capital structure, the leverage of the business and the profitability of it we have taken really a step change from a year ago to today and that’s evidenced in our earnings estimates and consensus, we beat the consensus of last four quarters, we have beaten production EBITDA three of the last four quarters and a lot of that is a testament to some of the work that the operational team has done in terms of keeping production line, keeping cost under control. We also raised quite a bit of capital last year, a lot of non-debt capital raised about $1.1 billion. We completed the Repsol joint venture in January, we IPOed SDR our third royalty trust, sold some royalty trust units, sold some non-cash tertiary assets. All of that allowed us to raise over $1 billion in non-debt capital to fully fund that 12 capital plans. So in ‘12 similar to ‘13 we are outspending our free cash flow…

Excuse me, thank you James. All right for the development piece I’ll kind of add another layer to some other things that Tom and Matt and James have talked about. When we think driving higher rates of return there really are kind of two ways that you can impact it. First piece is just well performing alone and I will talk a little bit about the deliverability, how we think we can up with that in 2013 and then also just lowering your development cost and your operating cost going forward. So we got lot of material that we think you will find interesting. In terms of just kind of this first bullet, the way we are going to address deliverability is, in 2012 we have a very large land positions, so we laterally extended and so this year we are going to concentrate in those areas that we do have development infrastructure. And beyond just kind of a lateral or top view, we are going to put together a program that puts the well bores in kind of a side view and make sure they are in the right zone and we will talk a little bit about that. And then Matt mentioned kind of the success that we've seen with the ESPs. There really is a phenomenal economic result and because of the power and the saltwater distribution system that we have, we are one of the few companies that can actually employ ESP benefits. In terms of just the development costs and the operating costs themselves, Tom had mentioned and I'll second it, we have some of the premier teams in the business and I think that will be pretty apparent as we go through the presentation and then we are going to go through kind of…

I guess we are ready to get started again. My name is Rodney Johnson and I know its going to come as a surprise to everybody but I'm going to talk about the type curve. Just as a lead into that, let's talk a little bit about what our type curve is. Starting with the fact that three years ago as we entered in three or four years ago as we entered into display, we started showing you a proven type curve from our consultants. There are a lot of companies out there that actually develop their entire curves and they are not technically a proven type curve based on reserve results of the wells that are drilled. They maybe a projection of what they think the next group of wells would drill like etcetera. Ours we chose three years ago is to show you the consultant proven type curve and we've kept with that standing as we had moved forward. Now the difference is we've gone from 37 wells in the year-end 2010 to 145 year end 2011 to 644 this year end. So no surprise the numbers have moved around a little bit that hopefully we will give you a little clarity around why and how we see the play. More specifically, how we see the economics of the play, just not a simplified number and a lot of people like to use as an indicator, more general sense of the play. The first slide, we will kind of walk you down through derisked a resource play. What does that mean to us? Generally when we think about this play, I think if you are here from the beginning, we started this play by looking at the fact that we had 15,000 to 17,000 vertical wells across the…

First thing I want to talk about here is what our focus is? We are focused on low cost opportunities workover recompletions and drilling. We operate primarily almost exclusively in the Gulf of Mexico, shallow waters all our platforms of fixed structures, they are fixed to the bottom of the ocean; we don't have any floaters out there, we don't have any tension, we actually do not have any subsea completions either. Our properties range from the Western part in the Gulf of Mexico in Mustang Island all the way over to Eastern most portion in Pensacola. We have a very strong team; lot of experience; acquisitions, operations abandonment’s and we’ve got a fully staff team, we have reservoir engineers, production engineers, we hire and have full-time many other people they are on our offshore platform, we’ve got everything we need in house. Our production fourth quarter 2012, about 31.7000 barrels oil equivalent a day and that comes from 368 producing wells. We have 613 operated non-producing wells and we will address some of those a little bit later. We are very focused on safety and well-being of our employees and the environment, our INC to component ratio is very strong at 20% below the industry average. In quicker view of 2012, SandRidge acquired Dynamic in April of 2012, adding approximately 25,000 barrels a day of production, along the way SandRidge acquired additional properties through the Hunt acquisition, adding approximately 3000 barrels a day. Our fourth quarter production again 31.7000 barrels a day, highlighted by success in some low risk drilling rig completions and workover programs. Our total 2012 capital as you see $93 million drilling, $77 million in rig completions and about $4 million in facilities. Our business plan, pretty strong business plan; we want to find value accretive…

Hi, just a few slides on Corporate Reserves. As we think about it, 43% increase in SEC PV-10 value adjusted for sales and production to 7.5, net resource reserves and resource value, NAV of 28.6. Now, we did include about $1.7 billion worth of value for the appraisal area, when you get to the last slide I will kind of compare that we didn't include it in the total corporate at the end but we kind of talk about the compare and contrast of that number. Proved reserve replacement of 454%, increase in proved developed reserve value to 67% that number as I said as we start to think about bookings statistical PUDs next year in, we will probably go down some as you think about that and improved developed finding cost to 2,168. And we used the proved developed we think, we agree we think it’s probably a better indicator because it doesn't hide how many PUDs you may or may not have added into the true representation of throughput. If you think about this year end what comes to mind in my mind is our conversion to oil. How impactful our conversion to oil was a couple of years ago? If you think about the overall price debt that we dealt with this year end, last year end 411 or 412 down to 276 natural gas price, oil stayed relatively steady but that drop in natural gas prices as we have been a natural gas company would have been devastating to our reserves this year end. The way it was, if you kind of go through our waterfall, we had 24 million barrels of investment that's tertiary property CO2 recovery that we had in West Texas; we actually sold those early in the year, our acquisitions of Hunt…

