SandRidge Energy, Inc. (SD) Q1 2013 Earnings Report, Transcript and Summary

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. This year we're drilling within that infrastructure and I think that makes 2013 a pivotal year for the company and we want to continue to improve our credit metrics. So one of the things James will be talking about is just the continuing efforts to make the company in a better financial position, which today we're in the best financial position the company has ever been in our six year history. This is just a slide that goes to show that really if you just focus on the bottom right, on the financial leverage of the company, proforma of the Permian sale, we're in the best debt-to-EBITDA position that we've been in and we've historically had a high leverage position, especially after we moved out of the natural gas production after we moved from a product that as EBITDA was falling in 2008, 2009, with natural gas process moving down, we had to use some leverage to ride the ship and we were able to do that and now successfully have moved forward with our financial leverage down to approximately two times. We did make a move as I mentioned in 2009 into oil that was with building around the Permian, we chose the Permian at that time, because no one else was really working there. We liked the shallow nature of the Central Basin Platform. It was the area that had produced the most oil and gas in the tightest and concentration of any place onshore US that had 2.5 million acres that produced billions of barrels of oil. So we thought that the best place to find oil was where it already been found and we focused on the Permian Basin. We invested about $1.2 billion over the course of the couple of years and then end up making a sale for $2.6 billion and just closed. So we can see that our strategic rationale behind that was that we bought Permian assets at a time when other people weren’t buying in 2009 and early 2010. And then we chose to sale the Permian when those assets had moved up in price and became one of the hotter places in United States to sell. And I think that and everybody knows today that we got out at a good time and today is more of a buyer’s market. There is a lot of properties held for sale and I think we timed that perfectly to move our Permian oil and to put the company in a great financial position. So today’s agenda is again my comments are very brief, but today’s agenda is we will talk about the Mississippian, we will talk about the Gulf of Mexico, we will talk about our corporate finance and then Rodney will go through reserves in the Mississippian. It is our growth engine. We will be drilling a lot of wells there; over 580 wells this year. So it is an area that we’ll see continued production growth and EBITDA growth. We will continue to delineate and develop our Kansas acreage. We will drill 200 wells in Kansas this year, I got lot of questions about Kansas; we will dive into that in deep detail. There are some beliefs that no wells in Kansas are any good, well that’s just not true. There are good areas to drill in Kansas and we have lot of acreage in Kansas, over 1 million acres, but there is nothing geologically that changes once you cross from Alfalfa County to Harper County Kansas; its just that’s a man-made barrier. And the geology is still the same, so we will go into that. We will also talk about our operational initiatives; Dave Lawler will spend a lot of time talking about how we have moved our drilling costs down, how we continue to move our costs down and how the three logistical changes and efficiencies that we have moved from $3.6 million per well to $3.1 million per well. Keep in mind, every time we drill our 581 wells this year we are saving over a $1 million over the average of our peers. We have higher rates of return because of that, so there are two sides to rate of return, its how much oil you find and how much it cost you to get, so the Mississippian has always been a play, an idea that you know you are in oil system, it’s just how easily you can get that or how cheaply you can get that oil out and that's what we have worked on the most is how do we control costs. So there are really two kinds of place you can be in today where you might own 1 million acres of land onshore US, you can have ultra type reservoirs that have never been drilled before and those can be very profitable, but you have to spend more money in order to find more oil, that’s the way you increase your rates of return. In hours its just not ultra-type, so what we do is we try to spend less money to find how much oil is attractable; we don't have to spend more to get our more oil, we just try to spend less money to get a higher rate of return and I think we are being very successful with that; driven around the saltwater disposal system. And then we will talk about the much debated and much discussed type curve. So that's taken on a life of its own and hopefully Rodney will be able to discuss that and give you a better clarity. So the Gulf of Mexico, Gary Janik is going to be discussing that; our results have been extremely good, better than we expected when we bought that and we will spend a lot of time talking about how much the production has held on, the bolt-on acquisitions we made and it does generate free cash flow for us to drill on Mississippian asset. James will spend his time talking about corporate finance. We are in the strongest position in our history. We have with the premium divestiture, we have the ability to fund well into our 2014 capital plan and that gives us multiple options to fund our Mississippian development out through 2015 and James will be talking about two or three of those as we as a team, management team, what we do is focus on now how do we get ourselves funded through 2015. If we are going to be out spending cash flow we need to know how we are going to be funding that or we’ll have to have CapEx out in the future, and then lastly, just the corporate reserves. So with that, I'll turn it over to Matt and we can start today's program. Thank you very much.

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. Reserves in the play; we have increased reserves by 77% to 227 million barrels of oil equivalent. Tom mentioned, we continue to delineate the play drilling an additional 400 wells in 2012, so this is a very new play. In 2010, we drilled 37 wells, and in 2011 we had about 145 wells in our database and by year end in 2012 we had about 644 wells in the database and through February we are up to 690 wells, so a lot of wells, a lot of data and certainly more history. We've expanded our saltwater disposal and electrical infrastructure and what that does is that substantially reduces LOE and so you’ll see really a major LOE reduction just year-over-year in this play and I'll talk a little about the well cost already, but we have been able to reduce well cost by $0.5 million of well just in 2012 and there is three or four more initiatives that Dave is going to talk about that’s underway now and what we hope to do is to reduce well cost by down to $3 million or even below exiting this year. The Gulf of Mexico, we bought DOR last April and then we did a little blot-on acquisition with Hunt in June of last year and those two, at that time, at the time of acquisitions, those two assets were combining for about 25,000 to 26,000 a day and today we are at over 30,000 a day with those two assets and so we will talk a little bit more about that. Our plan in the Gulf of Mexico is to spend about $200 million a year and keep that production essentially flat and throwing out some free cash flow that we will reinvest into the Mississippian. The Permian Basin, we just sold an asset there that was producing about 23,000 barrels a day in Q4 for $2.6 billion; we paid out some debt, reduced debt and it also gives us funding for our Mississippian play. And of course, the financials, Jay is going to get into more detail, but we're in a very good financial position today. So just looking at year-over-year comparison from last Analyst Day to this Analyst Day, when we were here last year; we're producing about 66,000 barrels equivalent per day. This year we ended the year at 107,000 barrels equivalent per day. So a substantial increase in production. Mississippian production, we've gone from 15,000 barrels a day to 36,000 barrels per day. Reserves have grown by 20% from 471 million barrels equivalent to 566 million barrels equivalent and adjusted EBITDA is around $654 million to over $1 billion. Just 2012 production and review, you can see the quarter over quarter progression in the top table; 66,000 barrels per day in Q1, of course Q2 moved up to 90,000 barrels per day that’s with additional drilling in the Miss and also Dynamic acquisition. Q3, Q4, those growth are essentially drilling, totally from the Mississippian growth. In fact from Q3 to Q4 as you can see in the bottom graph, our Permian production declined, once we get the [PSA] in the Permian permit, we’ll start completing wells and stop spending capital. So there was a slight drop off in the Permian Basin production, but the Miss more than carries that. And talking about the Mississippian production you can see it’s very, very healthy quarter-over-quarter growth. We went from 19,000 barrels per day in Q1 to 36,000 barrels per day in Q2. So we averaged about 20 rigs in the Mississippian 2012, but from Q3 to Q4 even though we have a very, very nice increase in production, we ran 29 rigs in Q3 and 30 rigs in Q4, so just a one rig increase quarter-over-quarter at the end of the year there. Gulf of Mexico, we started the year which is less than 3,000 barrels equivalent; we had some legacy Gulf Coast assets and a little bit of legacy Gulf of Mexico assets. We closed on Dynamic last April, that brought that up about 23,000 barrels equivalent per day and then in June we closed the acquisition of Hunt which was another 3,000 barrels equivalent per day. And so getting with our operation team getting all the production back on and do some re-completions we were able to end the year at nearly 32,000 barrels equivalent per day. And so what we hope to do this year is again spend about $200 million, we spent I think $150 million last year on some of these E&P activity, but spend $200 million in this year and keep that production basically flat. Year-end reserves, we had 20% just absolute growth from year-over-year, from 471 to 566 and when you adjust for sales and production, we produced 33.6 million barrels and then we sold little tertiary we had in 2012, but adjusting for sales and production we had reserves growth of 37%. Just on the oil side, we grew oil reserves by 35% and when adjusted for sales and production we grew it by 62%. PV-10 went from $6.9 billion to $7.5 billion, 9% growth; adjusting again for sales and production is 43% growth in present value. 454% proved reserves replacement, our proved developed planting cost and this is just the movement in the PDP, excluding PUDs was for the company $21.68 per barrel equivalent and for the Mississippian it’s $13.91 per barrel equivalent, so extremely good F&D cost in the Miss there. And we had a 112 million barrels equivalent of negative revisions and about 85%, 86% of those revisions was feted low natural gas pricing. We will also show you a table here with the proforma adjustments for the Permian sale and so the Permian sale will account for about nearly 200 million barrels of equivalent bringing our reserves down to 367 million barrels equivalent. And then you see the pie chart showing the split commodity money mix of 46% oil and 54% gas and also of our reserves, you are looking at 46% PDP, 11% PDNP and 43% PUDs. 2012 spending, our CapEx in 2012 was $2.174 billion. We drilled 396 horizontal wells, 60 disposal wells and 717 wells in the Permian Basin. Drilling in the Permian’s can certainly be reduced dramatically this year as we sold off the assets and what we have left to drill in the Permians are drilling in the royalty trust. So in 2012, we drilled 1,173 wells, spent about $400 million in infrastructure workovers and some non-op activity and then $150 million in capitalized G&A. Land and seismic, $191 million. This year, we are going to spend about $100 million in land and seismic and two years ago in 2011, we spent $350 million in land and seismic. So that category has certainly been reduced dramatically just over the last couple of years and about $195 million we spent in Midstream and a lot of that has to do with the electrical infrastructure that we put in for the Mississippian. So about 81% of all our capital spending goes to E&P and then about 43% of that goes in the Mississippian drilling. So some high level 2013 objectives and you know, our focus, our number one focus is to continue the increase rate of return on the Mississippian drilling and we know the range of the type curve. We've been talking a lot about that and so our number one goal is to continue to reduce costs both on the capital side and on the LOE side. We are getting much better with all the data that we have now with nearly 690 wells drilled through February and with history we are getting a lot better at our selection process of not only were we drill it geographically but where we drill in the Mississippian, and so we are starting to learn more and more about the play. The well and completion design, we have some initiatives going forward that could help to further save costs, that includes pad drilling. There might be some areas we can drill without intermediate casing. We are going to continue to try different bids, different rotary steering equipment that can help us on saving days. Use of artificial lift, you know, we are using basically three types of artificial lifts right now and that's electrical submersible pumps, that's the probably the choice right now where you are at in the reservoir, in the pressure regime that we are working at. We've seen that electrical submersible pumps have the ability to greatly increase production and we think reserves and so that's something we are looking at and that has to do, a lot to do with how efficient we are at building out our electrical infrastructure that do require a lot of electrical power. So we have at the end of 2012, we had 77 wells on ESPs. They are outperforming the type curve and we will show you that in a little bit but hopefully we will increase this by probably another 300 to 350 wells this year, as far as getting wells on ESPs. We also have gas lifts. A lot of these wells will bring on additionally with gas lifts. Gas lifts are very efficient lift mechanism and then some of the lower fluid wells we have on plunger lifts as well. So we are continuing to diversify on our lift mechanism. We are working continuing to reduce LOE and CapEx. I'll talk a little about casing. We've done a really good job reducing our spud-to-first sales times. We look at some of our competitors out there and they are kind of 60 to 90 days working on a 40 to 45 days. So we've done a good job there. Multi-well pad drilling, we've done some two well pads experimenting with some four well pads going forward. I think that will continue to reduce costs both in facilities and also location building and rig moves. Efficiently using infrastructure to manage our cost, we do have a very large infrastructure footprint, particularly in Woods and Alfalfa and Grant Counties and I think about 80% of the wells we drilled this year would be within the existing infrastructure. And we will continue to delineate Kansas acreage, Rodney just can go through just a series of production graphs, all the way up through Finney County, Kansas. That’s going to show you some really good results and why we're still very excited about Kansas. We do plan to drill probably 180, 190, maybe 200 wells in Kansas this year. So it is a big part of our program. And then in the Gulf of Mexico, we will spend $200 million doing workovers, recompletions, drilling and hopefully we will have some opportunities from bolt-on acquisitions. We did a Hunt deal last year for about $40 million that Gary Janik is going to talk about and you know, we bought that at about 3,000 barrels equivalent per day. We have it producing over 6,000 barrels equivalent per day now just spending a few million dollars, it’s been very exciting, extremely good acquisition. In the Gulf of Mexico, what it does present, what we have is everything we have other than one platform is in shallow waters within 300 feet of water and so we have a lot of low risk opportunities there and recompletion side, workover/recompletions, lower cost to operate. 