Good day, ladies and gentlemen, and welcome to the Q3 2013 SandRidge Energy earnings conference call. My name is Gwen and I will 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. Eddie LeBlanc, Chief Financial Officer. Please proceed, sir.

Thank you, Gwen. Welcome everyone and thank you for joining us on our third quarter call. This is Eddie LeBlanc. With me today are James Bennett, President and Chief Executive 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. As required, a reconciliation and discussion of these measures 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 trust. Finally, you can expect to see our second quarter 10-Q filed after the market close today. Now, let me turn the call over to James Bennett

Thank you, Eddie. First, I would like to thank all of our excellent employees for their continued hard work and focus, the results of which is another strong quarter. Earlier this year, we refocused the business centering around a few key themes, capital discipline, improving returns on capital, getting our cost structure in line with our asset base while at the same time continuing to grow production and assets. Operationally, this required us to do several things. First, high grade our development program in the Mississippi and to direct our resources and into our more proven focused areas of Oklahoma and Kansas. Second, continue to learn and improve our well performance in order to increase production rates, EURs and returns. Third, uncover additional opportunities within our $1.8 million mid-continent acreage position. Our teams have executed on all of these fronts, our development plan in the focused areas in on track and exceeding expectations, IP rates and performance remain well above our tight curve as shown on Page 13 of our slides, where graph outlines all of our focused area wells versus tight curve. Our well cost of under $3 million are the lowest in the industry and our lease operating expenses have improved 22% year-over-year. On the learning side, we are improving our completion methods, including new frac designs, open hole completions and improved ESP placements just to name a few. Finally and importantly, we are finding more opportunities within our acreage position. In earnings release, we mentioned a successful appraisal well in Western Craig County, Oklahoma, and Dave will talk more about our appraisal success and finding at [Marmaton], Kansas. I think these appraisal successes are important benchmarks as we continue to find more opportunities even outside of our focus areas. Inside our focus areas, we are seeing successful…

James and good morning to everyone join us on the call. We have a fair amount of material to share with you today. In addition to providing detail on our quarterly performance, we wanted to provide you with an update of a number of important initiatives that we are pursuing across the business. While embryonic, we believe many of these initiatives have the potential to add significant value to the company over the long-term. To facilitate this section of the call, we have prepared a set of companion slides that we have published this morning. So I will refer to these periodically during my comments. Starting with CapEx. We spent approximately $329 million in the quarter which was consistent with our planned expenditures. This funding supported a 22 rig program in the Mississippian which was 15% fewer rigs than in the second quarter and 30% fewer rigs than in the first quarter. In addition, we drilled two wells and performed three operated recompletions in the offshore. In the Permian, we maintained a three rig program to meet our commitment to the Permian Royalty Trust. We are pleased with the results for our capital program and with the execution of our operating teams. We are clearly on track to meet full-year guidance of $1.45 billion. In the midst, we maintained an average well cost of $2.95 million in spite of drilling additional footage for deeper objectives and installing ESPs on 75% of the wells. We were able to fund this additional cost through continued reductions in our facilities expenditures and greater efficiencies associated with pad drilling. As James mentioned, the best way to highlight our ongoing improvement is to compare year-on-year performance. In the first nine months of 2012, we drilled 271 wells with infrastructure for cost of $676 million. In…

Thanks, Dave. James and David have highlighted our recent operational performance, including reviewing our appraisal programs which highlight opportunities for our future capital expenditure program. I will discuss the financial results of operations efforts and intend to provide direction for possible future results. First, let's review the current results. When I refer to pro forma information it is actually historical results. After given retroactive effect to the permanent and tertiary asset sales and acquisitions of assets in the Gulf of Mexico in 2012, in other words it is an illustration of pro forma results of current SandRidge properties. Adjusted EBITDA for the third quarter of 2013 of $252 million compares quite favorably to the pro forma adjusted EBIT for the third quarter of 2012, of $182 million, a 38% increase year-over-year. The 8.2 million barrels of oil equivalent and production for this recorder is a 12% year-over-year increase from pro forma 7.3 million barrels of oil equivalent produced in the third quarter of 2012. As James mentioned, we have reached and exceeded our goal of a low G&A run rate of $150 million for the fourth quarter. Our adjusted G&A run rate excluding one-time items outlined in our earnings press release was $144 million for third quarter. We are guiding to $145 million run rate going forward. As you can see on Slide 14, our total production on a pro forma basis has improved year-over-year for the nine months ended September 30, 2013, and the adjusted EBITDA has improved significantly. Adjusted EBITDA associated with production for the first nine months ended September 30, 2013, were $740 million and 24.4 million barrels of oil equivalent, 42% and 18% increases, respectively, over the nine months ended September 30, 2012. Our adjusted EBITDA has benefited from our cost reduction efforts. Our adjusted EBITDA…

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

Morning, guys. Good color. I guess Dave - and question here for James. This is as far as on Marmaton obviously a great result there, your thought on the potential just on how many acres you have maybe that type of potential and how actively you would go about developing that?