I'd ask Matt and James to come up also. So I'm very proud of the team we've put together. I'm pleased with our results as we move out through Kansas so far and I'm hopeful today that you remember our strong liquidity position that we have $2.5 billion of liquidity, we have debt to EBITDA down to two times, that you’ll take away that we are a premier operator in the Mississippian and no other company has chosen to move across 200 miles of land and own an area, they put in their own infrastructure system with their own electrical system. I think you can see what the difference means to a company and rate of return whenever you implement all three of those together, electrical infrastructure with salt water disposal and then the drilling of these wells and then lastly just remember that everyday we chose to increase rates of return by driving down costs and so there's an intense focus on this whole group to know about every detail from a tank battery to a frac job to a rig and driving down costs and that's why we've been successful in increasing our rate of return. And with that, this team will be here available for questions.

So, the ESPs sounded very impressive but it sounds like the ability to deploy past 2013 is much less because of limited electrical infrastructure. And also then you have more decline rates, heavier decline rates on those higher IPs in 2013, so you are kind of running up and down the escalator more in 2014 and then I understand the lower IP rates in some of the extension Miss is not indicative of poor total IRRs but it certainly indicative of initial cash flow and as we think about getting your arms on operating cash flow basis around your CapEx and getting to breakeven at some point how should we think about 2014 and beyond when you have fewer ESPs being deployed maybe a higher decline rate and to a degree you are drilling more in the extension Miss not in appraisal area that you are getting less first year cash flow?

Yeah, yeah, there are several questions there within that question but on the ESP front, so the ability to install ESPs depend on one the most efficient way to do is when we have a little more electrical infrastructure in place and that's the cheapest way to operate ESPs. However, in areas that we don't have electrical infrastructure we can always run ESP on generators and so now what we are trying to do is get off diesel generators but they do have generators that you can run on natural gas which is very efficient. So the ability to (inaudible) those piece is really not limited on how many we put in but it's more based on what's the application for ESP, where in the life of the wells its best for ESPs and which areas works best for ESP. So at the end of 2012, we had 77 ESPs with 90 days or more production. Today, we have more than double that amount of ESPs running. They are just newer installations and for the year 2013, we're looking to install call 300 to 350 ESPs. So we're actually putting more and accelerating ESP installations. Not going the other way around. So all of that should improve, actually improve cash flow of the wells and you saw the, how the ESP wells, or ESP leases 77 we showed you on a normalized basis was actually outperforming the type curve. So that does give you upfront cash flow improvement which, at the end of the day gives you better rate return on the wells.

And the 2014 you expect to be able to maintain that ESP deployment?

Yeah, we should. I mean, we're going to drill 581 wells this year. Let’s assume we can drill similar number of wells in ‘14. We're continuing to build our electrical infrastructures and so yeah, I don't see that slowing down. In fact, I think it's going to speed up.

In terms of cash flow, the drilling plan is built into our model. So we got certain amount of wells we're drilling in Kansas and appraisal area, certainly lower Kansas and Southern Oklahoma. So the combination of those gets us a balance cash flow we still have 800,000 acres in Oklahoma to drill. So we got enough balance of the inventory that it gives us the right cash flow and if you look forward the next few years, our goal with the liquidity we have now, I think gets us through ‘14 to start to use some of those other sources of capital whether it's amortizing units, JV so our disposal system monetization to get us through ‘15, so the balance of the wells whether to use the ESPs or not is built into our plan.

With regard to the extension wells, you make an assumption that every well we drill in Finney County is going to be 60 barrels a day and where what you see is by if you look at the map, show the little dots where we drill wells and do focus on the best cash flowing in areas as I mentioned, rate return are the most important thing to the company. So what we do is when we have a well, there has a very high rate of return we tend to draw more wells around that. We haven’t drill many wells in Finney County because it didn’t come out on lower rate but what if you could move across Finney County and find wells instead of coming on 50 barrels a day, there you can find wells come on at 100 barrels a day, or 150 barrels a day and still have that low decline. We think they are out there and so we are willing to spend a small part of our budget to look for those appraisal wells and to find new areas. Now what we have also set the days at 90% of our budget is going to be within our infrastructure and obviously we are going to look at, trying to move the main to the right on the bell curve, so we do focus on rates return.

Hi guys. I have question about slide, I think it’s a 115, the SEC PV-10 your Mid-Continent, which you are telling us remain flat at $2.3 billion year-over-year and I guess what I am wondering is you spent about $1.4 billion in CapEx, gross of your carries, I assume that cash flow a couple of $100 million, may be $350 million. So your net investment in this asset year-over-year was about $1 billion so could you explain to us why it’s flat, I am sure some of it’s gas leverage?

Sure. First of, if you look at slide there is $420 million of production value that took place during the year. So you are offsetting at $420 million of production value and where the type curve hit as more was probably on PV-10 then it did on the adjustment to the reserves. So a large part you had the pricing adjustment in the 675 and you also have the revision to the type curve in that 675. So while it did remain somewhat flat, we would expect it to continue to grow was we move forward, right and those are the previous adjustments that took place that made up that 675.