2013 production guidance, I am going to talk little bit more about the total production guidance on the next page which gives a little bit more clarity on that, but I think one thing we should focus here on this slide is the Mississippian production, how we have grown in. In 2012, we produced 10.1 million barrels equivalent of which 4.6 million barrels was oil with some NGLs and then on the gas side, 33 Bcf of natural gas. And so, we just recently execute a percent of proceeds contract with our gather Atlas pipeline and what that allows us to do is it allows us to capture NGLs, which we have not been able to in the past. So in 2012 of the 4.6 million barrels of liquids, 4.5 million barrels was oil and 100,000 barrels was NGL, we just had a little bit of NGL that produced outside of the Atlas contract area. But this year, we are looking at growing our total liquids production by 78%. And so that’s 8.2 million barrels and of that 8.2 million barrels, we are looking at 7.2 million barrels of oil and about a million barrels of NGLs. And so this contract how it works is that we can immediately start capturing natural gas liquids from wells that are brought online from 01/01/2013 onward. And then in the middle of 2014, we will able to capture our liquids for all our legacy gas that’s producing now and so it's a valuable contract, it certainly a value enhancement to the play. And then in 2013, we are looking to produce 55.5 Bcf of natural gas from the Miss that is shrunk for the liquids recovery. So we are looking at 68% growth in natural gas and 73% growth in total production of the Mississippian. So, this is a pretty good slide, showing the movement in production guidance, so if you look at it from end-to-end, you are looking at 33.6 million barrels equivalent in that’s what we produced in 2012. In 2013, our guidance 34.3 million barrels equivalent, so on a surface that doesn’t look too impressive, but when you consider that we sold the Permian Basin, and we closed on that February 26 all the Permian productions out. But if you look a little bit the movement of these numbers, if you take the 33.6 million barrels equivalent and you take out the 8.8 million barrels that’s what we produced in the Permian last year and we just kind of normalize it, taking that production out and then adding back in 3.2 million barrels for acquisitions. And then, we take our guidance of 34.3 million barrels and we take out the Permian this amount we produced in January and February before we sold it. You are actually moving a number from 28 million barrels of equivalent to 33.1 million barrels equivalent and its 80% growth in the guidance. And so you know the way I think about it is we have 18% organic growth in production and we are going to spend about 20% less in capital in 2013 than we did in 2012. So our 2013 capital guidance is $1.75 billion of that as you can guess the bulk of the spending is in the Mississippian. We are looking at spending $1.23 billion drilling horizontal wells in the Miss that's 581 wells that we have planned, about $141 million for salt water disposal wells and $141 million again for the Permian that's just drilling the Permian trust wells only, $200 million in the Gulf of Mexico and certainly you see our JV carry there of $550 million. So we have a net total drilling completion spending of $1.16 billion net of the JV carry and we planned to drill 874 wells in the all areas primarily in the Mississippian. Infrastructure, workovers and non-op, we have $213 million budget, $60 million in capital G&A for total E&P spending of $1.45 billion, land and seismics a $100 million. We still own rigs; there is $30 million that we have planned for this year is probably a little bit high. I think we will come down on that since we laid down some rigs with Permian sale and then we will have a $170 million in Midstream which primarily again is electrical infrastructure. So if you are looking at pie charts 83% of the spending goes to E&P and a little bit goes to land, oil field and Midstream, and then in the drilling and completion about 59% of that money is allocated to Mississippian horizontal wells, 12% to SWD, 12% to Permian and 17% to the Gulf of Mexico. So this is just a comparison of the 2012 to 2013 CapEx plan. So for Mississippian horizontal, we are going from 396 wells to 481 wells. Disposal wells a slight increase from 60 to 74 and then the Permian grade reduction in drilling because of the sale. So from a dollar standpoint, Mississippian D&C, we are moving $560 million to $680 million. Permian drilling complete, nearly $0.5 billion, that would be reducing down to $140 million, Gulf of Mexico, the only difference there is we have a full-year spending this year versus just kind of three quarters year last year, $151 million to $200 million and then the non-E&P is going down by $114 million and that's primarily in the area of the land spending. So Mississippian overview, you’ve seen the slide quite a bit. We have 1.85 million acres that span down from Payne County, Pawnee County, Oklahoma all the way to Sherman County, Kansas. There are 11,000 potential drilling locations here, 18-year of drilling inventory. We are currently running 32 rigs, 22 in Oklahoma and 10 in Kansas, that's twice the nearest operator, twice the amount of rigs, 36,000 barrels equivalent per day production Q4 2012, through February, we drilled 682 wells, that's 45% of all the horizontal wells drilled and we are operating currently 116 salt water disposal wells. So, we have about 1.6 million to 1.7 million barrels a day of salt water disposal capacity and right now we are in checking 650,000 to 700,000 barrels a day. So with that said, we should be able to maximize our efficiency this year with drilling within our existing infrastructure. And so, just a little bit more of the map, you can see that the yellow coloring is the SandRidge acreage, the red are the SandRidge wells, the blue are industry wells, but I think the most important thing on this map is all the green dots and those are all the vertical Mississippian wells that's complete over the years. I think there's over 17,000 to 18,000 vertical wells and what that gives us is the confidence level that this Mississippian reservoir is present throughout this acreage area and also hydrocarbon and oil and gas is present throughout the acreage area. So that does reduce the risk of exportation as much as we continue to go forward and delineate the play. Mississippian production growth 72% growth that we are guiding to in 2013, but you can see growth has been impressive ever since the first quarter of 2010. We spud our first well in the fourth quarter of 2009, brought online first quarter 2010 and back then we only produced 300 barrels equivalent per day but you can see strong quarter-over-quarter growth during this time period. We exited ’12 with 36,000 barrels and so with our guidance for 2013 of 17.4 million barrels equivalent that's an average of 47.7000 barrels equivalent per day. So we are expecting really another strong year of growth in the midst. So we’ve had a 131% annual production growth in Q4-to-Q4. Commodity mix has been steady at 45% oil. This is excluding NGLs and 55% natural gas. 80% of the Mississippian cash flows come from oil production. You can see the table on the bottom right there. It just shows the number of wells that we've drilled over the last three years and t hen we anticipate to drill in 2013. And so I think the most important thing about that is now we have wells that are going on three years old and that does help a lot with our type curve projections, not to mention all the data points that we're adding every day, every week and every month as we complete wells. So the Mississippian plan, you know, we will have slight decline, production decline in the WTO, that’s our dry gas area. We have no plans to spending capital there. We plan to keep our southern division, which is primary Gulf Coast, Gulf of Mexico relatively flat. And so the plan is to use the Mississippian drill production double-digits. Certainly, in the Mississippian itself, but it's a good enough asset that we're going to grow the entire company double-digit by drilling in the Mississippian. We will continue to increase rate of return by reducing cost in our play. We will go into a lot more detail there but we're looking at trying to get to down to $3 million this year and then potentially down below that by the end of 2013. We will continue to optimize our infrastructure that we laid in place the last couple of years and be more efficient and where we drill wells and this will help our LOE. And we will continue to delineate the play and grow it moving it into Kansas. So the type curve, I think we had this slide on our earnings call last Friday. And there has been a lot of movement in the type curve over the years in this play but I think in the realm of ranges that has moved it still a very strong, very strong rate of return and the economics are very good for this play. So in November, we took in on our own to take down the type curve because we did see that oil was declining faster than the year in ‘11 type curve and we took it into 150 plus or minus 150,000 barrels of oil. And then at year-end with our third-party consultant, they mulled at a 107,000 barrels of oil. So the 45,000 barrels of oil from 107 to 152 spreads over a 50 years and you can look at a green curve, you can see how tight those two forecasts are and with reasonable engineering, I think you can go with either one of those curves whether you choose to be conservative or you choose that match of data where we matched it. And so, I think with also the new contract percent of proceeds contract even though we lost 45,000 barrels of oil, we have made up in volume at least with 60,000 barrels of NGLs. We didn’t make up all the values we hope to but we did bring a lot of it back. And so now, instead of having 152,000 barrels of liquids, we have 167,000 barrels of total liquids with the new percent of proceeds contract and after shrink at tailgate of plan, we have about 1.2 Bcf of gas. So our type curve from what we got in November to where we got it to year end move from a total production standpoint or total EUR I should say 433,000 barrels equivalent to 369,000 barrels equivalent. We will go little bit more into rate of return but the difference in rate of return in those two curves is 57% rate of return at 3.1 million barrels versus 50% rate of return, so not anything that would make us want to change our view in the Mississippian or change our business plan. So on the gas; you can argue that the gas is actually outperforming both of those type curves we have on this page. And so with the liquids and what helps the rate of returns is actually in the year one we are producing about 4% more total production and cumulative difference through five years is only 5% in BOEs. So this slide shows that about 90% of rate of return generated by drilling by these wells take place in the first five years of the well’s life, and that all has to do with the low cost of the play, you are looking at this $3 million, $3.1 million to drew and complete, you are looking at relatively high IPs of 700 barrels equivalent per day and you are looking at the hyperbolic nature of the decline. All those things drive the rate of return and it get to a level that what happens after five years where these wells start flatten out lower rate has very little impact on the rate of return but it does have impact on ultimate oil recovery or ultimate gas recovery. It just you know the numbers may seem big but when you spread over 50 years, they have very low impact on the economic performance. So where we are today with our cost $3.1 million that's what we ended the fourth quarter with and if we can effectually get cost down $3 million or below going to 2013, we probably can make an argument we are better off with the lower type period than lower cost than we were a year ago on economies performing basis. So at $3.1 million just comparing the two type curves, moving away from 57% ROR to 50% ROR but let's say that we are at $3.2 million with November type curve with 50% ROR and we can effectually get to $3 million with the new type curve, we will be at 55% rate of return. So we are talking about realm of rate of return changes that are very small but yet very robust at the well ahead. ESP performance, so at the end of 2012 we had 77 wells that were on electrical submersible pumps that had at least 90 days of production on them. And so you can see the year end type curve, the red are for the gas, and the grey lines are for oil. You can see that both oil and gas are outperforming the year end type curve but by a pretty large margin and this is early life. But even if we don't increase EURs and all we do is make an acceleration case on the economics, you see dramatic increases in rate of returns in NPV and so even if we look at the oil, even if we stay with our 107,000 barrels of oil and we get the acceleration of that oil production and a little bit of acceleration on the gas production now you are looking at a rate of return of 86% at $3.1 million. So ESPs are making a difference and we plan to like I said install probably 300 to 350 ESPs this year. So