Good day, ladies and gentlemen, and welcome to the Second Quarter 2013 SandRidge Energy Earnings Conference Call. My name is Tahisha and I’ll be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Kevin White, Senior Vice President of Business Development. Please proceed.

Thank you, Tahisha. Welcome everyone, and thank you for joining us on our second quarter call. This is Kevin White. With me today are James Bennett, President and Chief Executive Officer; Eddie LeBlanc, Executive Vice President & Chief Financial Officer; and David Lawler, Executive Vice President and Chief Operating Officer. Keep in mind that today’s call will contain forward-looking statements and assumptions, which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. Additionally, we will make reference to adjusted net income, adjusted EBITDA, and other non-GAAP financial measures. A reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website. Please note that this call is intended to discuss SandRidge Energy and not our public royalty trusts. Finally, you can expect to see our first quarter 10-Q filed after the market close today. Now, I would like to turn the call over to James Bennett

Thank you, Kevin, and welcome everyone. I also want to welcome the newest member of our senior management team, our Chief Financial Officer, Eddie LeBlanc. Eddie brings to us over 30 years E&P finance and CFO experience and we are excited to have him here. Now that we’re more than halfway through 2013, I feel confident saying that the course we laid out earlier this year is delivering results. In the first quarter we made changes to our business plan to high grade our capital program, focus on returns, exercise capital expenditure and overhead cost discipline and lower the risk profile in the business. And our second quarter results are evidence that these changes are taking hold. Highlighting the recent successes to come out of this plan are the fact that our production continued to set new highs and our costs new lows. Since building our Mississippian position starting in 2010, we have emerged as a dominant operator in the play and we continue to make improvements, exploit our knowledge base and create better returns. Quarter over quarter, we grew our Mississippian production by 20% and Mississippian oil production by 30%. We grew total company production, adjusting for the Permian sale by 5%, even taking into account expected declines in our Gulf of Mexico business. Our well performance continues to improve, with 111 second quarter Mississippian wells producing an average peak 30-day IP of 377 barrels of oil equivalent per day. We had six wells with 30-day IPs over 1000 barrels of oil equivalent per day. Recall that we high graded our drilling program to concentrate in our six county focus areas, where we’re seeing more consistent results and can better utilize our infrastructure. This year we anticipate 90% of our drilling to be concentrated in these areas where we…

Thanks, James, and good morning to everyone joining us on the call today. As outlined in our second quarter earnings release, the Mississippian offshore and Permian business units continued to deliver strong results. And while we are pleased with the numbers themselves, we are also pleased with our progress on three key initiatives which are serving as the catalyst of the improved performance. First, we have significantly increased our production in the Mississippian business unit. As James pointed out, we delivered 111 wells to first sales with an average 30-day IP of 377 BOE per day. This rate is 39% above expectation. If you recall from our Q1 earnings release, our average 30-day IP was 21% above expectation. So we are pleased with this sequential increase. We attribute this production improvement to our sub-surface characterization and modeling efforts. Our model is based on the data collected from over 850 horizontal wells, 126 disposal wells, 13 hole cores, horizontal formation image logs, and recently acquired 3D seismic covering 183 square miles. We’ve analyzed this data and formulated seven value enhancing variables that help plan our well planning process. One of these variables for example centers on the natural fracture systems and enhanced hydrocarbon recovery. When combined, these seven variables allow us to high grade our projects during the well selection process and by identifying the specific area, depth, zone and artificial lift technology required to maximize value. Second, we have significantly reduced our drilling and completion costs. As highlighted, we decreased our well cost from $3.1 million to $2.95 million during the quarter. This $150,000 improvement increases our rate of return from 44% to 50% and increases the number of wells in our development portfolio since more projects now exceed our capital investment threshold. Approximately $100,000 of these savings was achieved…

