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SandRidge Energy (NYSE:SD)

Q2 2012 Earnings Call

August 3, 2010, 09:00 am ET

Executives

James Bennett – CFO

Tom Ward – Chairman and CEO

Matt Grubb – President and COO

Kevin White – Senior VP of Business Development

Analysts

Neal Dingmann – SunTrust

Dave Kistler – Simmons and Company

Duane Grubert – Susquehanna Financial

Amir Arif – Stifel

Craig Shere – Tuohy Brothers

Scott Hanold – RBC Capital Markets

Joe Allman – JPMorgan Chase & Co.

Charles Meade – Johnson Rice & Co.

Richard Tullis – Capitol One Southcoast, Inc.

James Spicer – Wells Fargo Securities, LLC

Omar Jama – RBL Capital

David Snow – Energy Equities Inc

Operator

Good day, ladies and gentlemen, and welcome to the second quarter 2012 SandRidge Energy earnings conference call. My name is (Pam) 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 instruction). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. James Bennett, Chief Financial Officer. Please proceed.

James Bennett

Thank you, (Pamela). Welcome, everyone and thank you for joining us on our second quarter 2012 earnings call. This is James Bennett, Chief Financial Officer. With us today we have Tom Ward, Chairman and Chief Executive Officer, Matt Grubb, President and Chief Operating Officer, and Kevin White, Senior Vice President of Business Development.

Keep in mind that today's call will contain forward-looking statements and assumptions, which are subject to risk and uncertainties and actual results may differ materially from those projected in these forward-looking statements.

Additionally, we'll 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 royalty trust. The trust will be addressed on separate calls on August 10. Also, SandRidge will file an (NYSE:NQ) on Monday, August 6. Now let me turn the call over to Tom Ward.

Tom Ward

Thank you, James. Welcome to our second quarter operational update. As you've read, we announced another very solid performance this quarter driven by the growth in oil production. The key themes I will discuss this morning that differentiate SandRidge are as follows:

Low risk shallow carbonate drilling with low costs, willingness to lock in future profits through hedging, and our increasing balance sheet strength. The SandRidge management team has operated differently than most of our peers over the last few years. We built our foundation on shallow, conventional, low risk oil assets.

The Central Basin Platform in the Permian Basin is a good example. In 2008, we produced 4,000 barrel of oil equivalent from this area and today, we produce over 30,000 net barrel of oil equivalent per day from shallow carbonate vertical wells.

The Central Basin Platform continues to provide repeatable low risk, high rate of return drilling opportunities. Even though the wells only average 53 barrels of oil equivalent per day during the 30 day peak period, the low costs associated with the drilling and completion of these wells makes them very attractive investments and efficient use of capital.

By buying in an area with a long history of production, we not only lowered our drilling risk but also do not have the issues with takeaway capacity as others experience in newer, more crowded areas of the Permian. This last quarter, we drilled 206 Central Basin Platform wells and plan to continue with this program in the future and maintain a ten year inventory of drilling locations.

The Gulf of Mexico properties we acquired this year have gotten off to a good start. The integration of DOR has been smooth and production has been in line with our expectations through the second quarter. We do not plan to risk capital exploring for large new fields but exploit existing properties and generate high rates of return through re-completions and in-field drilling to help us fulfill our three year goals.

We were able to capitalize on a region of cheap oil with this acquisition and it gave us a platform with a great operating team to further exploit inexpensive oil at a time of dislocation in the marketplace. Not only did we buy inexpensive oil, we are now able to sell expensive oil.

As of August 1, the LOS mark was positive $18.75 per barrel over WTI. Plus, the acquisition of the Gulf of Mexico properties lowered our debt ratio a full turn and gives us more debt capacity to stay within our goal of approximately three times leverage. We continue to feel comfortable we can maintain our 25,000 barrel of oil equivalent per day production rate by spending $200 million of CapEx on drilling and re-completions

Mississippian continues to be our growth venture. Last quarter, we drilled 91 horizontal wells and our production continues to meet or beat our expectations. This play is also a shallow low risk carbonate reservoir where our production per well on a 30 day rate has continued to improve over time.

The value driver of the horizontal Mississippian play is the ability to consistently drill thousands of high rate of return oil wells over hundreds of miles. It's a story of scale. Our team has assembled 1.7 million net acres with room to drill more than 8,000 horizontal wells and now nearly 50% of that acreage has been proven by the 872 horizontal wells that have been drilled.

Each quarter, we become more convinced in the size and scope of the play. SandRidge has now drilled 382 producing wells across the original acreage we put together from 2007 to 2011 and we are seeing consistent results from Comanche County, Kansas through Grant County, Oklahoma. This covers an area of more than 150 miles in an area where we have nearly 850,000 net acres or a ten year inventory at today's (root) count at only three wells per section.

We also have optimism about our extension acreage in western Kansas where we control nearly 900,000 net acres and where there've been more than 7,000 (inaudible) Mississippian producers drilled. We are now drilling oil wells in the extension portion of the play with three rigs and we'll know more about the results by the end of this year.

The second quarter was very good from a production standpoint. It seems that every operator believes investors only care about the large producers in each field. We do continue to have high initial production wells but that's not the driver behind our growth.

For example, we mentioned in the press release that during the second quarter, we completed five Mississippian wells that produced more than 1,000 barrels of oil equivalent for 30 days. They actually averaged 2,000 barrels a day. However, it's more important to note that we completed 90 wells that drove our production increase. We do not rely on the 1,000 barrel of oil equivalent or greater wells to meet our expectations.