Sure, Neal. Thanks for the question. We are very excited about the Marmaton at this point. As you know, it's a regional zone, very prolific. We built a geologic model to identify this particular play and it looks like we probably will have maybe up to seven or eight horizontals, we will have to see how it goes with the first few, but may have seven to eight horizontals as a follow-up. Team is looking in the general area and are confident that they can find something similar, so we don't have a particular acreage number that we could share at the moment but what we do feel like is that we can export this and find other Marmaton plays in that general area.

Okay. Then just one follow-up if I could. What's your thoughts, I guess, so you are more encouraged, less encouraged on the middle-Miss after the result there?

We are very encouraged. You know, for the year the 30-day IPs are very strong and what we do see Neal is that there is primary producing interval that we target first. Then as we gain greater knowledge in the area, then we look to add that second wellbore, and without a doubt the middle Miss is a very, very strong contributor across more than one county, so we have high hopes for that zone.

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

You could comment a little bit on those Woodford wells. Clearly a little bit disappointing and you know that there are other wells out there, so what is your kind of ingoing hypothesis on what might be going on with these specific wells versus what might happen in the future?

Sure, Neal. Great question. On our first test, we drilled what we believed was the best zone to be in, so as you know in any shale play you need to be in that [brittled] section of the zone and we felt like we were in that 100% in the first well. Then we went back with our log analysis that we ran in the open hole and compared that with our frac, and what we found is that in certain parts of the wellbore, we had a tough time putting the stages away and so we have tightened up that target interval, if you will, going forward and so we were thinking that we are going to get a better result there. Then in general, we think that as we get a better understanding of the fractures in the area, we can target the fractures that are intrinsic to the Woodford and we can be in the correct portion of the zone. We are also looking to make the fracs a little bit larger, but we did up size those compared to the Miss.

Okay. Then another plays you are doing some new work. In the Gulf of Mexico, there is a reference to doing some wide azimuth work. Can you talk about what kind of potential might be there and it sounds like you will be looking for partner rather than doing it on your own, if you could walk us through that?

Sure. Underneath Bullwinkle platform, we have identified significant number of Miocene age sands. They are between 15,000 feet and 25,000 feet, so it's a little bit outside our skill set to drill those ourselves, but we did acquire in the last several months the wide azimuth 3D in order to better identify those targets and illuminate the structures. We have initiated conversations with industry partners who are very interested in the prospect and this was a prospect that was identified by Shell several years ago before we acquired the property, so we are pretty excited about the oil potential underneath Bullwinkle.

Then finally, you have got some dual laterals. Have other operators done any dual lateral work where you are trying it or are you kind of plan nearing that?

Dwayne, we feel like we are the first ones. We don't have a full view if someone else has tried this, but to our knowledge we don't know if anyone else has performed the dual laterals.

All right. Thank you very much.

And your next question comes from the line of Charles Meade with Johnson Rice. Please proceed.

Good morning, gentlemen. Thank you for taking my question. I think this might be best for David. You have touched on this a bit. I wonder if you could give a little more detail on what your process is and what your working hypothesis is on selecting the sections to go and do multiple Mississippian laterals? Is it just the productivity of the first lateral in the section or there are other things that you are looking for?

We are taking our initial attempts based on, if we have rich hydrocarbon in the area. So we are not treating this as an exploratory opportunity. So we wouldn't do a lateral or stack play in areas unless we were fairly certain that it was going to be productive for us. So as an example, what we will do is, in one section we might drill an upper, in the section over we might drill a lower and if both of those wellbores come in per expectation, then we would start to fill in the acreage between. So we are trying to step into it and make sure that that we have positive economics before we continue with the development.

Got it. That definitely adds to my understanding and that makes sense. The one other question I thought I would try is, it was a good detail you offered on the Open Hole completions that you are doing and you also referenced these dendritic fractures that you are trying to achieve. Now, presumably, you have always been trying to get complex fracture network. What are you doing differently? Or is it really just come from having an Open Hole packer?