Thank you, Dave. This being my first earnings call as a member of the SandRidge team, I am extremely fortunate that our Mississippian production and our execution on operating cost savings [initiatives] have not only allowed us to exceed consensus estimates in each category, but have also provided strong financial results for me to discuss. Our second quarter adjusted EBITDA of $268 million is basically flat not only with the $270 million of the first quarter of 2013, but is also flat with the $269 million of adjusted EBITDA reported in the second quarter of 2012. However, it compares very favorably with those periods on a pro forma basis considering the divestiture of the Permian assets in the first quarter of 2013 and the acquisition in April of 2012. On a pro forma basis, the $268 million of adjusted EBITDA in this quarter exceeded both the $219 million in the first quarter of 2013 and the $186 million for the second quarter of 2012, a 22% and 44% increase respectively. Our last 12-months pro forma adjusted EBITDA is $897 million. Our adjusted net income of $44.6 million for this quarter results in adjusted net income per diluted share of $0.08 as compared to $37 million of adjusted net income or $0.07 per diluted share for the second quarter of 2012. Adjusted operating cash flow for this quarter is $176 million as compared to the $182 million for the first quarter of 2013 and $223 million for the second quarter of 2012. It is important to remember that in calculating adjusted operating cash flow, we only adjust for cash received or paid on certain commodity derivatives and for changes in operating assets and liabilities and not for the effect of one-time items. The admirable operational performance that Dave has reviewed with…

(Operator Instructions) Your first question comes from the line of Neal Dingmann from SunTrust. Please proceed.

Say, you guys, James for you or David, just wondering on the -- obviously great results on this middle horizontal Miss, was wondering just if you would look at the acreage, any idea of just kind of what percent or total acreage you might have potential for this type of grade play.

Hi, Neal, this is Dave. We won't give a number at this time because we are still kind of in the early portion of developing the different zones and the testing program. But we found one area that seems to be pretty strong and so we are just continuing to push the envelopes of that particular region.

Okay. And then obviously, you had mentioned Dave that type curve obviously, just on the average is now at the -- or it looks like the 30-day IP was up to 377. I guess what I am wondering, will you put out any time soon, you know had the type curve overall improved or just your thoughts on average type curve value improvement.

Neal, we won't comment on kind of type curve at this juncture. Every year kind of at the end of the year is when we kind of revise or make an edits that are needed. So at this point we are just encouraged and we will just continue to watch the wells and then as we kind of close out the year, we will go through a formal process with our team and our auditors and come up with that answer.

Okay. And then just....

Just on the stack pay, if you look on our presentation that we have up on the website, we have kind of detailed map in there where we show the different members of the Miss, upper, middle, lower and how that extends across the play. So while we don’t have specific acreage, I can give you an idea of the stack potential that we see really across most of our leasehold.

That helps. And then lastly, just again now, kind of with Eddie and James that you had mentioned about cutting the cost I guess a little bit, or just overall spending. Just wondering on any thoughts you could give on potential acreage you think you will keep between sort of now and sort of on a end of the year exit rate?

In terms of acreage that we will keep?

Yes.

Yeah, let me give you -- let me just talk about acreage for a second, give you a few stats. You know with about a 425 well program, we can hold between 200,000 and 250,000 acres annually. Kind of depending on how many second and third laterals we are drilling. So that’s on an annual basis. And on the total play, in 2013 we have 250,000 acres that are expiring. We have extensions on 60% of those at $131 an acre. And we think we will extend probably 75% of that 60% if that makes sense. So if we extend it all that would be $20 million. In 2014, for the whole play, we have 740,000 acres expiring, but we have extensions on 80% of those at $127 an acre. That would be $75 million. We think our budget next year in land will be in a similar zip code of $100 million. In terms of what we’ve HBP’d because we get that question too, for the total play we’ve HPB’d about 17% of the acreage, 40% in Oklahoma and 7% in Kansas. And so that’s the total play, Neil. So let me just talk about the focus areas for a minute where we have a 925,000 gross with 615,000 net acres and that’s roughly 200,000 on a net basis in Kansas and 420,000 in Oklahoma. We’ve HBP’d 42% of the focus areas, 48% in Oklahoma and 28% in Kansas. In 2013 we have 170,000 acres expiring in the focus areas again. We have extensions on 42% of that at $162 an acre and we anticipate we’ll extend probably 80% of those. In 2014 we have 150,000 acres expiring in the focus areas. 42% again we have extensions on and that’s $271 an acre and that would be $17 million if we extended it all. So between the acreage that we’re going to HBP by drilling, the extensions that we have which are very reasonable again in the $130 million range and the land budget we have which we’re very comfortable about our land position ability to keep what we want. Now we will let some land expire that we don’t plan to drill or is not prospective or we haven’t had positive results. But what we’ve also been able to do is add in acreage. Year to date in our focus areas, we’ve added 35,000 acres at about $700 an acre. So about $23 million and these are in the best areas of the play that we like, offsetting our best producing wells. So while we’ll let some acreage expire, we’ll renew acreage that we like and we’ll add in even better acreage. So I know it’s a long answer, but I hope that gets some of the acreage and HBP and extension data out there.