We drilled 21 wells during the last quarter that had greater than 1,000 barrels of oil a day equivalent of production for 24 hours but that really doesn't mean anything. What is important is that we can grow our oil production by more than 50% and our total production by 40% this year and continue to drill low risk type curve wells for many years to come.

Plus, we had the opportunity to realize lower costs going forward as our drilling efficiencies continue to improve as we've front-loaded our saltwater disposal system and electrical facilities. During the last year in the Mississippian, we drilled only 30% of our locations (inaudible). This trend continued through the second quarter.

We've invested heavily in the future by building our electrical infrastructure and water disposal systems ahead of our development drilling. The Mississippian play is built on a firm foundation.

I've discussed the low risk nature of our reservoirs but we've also moved to a strategy of lower balance sheet risk during the last few years. In 2008, we produced 95% by volume natural gas. Today we produce 56% by volume oil and 91% of our reserve value comes from oil. We also have mitigated balance sheet risk with our oil hedges.

We've hedged 15 million barrels of oil in 2012 for about 83% of our projected volumes at just over $100 per barrel. We've also hedged 18.5 million barrels in 2013 at $96.24 per barrel and have started adding to our 2014 hedge book with 13.4 million barrels hedged. We've even hedged 5 million barrels of oil in 2015.

It's much more important for us to be in a position to manage any problem that may result from a global recession and continue to generate high rates of return than hold out for an additional $10 per barrel. Our business is such that we plan ahead by at least six months and we should not have the uncertainty of short term pricing to make our long term decisions.

Although some of the moves that we have made over the last few years have surprised some, strategically they've been intentional. First we bought producing oil assets in a geographic concentrated area. Generating cash flow was significant further development potential. Next we began leasing undeveloped oily acreage and different than most, leasing in only one play, the Mississippian.

We did buy a large acreage position but have already raised nearly $2 billion more than our cost basis from the sale of only a portion of this lease hold. Even after the sales, we have over a decade of future drilling. Our growth engine continues to be the Mississippian formation and Kansas and in Oklahoma and we do not anticipate having another large acreage play in our near future.

In our two core areas, we are the most active driller and among the largest producers and acreage holders. This concentration is deliberate. It results in SandRidge being the most cost-efficient operator in our core areas, which is different than many of our peers who operate across many different plays.

SandRidge is now looking forward to continuing to build upon a solid foundation that we started establishing several years ago. Changing to an oil company wasn't easy but by strategically acquiring EBITDA and carefully choosing our acreage play, we have accomplished what we set out to do.

We have been consistent with our three year goal of having EBITDA above $2 billion, drill within cash flow, and improve our credit metrics to below three times. When that is achieved, we will have become a mature company that can slow down our growth targets and look opportunistically for acquisitions using debt and equity.

However, in the meantime, we look forward to continued growth as we develop our core low risk assets. I'll now turn the call over to James.

James Bennett

Thank you, Tom. We had a strong second quarter with continued growth in oil production, reduction in our leverage, proven liquidity, and beating contentious estimates across all categories. For the second quarter, adjusted net income was $37 million or $0.07 per diluted share. Adjusted EBITDA was $269 million and operating cash flow is $222 million or $0.40 per diluted share.

Second quarter adjusted EBITDA is up 72% over the comparable 2011 period driven by the Dynamic off-shore resources acquisition and continued organic growth in oil production. Production for the quarter averaged 90,200 barrels of oil equivalent per day, a 36% increase over first quarter production and 45% increase over the comparable 2011 period.

Recall that in the second quarter of this year, we closed the acquisition Dynamic so for the quarterly reporting period, the acquisition contributed a little over two months to our consolidated numbers. Excluding the impacted Dynamic, which accounted for about 1.8 million barrels of oil equivalent in the quarter, our base production grew 6% over the first quarter 2012 and 14% over the comparable 2011 period.

This was driven primarily by the Mississippian which averaged production of 25,200 barrels of oil equivalent in the second quarter, up from an average of 19,300 in the first quarter.

Our per unit measures LOE for BOE increased as expected due to the inclusion of the Dynamic off-shore properties. However at just under $15 per barrel, LOE was below the low end of our 2012 guidance range due to a continued focus on fuel level expenses such as a reduction in produced water hauling and downhole pump repairs.

Excluding the off-shore properties, our recently divested tertiary assets second quarter heavily decreased to $12.42 per BOE, down from $13.19 the first quarter of '12 and $13.24 in the second quarter of '11. As a result, we're lowering mid-point of our full year LOE guidance by 6% to $16 per BOE.

In terms of other per unit costs, G&A of $7.52 per BOE was above our guidance range but includes just under $12 million of expense one time transaction costs associated with the Dynamic acquisition, our Royalty Trust IPO, and tertiary divestiture. B&A for BOE is $17.95, just over the high end of our previous guidance as a result of the inclusion of the Dynamic assets and the impact of non-core asset divestitures in 2012.

CapEx for the quarter was $562 million down slightly from $570 million in the first quarter. Eighty percent of the quarters CapEx was on drilling and production for E&P operation, a concentrated in the Mississippian and the Permian.

We've slowed our land purchases since the first quarter and anticipate spending little on new lease hold in the remainder of the year. Regarding 2012 CapEx guidance, we're increasing our estimate for full year's CapEx to $2.1 billion, up from $1.85 billion primarily due to increased facility costs in the Mississippian and Permian and lease hold acquisition costs.

Our June 30 total debt was $3.55 billion and net debt was $3.1 billion giving us a quarter end leverage of 2.9 times. Long term debts consist entirely of senior unsecured notes with maturities ranging from 2014 to 2022 and only one $350 million maturity within the next four years.