Okay, got, and that's what repeat in the mind, second and it’s my last question. About your PV-10, so your PV-10 pro forma for the Permian sale is $4.3 billion and your enterprise value is $7.1 billion. So clearly your PV-10 encapsulates everything all the value you can create in the next five years, but you are also telling us that you can't hold all your acreage your 15% HBP and not to worry about that because you can pick up acreage on the (inaudible) for really well, so what is the delta between the $4.3 billion and $7 billion, $7.1 billion is it gas leverage, is it acreage value in the out years which is interesting because you are also telling us not to worry about the production in your type curve after your five, is it the value of your salt water disposal system is that what I am missing, if you could just help us with that? Thanks.

Sure, keep in mind that the $4.3 billion of PV-10 is proved reserves only and so gives no credit for probable, possible or un-book. So if you just go back last year the year before gave us no value for the probable and possible that would have been incorrect because we clearly drilled new areas, proved up new locations and booked the lot of new reserves. So we grow our drilling plan, we've got a big resource potential and so the way you want to look on, on PV-10 our resource potential if you use some of the NAV estimates and resource estimates that people use you get much higher than $4.3 billion. So I think just valuing only on the proved reserves leaves out a large chunk of the acreage in the Mississippian and the value there, there's a couple of other things you mentioned saltwater disposal I mean that's probably in there too but I think the value of the undeveloped acreage of the Miss is multiples of what that would be.

With regard to the acreage and HBP acreage there really wasn’t any such terminology prior to 2008. Companies never worried about HBP their acreage because it was really meaningless and for us, yes we have a large acreage position, we might drill all of it, we might not drill all of it, we have an infrastructure system in place that allows us to capture acreage that other companies can't use, the average cost per acre that we have across the whole Mississippian play is just over $200 per acre. It’s really in my opinion a meaningless term to talk about how we are going to HBP our acreage. I mean would you rather companies go out and spend in areas that might not work as well just so that they can claim that they are HBP is their acreage. So I'd just refuse to talk about HBP and acreage.

I have two questions, one quick, one a little bit longer. Can you give us some detail on the PV-10 broken down into PDP and PUD in the Mississippian, that's the quick one. The longer one, short question but potentially a longer answer, can you walk us through the economics and putative magnitudes that would come from an SWD monetization, there are a lot of different numbers floating around out there and can you kind of benchmark us in terms of what those, what you think how realistic they are.

I think we can do both. Rodney if you’ll take the first one, and James the second or you want to take it.

In terms of the system we have invested $450 million and at the end of the year we will have $650 million of capital invested in it. I gave you some of the other stats, I don't know whether it’d be meaningful evaluation wise but 700 miles of gathering lines, 1.6 million disposal capacity and at year end 106 disposal wells drilled and so what we are giving out is kind of an EBITDA number of the system but there's been some numbers doing the round by analyst and others evaluating these kind of assets obviously EBITDA multiple is an easy one but even as a multiple of books so we think if we have $400 million to $650 million invested in it, the evaluation starting and building dollars is pretty easy place to get to.

Follow quickly, would that imply a change to your LOE and of what magnitude.

Yes, it would imply because we would be paying a fee to dispose off that water. Now it’s much less expensive than trucking the water at $2 a barrel disposing it off into a system at a cost of fraction of that. So would have a change in our LOE but it would be value enhancing. The multiple that you are selling this asset at is greater than your increase in LOE. So there's a pretty big valuation arbitrage just like drop down MLPs that companies do, it is still big evaluation arbitrage and any increase in LOE and the enterprise value boost that we will get.

Yeah, on 115 we showed 60% proved developed reserve value for the Mid-Continent, most of that is the Mississippian and your $2.3 billion worth of value so 40% would be in the puds and 60% would be in the PDP through PBP category. I can if you want come over afterwards, I can give you a complete table.

Tom, just a little bit of clarification in terms of the JV care, when does that specifically run out and when you talked about on your call along Friday, about 1.75 billion CapEx, how does that play in to the funding gap there?

In to ‘14?

In to 14, yes.

Yeah, we won't be able to have guidance in the CapEx next year, but depending on if whether we did a JV in ‘13 or not and had additional carry in ‘14, assuming we don’t, the JV does run out in the first quarter of ‘14, we're projecting. So about $100 million in to ‘14. I think $550 million this year of carry. And the other way to look at this is that CapEx is always fungible. If we don’t have success in monetizing all our disposable systems, selling unit, or in doing a JV than CapEx would narrow the shrink.

Great, appreciate that and maybe switching over a little bit to moving to development mode, you talked about the different lithologies in each one of the respective counties and when you move to a development mode, it seems like one of the benefits is, economies of scale and being able to prosecute a similar program across a whole sloth of acreage, does this create any challenges to moving in to a development mode because the variability of how you attack each one of the plays or each one of the counties little differently based on the rock properties?

Not based on the rock properties. The only, we've already accomplished the difficulties of moving in development role by the amount of money we spent to-date on infrastructure. So from this point forward, we're already more in development mode. In fact, in 2013, we're going to be 90% in development within inside our infrastructure. My belief is as I said there can even be more than four wells drilled per section as we are seeing other operators do and the infrastructure continues to be a very premium corner of display for us. We will be able to drill if we chose to just in the southern county as we’ve already discovered in Kansas and Oklahoma for many, many years.