I think there is an opportunity to outperform our year end type curve. Drilling within infrastructure, we’ve made a lot of big commitment and a lot of investment to infrastructure. And there are seven areas here that we have pipe in the ground where we can move water around without trucking. You know the larger of those areas are certainly Grant, Alfalfa and Woods where we've had the most drilling since we started this play but Comanche county has a large infrastructure in place now and also southern Harper and moving on to Ford and Gray. And so the table at the top right shows you a little bit, just gives a little picture of where the disposal wells are located and where the SWD pipeline and electrical lines are located and then the table on the bottom left kind of gives you the well plan of where we plan on drilling this year. The bulk of those wells probably 40% to 45% of wells we will be drilling in Alfalfa County where we have the most infrastructure in place. But you can see we have 74 in Comanche County Kansas and moving on all the way down to Woods County where we have 53 wells for a total of 581 wells. We do plan to drill 40 wells in some of the northwestern counties and a little bit more northern Harper and some that we are calling appraisal wells. But over 90% of the wells will be development type wells that we are planning this year. The percent of proceeds contract just a few words on it. It is a very, very value enhancement for the play. We have a great partner with Atlas, you know they basically have their gas line to us as son as we frac the wells, and that's what helps us. When we talk about spud-to-first sales we certainly are moving in the right direction getting wells drilled quickly. I think we are down to 21 days or so now, but we still have to frac the well and get the well on sales and Atlas does a good job of helping us get from spud to first sales. And so we've chosen to partner with them. We had a lot of interest in this play from multiple pipeline companies. Our contract was not up until July, I think it is of 2014, but they are excited about this play and we were able to execute a contract before that expiration day and to help us with capturing the NGLs. So from an NGL standpoint and the new type curve, we are looking at 167,000 barrels and that's based on average of recovery for 2012 where they actually rejected ethane for parts of the year. Going forward if ethane prices improve and they go into full ethane recovery, our total liquids can move up from 167,000 barrels to 194,000 to 195,000 barrels. That’s another additional 27,000 barrels of liquids that would enhance well economics as well. This contract, I think, covers 15 counties and some like that, mostly Northern Oklahoma, Southern Kansas and our legacy production, which we are moving a lot of gas now for wells that were drilled up to 1-1-2013, and that gas will capture NGLs in that gas starting in July ‘14. So that would be another up lift in our economics at that time. Gulf of Mexico and Gulf Coast, this is what we call our Southern Division and Gary Janik can go in to lot more detail on this. But I think I probably say this numerous times already, but our plan is to spend a couple of hundred million dollars, generate free cash flow and redeploy that in to the Mississippian and you can see the math there that the bulk of our platforms with the exception of Bullwinkle are within 300 feet of water or less. So in shallow water, we can really, you can kind of see the names here on the little tags. We have some really exciting things going down their Ship Shoal 301. We just drilled and completed a well there. It's flowing about 1,700 - 1,800 barrels oil a day, probably 1,600-1,700 pound. It's a very strong well. We have more to do there. We just finished three or four recompletions at Eugene Island. These are uphole recompletions that we're going in and open the sleeves. They probably run less than $2 million each. Gary will go in to some of those in detail. But just to give you a flavor, some of the opportunities we're looking at, with our Gulf of Mexico and what our plans are. So the Gulf of Mexico, just a look and review, already gone over this but we started at less than 3,000 barrels equivalent in Q1 of ‘12, ended up over 31,000 barrels equivalent at the end of the year. We just spend $200 million that the breakdown and the spinning of the 200, something I haven’t talk about, but we are looking about $150 million for drilling, $30 million for recompletions, $18 million for facilities and just a little bit of $3 million in land. And you see the pie chart how that’s beaks up through. So that does conclude my part of presentation. Here is James for finance.

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 a bit, and we have been able to successfully raised external sources of capital back in ‘11 and ‘12 and we have done it again in 13. We have also continued to hedge is something we have done for many years and about $90 million of hedge gains last year from our oil hedges, we routinely hedge 85% of current year’s production and hedge out two to three years and you will continue to see as do that. In terms of on the balance sheet side, so we did sell the Permian, just closed a couple of weeks ago, last week proceeds $2.6 billion which you have heard. You’ve heard the reasons why we did that. We had two really big assets the Mississippian and Permian were both consuming the lot of capital and with the balance sheet and the funding available to us, we really couldn’t fund both of those. We wanted to focus on higher growth good return project to the Mississippians, and so we think the Permian sale was at the right time and had a good valuation. That property was getting more mature, so $2.6 billion of proceeds allowed us to do a couple of things; gives us liquidity right now of $2.5 billion which you can see on the bottom left there, we are going to repay $1.1 billion long term debt, so take our long term debt for $4.3 billion down to $3.2 billion. With that repayment, we are going to have no near term debt maturities, our first maturity is in 2020 and what this does is allow us to fund the Mississippian program for the next couple of years. So we always like to keep the business funded one to two years out, and this gives us that opportunity. We will talk about other funding mechanisms we have to fund in ’15 but this gives us a lot of flexibility for the next 24 months. 2013 you've heard Matt and Tom talk about Mississippian, and our focus will be on the Mississippian, that's where the majority of our capital goes, a small amount to the Gulf of Mexico, but we are focused on drilling the Mississippian. Production growth of almost 20% and CapEx of $1.75 billion, that's down 20% from the previous year. So part of the goal to sell the Permian, was to have a lower CapEx level to be able to fund that more effectively with our cash flow and our capitalization so that also allowed us to reduce our CapEx going forward. In terms of CapEx we've, you've heard Tom say, I'm going to say it again we have a goal this year to really sticking to that $1.75 billion, so we want to achieve that close to 20% production growth with this level of capital and not exceeding that. We already launched to make whole of the debt of $1.1 billion of bonds. In terms of leverage right now we are at two times leverage and we will increase it a little bit as we chew through our cash that is a net leverage that's how our bank covenants are calculated. We would like to keep that around three times and we think a year ago at 4.3 times is too high. So we think the leverage ratio is around three times is appropriate for a company of our size and on the bottom bullet there, we will continue to hedge and protect cash flows out the next few years. In terms of the next funding source for us in the next chapter in us funding the business, we mentioned this on the call and there's several options available to us. We do have the saltwater disposal system, we've mentioned. We have 106, at year end 106 disposal wells in operation, 700 miles of gathering lines. We spent $400 million in capital on the business at the end of ’12 and end of ’13 we will have $650 million spend in it. Right now we can dispose $1.6 million barrels a day of saltwater. So we think it’s a strategically positioned midstream asset in one of the better plays onshore. So at some point in ’13 or in the early ’14 we look to monetize that, once it gets a little more mature and we’ve invested some more capital in it. That could take a lot of different forms, we get approached by people all the time, it could be a sale part of it, it could be a sale of all of it, it could be an MLP dropdown strategy. The good news is with the sale of the Permian we have some time and flexibility there and don't have to rush to do everything. But that is on our list of monetization tools. Also Kansas joint venture we do have about a million acres in Kansas and we think the opportunity is there to joint venture that some time later this calendar year. We also have about $650 million of subordinating common units that we hold at the three royalty trusts we've done and we've said publicly that we will potentially use that as a currency over time to fund the rest of our business. We've sold a couple of hundred million dollars of units over the last year and a half and as time goes by we will continue to use that as a source of capital. So in terms of the specifics of 2013 at the midpoint of our guidance using $94 oil and $3.45 gas which was a strip about a week ago we are generating an EBITDA right at $850 million give or take. After interest expense, preferred dividend and some P&L liability it’s a cash flow of about $400 million. Gary will talk about the P&A liability offshore. This year it’s a rather large number against legacy platform that we have to P&A and then also one last P&A payment on the Bullwinkle platform. So its unusually high year, I expect going forward it would be half that number. So $400 million of cash flow. Here's how we fund the rest of the year. We end the year with a little over $300 million of cash in the balance sheet. The net proceeds from the Permian after the debt repayment of about $1.04 billion that gets us to fully funding the $1.75 billion capital and even have little over $1 billion to spare. So ‘13 is fully funded. The rest of the proceeds take us in the ‘14 and comfortably get us there. Credit metrics and liquidity. From the top left there, EBITDA on a pro forma basis, LTM has caused $750 million and that's fully pro forma for the sale of Permian, the acquisition of Dynamic and Hunt and the divestiture of our tertiary properties. So 1.1 billion last year, but 750 million on a fully pro forma basis. You take that with 1.1 billion of net debt, gets you about two times leverage and liquidity of 2.5 billion. Hard to get to that liquidity number. We ended the year with 300 million in cash, we sold Permian for 2.6 billion after purchase price adjustments and fees it’s probably 2.55 billion. Subtract the 1.1 billion of bonds that we're going to make whole and that gets you to under about 1.7 billion of cash, add on top of that a $775 million revolver. That’s a 2.5 billion of current liquidity. Debt reduction of senior note profile, here is our bar chart of our stack maturities on page 38. On the top, here is where we stand today, that’s 4.3 billion of bonds. On the bottom, it's pro forma after the make hole of the 2016 and 2018. So 1.1 billion of permanent debt reduction, that eliminates our nearest two maturities; lowers our interest expense by about $90 million; takes our weighted average cost of debt down below 8%; and pushes our first maturity out until 2020. So we think this is a pretty defensive capital position that gives us lot of flexibility for the next several years with no maturities coming to it at all. On a credit facility, we do have a credit facility of $775 million as the borrowing base. That will be redetermined later this month and we don't anticipate any change to that borrowing base. We’ve had initial discussions with our lenders, they are comfortable and we are that our asset based pro forma in the Permian divestiture can fully support of $775 million borrowing base. So we anticipate that will get reaffirmed at the end of this month, and the next redetermination be in the fall on a normal schedule twice a year. In terms outstandings, nothing outstanding on the facility now and we haven’t had any borrowings on until mid 2011. Hedging, like I said we continue to hedge, it's an important tool for us to manage our cash flows, take a little bit of volatility out of the business, we are priced acres, so if we can manage that risk off the table we’ll try to do that. About 85% of oil production hedge this year that number you see 14.7 million barrels that’s consolidates that does include about 1.8 million barrels that are down at the trust, some of the trusts are hedged at higher percentage. But SandRidge is about 85% hedge and concluded the trust is at 14.7 million barrels of just over $98 per barrels. And we have another 24 million barrels hedged through swaps and three-way collars out through ‘15, and you will see us continue to hedge not sure exactly what price but we will continue to hedge out two, three and four years to again protect those cash flows. So if I wrap up my section, in summary, we have you will hear a lot about the Miss and Matt talked about and so will Rodney. We’ve got a lot higher confidence level in the Miss production in type curve than we did a year ago, much bigger sample set of production. We have taken type curve down, the change in November did have an impact on returns, this last change did not have a material impact at all on the IRRs. So a lot of confidence in the Miss and we’ve actually delivered on the production results in the Miss this year, in terms of our production guidance earnings and EBITDA. We had some changes to the type curve, but for us it’s still a really robust play that can earn call it 50% returns. We are a leader in the play, great land position; Dave Lawler will talk to it. We’ve got the lowest operating cost, the lowest CapEx cost in the business. We’ve got a very robust salt water disposal and electrical infrastructure system. So in terms of assets to execute right now, I feel like we are in a really good spot. We reduced our leverage by over two turns, we got rid of a $100 million of fixed cost and fixed charges and our interest expense and we have $2.5 billion of liquidity. So from a financial standpoint, I think we are in a very good spot, to go an execute the Miss over the next couple of years and we will be looking towards kind of the next layer here which is how to fund in ‘15, how to leverage in check, how to manage our commodity price exposure through hedging and you will hear more about that in the coming quarters. We will back up the end for Q&A, thank you.