Our liquidity is excellent at $1.3 billion as of July 31 consisting of a fully undrawn $1 billion revolving credit facility that matures in 2017 and $300 million in cash. The terms of funding our capital program, this $1.3 billion of liquidity combined with cash flow from operations is more than sufficient to fund our remaining 2012 capital budget to take us well into 2013.

Regarding our 2013 capital program, we have not yet come out with formal guidance but estimate our 2013 capital expenditure budget will be approximately $2 billion. Using the $2 billion spending level, current leverage of just under three times, and growing EBITDA, we can comfortably fund our 2013 capital plan with cash flow from operations, current liquidity, and additional debt.

Also, as alternatives to debt funding, other sources of capital available to us include sales of existing Royalty Trust units, possible JVs for additional Mississippian acreage, and non-core asset sales. As an example, in the second quarter, we raised $155 million through the sale of non-core tertiary asset in west Texas and the sale of some of our common units in SandRidge Mississippian Trust One.

In summary, the effort to fill our funding gap for growth is starting to ease. Our company continues to mature and we are on our way to funding within cash flow as stated in our three year objectives.

On Page 8 of our earnings release, we have outlined updated guidance for 2012. We increased production guidance by 700,000 BOE to 33 million to reflect current year acquisitions, divestitures, and better than expected performance from the company's core asset. This production level represents total equivalent growth of 41% over 2011 and oil growth at 64%.

As I mentioned, we reduced risk and cost guidance by 6%. Oil and gas DD&A rate increased by $0.60 at the midpoint of the range due to changes in the depletion rate as a result of the Dynamic acquisition and the sale of the company's tertiary assets. G&A projections have increased to include transaction costs I discussed earlier.

EBITDA (inaudible) services, midstream, and other increased to reflect the improved drilling profit margins and higher third-party working interests for wells drilled by our own Lariat rigs.

In earning's release, we've updated our hedge position through 2015. The downside protection of these hedges was apparent in the second quarter where we had contraction maturities over our hedges (inaudible) gained at $32 million and adding over $4 per barrel to our realized price.

For the remainder of 2012, we have just over 80% of our guidance oil and natural gas production hedged and from 2013 to 2015 have an additional 37 million barrels of oil hedged. We have been and continue to be aggressive users of hedges to protect ourselves against contractions and commodity prices and we have one of the most hedged positions among our peers.

One final note on Royalty Trust, an effort to assist the reconciliation from our financial statements back to our guidance, we added a new table in our earnings release, the table labeled Net Income Attributable to Non-Controlling Interest on Page 12. It's the non-controlling interest, or NCI, from the income statement and adjusts for non-realized cash hedging gains or losses to arrive at an adjusted NCI.

This adjusted NCI's consistent with how we guide the trust earnings. As similar to earnings per share, we don't project non-cash unrealized mark to market hedging gains or losses. This concludes management's prepared remarks. (Pamela), please open the lines for questions.

Question-And-Answer

Operator

Certainly (Operator instructions). And your first question comes from the line of Neal Dingmann with SunTrust. Please proceed.

Neal Dingmann – SunTrust

Morning, guys. Hey, Tom, just a first quick question. Wondering how much you can say, Tom, on the new production guidance. Obviously most of that is related to gas. Is there anything we can insinuate as far as what that means for the new horizontal Miss? Are you assuming that's going to be a bit gassier? So maybe I guess my question is if you can comment on the makeup, your expectations of the new horizontal Miss versus the original?

Tom Ward

You're saying the new horizontal Miss being the extensionary?

Neal Dingmann – SunTrust

Yes, sir.

Tom Ward

No, that has nothing to do with our guidance, so I'm – we are not projecting extension acreage in our guidance.

Neal Dingmann – SunTrust

OK, and then just wondering on that guidance, after having obviously the big second quarter as far as total production, maybe a little bit surprise you. I guess you didn't increase overall guidance. Is there – maybe if you could talk about in that guidance assumption for the production, kind of if you could break that down a little bit, kind of what type of growth you're assuming between the three areas, horizontal Miss, Perm, and the offshore.

Matt Grubb

Yes, let me take that. Hey, Neal, this is Matt Grubb. Give you a little bit more detail on the guidance, how we came to that. First of all, we – our new guidance, on paper, it didn't look like we increased oil production but in truth, we did sell a couple hundred thousand barrels of oil in our tertiary sales and didn't move that oil guidance down. So there's growth in there that's embedded that's not – may not be obvious in the guidance.

We did have a very good second quarter and a number of positive things happened for SandRidge in second quarter and if we just for a minute ignore our DOR acquisition Hunt acquisition and just look at organic growth, we still had 6% growth quarter-over-quarter from second quarter to the first quarter.

And if we continue to ignore DOR and ignore time and then performance sell of tertiary year-over-year, we would have organic growth about 14%. So all those things are very strong and then when you put in Hunt and DOR back in and take out the tertiary for the rest of the year, I think it's still about 38%, 39%, 40% growth.

But if you just look at a little bit more in detail from Q1 to Q2, I think in Q1 we had about 66,500 barrels equivalent per day and of course, we had acquisitions come in in Q2. We took over Dynamic about the middle of April and then we closed on little Hunt acquisition I think around June 20 and then we sold tertiary June 1 but adjusting for all those numbers, we averaged about 90,000 a day in Q2 so big move as a result of the acquisitions.

However, as Tom mentioned earlier in his spiel, we had a number of wells in the Miss that performed very well. We had five that was making a couple thousand barrels a day for the first 30 days. We bought Hunt – when we bought Hunt, we modeled that coming in at 3,000 barrels a day. There are some pipelines and some platforms...