Just following up on that question actually, you mentioned earlier that when you see good wells, see want to move more into development mode around those areas. That would seem to imply, that you think there is potential to narrow focus to sweet spots. On one hand though you are saying the lithology changes potentially in every lateral section, as you do move into development mode, do you think you get better results if you drill around some of the good wells you have already drilled or will it just remains statistically and doesn’t really matter where you drill?

It is fairly hard to explain off of the map that we use, but in each of these counties there is hundreds of thousands acres of land with potential and every time we drill in new areas it doesn’t prove up one just well, it proves up areas of wells. So across our Alfalfa county for example we have the most wells, we are drilling in areas of fairly prolific wells, currently if because we have already discovered that and will have several years in fact just to drill within Alfalfa county. So the answer to the question is yes. So every time that we find a good well it tends to open up a fairly large area of new opportunity for us and one of the reasons that we would have bought made an acquisition last year of 1000 barrels a day of oil equivalent was because that 50,000 acres of land happen to fit right on top of our infrastructure system and in areas that where the best wells were being drilled.

Great thanks. Let me ask one follow-up. When look at the resource value assumptions that you have talked to here, how does that play into what you will be willing to accept in terms of evaluation for your Kansas properties as you complete the JV?

We well review that, we haven't talk to any potential other than just some (inaudible) discussions with any potential JV partners, and what we see is the cost or the amount per acre that we get is more around the company, so we believe that even that our partners would have paid $3,000 or $4000 on acre for the current JVs are both very happy because they have the experience and for decades who will be drilling with us and use that experience to save on cost per well and if the benefits of us knowing so much about this play, so it can be quantified we do quantified around a dollar for acre but its really much different to that, and so we’ll get the best we can but at the other day we do want to get to that point and we think the JV does that of getting through 2015 where we grow our company and we are willing to give up some acres to do that, and some more expertise, so I can't answer to the question is to how much but we believe that they will have ample evidence after we drill another 200 wells in Kansas but there is acreage there that is much like for what we have in Oklahoma.

Tom, two questions. One is can you just talk to us a little bit give us some color on your reaction to the Chesapeake Sinopec JV and it’s my understanding that acreage is very much contagious with your own acreage there in Oklahoma that will be number one. And then number two is if you do the Kansas JV here in 2013 should we assume that that would be targeted more toward Kansas properties on the border where you are drilling wells as opposed to the appraisal properties in the northwest.

My expectation would be all the way across Kansas because if you do a JV usually the partner wants to have your knowledge in all the counties not just in a small portion of those. So I think the JV partner and us would probably prefer to have a full western Kansas JV. With regard to the Chesapeake Sinopec JV I think it was one that if you I think its reasonable to expect that if its not your target area first of all to say yes Chesapeake’s acreage is very good, they have acreage mixed with us across all the counties in Oklahoma if we had that we would put a lot of bricks on it and just like they will with Sinopec. I think we are somewhat different. in fact in the two JVs we've done have been somewhat different and we've said that our cost for drilling wells are less than our peers, I think that is we can quantify at least $1.1 million per well that we are under the average of our peers in the play. The infrastructure is an incredibly important part of this that we have or the infrastructure in place. So the JV partner doesn't have to come and buy into or build out additional infrastructure and we already have 31 rigs that are running into place so the ramp the PV of the JV with us happens very quickly and then the electrical infrastructure is just the change in the rate of return of having ESP on a well versus not having ESP is also dramatic. I think that not anything Chesapeake does a very good job of drilling wells, they do an incredible job of putting together big plays. This just happens to be our niche and our focus area.

Two questions Tom, the slide that was chatted about earlier with the PV-10s in the Miss, I'm curious if we were sitting here a year from now, and we put revisions aside so no type curves, no commodity prices, and you look to the CapEx budget, you put into work this year, in your mind what would that imply about what that PV-10 should look like a year from now, that's the first question. And the other sort of related but not at the company level but at a well level, you've talked about the $3 million, you've talked about rates of returns, have you looked at the NPV of a well, so if you spend $3 million what do you think the value is that you create by spending that money.

Yes, its obviously very difficult to estimate what the PV-10 is going to be but I think one of the things Rodney was alluding to earlier is the way we or the potential where we can book puds going forward right now in the Mississippian which is where we are doing all our drilling essentially. The pud to PDP ratio is just a little bit over one to one, okay and we go into more of a statistical booking of puds and so when we think of PV-10 of the total proved for the Miss right now is $2.3 billion and 60% of that is puds and we can book a multiple of that and you can have several billion dollars of increasing value just based on the different methodology in spud booking.

I would also add that my opinion is that the next year the type curve will have less decline and you won't have a curve that's below what the vertical wells have been producing for decades.

Two unrelated questions, one Devon came out and they are increasing activity and they are intending to run seismic over their entire acreage. You guys haven't really been very vocal about thinking that seismic is worth while. So if somebody could comment on that and in the meantime a lot of people put forth that they think gee you ought to sell the Gulf of Mexico and I know you guys disagree with that. I think it would be useful if you would have addressed to the group why it doesn’t then make sense?