Your next question comes from the line of Charles Meade from Johnson Rice. Please proceed. Charles Meade – Johnson Rice: I’d like to ask a little more about the middle Mississippian zone and try to decompose that 710 BOE average. And specifically one, could you give us the product split on that average? And then the second thing I’m wondering there is what the variance behind that average is and specifically if there’s one well that’s really bringing, pulling that average up or if alternatively those wells are pretty tightly clustered around that average.

Hey Charles, this is Dave. Just the first part of that question, the split is approximately 45% oil. So consistent with what we’ve seen with the rest of the play. And then in terms of just overall delivery, what we’re seeing is just when we target this part of the zone as we’ve expanded, naturally the primary interval is the one that we want to target first. So as we started the play, we started at the top and then as we started looking at the C and seeing the results that were coming in, we started moving more in that direction. So again what we’re seeing is very strong production. In terms of the repeatability, we are seeing some very tight performance. So overall it looks like it’s very strong and of course we’ll have to watch over time how the other wells come in. but at this point it’s a pretty tight band. We don’t have that production dominated by a single well by any stretch. Charles Meade – Johnson Rice: That’s great color David and of course it’s early, but it looks like it could be a step change. But the second thing I think you just touched on briefly, but I just want to make sure I understand the nomenclature you use when you’re talking the middle zone. It sounds like what you’re talking about is the Warsaw C and you’re targeting that in areas where that’s not the member right below the unconformity. Is that correct?

That’s correct, Charles. I can see you’ve done a little research on it. Yeah, we use the middle Miss, but that can also – you can use the term C to explain it. But yes, what you see are different process intervals within the Miss itself and even within the different benches. So when we talk about middle Miss, just for clarity we try to break it really into upper, middle and lower, but in this case we are talking about the C.

Got it. And this will be the last thing I try on this, so if I look at your [sub-crop] map here, what it looks like is that you have got a stretch. Perhaps, it looks like you made right through your core of Woods, Alfalfa, and Grant where that C would be the member that’s not immediately below. So is that kind of your fairway at this point you think?

That’s an area that we are certainly interested in. But you are correct in that as you move to different parts of the play what could be characterized as middle is different than the C. But in particular what we are talking about here, you have identified correctly that the C is the middle in that portion and that’s something we are excited about.

Your next question comes from the line of Dave Kistler of Simmons & Company. Please proceed. Dave Kistler - Simmons & Company: Kind of want to focus a little bit on the 3D that you have done. Can you talk a little bit about what that’s done for increasing the probability of identifying better performing wells? And kind of on that landscape, talk about it in terms of what that does to inventory? Is that taking up aggregate inventory or is that also identifying areas you don’t want to go to and reducing a section of inventory. Just trying to get a better picture on that?

Okay. Thanks, Dave. I think kind of the key issue with 3D, I think we have always said that as we started the play, we felt like there was sufficient historical production to be able to target the best intervals, the most prolific intervals. And we have found that really to be the case. But as we progress through the play, we are adding in kind of all the tools available to us. So in Q2 we picked up pretty significant 3D survey in one of our project areas. And how we have used that, at least initially there are pretty large fault zones that you can lose circulation in, and so we have been able to avoid drilling some wells that may have been problematic for us. But we have also seen some trending and some success where production has been higher around some of those fractures. So we are starting to integrate that data and see if maybe we can repeat that performance. Still a little bit early for us to claim success associated with the 3D itself in terms of higher rates but our scientists have been looking hard at it. We have avoided a few wells that are in the area of those lost circulation zones and it does look like we are going to be able to pick some stronger production perhaps off that data. So we see it really as another tool available to our teams and we are going to continue to expand our inventory of 3D. Dave Kistler - Simmons & Company: Okay. I am just trying to digest that, I know it's pretty early days. In aggregate you feel confident that that’s reducing statistical variability between the wells that you are drilling. Is that a fair statement or....