It actually – when we closed it actually was making probably about 2500, 2600 barrels a day. We got production back on since then and it's up 3500, 3600, 3700 so we think there's some plus production that's going to come off back down to our projection and then DOR is doing slightly better than we modeled, even.

We modeled 25,000 flat for the year serving with 10% for hurricane risk for all of our Gulf of Mexico in June – I'm sorry, in July, August, and September. So the Gulf of Mexico now with Hunt, with Dynamic, and (inaudible) Gulf of Mexico. That represents part of 28%, 29% of our total production when you put a 10% risk in there going forward essentially for Q3.

That does impact your guidance and so when you see in our public slide of 104, I'd say that's a pretty big move up from the 90 that we averaged in Q2 and that's a result of cement flush production and some of the big wells we saw but going forward, we don't model those big wells in.

We don't know when we're going to hit them but we model our type curve and so with the declines on those big wells with some of this flush production coming off, we could see August maybe even slightly down below from July.

I don't have the official numbers yet but we'll probably be in that 103, 104 range and so with some production coming off in August, we might be down around high 90s to low hundred and when we start ramping up again, the rest of the year and so as we get through August and we get through September and we don't have any hurricanes, I think there's a chance we might up our guidance in Q3.

We'll have to wait and see but that's the reason for the guidance and because of all of the positive things that happened really in the last 45, 60 days, we're going to err on our guidance, we're going to err on the conservative side.

Neal Dingmann – SunTrust

Hey, good, great color, Matt. Last question if I could, Matt, for either you or Tom. Just wondering on the new lifting guidance if you could maybe just comment around what you're seeing as far as well cost and the horizontal Miss both for the original and into the newer area including the water parts of it.

Matt Grubb

Yes, are you asking specifically about CapEx or LOE?

Neal Dingmann – SunTrust

More about LOE, just kind of I guess you can talk about kind of your type curve for the horizontal Miss now besides obviously that URs may be going up a little. Just wondering what you're thinking average cost would come out at.

Matt Grubb

Well, LOE, we've got it down, our LOE, to a midpoint of about $16 there from $16.80 or so and one of the things that we – one of the reasons our CapEx went up this year is because we are accelerating some projects to reduce LOE. LOE reduction doesn't come free but long term, it's the right thing to do and so we accelerated some water disposal facilities, drilling those disposal wells and so on.

But the LOE guidance, one of our big focuses in the company – I mean, the major components that drive LOE for this company is water handling is number one and then compression is probably number two. We have a lot of gas lift compressors we're running and of course you have your gathering expenses and so on but we're moving today probably a little over 500,000 barrels of water in the Miss and we're only trucking about 3% of that.

And so from the high this year, we have probably reduced our trucking volume by about 15,000, 20,000 barrels a day and so all of that works into reducing the LOE to our new guidance as you see it. So going forward, I think LOE will continue to go down because as these wells we have 380, 390 wells producing now in the Miss.

As they decline, the water production will decline with it and so it is with the acceleration of the infrastructure to move this water, we can continue to add more and more water from new wells into new infrastructure. That would drive down both LOE and CapEx from the infrastructure standpoint.

Neal Dingmann – SunTrust

Thanks, Matt.

Tom Ward

And Neal, just to clarify your question to me, in the extension Miss, we would not plan on having a high gas amount in those wells because the vertical wells were nearly all the well, so just based on vertical wells, you wouldn't expect as much gas in the extension.

Operator

And your next question comes from the line of Dave Kistler with Simmons and Company. Please proceed.

Dave Kistler – Simmons and Company

Morning, guys. Looking at your oil production numbers where you incorporate NGLs in that number, can you kind of break out for us what percentage of that production is NGLs?

Tom Ward

Yes, we're running about 11% NGL in our total (inaudible) so 89% crude oil.

Dave Kistler – Simmons and Company

And that was down from 13% in the first quarter and is the driver of that being down primarily the Dynamic acquisition because I'd imagine the Mississippi lot production going up but actually be adding NGL production.

Tom Ward

No, it's actually from the Mississippi line production going up because in the Mississippi line, we're not booking NGL volumes. We get a little upgrade on the gas side but it's all crude oils so as we continue drilling Mississippi line and develop that and oil production continues to increase in Mississippi line, it'll continue to drive in NGL.

Most of our – 85%, 90% of our NGL comes from the Permian Basin and the Mississippian is going to outgrow the Permian, so your NGL's going to go down slightly.

Dave Kistler – Simmons and Company

OK, that's helpful color. I appreciate that and then just thinking about these five wells that you guys put online that were about 2,000 barrels of oil (inaudible) 30 day rate, can you talk a little bit about what you're seeing that's leading to that variability? Have there been any more signs to identify areas where you're having those kinds of impacts? Anything kind of new since last quarter in terms of what you've learned about those wells?

Tom Ward

No, you're just going to have a few percent of your wells are going to be extraordinary and what the industry is really focused on the few percent of wells that produce very high volumes and not the total wells that all of us drill. So we will drill high volume wells, especially when you hit a nice permeability streak and you have good storage capacity in a location and they'll come on a very high rate.

That's nothing new to this play or any other play that I've ever been associated with. It's just that over the years, we've come more to rely on a single 24 hour IP or a 30 day IP of one particular well rather than a play.

What we're trying to do is to get you to focus on a play that's going to cover hundreds of miles in size and scale and that you don't need to have a thousand or 2,000 barrels a day in order to build a company and that's where the real focus is is if Comanche County, Kansas, which hasn't had any wells that produced a thousand barrels a day for a 30 day average, it's still a fantastic country to drill oil wells in and even though the...