Yeah, with regard to seismic, we just have so much well controlled in the areas that we're drilling that you have a good understanding of what sub-surface looks like. So if you 17,000 vertical wells or every time we drill saltwater disposal well, we get a log, that can tell you where structure is, you can do just basic geology and understand what structure is and we're having very good success in drilling oil structure wells. So and honestly if you take a look at a log it looks wet, because it produces a lot of water. So for us, we embrace the challenges that are there with the Mississippian because that’s the reason the opportunity is there. We're drilling more conventional rock that has a little bit better permeability then a nanodarsey reservoir but also with that that challenge is that in the past history we’d know we’d produce a lot of water in this reservoir. So what we've done is to say how is the least expensive way we can drill a well with a least expensive way if you have a lot of sub-surfaces that you don’t really need to spend on seismic. Now we do have plans out across the extension area or the appraisal areas that we will shoot some seismic and try to understand some different ways to operate and Repsol is leading with that also and trying to look at different ideas across the north western part of Kansas. Second question about the Gulf of Mexico. I’ve got my opinion somebody also want to talk about a little bit?

Well, you know, the Gulf of Mexico, the whole plan, the whole idea of the Gulf of Mexico purchase, we can spend minimum amount of CapEx and keep production flat with low or free cash flows. So in Q4 cash flow about $40 million, we expect about $160 million of free cash flow this year, excluding the impact of P&A. So in 2013 there is a big P&A charge of 120 million but half of that 60 million or so that is from kind of one-time items of some legacy, P&A that we would have to do anyway and that our commitment to our superior on the initial acquisition of Bullwinkle. So going forward on the P&A front we are down to kind of 40, 50, 60 million levels. We do have significant free cash flow that’s generated of those assets. So it’s really worked out as we plan and even better and I think Gary talked a little bit some of the successful evidence on the recompletions and drilling and we continue to perform on some of those opportunities we should go to outperform our plan.

Just add one thing to what Matt said, we model that pretty much flat production from where we bought it and we have been able to exceed that. So the success we have had, we have been very happy with so far also we have with Mississippian a long life on (inaudible) asset, 20 year or (inaudible) kind of asset that requires a lot of capital so to blend in, our third issue of our business of a shorter reserve life froze our free cash flow helps deliver the business, we think it’s a reasonable balance I suppose to having a 20, 25 year reserve life to bring it down a little bit, we have run many models on divesting it what it does to cash flow, leverage, liquidity interest coverage all the measures that people use and they are all pretty dilutive.

My last comment there is just that the Gulf of Mexico, shallow, end of life, reserves that we look at is also a nitch that the Dynamic/SandRidge team does an exceptional job, they have very little competition and you can buy some of the cheapest oil in the country sitting right there. We sold the most expensive oil in the country in the Permian. So I think until a lot more people do what these guys do that you are going to continue to be able to make niche acquisitions like the Hunt acquisition and we can go through that again and so there is no better rate of return on acquisition if we can continue to make acquisitions like that I think we will be foolish to sell the Gulf of Mexico.

Tom, just adding onto Dwayne’s question a little bit, if you can talk about the rock properties where you are versus you know where Range and Devon closer to the Nemaha ridge and I know some people are looking at results and trying to compare them the years, just wonder if you could comment?

Sure, there are areas within every county across Mississippian where you can drill within 15 or 20 miles and have exceptional results, it doesn't necessarily have to be in one type of reservoir that's what we are trying to show is that we have some wells that produce out of the Mississippi chat, they are very good wells, we have very good wells out of the dolomite just high across the higher decline, higher fluid level wells and then we have tight wells that are all limestone, that also have very high rates of return because they come on at very rate but decline very quickly. What we have a better poorest rock that can be at a low initial IP would have very long and steady declines. So the Mississippian can't be classified as one play and one particular area that is only this can happen as what it can be is multiple fields across a very, very large area that if you are willing to move some water and putting infrastructure system and keep your cost low as what enough operators don't do is they don't cost, they don't keep their eye on how it costs them, they keep worrying about what their IP is and that's not only in the Mississippian, that's across our industry is that we had become a series of companies or an industry that only wants to have a 1,000 barrels a day of IP, it doesn't care whether we make money or not and that in my opinion if more people would focus on how much it costs them to drill a well that we would end up making more money as an industry and that’s just my opinion.

And then just one follow-up to that Tom, David when he was up there, he talked about all the different formations, that now you are looking at in a couple of counties, I guess going forward how are you going to best identify that, are you going to try to go after I guess what the highest rate of return I guess in each of those formations?

In new counties we are drilling in or…?

Right, and in the two that he was talking about and then as you kind of progressed past those two, I guess you have done with Garfield and etcetera?

Yeah, those are still obviously very early, there's only few data points, what we try and say there is from an asset value there are other potential zones that are very productive; we will probably drill a handful of wells this year to see what kind of IPs, what kind of EURs, what kind of cost, what kind of rate of returns we are getting and then if it works we will built into the programs, stay within our $1.75 billion CapEx, but I think the point is that historically in the last three years we've been really targeting just the top of the Miss and what we are trying to say is there are more resource opportunities going to the middle Miss, lower Miss and potentially down into the Woodford.

And just on top of that if you noticed on the slide that we didn't let there be a one-day, five-day or 30-day IP before we declared victory for all these new zones so we waited 200 days and watched the wells and see what the decline rate was and it looks favorable, but we are not going to jump in and have all of our rigs trying to drill those zones; we will move into it methodically.