Well, as well as you know, the Open Hole packer allows the natural fracture system to contribute and as we are seeing more and more, we have talked about on the previous call that we have a series of variables that we look for when we are selecting our development areas and one of those criteria is the natural fracture. So what we are seeing over time is that we can do better with the Open Hole packer system. So we are moving that way. In terms of the dendritic fracs, this is one of several techniques that we are trying and the way that a dendritic frac works is, you start and stop the fracture process and the thought that there is in some way you can contribute or enhance the fractures that are there. So it really just going to take some time to figure out and determine if that's going to be something that takes on a broader role in the play but it is just part of our program to continually try to improve and see if we can get a marked uplift in production.

Great. Thank you for that detail.

And your next question comes from the line of Stephen Shepherd with Simmons. Please proceed.

Hey, good morning guys.

Good morning.

I was wondering if you could provide a little bit of commentary regarding the quarter-on-quarter decline in the 30 day rates in the Miss and the distribution of the results. Was that decline being driven by a small number of outlier wells with very low rates or was it a function of where you were drilling in the play or were there any other factors worth mentioning that drove that decline?

I will start with a couple of things. We had some strong rates in the first couple of quarters, 345, 377. We are going to see a little variability quarter-to-quarter. W are not all that worried about it. We did point out in the earnings release that we had several very high volume wells that were constrained due to some gas takeaway capacity. Those have since been alleviated and have come on at rates close to 900 BOE per day. So if you want to put those back in to the mix, I think our rate would be higher. I think all-in-all, we are pleased because it is still well above our tight curve results, which are about 270 BOE per day.

Okay, and then I have got one more here. So I am attempting to connect the dots on all the various production forecast you guys have given in the slide deck and in attempt to isolate what just black oil growth in the Mississippian is going to look like on a pro forma basis next year? And I am getting to kind of like 57% year-on-year number for oil and like a 15% year-on-year growth number for NGLs, after adjusting for the Permian divestiture. Did those number seem reasonable? Again just trying to decompose the liquids into its component pieces and if not what is your expectation for what just oil will be growth in the Miss year-on-year in '14?

So you are talking about the whole company or just the Mississippian?

Just the Mississippian

So on the Mississippian, we have 50% liquids growth, and on a daily basis we are seeing 63 for the day versus daily rate of 63 versus 46 for 2013, so 46 a day in '13, of that 22 was liquids. 62.6 a day in '14, which 33 of that's liquids, so let me give you the oil breakout on that. Just a second. Here we go, Mississippian, so 2013 black oil, let me just give you a million barrels and you can do the conversions, 6.9 million barrels, 2014 black oil, 9 million barrels. Liquids would be for 2013, 1.3 million barrels. 2014, 3.3 million barrels, so a 30% growth in black oil. Is that what you were looking for?

Yes.

Your next question comes from the line of Jeffrey (Inaudible), Tudor, Pickering, Holt. Please proceed.

Good morning, guys. Just one quick question from me on the Woodford. Is there a view yet on the extent of the play across your leasehold, maybe your outlook on prospectivity there or how the asset might layer in with your operational program as far as timing and ranking goes?

Sure, Jeffrey. We have mapped the Woodford to be across a vast majority of our acreage. As you know the question is just as you go further North, what level of productivity you will see still needs to be tested, so we don't an exact acreage count today and we might try to share that by Analyst Day, but in general the Woodford is across virtually all of our Oklahoma acreage and we are pretty excited about it. Thank you.

Your next question comes from the line of Adam Duarte with Omega. Please proceed.

Good morning, guys. Sort of follow-up to the last question. Across all of your multi-zone initiatives, how much of your acreage do you think is perspective for these types of wells? Do you have an estimate of what a potential incremental resource associated with these programs would be?

Yes. Adam, I think we will have much more detail on that at analyst day in terms of kind a mapping and acreage counts for multi-zone and Woodford. We think about it like this and our focus areas with the 600,000 acres in over 3,000 net potential locations. When we say potential locations that's assuming one zone, so assuming an upper Miss in most of that acreage really all that acreage. If we take even a portion of that acreage and assume its perspective for Chester or Marmaton, that's all additive, or Middle Miss and lower Miss, that's all additive and then we think a large portion of it has Woodford, so I don't think we can come out and say that we think we have two zones across the entire focus area, but we think it's absolutely more than one and all that's very additive to our resource base in NAV, and also note that whatever other zones we can find for the most part we are able to develop it with our existing infrastructure which we think is key here, so going down into these deeper and other zones using the existing electrical and saltwater disposal infrastructure makes these the second, third zones much more economic, even at very similar producing rates, much more economic than your original target interval.

Got it. One follow-up. In the Gulf of Mexico subsalt, can you tell us a little more about the JV discussions you are having in terms of what types of partners you are looking for and do you have resource estimates for your two prospects there?