And these five wells we drilled were in three separate counties. If you look at the 21 wells we drilled were scattered across that had the 24 hour rate were scattered across all the counties we drill in. So it's more of a geological work within each county and each township to understand the best places to drill and that's what we'll continue to do.

Dave Kistler – Simmons and Company

OK, that's helpful and then you guys made a comment that your rig count would stay and you'd split the line at 33 rigs and if I recall correctly, you guys were looking at ramping to as many as 40 rigs over the next year or so.

Tom Ward

No, that's through 2013.

Dave Kistler – Simmons and Company

OK. As we think about that, obviously efficiencies are allowing you to drill as many wells. With 1.7 million acres, if you're running 33 rigs or ultimately going to 40, can you hold all that acreage backward option or does that kind of force the hand for selling a portion of that down or doing a JV to accelerate that activity.

Tom Ward

We can hold that. We're projecting to have or have projected to have 45 rigs by the end of '13 which would let us hold all of our acreage. I don't know that we will drill every acre we have but it is still that – and it doesn't mean that we wouldn't sell down further into the next year but that would be more just a decision on how we want to use capital.

Dave Kistler – Simmons and Company

OK and one more follow-up just on that again. If you're moving to 45 rigs in '13 yet you make a statement of keeping the CapEx kind of around $2 billion, how do those two tie together, especially when you're having the kind of efficiency gains that you've witnessed year-to-date.

Tom Ward

If we continue to have efficiency gains, you obviously don't have to have as many rigs to spend the same amount of money so it is more around a capital requirement for us than how many rigs. There's nothing magical about having 45 rigs versus 40 rigs versus 35 rights if we can drill the same amount of wells.

Dave Kistler – Simmons and Company

OK, I appreciate the color, guys. Thank you very much.

Operator

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

Duane Grubert – Susquehanna Financial

Yes, Tom, in passing, you mentioned the percentage of wells that were PUDs. Can you walk us through that a little bit, just clarify what you meant and how we might interpret that when we think about reserves bookings later in the year?

Tom Ward

Sure. Whenever we drill, the wells that we're drilling, only about 30% of those have already been booked as PUDs so there will be additional wells. So there (inaudible) being drilled that will have offsets to them that we'll be brining on as proven undeveloped producers this year.

Duane Grubert – Susquehanna Financial

All right, that's helpful, and then on the CapEx for infrastructure, can you guys tell us a little bit about the specifics? Are we talking about tanks and roads and stuff or what exactly is it?

Matt Grubb

Yes, for CapEx infrastructure, it's really primarily saltwater disposal, well facilities because what you just talked about and what Tom just talked about (inaudible) wells, 30% of those wells are PUDs, that mean we're out drilling locations. They aren't offsetting the existing locations, right?

And so as we drill these step-out wells, we're going to have to lay longer lines and then also you have electrical infrastructure we're building against all our (sub) pumps. So that's the infrastructure we're talking about so as we go to – so as we end 2011 last year, our producer to saltwater disposal ratio was kind of four, a little bit over four over one.

As we end this year, we should be five to one but next year, our program should be more stepping back in to existing infrastructure. That's part of our acceleration of the infrastructure, spend money now, spend it next year, but we chose to do it now so we can step out (inaudible) and then go back in and fill in some of these areas.

And so next year, we're looking at drilling maybe 600 horizontal and probably we'll drill 70 disposal wells this year, so 50 next year. Then your ratio's going to bounce up to about 6.5 to 7. So we said all along that once this play developed, we should be around ten to one, so we're moving towards being more efficient every year as we drill out this play.

Duane Grubert – Susquehanna Financial

OK, that's good, and then in the second quarter, I don't think there was a Gulf of Mexico well drilled and I just was wondering if you can give us any idea on how you're integrating the new properties and if it changed those people's drilling schedule versus when you bought it.

Matt Grubb

No, the CapEx stays essentially the same. We do have review on what we drill down there and the timing and the projects moving around a little bit. We had one guy here that we transferred down to head up that asset development part of the program, so yes, there's some movements but we still expect to spend $200 million this year in DOR and probably drill ten wells and participate in another three or four (inaudible) wells.

Duane Grubert – Susquehanna Financial

Great, thank you very much.

Operator

And your next question comes from the line of Amir Arif with Stifel. Please proceed.

Amir Arif – Stifel

Good morning, guys. Just a follow-up question on the CapEx (inaudible) or is it the infrastructure for saltwater disposal at the Gulf? Is that (inaudible) from what you guys were thinking at the start of the year? Does it look optimal or are you just building up more for (inaudible)?

Matt Grubb

Yes, it's different. It's not costing more. When you're running this many rigs, you come up with a plan of how many wells you drill but then once you get down to actually drilling the wells, it depends on (inaudible) damages, where do you get rot away for pipe, for electrical, for certain things, so those things tend to move the schedule around a little bit.

But also we probably drilled – with the success of this Miss, we do have a lot of acreage and as we gain more and more success through the drilling and gain more confidence, we start drilling more step-out wells in the Miss, so that part of it probably changed a little bit and you add all those things together, it did add up to more infrastructure costs for us this year.

Tom Ward

So we could, if we chose to, drill more infield wells and not spend as much on facilities but if the play's going to work, you're going to have to build out facilities at some point and the way we look at this is that if new areas are working just the same as the original area, you might as well be building out facilities to get to those wells now.

Amir Arif – Stifel

I know the IP s aren't getting better. I mean, I think last year was 275. Now your average (inaudible) 325. Do you have an updated EUR number (inaudible) on average?