I have a question about the Nemaha Ridge why you didn't focus on it and whether it is in fact the lowest cost and best part of the Mississippian and how your assets then would compare to ranges, smaller participation on that Ridge?

Sure, we do have acreage along the ridge and we have good wells there, range has very good wells, we've participated in a lot of range wells also. But we also have as good if not better rates of return in wells that aren't near the ridge. So as you move from the Nemaha Ridge to the west that happens to encompass our acreage I think we can put up the well reserves we have in fact we have, we put every well reserve we have on a slide that shows what our average well is and I think we compare favorably with everyone and then there's no one who can drill a well cheaper than we do. So we think we are as good as anyone if not bad with the well; we think we are best in class on rate of return.

Just a quick question on Southwest POP, contract, when I was kind of playing with the numbers a year ago, it seemed like after train on a wider gas basis and your remaining volumes because you don't get that premium pricing and there are some liquids in it. But there wasn't that much uplift once you take the NGLs out. Do you see that changing now maybe because there's more Mt. Belvieu pricing with new transportation infrastructure?

Yeah, you know I do, I think that contract will enhance the play and just in terms of putting some numbers around that just the contract itself we saw kind of 15% uplift in value from a rate of return is kind of 10% to 11% to 12% uplift. In other words if we ran the year end rate of return at $3.1 million well cost without that contract I think we are around 44% to 45% with the contract and it buckets up to about 50% and so yeah we're getting an uplift from the added NGLs that we will be recovering.

Tom, two quick questions; it looks like the 2013 guidance is pointing to a decrease in G&A, I guess on a barrel basis; can you talk about any initiatives around that and then secondly, what's the useful life of the ESPs and any added cost to the operating structure?

Yeah, ESP does add about $200,000 to put on new ESP and then the life of that is just really around what the volume of the production is. So you can move from ESP as the production declines, maybe down to gas lift and ultimately rod pump in the later life of the well. So I don't know, its different wells last longer but we've had ESP now I guess the ESP is in more than a year and so we think they can last for a substantial amount of time.

Right, on the G&A midpoint guidance, previous midpoint guidance, I think we have about $20 million reduction in G&A; some of that is due to some headcount reductions; some is due to headcount reductions related to the Permian sale and just general kind of tightening some of the spending on corporate and other. So that was a marked effort between October and now to bring that down a bit.

Slide 110, can you please provide that for Miss only, Mississippian only and I think you said you have, this is by well count PV-10, I think you said you had basically two to one for this year’s drilling at the Miss; so if you guys are doing 581 gross wells, you have roughly 1,100 PUDs in the Miss booked. Is that right or how many Miss PUDs do you have gross in that if you can?

Good question, we have to go offline to get a table put together for Miss or Miss not.

But just in general, how many can, Miss PUDs only?

Yeah. It was, we have 644 PDP wells and it’s around 750, I can't remember the exact number.

So that’s gross or net?

That’s gross.

So you are drilling 581 and you only have 700 to change PUDs so you are going like a year and half of inventory booked as PUDs?

Yes, that's correct. That’s the one-to-one ratio that we are talking about earlier.

Okay and then going to slide 45, all those virtually almost all of them are upper Miss only zone, do you have any…

Yes, yes, the only thing we book so far again. We are kind of the PUD booking methodology is kind of one of booking around now and they are all in the upper part of Miss, we don’t have anything extra book beyond that.

So like of these 581 wells gross drills you are going to drill this year, how many are you going to try to experiment in the middle Miss and the lower Miss and…

We don’t have a number in mind, we just start looking that production data it does look promising, but we haven’t set out of program on experimenting how many we are going to do there. We do I am going to say probably less than 10% of wells will be going into lower portion of the Miss.

Is so far this as page 45, that just an isolated example or have you guys have done that more than once?

I am sorry I don’t get that.

Where you actually drill multi-zones in a relatively narrow acreage area we all know that’s all productive?

Where we drilling?

I guess the question is the 11,000 locations is basically that's been above or Miss only, right and potentially you have multiples of that if multiple zones work?

Yes, yes. Potentially we do have multiple zones potentially we are looking for laterals in or drilled deeper put a lateral somewhere in there and then do a vertical completion on the well and there are lot of different things to do out here and I think you look like the Wolfcamp, West Texas where they upper, middle, lower Wolfcamp in the shale, their are operators are talking doing two, three, four laterals to extract hydrocarbons from each of those reservoirs. There is an opportunity here to maybe do that as well but we are not there yet on to that level.

Do you think you will do enough this year to have an idea at the end of the year that with now these zones work across wider parts of acreage?

I don't know we will do enough to say the work across our 1.85 million acres, I think we will do enough to test the concept in localized areas where we think there is good opportunities Woodford, for good opportunities middle Mississippian development.

Okay. Thanks.

I think that what we said on the slide easily that we think we at least 350,000 acres and 340,000 acres that has this potential in that one particular area. The 11,000 locations also only counts four wells per section and then at the more we know and the more we see, we will start drilling our wells the spring in these new zones, we will see we know something about the end of year and be able to book some reserves there.