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 three initiatives that we think are going to be very strong this year; one is rotary steerable technology, its an offshore technology that we've used onshore now and we are pretty comfortable with, because the maturity of the play we are going to be able to go from kind of go from kind of single well pads to more of a concentrated system where we can skid rigs on the same location, so you've seen some of this in the Bakken and the Marcellus and its kind of arrived at the Mississippian at this point. And then we are also able to customize the kinds of casing that we run on these wells, so instead of running kind of a generic system, we can now customize and potentially cut out significant costs. And then when we think about our true competitive advantages of the company I think it will be clear just how much value we can derive from the water disposal system and also our electrical distribution network. Okay, so I won't spend a lot of time on this, but there are two bullets that I want to kind of point the group to. You’ll see that we are about 68% development and 32% appraisal. So this is about 230 miles across the play, so a very significant broad view about where we focused our development program and 32% of those wells were kind of “appraisal” so this was a pretty significant step out from our existing infrastructure and these were kind of the exploration wells if you will to test where we want to go in the future. And then as part of this, we've talked about it in the past, but we primarily focus on the upper member of the Miss and that will continue, but we have some pretty exciting things that we want to share with you today. So a little bit more detail, you've seen this slide in terms of just account, but I just wanted to highlight a few things. We do have kind of seven project areas that are pretty extensive. You do see in Alfalfa we have a concentration there that's really kind of where we started, its the only reason, but you will see a significant amount of development in Grant, and Woods and Comanche and what's interesting we've talked about efficiency a little bit so far, but we are going to increase our CapEx, our well CapEx by about 34%, but we are going to increase the number of wells we drill by 47%. So you are starting to see the efficiencies kicking at this point. We will also increase our production by about 73% from 10.1 million to 17.4 million barrels. Before I leave this slide I would like to kind of flag the lower right corner. This is kind of an area, I wanted to talk a little bit about the appraisal wells and what we are going to look at, so just to the South of Alfalfa and Grant is where we are going to do some appraisal work and I'll talk about that here in the next slide. We are particularly excited about, so we'd mention we focused on the Upper Miss, but what is interesting about the Miss plays is there are three distinct members, so there's the upper, the middle and the lower miss and then underneath that is the Woodford Shale that you've heard a lot about. So we have two counties here, we have Grant and Garfield counties and starting with the Simpson Trust, the green star there in the lower left of the upper graphic, the Simpson Trust is in the upper Mississippian. It's been a very, very strong well. It's correlated with the production chart below and it traversed over to the red star, Sawgrass that is a middle Mississippian member. And as you traverse further north, you can see the Kilian 1-7H and it’s a lower Mississippian member; now all three of these wells are prolific producers. And then recently, we participated in the well of Thompson 2-6H which uses a strong Woodford test. So it's interesting about just this county alone, we have the potential for four stacked pay sections. So we have 500 controlled sections within this network, 200 that we have mapped, we think have stacked to pay potential. So when we think about our appraisal program, what's interesting about it is we will have wells that are away from the development or our infrastructure footprint, but also within the appraisal, we are going to be coming into the same section in drilling wells in those different members to try and prove that concept up. So again, we've identified success in all of these zones and we have now mapped where we think we might have repeat the success, where we can stack these objectives. So it's important to note here too that the distance between the vertical, distance between the upper and the Woodford here is about 600 feet, so they are two true distinct, discreet reservoirs that we would be impacting. So we're very excited about this and what we might be able to come up with in 2013. Okay, just in terms of improving capital efficiency, we like to show this slide, because it shows just I think the level of sophistication that the group is coming to terms with in terms of the data and what we're learning from the play. The first well was an appraisal well and we traversed two porosity intervals within the upper Mississippian. So kind of wanted to point out here that the two porosity intervals are about 15 feet apart, so we drilled the first well and traversed the upper porosity interval, so also make some gas shale, but then continued on down to the lower porosity interval and ultimately put the well to sales and we are disappointed with the results. But what we did do is come back and integrate all the information that we have collected from the first well; started comparing that to the data that we had in the area and we came back and drilled a second well, 4,000 feet from the first and we came up with some pretty prolific results, so well two delivered in 70 days about 32,000 barrels of oil and about 41 million standard cubic feet of gas. And so when we talk about kind of 2013, and how successful we have think we can be what we are doing is we’re actually coming in and drilling wells with inner infrastructure, but also we are gaining a little bit more efficient with how we spin those CapEx dollars, because we are learning so much about the play and where to place to the laterals and so again very strong results here. Okay, and I wanted to put another layer of information out in terms of ESPs and just how prolific they can be; we started looking at the production profiles of the gas lift wells and we do have an exceptional sub-surface team and the group, we just sat down and start to go on through these and you see this gas lift well here in the lower left. It's moving about 200 barrels of oil a day; pretty flat gas rate at 2.2 million and so you see particular example really across the play, it was also moving a fair amount of water. We came in and we drilled a second well in this section and put the well on a submersible pump and what you have was 100% uplift in oil production within the first 150 days. So the first well produced about 26,000 barrels of oil in 150 days and the second well produced about 52,000 barrels and 430 million of sand in cubic feet. So what’s really happening here is we are cautious to brag up addition EUR, but at a minimum and what we are seeing is dramatic acceleration of value and this is where we think ultimately we hope that we can extend the EUR but it will take time to prove up that concept. In addition to installing these ESP’s at inception, we are also combing to the field and putting this piece of equipment in the ground where it makes sense, so this particular well was on a pretty flat decline just like the previous example, and we came and added an the ESP around day 90 and went from 300 to 600 barrels oil a day and the average uplift since its been online of about 75% and just very, very strong economics and we have dozens and dozens and dozens of examples just like the one that I am showing here. Okay, so I really tried to focus on there and the first piece was just deliverability, so we think that our capital will be more efficient this year than last. We are drilling in areas around infrastructure; we are learning lot and lot more about the side view or what zone we need to be in and we are dramatically accelerating the production with the electric submersible technology. In terms of just the cost control, really we can be more pleased with the exceptional teams that we have that work for the company. We have sat down and tore apart every aspect of the drilling and completion operation and in some cases we’ve put 66 people in the same room and gone to every single step, so that kind of effort is what has allowed us to go from 3.6 to 3.1 and on a gross basis that’s going be a $200 million to $300 million savings in 2013. So we are very, very pleased with the results and as most of you know we increased speed, it usually costs and so we wanted to show you companion set of slides so you can see that really wasn’t happening and so our spud to spud progression has gone from 27 days down to 21.6, so that’s 32 rigs moving every 21.6 days, is a very, very fast operation and next if anything if you guys could just come out and we head in the field and you could see how efficient the group is; 32 rigs moving every 21 days and we did that for 125 wells in the fourth quarter of ’12 and what's also interesting about the 3.1, ESPs are notionally what we call $250,000 each. So we had a scope change within that cost structure. So not only are we down 3.1, that includes 25% of the wells including an ESP. So I just want to make sure that was clear. The only other thing I might add is Tom’s point about the offset cost is factual. We participate in a lot of wells in the Miss and we are probably at 1.1 million to 1.2 million ahead just on drilling complete costs excluding ESPs in the play. In terms of the completion program I just wanted to kind of highlight and put in here for your information what kind of completions we’re running. We talked about last year kind of case to our packer system. We are still running those and they have been successful. We are still primarily proven plug and at this point we think we are pretty pleased with kind of how the operation is working; just like with drilling we went through a whole teardown cycle of the completions and we've reduced the completion cycle time by about 27%. So we are pretty pleased that every time we spud a well, it’s on production 44 days later. We also spend a lot of time with our service contracts in terms of pressure pumping and water transfer and we've secured favorable contracts through the end of 2013. Just in terms of our performance initiatives this year, we are harvesting some technology from the offshore, so we can talk about rotary steerable technology. This is some really impressive equipment. The way this works is it essentially has pads that articulate the tool and we don't have to spend a lot of time tripping to adjust the motors. We just drill off from any surface gazing at a 1000 feet and then TD, once you intersect the pay zone and what's impressive about the technology if you look at the graph in the upper right, its taken us about 5.2 days to leave surface casing and TD dissection. At this point we moved that down on our nine well test case to on an average of 3.5 days and it takes a little bit of time to figure out how to work the tool, but on the last two we are down a full 50%. So we've expanded this technology and the use of this equipment to seven rigs at present and we think we can save about $100,000 per well and again it moves very, very quickly. The other piece that we talked a little bit about multi well pad drilling; so for the first half of 2013 we have 45 dual well pads and two quad pads planned. The blended cost for the program at this point we think will be about $125,000. The main savings is from the rig moves themselves not having long moves and we've been able to consolidate the locations in some of our areas that are very close to infrastructure and we have improved completion efficiency, so we can frac wells back to back and then also bringing a single power system for that pad. So we think this is another way we can improve our performance. One other item that can be pretty beneficial for us is eliminating the seven inch production casing or intermediate casing and the way this works there are certain lithologies where we can spud the well, set a 1,000 foot of surface casing and then TD the well, basically out from underneath the surface shoe. What’s beneficial about it is there is just a lot of time and cost associated with those two dealers; so not only can we eliminate a stream, but then we can size down to 5.5. So we think we can save about $200,000 per well by optimizing the casing streams and again that depends on what region of the play we're in, because it's so vast. Okay, a little bit more data on the saltwater disposal system. So we do have 116 active wells, 700 miles of pipeline and we've invested about $450 million gross to-date. What makes it so competitive is you really can’t go into the Miss play and drill a single well and then truck the water; it's almost a must that you have it. It cost at least $2 and in some cases $250 per barrel. So if you are using, say 50,000 to 80,000 barrels of frac water, you immediately incurred a pretty significant loss, just having to truck your frac flow back water. At this point, we're able to take even the frac flow back water, put it