Tom Ward

No, we'll do that at the end of the year.

Amir Arif – Stifel

Is 450 still the number that you have out there? Is that right?

Tom Ward

Yes, it's 456.

Amir Arif – Stifel

Based on the 275.

Tom Ward

Two seventy-five on a 30 day IP.

Amir Arif – Stifel

OK, and then I know previously you were thinking about basically selling another 10 to 15 acres in the play. Is that still a thought or has that changed?

Tom Ward

Well, we don't want to sell any more original acreage, at least today, and we have about 850,000 acres in the original play. We feel we have ample capacity to move forward into '13 and maybe even through '13 with other ways of financing so we don't have to sell any acreage in the extension area until we get through the end of the year and see how the wells are and how they compare to the original.

I think there's probably too big of a bid and ask right now and so I think it would be into next year before we really review selling down additional acreage in the extension area and it might prove out that we want to keep it all. We have many options that we can look at right now.

Amir Arif – Stifel

(Unclear). One final question I know, Tom, that you're mentioned that you wanted to use this play more as a large play repeatable but just focusing on those 1,000 barrels a day plus wells (inaudible), can you tell us what counties they are? Are they (inaudible)? Are they spread around?

Tom Ward

Sure, Alfalfa County, Oklahoma, Grant County, Oklahoma, and Harbor County, Kansas.

Operator

And the next question comes from the line of Craig Shere with Tuohy Brothers. Please proceed.

Craig Shere – Tuohy Brothers

Hi, guys, congratulations on a good quarter. A couple quickies and then a little more fundamental question. The three rigs drilling now in the extension Miss, can you comment on where they're drilling.

Tom Ward

We have given presentations in the past that show where the areas are but like I said, we drilled so far in Ford, Gray, Finney, Hodgeman, Miss.

Craig Shere – Tuohy Brothers

OK, and picking up on Neal's LOE question math, is it the CO2 fee payment delay in fact a delay or a cessation due to qualification for all setting CO2 tax credits?

Matt Grubb

No, it's just delayed. We have certain terms in our agreement with (inaudible) and to get the plant tested, get everything (inaudible) components run to their satisfaction but we're real close on that and we expect to turn that over to them here soon and so we probably will have a shortfall penalty kicking in starting in Q4 this year.

Craig Shere – Tuohy Brothers

OK, James, I don't know if you have any feedback on the prospect for offsetting that with tax credits.

James Bennett

Yes, we're going to – we'll recognize the expense in the fourth quarter of this year. We think there's a chance we ultimately offset it with tax credits but we're not taking that into the numbers now and that won't be determined for some time from now.

Craig Shere – Tuohy Brothers

So that would be a 2013 event?

James Bennett

2013 or even '14. It's not something we're taking into our guidance right now.

Craig Shere – Tuohy Brothers

I got you. Tom, the market's up, oil's up. You had a good quarter that beat consensus. Mississippian was terrific. SandRidge's shares are down and there's a couple things I note. One is just optical that despite the fact that you have effectively raised oil guidance optically, it appeared ignoring the tertiary divestiture to be flat and you guys are front loading your infrastructure to dispense that limit immediately apparent.

But even apart from that, I think there's a – that's just a comment but there's a question in here. In your February slide deck and I think there's concerns about the logic behind some of the more recent moves. In your February slide deck, you had a sum of the parts value of $690 million for the PV10 on the tertiary oil recovery play. Those later sold for about $130 and then you had a $50 million bolt on the Gulf of Mexico and now you're raising 2012 CapEx by another $250 million.

Can you discuss the thinking behind these more recent moves and the relative value of divestitures versus your development activities?

Tom Ward

Sure. I think first thing, on your comment, that we have to make long-term decision to run a company that can’t really focus on one day’s price movement in our stock and that as we continue to build the company on the quarries that we have in the Permian and the Mississippian that all will take care of itself, especially if we hedge in the volumes like we’re doing.

With regard to the tertiary, we feel like we made a good sell on cash flow basis. Yes there’s a tremendous amount of reserves there, but they come in over a very long period of time. You have to have access to CO2, which is fairly tight in the Permian Basin.

Then the other area was the BOLTON acquisition. You’re just buying assets for under two times cash flow and putting that asset to work on drilling long-term producing assets in the Mississippian. I just think it was a good trade.

Craig Shere - Tuohy Brothers

Understood. So, I guess ultimately probably the market’s greatest concern is when do we finally get our arms around CapEx to the degree that we don’t keep seeing inflation in CapEx and acquisitions on a net basis, and we feel like we’re really comfortably getting our arms around that on a go-forward basis?

I guess the question is, are you confident that $2 billion in CapEx roughly is about as high as we’re going to have to be going on a go-forward basis?

Tom Ward

That’s always been our goal. We said $1.85 billion to $2.1 billion when we came out with our three-year plan in 2011. The goal of the company is to be able to fund an aggressive drilling program and have that all within cash flow at the end of 2014, and I don’t think there’s any change to that. Well there isn’t any change to that.

As long as we can fund a $2 billion CapEx program, and grow like we’re growing, then I don’t see that there’s any issue. It seems to me that you’re concerned that we won’t be able to fund it, and I think you’ll be able to see by the end of this year that we’ll have 2013 funded.

Craig Shere - Tuohy Brothers

Understood. I appreciate it and it was a good quarter. Congratulations.

Tom Ward

Thank you.

Operator

And your next question comes from the line of Scott Hanold of RBC Capital. Please proceed.