Excuse me, I have the question on your acreage position, hoping you can clarify it for me, the 1.85 million net acres you have talked about how you have 500,000 in the appraisal area of the Miss, I think you also said earlier you had 800,000 acres yet to drill in Oklahoma, is that acreage position gross of the minority interest in the trusts and is the acreage position gross or net of the JVs, could you just flush out the remaining quantities to get us to 1.85 and talk about your accounting methodology for trusting the JVs?

I think I can. We have 1.85 million net acres that's a net to SandRidge. The trust acreage is included in that acreage and then what was the other question.

Could you quantify how much the trust acreage is and then previous question you said that 15% of the acreage is producing but you talked about 800,000 yet to drill the in Oklahoma, 500,000 in the appraisal area, I guess the balance is in more southern counties in Kansas.

Yeah.

And more clarification in general would be appreciated.

Sure. The Trust’s SDT had 43,000 acreage net, SDR has 53,000. There's maps even in both the respective S1s.

And for the balance between the 800,000 to 500,000 to get you to the 1.85?

Yes, and that does, that 1.85 does exclude our joint venture partners. So that excludes the two JVs we've done.

Alright, 1.35 so the remaining 500,000, that's the southern counties in Kansas?

Southern, did you get the extension, I mean the appraisal area?

Appraisal you said 500?

So then the difference is Southern Kansas.

Yeah, it seems like a lot of people have been focusing attention on the PV-10 or the Mid-Continent and how that has failed to grow year-over-year despite the $1 billion net incremental spend and I guess what I would like to get a better view of is that makes sense that the wells are gassier and that the SEC pricing is 275 but that's not indicative of the current strip. So maybe if you use a more realistic for $4.50 per number you know where do you guys see more of a market based PV-10 value of your Mississippian acreage because from everything I've seen 275 is really not a market indicative price for gas based on the current strip?

Yes, we agree with you unfortunately we are forced to use certainly for the SEC guidelines, forced to use the 275. So I think if we came up here and had 400 or 450 we would have an equal number of people complaining that we were hiding something but so we try to use the SEC what they require. I think you will see us run cases and we will put them in presentations at current strips, various prices $4 flat and things like that.

Have you run those cases and if you have what would be PV-10 of your Mid-Continent assets be under those model scenarios.

I don't think we have that right here. We’ve run it before but we don't have it in the presentation.

Okay. So I'm just…

It’s a good idea.

That value.

Okay.

Thank you. Page 27 you show us the 77 ESP wells, I am just wondering if you give us a little more data on projecting forward how many wells or what percent of wells will have ESPs say in one year or two years and what kind of lift you see for the blended RORs, EURs, etcetera. Thank you.

Yeah, you know I think couple of things; you are referring to page 77, that’s a page 27, that’s a 77 ESP well slide. Okay? And we said that these wells would, 90 days or better production is outperforming the type curve, the year end type curve and so in Q4, how were many wells we put in ESP, that’s included in our cost. That goes to 3.1 million. So, wells without ESPs were less, maybe $3 million somewhere in there, okay. So on a blended rate of return, if we took $3.1 million and say that’s kind of the blended case or blended sample of wells within without ESPs, at the year-end type curve, we're looking at 50% rate of return and so if we can put more wells on ESP, we can put a more percentage of wells in ESP this year than that blended rate of return should go up, okay. And so that’s good point you that brought up. So when we do our year end reserves, it doesn’t account for wells on ESPs or wells without ESPs. It just takes a blended case of all 644 wells that we drilled across the 230 miles whether it has ESPs or not and that’s why we believe as we accelerate the installation of ESPs, we can bring the type curve up and therefore the rate return as well.

Could you project for us perhaps of how many wells might have ESPs at the end of this next year? Thank you.

Yeah, we have planned 350 wells that ESPs that we will install in 2013.

This is a question about your process as you go into the, I guess, what you call the appraisal area. I noticed on the slide when you show each of those up, those wells that you loved to (inaudible) out, that your log is actually from the salt water disposal well, which makes sense because that's where you are drilling normally the way down (inaudible) but I guess my question is do you drill that saltwater disposable first before you go in and put in your first producer in the area and if you do, what would you need to see, or can you imagine anything that you might see on that log as you go down to the Arbuckle that would make you choose to place it lateral not right below down on conformity but instead go ahead and choose something that in middle Mississippian right of the back, have you ever done that and what would you need to see ahead of time to choose that up?

Sure. We look that at every appraisal area has either a saltwater disposal well or multiple wells that have been drilling vertically. And then not only that well but then you correlate it to other wells and you look for primary porosity as the easiest one to look at on, on electrical log and say this is the area that we want to be and it can be somewhere up near the top of the Mississippian but doesn’t have to be right below the unconformity.

Would you have choose to not near the top, straight off, into the middle?

We have, we’ve looked at that, we haven’t yet done too much extend because we like the idea around the original part of play was that erosional feature of against the Pennsylvania and conformity is helping to create the porosity away from what you see in that one isolated well bore log. But as we see other people and us have success, sure there can be across the streets that you rang in to better sets of porosity down in the middle Mississippian where lot of the older wells you’ve been producing front, obviously a vertical well is going to be producing from the top to bottom and there are some areas where you can see porosity (inaudible) go for many miles and we look to target some of those.