back into the SWD system and that efficiency saved us a lot of money on the CapEx side, not only for the long-term production side. So you noticed in the first quarter of ‘12, we were trucking about 6.3% of our water, in Q4, the average was 1.2% and at this point, we feel like we're getting close to that estimate of 10 producing wells per SWD. The chart here at the lower right shows that by the end of 2013, we will have about eight horizontal producers connected to each SWD and then at full development you have approximately 10 wells and as water taper is off we might be all that connect more to that so there is certainly upside to the 10 horizontals per well. Alright, and the power system is something that we are particularly proud of; the team proactively win out and build the distribution networks to the local co-ops and why this matters so much is because you need the power to transport the water into run the submersible pumps. So we have accessed over a 100 megawatts. This is a pretty large amount of power for those who aren’t familiar with it. We have 500 miles of distribution lines; we have three operated substations and four additional substations planned in 2013. How this links up to the performance of the company? We currently have enough power supply 400 ESPs and I think we have kind of notionally discussed that’s at least the two ex-uplift in oil. So the benefits of the ESPs is some kind of additional figures for you, a lot of our competitors are running diesel generators to run submersible pumps if they decide to run them and what we do know that it's about a $100,000 per month to run a diesel generator and power an ESP well. So we have a clear advantage here over our competitors that we have kind of all parts of the equation if you will to be successful in the play. Alright. This is kind of really, I like to think of LOE as a trailing indicator for how well you are planning your business and you probably noticed if you are inefficient on the CapEx side your LOE will explode; just the opposite has had happened, here our LOE dropped on very, very low, so at the beginning of 2012 we were at that 8% truck water, in December you will see just on the monthly basis we were at 0.9% and then you see the generators chart, where we had 35% of the wells were on generator in January of ‘12 and now we are down to 13% and half of those are natural gas. So what those two chart flow into is our LOE progression chart which is below that, so we’ve gone 13.38 to 7.65 which is about 43% reduction, and if you think about the fact that we are going to produce 17.4 million BOE this year, if you take that savings which is kind of 550, what you will is we are going to save probably about $100 million in LOE, so when you factor that with the CapEx savings is about $300 million plus the $100 million from LOE, you’re starting to see a very, very strong cash generating company. So with that I would like to think of the Miss really as an equation, it is in a place that you can just step out and drill a single well and be successful, so just to kind of highlight we have a material land position, a vast amount of that acreage is contiguous; we have extensive sub surface knowledge so I hope that example of which proxy interval that you needed to be in, what kind of support that give, we have stacked to horizontal paid potential, we have extensive co-work that’s ongoing, so we feel like we have the sub surface and we have leading position in sub surface knowledge, we do have a leading drilling and completion cost, we have the latest technology in use between the subs and rotary steerable systems and again we have a classic competitive advantage with our electrical distribution network and our saltwater disposal system and all that sums into being the lowest cost operator which we just talked about and that at the end of the day we think the sum of these strategic elements is what really delivers premium economic returns to the company. Okay, so with that I think its time for a break and then we will get started here with the next session with Rodney. Thank you. [Break]

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 acreage position. Those vertical wells set the stage for how we understood the performance of the play. When we think of derisking the play on this slide, what we're really talking about is derisking the economic performance of the first five years and by that I mean we now have 644 wells in our type curve, showing the outcome of the economics across 230 miles and give us a high level of confidence. I think James talked about earlier and that we can repeat these economics time in and time out and that's key to these understanding is, we've gone from an understanding of 15,000 to 17,000 vertical wells to now 1,500 horizontal wells in the play of which we've got data on 644 in our proven type curve and we got 82 rigs running. So we've gone long ways from what you would call an emerging asset to a resource play that now it spans out over 230 miles. Proven reserve potential, one of the things we will talk about today is we have gone a long ways from understanding the play from a density perspective. Now, we are talking about four wells per sections. Last year, we were talking about three and we are going to show you some information on five wells per sections. This improves the per acre recovery in the economics that we actually see per acre. So when you think about that we have come a long way from where we started in trying to understand the density of the play and understanding the risk profile of the horizontal performance. The other thing we are going to talk up a little bit about today is from a reserve standpoint because of the horizontal booking methodology, we call it the old methodology, a booking just the east and west offsets parallel to the horizontal path of the well bore for PUD booking. We are still ending up with about a one-to-one ratio of PUD to PDP. With that in mind, we have done a lot of work on statistical booking analysis and where we are today is we believe by the end of this year, we will have proven the statistical booking methodology for this play and be able to book all the way around our acreage position and call it a two-mile radius, which should significantly increase that one-to-one ratio and allow us to book a lot more proven reserves for this play. And finally, the confidence in the rate of return is significantly improved. If you think about it, 644 wells we had a 145 wells last year, 644 wells this year, but if you kind of put that in perspective of data points, last year end we had about 4,000 data points, but I don’t mean that’s 145 wells and how many daily information points we had on each well, now we have over 20,000 and its not just more wells but its longer history that we can look at and understand the profile and we will talk quite a bit about that today. If you look at the play, we just give you a little bit of background 1,535 wells now drilled across as we call it 230 miles. We have got a number of different players in the play, we have Chesapeake, Mid-States, Devon, Mid-States took over the Eagle wells, we have got Devon, Range, Shell, HighMount, Calyx. So we've got 82 rigs still running the play, this is still a very significant play across the US drilling for oil. If you think about where we were last year end, I am sorry, last Analyst Day. We had a 456 MBoe type curve. We still even at last Analyst Day from the beginning we have been talking about a type curve of 300 to 500 MBoe and that was as I said based on the 145 wells, we had three wells per section and we talked about last Analyst Day that we thought to B factor could improve. If you remember the 1,700 vertical wells we studied had a B factor of 2.5 and I know that is the technical term but it is pretty simple, it’s the shape of the curve, the higher to B factor the more been there is into the curve and the faster the well will flatten now and perform a lower profile, lower declining profile. In this year end, our consultants stayed with 1.5 B factor for the oil that they had last year end but we believe there is a lot of evidence suggesting that we will be moving to a higher B factor. We also said that statistical booking for the play was about two years off and now guess what we are about one year off from that statistical booking methodology. We've continued to extend the play and we've derisked the play. Our current outlook 369 MBoe for the performance of the well and that's 167,000 barrels of liquids. As Matt said, it’s a 107 barrels of oil and about 60,000 barrels of NGL liquids because of the Atlas contract and 1.2 Bcf of gas. The B factor for gas is up to two now. We think the B factor for oil will be increasing as we move forward in time and I'm going to talk a little bit about that as we move forward. There's a lot of call it new information or discussion going on in the industry right now. It’s hard to believe engineers could actually disagree about how to forecast wells but it believe me I think there's a lot of disagreement about how to forecast resource plays. Dr. Lee is actually going around the country now teaching in schools on concepts around new emerging resource plays type reservoirs and how they differ from in decline analysis from our old thinking methodology and we will go into a lot of detail as we kind of think about working on that. Rate of return, we've already spent quite a bit of time talking about rate of return but the confidence levels on that rate of return is significantly increased. It’s just not the confidence level and the type curve. But as Dave mentioned earlier, its confidence level and repeatability of the capital and the LOE it takes to produce these wells and I'm going to spend some time giving you some comparison analysis of what happens on the rate of return and the variability of the rate of return based on type curves, CapEx, LOE, gas prices, oil prices and give you a flavor of the movement that we've seen in the type curve versus some of those things. And of course, we've continued to expand the proven area and one of the things we are going to spend some time today is there is a call it a belief that a resource play like this have a simple indicator, its got to be simple indicator in EUR or 30 day IP or something that tells you this part of the play is much better than this part of the play. We are going to show you as we've expanded this play across 230 miles and guess what there's different outcomes across these 230 miles but when you think about it, we are going to show you economic results differing in different methodology from those different areas. We are going to show you a well in Finney County that on the IP indicator is exceptionally low. No gas, 60 barrels of oil but it looks like it’s going to tune about 250,000 barrels of oil and generate a 40% rate of return, what does that mean? Well, that means that it only shows 60 barrels a day on our chart for 30 day IP but its going to generate a 40% rate of return. So the play is not just a simple indicator that you can take and say okay, the play is not working because the IP went down this quarter or the play is not working because the EUR has changed, it takes a little bit more analysis as you look at this and think about it to understand the play and we will spend some time doing that. And of course, finally, the proven reserve booking potential has increased. As I said, four wells per section and then we will be moving into a statistical booking methodology probably by next year end. Alright, the all awaited type curve. The methodology and what's interesting about this is we're still using call it old methodology or decline curve methodology that’s been developed for decades now. In the old methodology and higher call it metrics porosity methodology, it was always said that you couldn't use anything higher than a 2B factor. In fact, anything higher than about 1.5 was taboo and the reason being is in higher porosity rock, it's fairly simple. The rock will perform uniformly. It will deplete naturally and you will see this nice bend and this nice curve. Well, guess what, we're not dealing with those rocks anymore, okay. We dealing with tight reservoirs that we're inducing fractures and we're putting massive fracture networks on. What that does is that generates what we call a two stage decline, the early time data is dominated by the fracture networks and the primary porosity and the late time data is dominated by the tight rock and the metrics rock that will ultimately give up, call it a flat decline and where that transition period takes place, yields a two-stage decline and you are going to here more, I believe, more and more about two-stage decline in the any conventional resources as we move forward. Now, what we believe as we look at these type curves, our type curve is the proven type curve identified in the red and green that Matt went forward with, that’s our consultant proven type curve. It's still using a 1.5B factor and if you think about it, it's not surprising that our EUR would adjust. Effectively, what happens is, if you don’t spend time or if you don’t see the evidence, you don’t believe there is enough evidence in the older data of the 145 wells to adjust the b factor and then you take that B factor and apply it to 500 new wells in our dataset that came on