Scott Hanold – RBC Capital Markets

Good morning. I know you guys are probably not prepared to talk about any of the results up in Kansas (Boygan) that you've got a I guess a statistically comfortable sample to kind of talk about, but can you say in general, the wells that you have drilled, you said that they’re encouraging. Can you provide a little bit more context around that relative to your core asset or some of the verticals? Historically, is there just some kind of color on that?

Tom Ward

Well we drilled 50 wells in Kansas that have basically exactly the same production as in Oklahoma. Now as you get up into the extension portion, which is one set of counties north of the southern counties, which are -- and the original that we drilled in would be, Harper, Barber, and Comanche.

As you go further north, we have just now started drilling in those counties. Our first wells were 80 miles north of existing horizontal wells, and we’re comfortable with the extension play because there are so many wells that have been drilled and they produce oil and we’re in an oil system. So the same types of rocks, the same type of geology, that’s what makes us comfortable and we’re seeing oil.

So that’s all the color we wanted to give because we will drill good wells and we will drill poor wells and in the next few months we’ll have enough of a data set to be able to say if these counties early on are as good as the counties to the south.

Scott Hanold – RBC Capital Markets

Is there any sort of, when you step back and look at the geology, pressures, your difference between what you have in more the core developing areas versus the, the more north area, would you suspect it’s going to have more oil that’s pressure, or I mean is there some general context you can sort of set an expectation on?

Unidentified Corporate Represenative 1

Yes, what we said is that the wells have a higher oil content than the wells in the original area.

Scott Hanold – RBC Capital Markets

OK, fair enough. And when you step back and look at the infrastructure of the permitting process in Kansas versus Oklahoma, is there going to be a little bit of a higher need, is the infrastructure going to be sort of need to come up (inaudible) quite a bit if you start getting more aggressive in some of your newer acreage?

Tom Ward

Should be the same. Kansas is a very easy place to operate in.

Scott Hanold – RBC Capital Markets

And Finally on the CapEx, just so I’m clear, and maybe you’ve talked about it and I just can’t figure it out here, but to be more direct, it looks like you pulled forward some CapEx into 2012 from potentially 2013 and maybe beyond that because of higher -- better results and your activity.

If I were just sort of looking at it, you talked about potentially kind of $2 billion-ish 2013, wouldn't that number have been higher if that spending that CapEx this year? Is it really pulling it forward to save for 2013 as well?

James Bennett

Yes, yes. I mean, when we talk about CapEx and funding GAAP, I think we need to talk a little bit longer than just snap shot of this year. Things we’re doing right now is going to reduce what we have to do next year and the year after and so on to develop this Mississippian play.

So yes, I think we’re going to be -- we’re at $2.1 billion this year. I think we’re going to be around -- maybe it’s too early for me to tell you exactly what the guidance is going to be for next year, but we’re looking at probably $2 billion. So it’s going to be a little bit less than this year.

One thing, though, is we’re done with our land spending. Land and seismic this year, we’re probably looking at about $200 million and part of that seismic a big chunk of that is licensing coming over from the bill from Mexico acquisitions, and then the land, we’re done with our land acquisitions.

So that, alone, there is enough to reduce CapEx. So, yes, that and the infrastructure bill out we’re doing, I think all those things are working to reduce CapEx going forward.

Operator

And your next question comes from the line of Joe Allman with JPMorgan. Please proceed.

Joe Allman – JPMorgan

Thank you. Hi everybody. So hey, Tom, I know James gave the list of events that can help reduce the funding gap so what are the next events, say between now and year end, in monetization and raising external funds that can help reduce the funding gap?

Tom Ward

Yeah Joe, we’ve got a billion, at quarter end we had $1.421 billion liquidity. Now we’ve got $1.3 billion. That comfortably takes us through the end of the year and into next year. I don't think we can comment on specific transactions.

You’ve seen us be very active year to date in selling non-core assets, selling royalty trust units, so we’ll continue to look at those, but I don’t think we can comment on specifically what those other sources will be between now and the end of the year.

Joe Allman – JPMorgan

I’ve got a question on oil acquisition. I’m wondering how that fits into the Gulf of Mexico budget. So your budget on an annual basis is $200 million for the Gulf of Mexico. This is a $50 million acquisition. This is just simply added to that budget, or does it replace some of the drilling that you would have done to get production?

Matt Grubb

Well we don’t have anything planned from a CapEx standpoint for Hunt. That was basically a PDP acquisition that we bought at very low multiple. Some of the properties we already had interest in, so it was truly both on, but there’s no CapEx expansion plan, not for that acquisition.

Joe Allman – JPMorgan

I guess what I meant, Matt, is that my understanding is that your plan to spend $200 million a year in the Gulf of Mexico. If you were to make small bolt-on acquisitions, that would be part of the $200 million budget.

Matt Grubb

Yes, that’s correct. That's kind of our goal for the Gulf of Mexico, we look at that as kind of 10% of our CapEx budget and I think we can stay comfortable within that and keep our production pretty flat.

Joe Allman – JPMorgan

OK so this $50 million acquisition, this is above and beyond the $200 million you plan to spend over a 12-month period, is that right?

Matt Grubb

Yes, the $50 million acquisition cost itself, yes, that’s correct.

Joe Allman – JPMorgan

OK, but going forward, when you look at bolt-on acquisition, you expect them to be above and beyond the $200 million of CapEx.

Tom Ward

I’ll try to get it, Joe. So the Hunt acquisition, well let’s go back. So DOR already had a program in place that would have us spending close to $200 million. The Hunt acquisition is a bolt-on, on top of that for this year, going forward where we wouldn’t already have the rig contracts in place, the acquisitions would be included in our $200 million. That’s what we projected.