I got a question (inaudible) somebody earlier asked a question about seismic. In lieu to seismic we do get a lot of well data when we drill wells because it’s like more positive indication of data to analyze. So in an appraisal area and a lot of areas frankly when we drill a disposal well of course we run our triple combo which gives resistivity and porosity and then you see how thick the Mississippian and we’ll run an emerald log to help us understand the saturations because this Mississippian can be 200, 300, 400, 500 feet, so you really know where it is that has the highest saturated hydrocarbon in that well and then sometimes we’ll run an imaging log to help us understand the fraction in that area and so we got all this data points now with the 160 disposal wells with modern logs, we can start mapping this thing out and understand how the trends are work best to place this laterals. And we say the top of Mississippian we usually talking the top hundred feet probably lot of times top 50, 60 feet but with in even that range, you can pin point down to 50, 20 feet that will make a difference, I think Dave had a lot of talk about that earlier in his presentation, so that is part of the learning curve and some of the tools we are using to help us hopefully continue shift this distribution of IPs and URs to the right as we move forward.

(Inaudible) for James. Just think about the CapEx for 2013 and maybe assuming as comparable number through 2014, if you knew to reduce that by say $300 million and $400 million just from cash flow perspective and as you think about the $858 million of EBITDA projection for 2013, what will be the impact to that number and how close to understanding that kind of EBITDA target are you, if you have to reduce CapEx this year or next?

Yeah, we do a lot of sensitivity to come up with what’s the right budget for this. Some of this is dependent on how much you want to grow, how much capital we have available what is the right amount of leverage, what the funding sources do we have, we blend all those together and came up with the 175 versus what leverage to pull, I don't have for you a variants if we spend 1.2, 1.5, 1.75, 2, 2.25, here's the various EBITDA so we don't provide that, I think people have models that analysts do and others that can sensitize that but we don't really have variants around that what I, only variants we really publish is commodity sensitivity in it. The dollar change (inaudible) not that impactful this year because we are so well-hedged, its under $1 million and $0.10 change in gas is about $9 million because we are selling hedged gas. So that's really the most sensitivity we provide.

Okay, understood, the three times leverage target is that a net leverage target.

Yes, those are all leverage so we are two times now and our bank covenants are net leveraging and the rating agencies may be don’t look at it in leverage we tend to think about it in terms of that leverage that we could industries pay down debt if we needed to, pay down if we needed to, we could cut back CapEx.

Hi, so just a question on your CapEx numbers, if I look at 2013 guidance and I take the total expected cost in the Miss and add the saltwater disposal to that and divide it by the net wells I get a cost of like $3.6 million per well which is very similar to 2012 if you do the exact same things, so I'm just kind of wondering I thought the costs were supposed to be coming down.

Yeah, that's good question and so you can see the cost progression in 2012 from 3.6 to 3.1 in Q4 but in our budgeting we are still using that I think 3.2 or 3.25 for well costs. So hopefully we can come in below that budget. So if we ended the fourth quarter at 3.1 right and we continue to get that cost down $3 million or below then I think we will get to the numbers you are thinking about.

That those not include saltwater disposal, correct?

That's correct.

We are looking at saltwater disposals as a system as a separate asset that we will invest again but to monetize or if you look at another away that over the course of life of the wells we only put in 10 wells for disposal we could add about $200,000 per well, for saltwater disposal. Any other questions.

Yeah, Tom off of the webcast we've got a couple of questions, maybe for Rodney, what's the risk of reserve damage if you are running ESPs.

I think there is very little risk of reserve damage, when you are thinking even moving 4000, 5000, 6000, 7000, 8000 barrels of water a day and you spread that out over a 4500 foot lateral, you are getting barely any movement in the reservoir. So the risk of the damage like we might think about in the Gulf Coast when you are over drilling the reservoir you are creating a lot of drown down pressure and then the formation might cave in or you might pull in fines, we don't have those issues in this reservoir. This is a pretty competent rock.

And what's the company's philosophy for keeping its CapEx within its cash flow?

We think about it in a couple of different ways. I'll mention the leverage again, really, its going to be dependent on our leverage, how much we are hedged or liquidity and then what funding sources we have available. So as we've said in the last if you look at our funding chart that I showed with CapEx and cash flow and CapEx, its been that way the last few years. We've had some reasonable sources to raise capital and we think of a prudent manner whether it's been a royalty trust or in cash. The non-core asset sales or bigger asset sales. If we can fund it in a prudent manner, not over lever the company, not dilute the shareholders and we think out spending in the near-term is the right thing to do. That being said, we realize that at sometime we need to get closer to cash flow and that’s our goal. So in the next few years, when you do start thinking about, showing funding out through ‘15, narrowing that cash flow to CapEx gap, it's a big goal for us.

Another question off the webcast, how much of the production guidance for 2013 as a result of the change in the Atlas contract?

Yeah. So it's all a change in the NGLs and the gas and so in 2012, we produced, from the Mississippian we are producing about 100,000 barrels of NGLs and in 2013, as a result of the Atlas contract; we expect to produce about 1 million barrels of total NGLs in the Miss. But we're also shrinking the gas because you are taking NGLs out of gas. We are also losing about 300,000 barrels worth of gas shrinkage. So the net impact is 600,000 to 700,000 barrels, that’s attributable to the contract.

As always we're very thankful to have so many people come and listen to the presentation. I am very proud of our team for putting it together and all the work they do through the year and we look forward to seeing you next year. Thank you.