this year, then guess what, you come up with a fairly conservative outcome for the ultimate recovery. And that’s where you come up with this 107 and what we chose to do, we will show you the difference between the 107 and the possible outcomes that we could still see and then show you the impact of the rate of return, and we will go through that in a quite a bit of detail. This next slide really goes to the heart of what I am calling the two-stage decline and when you look at it, in magenta, let's call it magenta that's the plot of the 1,439 wells we plotted in Woods, Alfalfa and Grant County. These are the historic wells that were drilled over decades. And if you noticed, somewhere around that three year mark, you see this transition and flattening of the profile. So you go from what we had call primary porosity with induced fracture flow to metrics porosity flow regime and at that point, these wells went on what I would call a 1% or less decline and guess where they broke at? They broke at about 10 barrels of oil a day. So if you think about that you got a vertical well producing and in if flatten out about 10 barrels of oil a day. Now we've gone out and drilled the horizontal well. We've gone 4,000 feet in lateral length and we put 10 stages of frac on it. Right now, the green curve would have us rock below the performance of that vertical well in about I will 10 years. What we believe will actually happen in this reservoir and we are starting to see evidence in some of the older wells is these wells were dropped down to may be 20 barrels of oil a day to flat similar to the vertical wells and we put just for purposes of today, we put a 3% decline and that's identified in that grey bar. Well, if that actually happens in this reservoir, you are going to get 180,000 barrels of oil out of each well. So the variability and the ultimately you are, it’s still fairly high in the outer years as Matt alluded. We could still end up looking at these 644 wells, 30 years from now and saying we actually recovered 180,000 on average from these wells. That's the kind of variability that exist in the ultimate you are but what we are really here to talk about our economics and we are going to go through some of those economic criteria’s and show you the variability even if that happens it doesn't vary the short-term or the call it the five year outlook of this play at all. We would still have a very robust economic even if we end up its lower curve. Next slide shows the transition of our type curve. If you look at this, we started this play and I can't remember the well count it was less than 10 and we originally came out with the type curve at 235 MBoe. At year end 2010, we had 409; we had 37 wells in our history. We then move that up last year to 456 with a 145 wells and then we ended with this year with 369. If you think about it from year end ’10 to today, we've got about 17 times the wells in our data sets. So its not surprising these numbers can move around some on EUR basis and we will talk about the impact of rate of return here in the next slide. Now Matt went through this, I will give you a little bit more detail, the way we run the slide, is fairly simplistic, when you see the rate of return I just say 30% at year three, we actually stop the well from producing after year three. So what this chart shows you is if after year five we only tune 50,000 barrels of oil out of the well, we would get at 45% rate of return for our money. If we actually tune 107,000 barrels of oil out of each well that rate of return only goes up to 50%, so it gives you a relative sense that even if we only tune 50,000 barrels a day of queued out of wells, we are going to get a 45% rate of return for our money and the difference between talking about an EUR and a lot of emphasis on the EUR movement and this is if you think about where we are today versus where we are last year and we are now at 644 wells in our type curve, we have got a lot more confidence that we are going to perform the variability within that first five years is not very great, you are just not going to see these wells steepens or move very much from that first five year forecast but you are going to see that variability in the out years. So our confidence level in that rate of return has gone up a multiple from where we were last year. We actually had our engineers try to generate some confidence level charts and I finally scrapped it because it would take me at least an hour to explain the confidence level charts that we came up with for you but the confidence level is significantly increased from where we were last year. This next chart walks us through a little bit of the rate of return implications of these discussions. What we are really talking about here is you have a 6% rate of return change between those type curves, 107,000 barrels of recovery of oil or 152,000 barrels of recovery; you have a 6% rate of return change from those two numbers. Guess what as Dave was talking about all the work going on for the CapEx and the lower the actual CapEx a $100,000 of change in CapEx dollars, so going from $3.2 million or $3.1 million to $3 million per well changes the rate of return outcome by 5% and a $10 change in oil price changes you by about 10% rate of return and since we do make quite a bit of gas for each of our wells approximate $1 change in natural gas pricing changes you also by about 10% rate of return. So it gives you a little bit of relative impact of the things we are talking about so what are we doing, we are focusing on the things that Dave talked about, we are focusing on CapEx and LOE reduction and how to improve the performance of our wells to maximize that rate of return as we see it and the outcome of the EUR will be what it is, as we look out over the history of the well. The next slide, the other key interesting thing about the play from a learning perspective is what we did here is we took a distribution histogram up there in the right hand corner of our wells and as we I think as we said in the past we've got a fairly wide distribution of EUR outcomes and if you look at this slide what we are looking at is the upper P50 grouping of wells. So everything above the P50 mark we plot it on a map. Last year in we had obviously 145 wells we had approximately 73 in the upper P50 mark and those wells were primarily centered around Woods, Alfalfa or primarily Woods and Alfalfa. That's where our dataset came from last year. Now we've got 644 wells of which 322 are in the upper P50 outcome and this gives you the breadth of that outcome across 230 miles, all the way up to the northwest and Finney County and I apologize we cut off the chart down to the southeast in Harper County. It gives you an idea that not only have we extensively drilled more wells across the play but we've expanded the concept of the play and proven up horizontal versus the vertical performance across a lot more region of the play as well. One of the things we will talk about your hearing some news in the press and Ken I know has talked about a Hodgeman and Ness. We are going to show you not only our successes but our failures as we talk about this. As we think about where we are today we've been very successful moving our geological idea and our vertical concept versus horizontal up across a 10-12 county region and we will talk a little bit about what we are calling the appraisal area today and versus where we've put our NAV value. Our NAV value is now centered primarily from Gray down to Harper County where we've drilled the bulk of our wells. We have drilled up in Hodgeman and Ness and I'll go through that in a little more detail. One of the things you will hear and a lot of discussion about in some of the write-ups is taking our Mississippian 30-day IP data as I said and saying well Kansas isn’t performing, Oklahoma still looks okay but that limits the play to Oklahoma. When you think about it, our 30-day IP is 270 BOE per day. That’s our type curve. Oklahoma is about 356, but we've been expanding the play up across Kansas, across a very wide region and our outcome today is 254. Now what doesn’t get taken in to account as I said earlier is what is that equivalent barrels of oil a day, equivalent, what's the decline rate that goes with it, what are the economics that go with each of those? We're going to actually take you through, 20 examples; you are going to have a great day. We're going to take you through 20 examples all the way up from Finney County and we're show you well performance from Finney County all the way down to harbor and we we’ll show you come examples of the variability in the play as we move across. And we're not only seeing variability in IPs, gas/oil ratio, we're also seeing initial declines but generally speaking, what we're going to show you is we have economic wells in each of those counties, very economic wells. Different characterization but keep in mind, this is 230 miles. That’s a very large area and it's based on simple concepts. Vertical wells were drilled here. They had good vertical performance. We're taking horizontal technology and drilling next to some of that vertical performance. The other thing we noted and we did, and I don't think we showed you last analyst day, was we did a lot more work on the vertical performance. And one thing that we did note as we study the vertical performance is Kansas has a much shallower decline from the vertical performance than Oklahoma did. So in the Oklahoma data I think we have showed you last analyst day, we had a 65% initial decline from the vertical performance those numbers are more in 20% to 30% initial decline in Kansas and I think we have talked about Kansas we believe has a tendency to have better reservoir quality and we will go through that a little bit, it is good and bad I am going to show you both of the side as we talk today. This is that vertical performance keep in mind down there in the red doted outline is the 10-county area in Kansas, there were 6,000 vertical wells, this is where our NAV value of the 15.3 million blends in Oklahoma and this region of Kansas, okay. That outcome for that 10-county area was 50,000 barrels of oil. Now think about the 50,000 barrels of oil as you look at this play and think about our type curve, okay, what do we need to get a 45% rate of return on our type curve, we need 50,000 barrels of oil accelerated, okay, if we never got more than 50,000 barrels out of our horizontal performance, but got it at high enough rate, we would generate a rate of return. So really if you think about this vertical performance across here and keep in mind this vertical performance was comparable to the vertical performance that we saw in Oklahoma as well, as we started and entered into the play. Now the one thing that we did note is a shallow decline as we look at this. Now the other piece of information we are going through today is appraisal area, we have got about 7, 8 wells that have been drilled up in the appraisal area one, I call it in Finney County that is a very good well but as you move over into Hodgeman and Ness, it’s a different character and we will go through that. But keep in mind there is 400 million barrels of oil that we have been keen down at this region, not only in the Miss but in Kansas City, Lansing, Pennsylvania zones a number of other producing zones and if you look at this, it’s a little hard to see from the slide that our acreage position is spread out throughout that vertical production history. So not only are we looking at Mississippi and performance in this areas and appraisal area but we have got a lot of other zone potential to look at as we move into this area. All right, what is working, what is not working as well, but we have been very successful following the sub crops from Oklahoma into Kansas. I know we’ve shown this map before, showing you the various layers of sub crops, I wont go in to all the discussion on geology and hopefully your up to speed and little bit on that. The NAV area that we are talking about that we’ve assigned NAV value to is dominated by the Warsaw through St. Genevieve sub crops. Where Hodgeman and Ness is a little more challenged is its more in the Osage sub crop and we will go through a little bit more detail of that as we go through that, and interestingly enough not intuitive is that area was very prolific and Hodgeman and Ness as far as vertical recovery, and it actually has reservoir quality and I will go through a little bit of information on that here in a minute. We actually tested six non commercial wells in Hodgeman and Ness, not inconsistent with some of the data you are hearing coming out of EnCana and some of these other information. Now if you look at that map there's a significant amount of vertical production in those two counties. Actually 133 million barrels came from that two-county area. Now what's not intuitive is in this reservoir I think we talked last time about compartmentalization, how we saw different varying degrees of gas, oil and water and they weren't necessarily segregated in a normal fashion. You didn't have water, oil and gas segregated in normal reservoir fashion. You had a different mix throughout the reservoir. Well guess what as you get better reservoir quality you have a tendency to have that segregation take place and the reservoir quality actually lends