Sure. On the subsalt prospect, this is a prospect that has a very high level of interest from the industry. We have been asked about this prospect two or three times this year alone and what we are trying to do is select a partner that has that expertise of drilling subsalt and so we have started those conversations, but it's still probably too early to share data beyond that. Again, we are very excited. We think we have two of the best exploration prospects in the Gulf right now between the deep Miocene underneath the Bullwinkle and the subsalt at South Pass. They are two potentially very lucrative prospects, so we are encouraged and we are starting conversations to select a JV partner that we think has the premium skill set to efficiently develop these with us.

Do you have estimates for the prospects?

Shell had estimated that Bullwinkle was somewhere around 200 million barrels of oil. Again that's just a Shell estimate and we don't have a number on South Pass 60 yet.

And on Bullwinkle, remind me, is that a four way closure?

These are sands that truncate against a salt diapir.

Got it. Okay, thank you.

Thank you.

And your next question comes from the line of Adam Leight with RBC Capital Markets. Please proceed.

Hey, good morning. A follow up on the Gulf of Mexico exploration prospect. How much total capital do you think you would be willing to risk on that and what kind of timetable? I am presuming this is relatively long lead time.

Yes. This is long lead time, Adam. This is multi-year kind of stuff. It's not something that we really are set up to drill ourselves. So we would, as Dave said, look for an industry partner that's got the skill set and experience and wherewithal to do this. I can't tell you exactly how much capital we would risk. We will weight that with what we are doing rest of onshore in the Mississippian. I would say, it would not, certainly would not be a material part of our capital program. It's just not in our core skill set, not high on the list to allocate capital right now to a project is risky.

Okay. Jumping to the Miss for second. You are talking about 30 wells, producers to water disposal wells. How much of that is fully built out and what are you looking at, in terms of full capacity ratio in each pad, in each area?

We have steadily climbed in the last several quarters, that ratio from 7:1, 12:1 to 15:1, now to 30. I don't anticipate it will stay at 30. I think 30:1 is a pretty high ratio. We originally developed the play thinking we could get to 10:1. I think we are very comfortable now, we can be in that 15:1 to 20:1 range. What's going to be more important going forward though, Adam, is the dollars we spend relative to the saltwater disposal. As we go to this low cost disposal design that Dave talked about and we mentioned in earnings release, we won't tie quite as many producers to that. We may tie five, seven, maybe 10 to it, whereas if it's more expensive disposal wells, we can tie 15 to 20. So we will probably get a little bit away from this disposal ratio, if you have been looking at our earnings slides, we are actually drilling more disposal wells next year than we will drill this year. So it may look to people like we are getting less efficient with that system but that's not the case at all. In saltwater disposal wells, this year we will drill 32. Next year we say we are going to drill 46, but more importantly look at the dollars we are spending on saltwater disposal. A flat $55 million. So the point is, we are going to drill more lower cost disposal wells. So that ratio is going to get a little misleading going forward. So I would encourage people to focus on the dollars.

Okay. That's helpful, and then jumping back on the LOE. I didn't quite get everything that you said. The increase in the fourth quarter that's implied, is it all attributable to Century plant or is there something else embedded on this?

Yes. A big chunk of that's the Century obligation. It's in the $33 million range. So call that a $1 BOE just by itself for the full year in the fourth quarter.

Okay, and then, your guidance shows G&A stepping down pretty nicely in 2014. Can you just generally give a sense of how you are getting there?

Sure. We had a pretty concentrated G&A reduction program that we started earlier this year and we made changes in competition programs, going to performance based pay, other advertising, sponsorship, aviation. Really changes across the board, and with the help of Eddie, he has come in and done a bottoms up review of the business and say what kind of resources do we need to run the business and we think we have made a big improvement down from over 200 million to what we are saying is about $145 million run rate now that we are guiding to 2014.

Okay, thanks. That's great.

And your next question comes from the line of James Spicer with Wells Fargo. Please proceed.

Hi, good morning. I apologize if I missed this in the guidance but just wondering how much of your 2014 capital program is allocated to the various Midcon evaluation programs versus your core Mississippian drilling program?

Sure. If you look on page 20 of our deck, it's about $50 million. So, of the $1 billion, $965 million I will round to $1 billion of Mississippian mid-con spending, about $50 million of that is what we are calling our appraisal program which should be really outside the focus areas.

Okay. That's helpful thanks. Then in your production guidance for 2014, are you assuming any production from the mid-con efforts?

From the appraisal efforts?

Yes.

No. I would say not none, but very little production from those efforts as assumed in our guidance.