I think it's fair that I could, Dave. But we wouldn’t say that at this moment but it's our intent that that would be the outcome. Dave Kistler - Simmons & Company: Okay. And then just looking at the 111 wells that you guys drilled this last quarter. Can you talk a little bit about the statistical variability? Was it tighter than it's been in the past? Any color there would be helpful?

We have reduced the variability. Since within our project areas we have more data, our teams are getting much better. I had mentioned the seven variables. All those things are contributing to kind of tighter performance band. So, yes, we are seeing kind of the result that we had hoped for. Dave Kistler - Simmons & Company: Okay. And on that 111 wells, it looks like there was little bit of a mix shift of drilling. More Kansas wells versus Oklahoma that probably ties to the [HBP] comments that James made earlier. But was there any kind of statistical deviation in terms of well results in the Kansas area versus the Oklahoma area, of your kind of six core areas.

Typically no. With these focus areas, even if we are on the Kansas side we are seeing strong production as well. So I would say it's fairly typical to what we have seen in the past and would be consistent across the board. Dave Kistler - Simmons & Company: And then just one last one on the aerial extended at middle Miss, it also looks like that works its way up into Kansas pretty dramatically, but it doesn’t look at least in the map that you’re laying out that that’s as stacked oriented pay zone. Is there a performance deviation because you get shallower up there if you not tested up there yet? Just any thoughts on that.

I think our program in Kansas to date has been very broad. So we haven’t been specific enough to make that conclusion. But as you know that middle member, that specific zone or the C, whatever term we may use for it, it does cross the border and we do think that there’s production in that interval along the whole trend.

Our next question comes from the line of David Deckelbaum from KeyBanc. Please proceed. David Deckelbaum – KeyBanc Capital Markets: A couple of my questions just to start off is, what's your outlook for the Gulf of Mexico right now as you go into 2014? And given just some the clients that you're seeing so far, what run- rate CapEx do you think you need to put on those assets to keep production flat?

Sure. We did talk about a couple of those of pipeline curtailments and other things we had in the second quarter that impact our production a bit. But we still see year-over-year about a 10% decline in the Gulf of Mexico business. You’re averaging about 31,000 barrels of equivalent per day last year. We averaged about 28,000 this year. We do have the well that Dave mentioned that's about to come online. So again we think we'll average about that 28,000 a year. So I wouldn't extrapolate our first quarter to second quarter decline as how the rest of the year is going to progress. Into '14, I think we'll have a similar you call it $150 million to $200 million CapEx plan. We haven't gone through our full 2014 budgeting process yet. We're doing that now. So we'll come out with an exact plan in the November timeframe. But I would expect something in the $150 million to $200 million range and keep that production relatively flat. If we're at the low end of that we may a small amount of decline in the Gulf of Mexico. David Deckelbaum – KeyBanc Capital Markets: Could you just remind me how much downtime are you baking in your guidance right now for hurricane season this year?

About 250,000 barrels of oil equivalent in the July, August, September timeframe. August, September, October timeframe. David Deckelbaum – KeyBanc Capital Markets: My last one just on the successes in this quarter on the IP rate improvements. There was a discussion about the introduction of ESPs and someone else brought up EUR is changing and obviously it's early. But is the conclusion at least from your perspective other than being in the focus area and perhaps there is a little bit more energy there that the increased IP rates are more related to the introduction of ESPs or do you think it's more geological?

Yeah David. We think it's a combination. We've ran a significant number of ESPs in the last 19 months. So just for reference we have 285 in the ground as of today. So there wasn't say it was a slightly higher concentration of ESPs this quarter, but not significant. So really what we're seeing is high grading of the technology that we're using, our sub-surface model coming together and then meeting up the appropriate artificial lift technology for the reservoirs that we're in. So I've heard that and just wanted to spell that that's not the driver. We did have some very, very strong wells come on in the gas lift. One of our 1000 BOE per day wells with on gas lift. So there’s no concentration or overweight of particular performance set that's ESP linked. There’s certainly appropriate in parts of the field and in other parts they're not. So it's just really the correct application in picking the right zone for development.