itself to where you may need more traditional closure, and I call that geological interpretation of a closure, a structure something like that to help you actually produce that part of the reservoir. What we are looking at and the other issue is as you start to get more of that segregation is fracking into that water actually becomes more problematic. You actually end up with high, call it no oil, you actually water out your wells. So we are going back and the operational teams are reworking the exploration completion methodology and we still see significant reserve potential out of this area. It’s going to take a different technique. We've been successful chasing the sub-crop methodology where the reservoir quality is not quite as quality, we've been very successful and guess what that area extends all the way up through Kansas, all the way up to the northern northwestern most part of Kansas, because this area in Hodgeman and Ness is going to take a different technique, its not condemned yet, its just going to take a different technique. I talked a little bit about the statistical book, pud booking methodology, first off we got an interesting question yesterday. This is not a major interference, okay. Let me take you for those not familiar with the statistical booking methodology you actually break this into what's called anchor sets and then you look at the distribution and the EUR outcome based on what your well, your primary well is in the area and then you measure the distance between your existing wells around that and you do statistical analysis. Concept is, is it just as likely that you drill north of a well and get the same outcome, a mile and a half away or is it just as likely you drill east or west and get the same outcome. Once you get enough statistical analysis you can move into a resource booking analysis that allows you to do what I was talking about earlier which is book more puds in a more regional sense or resource play sense than just a simple east-west offset in the old methodology. Last year in 2011 in a fairly complicating charting but we basically the green checkmark show where we passed, we passed like one anchor set and what we saw this year in is it takes just about 100 wells per anchor set to start to show the statistical proof plays out and in the bottom set in 2012 you see we pass the one mile radius we are about half way past through the 1.5 mile radius and I fully expect by next year end a two mile radius will be a reasonable outcome for background statistical pud bookings around our existing PDPs, what that means is we should see significant reserve growth from this methodology by next year-end, from booking puds. One to one is a pretty conservative ratio considering the vertical control and the horizontal control that we have in the play today. The other interesting part of the play, I know there is a lot of discussion in the play about density. How many wells per section can you drill? We had three wells per section. We have now studied pairs of wells, three wells that have actually been drilled in the section, four wells that may not be in the section but are next two each other and we’ve actually got 40 pairs, in excess of 40 pairs of wells that have been drilled within a four well per section spacing of each other. The jest of all that discussion is we've seen no interference from wells. We have seen unique events sometimes, not any different than you have seen in some of the resources plays like the Barnett shale etcetera. You can frac in to a well. The microfracture heals up and wells comes back to producing at least as good as it was before or even better. Now the interesting news is Chesapeake has drilled an area in northern Woods County, five wells per section. We do have access to that data and that data is showing very promising. From two perspectives, one is the density of spacing a five well per section and the other area that’s very interesting is the concept that you might be able to go in to these areas and frac multiple wells, virtually at the same time and in actually improve the fracture network. Let’s just go through a little bit of that. What that’s really saying is and it's nothing we haven't known for years in reservoirs is if you create a pressure sink by producing a well, you can actually communicate the fracture from the second well, to that first well. What that means is if you are communicating that fracture network directly to that pressure sink, you are not breaking up the rock as efficiently as you like to. So what’s the most interesting part of this study is Chesapeake actually went out and frac these wells or I wouldn’t call it there is a technique known as simul fracking where you literally frac the same day all four or five wells at the same time. They basically frac generally these wells without producing the other well, without creating that pressure sink, and the outcome today has been exceptional on these wells. So from that perspective it yields some insight and to may be changing how we go back into the development scenario as we look forward to developing this reservoir. All right now we are going to go through, let me see if I can, we are going to go through and talk about these 230 miles spread as the top performing wells, and top performing wells maybe a little misnomer. We pick the upper P50 as we kind of talked about and just chose wells throughout that upper P50 of outcome. I am not going to show you the lower P50, we obviously get those distributed across the region, but we are going to show you examples of kind of upper P50 and it highlights wells in 10 county, which you are going to see is varying IPs, initial declines and B profiles, these aren’t the best wells each example. Another interesting thing I find which you see a lot of people talking about deferred a little bit to data sets. We have seen most of the data in the area, in the play, we don’t have data on all 1500 wells, but we have seen data on the large percentage of that information set, what is interesting is a lot of discussion around fairly small sample sets and as I said this is 230 miles of data that we are going to show you and we are going to talk about sub crops, lithologies, I know that you are getting really excited at this point. But you are hearing the lot of stuff where people are talking about, you got to be in the chat, you got to be in the chart, you got to be in this, you got to be this. Well guess what we are going to show you examples across the whole play, where we are in lime stone, we are chart, we are in different sub crops, we are going to show you examples as you move across this play, then what we are trying to point out is we have done, is we drilled 644 wells in our PDP set and we have a statistical outcome across a very large region, but it doesn't necessarily mean there is a one answer that fits all. What we are doing is we are developing a play that is making very robust economics with different lithologies, different sub crops but we are getting the outcome that we have expected based on what we did, when we are into this play which is we understood the vertical performance and I am going to try to do is apply horizontal technology to this. With that said, the next slide is the example in Finney County. This is the far north west and if I don't mess up our presentation, I will kind of click through and show you how we progress generally across the entire play, and we are going to show you this examples as we walk away across the entire play with examples of good performing wells across the entire region. This is a low IP well, 60 barrels a day, now if you keep in mind our type curve is 272 barrels a day initial IP, that includes gas, guess what, as we moved into Northwest Finney County, its not producing any gas, started out as a 60 barrels a day IP, the projection on it right now is 240,000 barrels of recovery and it generates approximately 40% rate of return. Now that goes completely in the face of the 30-day IP chart. It would be in the lower most tier of the 30-day IP chart and yet it is a robust economic outcome. When you look at this its going to be difficult to narrow this play down to a single indicator; we've got to be in chert, we've got to be in this, we've got to have this outcome. This sub-crop is St. Genevieve, primarily lithology is limestone. You don't see chart you don't see chert, you see limestone on this. As we said, lithology, the other misnomer a little bit in this play is we see changing and I think we showed examples last Analyst Day is we see changing lithologies even in the lateral section. So it’s not like these lithologies are just regional changes; we will see changing lithologies as we go down the lateral section and when you think about this one, what we are trying to do is give you the primary lithology that we saw in the well bore. Gross thickness of 600, EUR outcome of 240,000 on an extremely flat decline compared to our Oklahoma wells. And I'll try not to belabor these too much; I'll go through these fairly quickly. This is Central Gray County, Kansas, lower IP than type curve but it still look like you are going to accum our EUR about 190,000 barrels of oil, a little bit higher IP than the last example. But still fairly flat decline compared to what we see sometimes in Oklahoma and we will show you some examples of that. We move into Southwestern Ford County, low IP, very flat decline, looks like its going to be about 245 Mbo. If you look at this the 30-day IP is about 143, that's half of our type curve and yet the outcome is going to be very robust economics. Sub-crop St. Louis, primarily lithology limestone and dolomite and a very thick section there. As you move into Northwestern Comanche County and we are also seeing different areas of gas content, particularly in Comanche County we will show as you move through Comanche County we are seeing quite a bit of gas, 109,000 Mbo of oil expected outcome. You know in that range of type curve outcome for 30-day IP, 290 sub-crop St. Louis with the limestone-dolomite lithology. Moving on into Southwestern Comanche County, this is an area where we've seen lower oil but much higher gas, 3.1 Bcf expected outcome, 205 a little bit below our expected outcome, but you can see again sub-crop St. Louis limestone-dolomite with thickness of about 700 feet. Here we are going to move into Eastern Woods County. Some of the wells again now you are seeing a pretty flat decline, guess what, this well would have been sub par Oklahoma IP, 30-day IP. You've got an extensive amount of history over a year with the date on this and it looks like its going to be 500,000 barrel oil well with about 883 Mboe outcome. This would have been sub-par Oklahoma kind of outcome for an IP and yet it's going to be an exceptional well when you look at EUR outcomes. And you picked up a little bit of chert there with limestone and chert in the St. Louis formation. We move in, we will move in Northern Alfalfa County. Here is a well with a high IP, exceptional IP, you are looking at a 1000 boe per day for a 30-day IP and you are looking at an exceptional outcome of EUR as well, about 1 million barrels equivalent with about 392,000 barrels of oil. If you see the different character in this one, much higher IP with a steeper decline compared to previous one in Woods County as we talked about and in this case there are limestone, chert and dolomite, all three and you're in spurge in sub-crop. Central Alfalfa County, low oil and gas IP with a flat decline profile and a high EUR about 859 Mboe with about 400,000 barrels of oil. Keep in mind that’s a 150 Boe per day outcome significantly below our expected 30-day IP outcome and yet is an exceptional well. Southern Alfalfa, sub-crop St. Louis limestone and chert in Warsaw; you had a much higher IP, 473, very high IP and you are above type curve with 172,000 barrels of oil and you are below on the 332 Mboe curve and Southern Harper; very high IP, high EUR, 199,000, oil with a fairly steep decline in your limestone, chert and dolomite in the St. Louis Spurgen. Western Grant, strong oil IP, with an EUR of 192,000, Mbo but still you are less than call it our standard oil type curve 30-day IP when you think about that and compare it to the oil outcome on Oklahoma. Central Grant, strong oil IP and oil EUR of 325,000 barrels, again higher IPs in this area, but steeper declines as we look at it. Northern Garfield, low IP with flat decline limestone and chert, St. Louis and St. Genevieve with an EUR of about 280,000 barrels of oil, but again, you had 202 Mboe per day, 30-day IP for this area. And Northwestern Noble county for my last one strong oil IP with steep decline with an expected of about 154,000 barrels of oil. So you can kind of get a flavour of that and primary lithology chert and limestone kind of as my final closing as you think about the play there is variation in the play. We are seeing a lot of variation, well-to well, area-to-area, but when you look at the play over a wide county area of 230 miles, we are seeing rate of return outcomes across that whole region and quite frankly we still got of area to drill up using the vertical data as our yard stick and the horizontal technology in Oklahoma and Kansas and we look forward to a lot more reserve adds as we move forward. And with that I will turn it over to Gary to go.