Okay. Great. Then just more broadly you talked about the narrowing cash shortfall GAAP over time here as EBITDA grows and CapEx remains relatively flat. Do you have any sort of target or timeframe in mind and sort of how this is going to progress over time?

I think we can say this that with $1.7 billion of liquidity, if we were to do nothing at all, we will find a well in the '16, we are not going to do nothing at all. We are going to grow EBITDA at a 20% clip a year. That shrinks your funding gap every year that adds more free cash flow that adds more leverage and ability to add on a reasonable amount of leverage at 3 and 3.5 times. I think some people miss is the fact that this EBITDA growth of the business you model that out over a couple of few years and you really shrink or eliminate that funding deficit, so we think that when people focus on the funding gap, as I said in my prepared remarks, they are missing the fact that this real cash flow growth solves their problem and solves it quickly. We are not ready to come out and say that in year x, we are going to be cash flow neutral, but you can model it out at that kind of growth rate and see that we get very close and close the gap in a very comfortable way.

(Operator Instructions). Your next question comes from the line of Richard Tullis with Capital One. Please proceed.

Thanks. Good morning everyone. Just a couple of quick questions. The $110 million in land in seismic in 2014 CapEx, where will that be dedicated?

I think a big portion of it's going to be in the Mississippian. There's is a small amount in the Gulf of Mexico, but predominantly in the Mississippian.

Okay. How much of that is seismic, roughly?

About $10 million.

Okay. That's related to the seismic shoot over the subsalt?

Some of it's the offshore seismic, but a large portion of it is Mississippian shoots as well.

Okay. How many net acres in the Miss are expiring in 2014?

In the entire play, 740,000 acres expire. Again that's an entire 1.8 million. We have extensions on 80% of those at a $130 in acre, so very low cost extensions. In the focus areas, for 2014, we have $150,000 acres expiring, extensions on 45% of those at $275 an acre. Again, that's part of the reason we have this $100-ish million land budget is to extend those where needed and also add-in acreage. Year-to-date in the focus areas, we have added about 60,000 acres through a pooling and acquisition of acreage close to our best locations in best wells, so we will let some acreage expire that we don't intend to drill or don't like the risk profile of it and will add on better acreage, so we think in addition, - we will end this year at about 600,000 acres in our focus area.

Okay. You say this time next year, what do you think your net acreage will be in the Miss given the spending and the expiring?

I don't Richard in the entire Miss, I do think in the focus areas it will about the same, of about $100,000 Yes.

About the same? Okay. What would be the average Middle Miss line well cost drilling outside the core area?

It would be probably $50,000 to $75,000 more expensive. Typically it's another 300 feet to 400 feet and it's highly variable in terms of what you might encounter, so for instance some wells we drilled - lower Miss Wells for example that required as many as 14 bits as opposed to just one bit perhaps in the upper Mississippian. So, in general, you are looking at perhaps an extra day of drilling and then it would be variable in terms of just the speed of the well.

And then would there be additional infrastructure cost on top of that?

Well, our goal is that it would be in the same infrastructure that we would build out for any other portion of the play. So it wouldn't be different than an upper or a lower on the first well but then you would see those building economics as you continue to add various zones.

Okay. What were the costs for the Chester lower and upper Mississippian wells ? I may have missed that.

Well, they are all in that same general range. Just that $2.8 million to $3.1 million. So we would anticipate that really for an overall horizontal well, we are looking at that range that $3 million range, but if it drills quickly it can come in at $2.7 million, $2.8 million. So we try not to put an exact price tag on the different intervals. We just kind of speak to the general piece of it. If it's deep, it will cost a little bit more and if it shallower it might cost $50,000 to $100,000 less.

Okay, and then just lastly. Is the amount given for the Century plant payment on the deliverability of the CO2, is that a pretty much in go forward amount?

Yes. It's close. What we have said in that $33 million range next year, it ramps up annually and peaks in around the 2017 timeframe, give or take, in the low 40s and then starts to decline thereafter.

Okay. Yes, tanks a bunch. I appreciate it.

At this time, we have no further questions. I will now turn the call over to Mr. James Bennett for closing remarks.

Thank you, everyone, for joining. Just in summary, we think we are on the right path here. We have made a lot of changes in the business this year, capital disciplined, focusing on returns and we think those are showing up in the numbers. We are consistently exceeding expectations. Something that we focus on here every quarter. I think we have got line of sight visibility into 20% cash flow growth for many years, which I think gives us nice earnings growth and closes any kind of funding gap that we have in the business. And finally, we have got great teams of people here, working everyday to drive the share price and create value for our owners. So thank you for joining. We will talk to you on the next earnings call.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect and have a great day.