Your next question comes from the line of James Spicer from Wells Fargo. Please proceed. James Spicer – Wells Fargo: I have a question on your guidance. It looks like your full year guidance implies a slight decline in production during the second half of the year. Your rig counts drops to 22 rigs from an average of 26 in the second quarter. And then in 2014, you are projecting double-digit production growth with an average of 25 rigs. Am I understating that correctly?

That’s right. You got it right. James Spicer – Wells Fargo: So you are adding three more rigs from the second half of the year and your production is going from flat to declining to a double-digit growth?

Well, keep in mind in the Miss this year, with our new guidance, we will have 70% of liquids growth and 66% total production growth. And that’s averaging that 25 rig count. So if you think about next year averaging similar 25 rig count, again that’s just the Miss, we have slight declines in some of our legacy Permian assets and a slight decline in Gulf of Mexico. But, yes, we can get to double-digit production with that 25 rig count next year. James Spicer – Wells Fargo: Okay. Great. And you talked about this for the Gulf of Mexico in terms of how much CapEx you thought you might need to spend to just keep production flat. What do you think that number would be for total corporate production?

You know it's not really a model that we run. We are trying to grow our production and net asset value and deploy our capital to get the best return for the shareholders. So we don’t really have a number that would be a case that would be flat production. It's not something we look at it this time. If the world would change and commodity price environment to change, or capital availability would change, it's something we would look at but it's not something we have right now. James Spicer – Wells Fargo: Okay. My final question is, your net leverage is obviously going to be increasing here over time. Just wondering what your comfort level is in terms of how high you would like to see it go before you would want to address that.

We are pretty comfortable at 3.5 times. I think we get nervous as it exceeds that and we would only do it for a short period of time. And we would address the issue directly prior to getting the 3.5 times.

And you know the leverage, you have to take a lot of variables into account there. When your debt maturities are coming up, we don’t have any until 2020, how hedged you are. If I am completely unhedged, I am pretty nervous at 3, 3.5 times. If I am completely hedged for a couple of years, it gives me a little more cushion. So I think there is a few other variables that go into that. It just depends on those.

Your next question comes from the line of Duane Grubert from Susquehanna Financial. Please proceed.

You guys are doing a lot of really interesting experimentation in use of stuff like the [rotary steerables] and all that. I have heard somewhere that some operators are trying vertical wells. And I would like you guys just to comment on, is there any applicability of vertical in the foreseeable future.

Yeah, Duane, this is Dave. We don’t see the primary development as vertical. We do see segmentation or compartmentalization of the reservoirs and we think that you get the highest rate of return from a horizontal development. That said, there may be parts to the field where verticals could work. We have drilled some verticals, we will probably drill some in the future. But as you can see by our CapEx program and where it's being spent, primarily we think it's the horizontal play. But we do know people have drilled some verticals and done well and we might drill some as well just depending on the situation.

And then in terms of sub-zones, Devon's out there this morning revealing its Woodford development. I know you guys in the past have acknowledged that there is some Woodford potential out there. What's your thinking specifically on the Woodford as where you are at in terms of gathering it into your thinking?

Okay. Great. I am glad you asked the question. We do have significant amount of Woodford acreage in our play. Very much similar to Devon's, particularly in Grant County. So we are actually a partner with Devon on one of those wells, or at least one of their wells in the area. And we actually spud our first Woodford well this week. So obviously it's very early and not something we really want to talk about until we get further down the path. But as we see this area is certainly prospective for Woodford.

And Duane if you remember, we talked about the Woodford potential is part of the stacked pay program at our Analyst Day back in February. So it’s something we've been working on for quite a while, getting it mapped out, getting the locations together and it’s something the team has done a great job putting together. And as Dave mentioned, we're starting on that program this quarter. Duane M. Grubert – Susquehanna Financial Group: And then finally, in the Gulf of Mexico where you have chosen to do some exploration work, how might we think about you doing a proportion of your Gulf of Mexico program as exploration? How do you make that allocation choice? And might we see you do incremental acquisitions given a lot of property acquisition activity out there lately?

Sure. So we'd caution the investor group that we're not out drilling sub-detachment wells by any means. But we do have a significant amount of acreage that we have 3D seismic on. And so we will participate in exploratory wells that are in and around our existing production. They may or may not be of our own, but they could be others. And so we'll be conservative with that exploration program. But certainly where we feel like it's a lower risk opportunity we would pursue that. In terms of acquisitions, the team does look at small bolt-on acquisitions and certainly there is room for expansion as those make sense. So James, did you want to follow up on that?