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 low risk acquisition opportunities. We are not out there just buying whatever we can get; we want to get to quality projects. Looking at those for a low to moderate risk exploitation opportunities, and we are utilizing our current infrastructure; primarily, we have fixed costs out there adding additional production adds very, very little expense to our LOE. Proactively, we are conducting abandonment to save operating expenses and reduced risks. In the past, most companies would put off the abandonment liability until the very end of the life of the field. We are trying to do that a little bit more proactively, take some of these platforms out that we are not using, plug the wells, at least temporarily abandon the wells, that eliminates a lot of risk in case we have any hurricane damage, one of our focus points is to conduct all of our operations safely, very, very focused on safety. We have a very, very strong culture of safety that we keep pushing. One of our strengths, we’re a proven operator in the Gulf of Mexico. We're fully staffed with qualified experienced professionals and support people. We have a ready infrastructure in case we drill a well, re-complete a well, it can go online very, very quickly and again we try to do everything safely and are safe operator. Acquisition capabilities, our strategy really hasn't changed a whole lot. We want to identify quality assets with motivated sellers. The Gulf of Mexico is not one of the prime positions that the market sees people being these days, but there are still people out there selling and there's still money to be made and we are trying to make that money. Silently acquire based on conservative valuation of crude reserves, we are buying what we are seeing. We are acquiring properties with low risk upside, but majority of the purchase price is based on what we know is there and consolidated interest in quality properties. Again, if we buy a property, we‘ll have a partner, we are going ahead and trying to buy some of those guys out. A little history timeline, along the bottom you can see in February of 2008 SPN resources was purchased by Dynamic, followed that up recently purchased by Northstar and made several other acquisitions through that time. In April of last year we were bought out by SandRidge and then this past summer bought Hunt Oil. A little acquisition case study, I'll talk about the Hunt acquisition, originally purchased it for $51 million, the purchase price $14,000 per producing barrel, purchase price for reserves, $6.23 and original operating income 1.7 times. Looking back on the acquisition, we’ve had about six months, purchase price $51 million and generated cash flow of $30 million. We sold one well very, very interesting sale. We had only the rights to one horizon and one well. The partner in that bought us out. So we sold it. We made about $1.7 million in capital investments and we will talk about those in just a minute. So basically at the end of the year, we had net investment of $15.5 million. Our remaining PV-10 as of 01/01/13 was $55.3 million. The production graph on the right indicates the production since we got it, came on, the big dip there is Hurricane Isaac, had some other shut-ins associated with some pipelines out there, but as you can see, in December we started over three well re-completion program and up to our rates, at one times over 7,000 barrels a day net. Now it's over 6,000 barrels a day and we will talk about those recompletions just little bit more in detail. One of the older fields we have out there Ship Shoal 301 an active drilling program out there, we've got the (inaudible) jackup drilling rig on location out there. We have a 100% interest in this. This is an area where we did not have a 100%, but when we saw some opportunities, we went back and bought out the other operator. We’ve drilled one well to-date to Ship Shoal 301 A side track mentioned that earlier; making about 18,000 barrels a day and about 1,800 mcf a day, a very strong well, just continuing to go forward with this. You can see on the top right hand corner, your graph is the log section on the Trim B sand. We've got another well at TD. We got pipe set in the process of completing here. Found it Cris S upper zone, actually was down structure of a well that we drilled as adjacent to. Found it productive and we found our target in the lower Cris S about, a little over 60 feet of play, currently in the process of completing that well, really looking forward to it; it ought to be a very strong well, high pressure over there we ought to get a lot out of it. The well last well to drill, see on the lower right hand map, out there towards the Eastern portion of that is our A5 target; it’s another Trim B target, similar to our A1 side track. It’s the next drill location and take about 25 days to drill it, about 16 days to complete it, that will be the last well of our (inaudible) contract. Mentioned Eugene Island 77 little earlier; we did three recompletions out there and did them about $2 million total cost; own this 100%. First recompletion was the number nine well, so it’s making almost $4 million a day with a right out of a 100 barrels oils flowing very, very strong for us. Eugene Island 77 number 10, the first of our T-1 sand completions, 540 barrels a day and 1.7 million a day of gas; a little bit of water there; we are trying to get a jumper line over there to get some gas lift of that well to see if we can increase that rate a little bit. And then the best oil we have got out there Eugene Island 77 number 11, recompleted this well again this is a very, very simple recompletions, little wireline went in there, setup plug perforated tubing making 530 barrels oil a day; 14.5 million a day very strong flow in tubing pressure. This well has more capabilities if we choose to open it up. The pictures on the right, we have got little structure map there and a little log section on each of these; just notice the fact that these are not the last zones in these wells we do have other zones in these wells and we can go up all too. For 2013, one of the things that’s not on here is we have plans oil line out of this field, currently, we have got a little bit of restriction because our oil quality has to be at a certain level for the pipeline to take it, we are putting in through a gas pipeline; we are meeting specs as it is, but there are some oil opportunities up hole and to fully capitalize on those, we’ve got lay an oil pipeline. Our 2013 forecast, we plan on making at least 28,000 barrels a day. We have already adjusted that for hurricane and operational risking. Our capital spending as Matt indicated earlier $200 million a day, so $200 million, $150 million on drilling, $30 million on recompletions, so about $80 million on facilities and $3 million on land, abandonment spending, $120 again Matt mentioned this earlier, $30 million to abandon 170 wells; we mentioned we have 610 wells or so that were not producing. This is part of our program to get a lot of those abandoned. We got 28 platforms we want to take out; we have to make a one time payment to well control of $23 million. This completely covers all of our P&A liability at Bullwinkle with exception of new wells that get drilled out there. And we’ve got a $38 million abandonment liability and each breaks 110, 105 then we’ve got take care of this year, we’ve got some pacing pressure out there, we’ve got to remediate; we need to get that facility up. Go forward, our normal abandonment run rate guidance, $65 million a day should cover everything we plan to do over the next five years. With that I am going to turn it back over to Rodney to talk about Corporate Reserves.

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 and Dynamic and little Panther acquisition in Oklahoma at 66 million barrels production of 34 and then the revisions of 112. The 112 is about 87% driven by pricing adjustments for gas, that's driven by our legacy assets in WTO or Pinon and then some smaller assets that we still have in the Mid-Continent the Sahara gas drilling that we have in the Mid-Continent. Mid-Continent was a significant growth engine this year to reserves, you can see Permian was still a large piece, we will give you some pro forma at the end of this we will show you the year end reserves and then pro forma out the Permian sale as we get to the end. If you think about our reserves, the one thing we like to point out is 98% of our reserves are third-party engineered not audited they are full blown engineered of which most of that is done by (inaudible) does all of the Miss’ essentially all the Mid-Continent and most of the Permian, WTO and the offshore properties as well, okay. Reserves and value were up from 64% proven developed to 67%, the Mid-Continent is up from 26% of our base to 31% and as I said, we will show you the pro forma as we get to the end. Now one of the things that shows up a little unique on this is the WTO other, it shows as a negative PV-10 value, that's, the reserves actually run as a positive PV-10 value but we have contracts associated with the WTO that have to be fulfilled whether we produce reserves into them or not and that's why that run is negative as you kind of think about that. Continued oil growth, 58% in oil reserves and 89% in oil value and kind of see that chart, what's most dramatic on that chart is the transition from year end ‘08 to year end ‘09. You know, we were 12% oil reserve mix in ‘08 to 48% and we gradually grown as we've gone through the years. And this chart is by type, by proved oil well value. 85% of our reserves are oil. PV-10 value essentially all of it is associated with it and 81% of our well count. Transition is pretty complete. If you look at this, we give you all the calculations. Feel free to tear this apart. Last year in, our drilling F&D was 20.09. This year end it was 20.40. All in F&D was 24.92 and this year end it was 21.89. Last year end, we had 303% reserve replacement. This year, we had 454% reserve replacement. And as I said, we're still booking about one-to-one in the midst. The next slide it walks you through the proved developed finding cost, 2,168 and with land and seismic 2,402. We gave you a separate chart showing of the breakout of the trust. As mentioned earlier, we had three trusts, one in the Permian and two in the Miss and this breaks out the trust ownership out of our reserve deck. It's 38 million barrels and $955 million value in PV-10. The next slide shows, it's a little complicated slide but the gist of this slide is unlike some major offshore players in some of the regions, we don’t end up with any single reserve quantity that dominates our reserve package. In other words, if one well fails some place, we don’t see a significant reserve right after our reserves. All it essentially says is we have a low risk profile. We have a lot of wells with individual forecast on them, but any single one well won’t change the outcome. Couple of other reserve issues that you hear about in the industry are PUD vintage is essentially we don’t have anything on our books right now since we are drilling most of our inventory that has a vintage over about two years. So our PUD vintage is exceptional in the industry today. And then if you think about our PUD inventory at our drilling pace right now, we could drill up our inventory in less than two years. So the five year rollback to the right and five year roll to the left. We are exceptionally good on both of those indicators. When you think of the Mid-Continent, the PV value remained essentially the same we will talk a little bit about that, that’s $2.3 billion of value net reserves or NAV value of $17 billion again this has 1.7 for the appraisal area in it, proved reserve replacement 918%, proved developed at 60% and value of oil revenue at 80%. And if you notice, our F&D cost are 13.91 per BOE equivalents significantly less than in corporate. Again, the world is not as simple as it sounds sometimes the 21, we have a higher F&D cost in some of the Permian assets but it did have a higher oil mix. So it’s not a perfect indicator in any of these circumstances just to think about it that way. Mid-Continent waterfall, as you think about the Mid-Continent, we had minor acquisition as I mentioned the 5 million barrels, 11 million of production we had 28 million barrels of revision, but 10 of that was associated with pricing associated the Sahara properties, the gas properties that we talked about earlier. So really there was about a 12% adjustment associated with all other discussion around type curve etcetera to the Miss properties of previous reserves bookings we give all of that and again 1.1 ratio and then you see the extensions of 125 million barrels of extensions in this, so significant growth engine as you think about the mix. We gave you a Gulf Coast semi waterfall just to give you an idea that the reserves as Gary had indicated have been very successful. The reserves effectively remained the same, you had 60.8 million barrels of acquisitions as we talked about, pricing revisions if you noticed somewhere in the middle of the page it's about 16.6 Bcf of gas that's some of the gas reserves that got hit by the pricing equation. So you had about 2.7 million of downward revisions from pricing offset by performance revisions of about 2.4. So all-in-all, our Gulf Coast reserves, well, their performance operationally has been exceptional. The reserves have stayed consistent with what we purchased for us as well, about 11% of our corporate total reserves and 18% performing after the Permian sale. Pro forma post sale, we gave you after the Permian sale 367 million barrels and $4.3 billion of PV-10 value and you can see Mid-Continent is 54%, Permian is about 19% after pro forma and Southern is about 33%. And finally, NAV slide showing are 20 and this slide we removed the $1.7 billion of NAV value potential. We would say that the appraisal area it’s about 500,000 acres in that appraisal area, a significant value that could be added there. You can see right now pro forma after Permian its about $20 billion NAV value with no assignment to that appraisal area and with that Tom, you want to make a quick comment and then we will go to questions.

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.