We do look at deals, Duane, in the Gulf of Mexico. They also have to compete with capital for the Mississippian and the rest of our program. We could boost our production quite a bit if we just wanted to do bolt-on acquisitions in the Gulf. But we want to make sure that we're deploying capital in the best way and developing out the Miss in a balanced program with the Gulf.

Your next question comes from the line of Adam Leight from RBC Capital Markets. Please proceed. Adam Leight – RBC Capital Markets: A lot of stuff has been covered, but I'll just maybe tidy up. If I missed it, just want to get a sanity check on when you thought the production would bottom out and start to turn up again. Are we looking at second quarter next year?

Next year or this year, Adam? Adam Leight – RBC Capital Markets: Well, if we're looking at declines based on your guidance, for this year. We start -- do we bottom out end of year, early next year and then start to creep back up again?

I see a question Thank you. Sorry. Yes. We hit the trough in production this year and start growing again certainly in the first quarter of next year. That's correct. Adam Leight – RBC Capital Markets: Okay. And on the -- if I missed this also on the middle Miss zone, did you A, give D&C cost? Is it pretty similar?

It is. It's right in that 29 to 30 range with submersible pumps. Adam Leight – RBC Capital Markets: And what about water, is that also looking to be similar to what you're seeing in the other zones?

Yes. Adam Leight – RBC Capital Markets: And then more on water, you've increased your ratio of producers to water wells. What's the maximum you've seen so far and what do you think is an optimal ratio if there is a consistent?

We're clearly over 10. There may be areas where we’re a little bit higher than that. But I think just ultimately the system is going to serve us well in that all of the SWDs or a good portion of the SWDs are connected together. So even as you extend the field you can continue to add wells and put it into the existing systems. So we've got two opportunities here. There is one of drilling additional wells within the focus areas and themselves. And then as we expand out, acquire others in the area, and then we can also flow back to that set. So I really think that 20 horizontals to one producer is possible and really perhaps higher than that as we proceed with the development and the water rates fall off over time. So it's a valuable system to have. Adam Leight – RBC Capital Markets: And then have you gone anywhere on the monetization effort? Have you had any interest? Have you had any discussions or is that just on holed for a while?

We have discussions, Adam, but it's really on hold. We think right now that the value that that system gives us in terms of keeping our cost low and consolidating the best acreage positions in the play offsets any need to monetize it right now. We're still investing capital in it. And we’ve still got it set up where we could monetize it at some time, but not something we are going to do right now. Adam Leight – RBC Capital Markets: Okay. And then on the land acquisitions, particularly in the Miss. Is this more in the six core counties, is it tuck-in acreage?

Yes, it is. We have added about 35,000 acres in the focus areas. We have about another 30,000 acres that we have added year-to-date in the rest of the play. A lot of that was just rollover acreage from the leasing activity last year that closed this year. But going forward, a vast majority of this tuck-in acreage, whether it's pooling or buying leases, has been in the six county focus areas. Adam Leight – RBC Capital Markets: Okay. And then lastly, just remind me, what you think your inventory is on drilled locations in the six core counties at this point.

It's about 3000, roughly 3000 locations. That’s about 615,000 net acres.

(Operator Instructions) Your next question comes from the line of (inaudible). Please proceed.

Just wanted to ask, most of my operating questions were answered, but from a general perspective, cash flow, you talk about you are comfortable at 3.5 times leverage and if we sort of project it out next year, the Street has you burning around $1 billion of cash. You have around $1 billion of cash now and that gets you to about 3.5 times leverage if your EBITDA goes up a little bit. So what happens in 2015? Do you burn another billion in 2015 or how should we think about that year? And if so, what's your strategy to bridge that funding gap? And then my second question is, if that’s the case, should you find a larger partner out there to either merge or sell to? Thanks, again.

You are welcome. Let me address in a couple of ways. Yes, we do have a billion of cash right now but we also have an unused revolver of $775 million. We think we could even expand that revolver if needed. So it's that liquidity that gets us through 2015. So we think we have got 2015 covered as well. Also our EBITDA and cash flow will be growing over this time. So our funding gap is shrinking every year. That being said, funding past '15 is something that we think about often and we have talked about the other monetization tools we have. Which would be, maybe our infrastructure system that could be sold or MLPd or monetized. There is possibility still to do more joint ventures in the play. And we have royalty trust units that we can sell and there are other options available. So post '15, we do have several levers that we can use to fill that gap. I think we are comfortably funded between now and then with our available liquidity. And in terms of longer-term, should we merge into another partner? We will do the best thing for the shareholders. We think the right course right now is to take this capital and deploy in Miss where we are seeing very good returns.

But I mean you would have to -- drawing on the revolver wouldn’t help you keep your leverage at 3.5 times, right. So I guess that’s -- as a bondholder I am just trying to figure out, in 2015, how you stay within your guidance of 3.5 times leverage. I mean you have to get your EBITDA up 25%-30% if you are adding a billion of revolver debt and you are spending your cash in 2014. So just from that perspective as a bondholder, I am thinking maybe this is better off in the hands of a larger company or maybe, or I am missing something. So if you could just address that.

No, I think you have missed anything. All I would say is, you know 3.5 times is a comfortable spot to be and should we bump up against a little higher than that for a short period of time, that would be okay. Again, it’s going to depend on our hedges, our bond maturities, commodity price environments, other things. Keep in mind that as our production grows, our oil is growing at a higher rate than our total production. So we do get some pretty good growth in EBITDA. So I would think that between 3.5 and 4, we are comfortable with that depending on our hedge position. And as we get closer to that, we will look at ways to bring that down, whether it's monetizing, selling something, bringing in some additional capital.

Or selling, right. I mean just the whole company to a larger company, right?

That’s always an option.

Your next question comes from the line Craig Shere from Tuohy Brothers. Please proceed. Craig Shere – Tuohy Brothers: Congratulations on the quarter. A couple of questions, first 3000 locations and the 650,000 net acres. You're still assuming close to three wells per section, not four. Is that correct?

No, we're assuming four, but we have about 550 wells drilled in that focus area. So I'm rounding a little bit. I think if you do the exact math you get the 3800 locations back off 550. So you'd be at 3200 locations. I'm just calling it approximately three. Craig Shere – Tuohy Brothers: Okay that's fair. And of course -- then of course we have stacked pay potential.

Yes. So I'm just talking about single zone locations here when I say 3000. If you've got multiple zones or stacked pay that obviously multiplies that number. Craig Shere – Tuohy Brothers: Fair enough. I want to understand a little more of this 25 average rig count this year and next. That's one way to look at it in terms of HBP’ing a specific amount of property that maybe you're comfortable with annually and having an equal average between the years. Another way of looking at it is we're ramping down very hard and then we're ramping up a little bit. And I wonder if this is more tracking the drilling liabilities on the trough. So as those dissipate and run out and more and more of your drilling is cash flowing to the C core, that you have more and more comfort raising that rig count. In other words I'm asking about will the direction of an uptake in '14 likely lead to uptake again in '15?

Yeah, it's a good question, Craig. And you're right on the numbers. We can tell you're focused on it. So we finished our drilling obligation for SDT in the second quarter. So that's three rigs that we'll continue to drill, all things being equal, but they will be drilling SandRidge wells, not SDT wells. So while our total production won't change because it's consolidated, they're going to be drilling 100% working interest, give or take obviously our revenue interest wells versus net SandRidge 20% working revenue interest wells. So that, while it's not going to change your production again because it's consolidated, it has a very positive impact on your cash flow. It's go forward to next year. The SDR Trust I think fulfill its drilling obligation in the first or second quarter. Similarly, you'll have three rigs that would have been drilling SDR wells that will now be drilling SandRidge wells. To go forward to the end of '14, the Permian Royalty Trust will finish its obligation. So again those three rigs we'll be drilling SandRidge wells with a full revenue interest and not a 10% or 20% revenue interest. So you're right. As those rigs roll off the trust, we finish the trust capital obligation. We get a lot more earnings power and cash flow from those rigs than they would have been drilling Trust wells. Craig Shere – Tuohy Brothers: So there’s two ways of thinking of this. One, staying flat with rigs. You're actually increasing that to SD’s account. Two, as you are increasing that to SD’s account, in other words cash flowing better and better, do you have more and more comfort deploying more and more rigs?

Yes we do. We will always have -- we have comfort now deploying many more rigs and we were at 32 earlier this year. We could deploy more rigs and we have plenty of locations to drill and the infrastructure and resources and team here to do that. It's really a balance between growth rates and our capital allocation, keeping a couple of years of liquidity and keeping our funding in check. So we could certainly deploy more rigs. It's just a matter of capital. Craig Shere – Tuohy Brothers: Understood. That dovetails pretty well for my next question. You've laid out a very good plan of where the money is coming from for three years forward, two and a half years. But one question is long-term, would you be interested in being opportunistic with the Gulf of Mexico or do you now see that as core?

All of our assets are for sale at some price. We're capitalist. We're here to maximize the share price. If the best -- if the valuations in any part of the business, Gulf of Mexico, Mississippian are high, if people are willing to pay us a good price for those, more than we think they’re worth in our enterprise then, we would certainly look at selling those, any of those, yes. Craig Shere – Tuohy Brothers: Well, but more specifically, you have repeatedly and appropriately emphasized the need to have financial bandwidth to invest appropriately in the highest return Mississippian opportunity which you seem to be improving quarterly. So given the Gulf of Mexico was originally kind of bit of a 90 degree turn, at some point if you can get out at similar or better pricing than you got in over a two, three year period, would that be an interest or do you just enjoy the free cash flow for the foreseeable future unless somebody gives much better pricing than you paid, you are going to keep it.

I think it's probably somewhere in the middle. We will weigh this option, the Gulf of Mexico with other options, monetizing our saltwater disposal system or joint venture. We will look at all those as we do every month and every quarter. And whichever one is the best option for the company and for the funding, we will look at it. But, yes, is that one of the options available to us to fill the gap post '15? Sure. It's not on the agenda right now, it's not the plan right now, but it's one possibility we have to fill that gap post '15.

Your next question comes from the line of Joe Allman from JPMorgan. Please proceed.

In terms of the higher rate average well that you drilled in the second quarter, does that also lead to a higher EUR than for the wells in prior quarter?

Hey, Joe, this is Dave. You know we are not going to project at this point kind of an extension to EUR. As you know we just need an amount of time to evaluate a well's performance before we could that. So even with the ESPs, our hope is that we can take the bottom hole pressure down lower over time and ultimately achieve greater returns from the well. But at this time we are not trying to project an EUR increase.

Okay. Thanks, Dave. And then in terms of these higher rate wells, how many of those do you have left in your inventory versus the lower rate wells?

Well, I think I would just speak to it from a program point of view. As James mentioned we have close to 3000 wells in our project areas and we would envision that those 3000 wells would match our existing type curve performance.

And is the intention to use ESPs on pretty much all the wells going forward?

No. We think we will probably be at that consistent level between 40% and 50% and if we overweigh it in a particular area because we find it's very rich, we could go up to 60%-65%. But I think just kind of going forward from what we see today, it would kind of be a 40% to 50% distribution for the foreseeable future.

Got you. And then on the cost side, you lowered the cost from $3.1 million to $2.95 million. If you include infrastructure, what would the apples to apples cost be?

If you include infrastructure?

Yes.

We dropped back a significant number of disposal wells for the quarter as well. So I think we would probably layer in another 200,000-250,000, if you wanted to make it apples to apples.

Joe, we would as a round number, $200,000, which is a 10:1 salt water disposal ratio in a $2 million disposal well. I think our wells are a little bit higher than $2 million because we are drilling some deviated to high angle wells, as well as larger well bores. But our ratio is a lot higher, 14:1 in the first quarter, 12.5:1 in the second quarter. So it would be somewhere in that zip code of $150,000-$200,000.

Ladies and gentlemen that concludes the Q&A portion of this conference. I would now like to turn the conference back over to James Bennett for any closing remarks.

Thank you. In summary, we are pleased with the progress we have made this quarter and think we are set up very nicely for the remainder of 2013 and 2014. I want to thank the excellent work and dedication of our talented teams of employees. Thank you for joining us on this call and we will see you on our third quarter call.

Ladies and gentlemen that concludes today’s conference. Thank you for participation you may now disconnect. Have a great day.