Joe Allman – JPMorgan

Okay and this acquisition, what do you think you spend in terms of multiple of cash flow?

Matt Grubb

Just a little over one times.

Joe Allman – JPMorgan

Okay. And then, Matt, is it pretty much 100% PDP?

Matt Grubb

It was yes, yes it was not 100%, it was very close though.

Joe Allman – JPMorgan

Okay. In your 8-K you didn’t give the reserves, what kind of reserves did you have at this point?

Matt Grubb

We’ll do all that at the end of the year, Joe, I don't have those numbers right in front of me, for the particular assets.

Joe Allman – JPMorgan

And then, Matt, earlier on in the call, I just want to clarify, did you say that quarter-over-quarter for the first quarter to the second quarter if you ignore (inaudible) and Hunt and the tertiary sale, the sequential organic production growth is 6%?

Matt Grubb

Yes.

Joe Allman – JPMorgan

And that’s the total company, right?

Matt Grubb

That’s correct.

Joe Allman – JPMorgan

OK. And then year-over-year, the second quarter '11 and second quarter '12, ignoring those same things, I’m not sure if you had factored other acquisitions and divestitures, but organic growth is 14%?

Matt Grubb

Yes that’s year-over-year from the end of '11 to the end of '12.

Joe Allman – JPMorgan

Does that factor all the investitures? I don't have my scorecard in front of me at all.

Matt Grubb

Yes, that’s ignoring (inaudible), Hunt and adding back in your tertiary.

Joe Allman – JPMorgan

Are there any other transactions we need to keep in mind to really figure out organic growth?

Matt Grubb

Well, I mean, East Texas, we sold that, that was about 25 million cubic feet of gas equivalent a day, but that was last November, I think it was.

Joe Allman – JPMorgan

And then lastly, that tertiary sale, I mean, was that mostly pre-developed or was that mostly developed?

Matt Grubb

Mostly, what’s on the books for that was mostly hunt pre-developed.

Joe Allman – JPMorgan

Thank you very helpful.

Operator

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

Charles Meade – Johnson Rice

Morning, gentlemen. Tom, I was wondering if you could give a little narrative on where you are on your rig count ramp in the Mississippian versus where you thought were going to be, heading into 2012 and then maybe kind of follow that up with a discussion of any efficiencies that you’re seeing there that are beyond or maybe below what you thought at the beginning of the year?

Tom Ward

We’re exactly where we thought we would be going into 2012. We are being a little bit more efficient than we anticipated, so we might not end the year exactly at 32 or 33, but we do plan to drill 380 wells.

Charles Meade – Johnson Rice

And then in that efficiency, is that a straight up kind of cost efficiency because of rig rates, or is it actually maybe better actual days to drill performance that’s reflective of the kind of rigs that are available now?

Tom Ward

Days on location are coming in quicker than we anticipated.

Charles Meade – Johnson Rice

And any comments about cost in the play?

Tom Ward

Well, costs are loosening, maybe everywhere, but as rigs, smaller rigs have left other gas plays, they tend to want to come to the Mississippian and so there’s actually a loosening of rigs today and stimulation costs, you know, of continuing to move down. We’ll be bidding our 2013 work here soon.

Charles Meade – Johnson Rice

And then one other question from me, going back to a comment you made earlier in your prepared remarks. I believe you said 50% of your Mississippian acreage is now proven. I guess to questions that is, is that-- I’m assuming that’s the 850,000 in your original play?

Tom Ward

Yes. 872 wells holed and drilled down into the original.

Charles Meade – Johnson Rice

And so when you say that’s proven, is that -- a little more detail on that definition, is that proven as far as SandRidge is concerned, or is that proven, kind of, counting for as an SEC definition, you’ve got a PDP or a (PUD) on it?

Tom Ward

No, no that’s not an SEC definition, that shows that there have been wells drilled across the areas that we have acreage that are horizontal that have proven that there’s an oil system in place and that we can drill wells there.

Charles Meade – Johnson Rice

So probably from an SEC sort of definition, that percentage is going to be a little bit lower.

Tom Ward

Oh, of course. You only book one well off of each side.

Charles Meade – Johnson Rice

Got it. Alright, that covered my questions. Thanks, guys.

Operator

And the next question comes from the line of Richard Tullis with Capitol One Southcoast. Please proceed.

Richard Tullis – Capitol One Southcoast

Thank you, good morning everyone. A couple questions on the Permian. Looking at your acreage positions throughout the play, are you guys seeing any potential horizontal drilling opportunities there?

Tom Ward

Our Permian acreage is mainly, the vast majority is vertical wells, at 4000 to 5000 feet deep. So yes, there could be some events where you’d drill horizontally, but it’s mainly just a vertical play.

Richard Tullis – Capitol One Southcoast

So no plans to test any horizontal targets this year, or even into next year?

Tom Ward

Not on anything of scale.

Richard Tullis – Capitol One Southcoast

OK, I think that’s all I have, thank you.

Operator

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

James Spicer – Wells Fargo

A couple questions on the financing side. With all the growth you’ve had here, I know it’s early, but do you have any sense or expectations as to how your borrowing capacity might change as a result of your fall redetermination? And then how much cushion, if any, do you like to maintain on your revolver to feel comfortable?

James Bennett

We like to set our base at $1 billion. I think we could have comfortably gone higher than that. We didn’t -- we’ve got to pay for that unused capacity, so we didn't feel the need to make it higher than $1 billion. $1 billion gives us plenty of cushion, I think. In the Fall and even into the Spring, we’ll look at resizing that. We’ve got plenty of capacity with the banks in our group.

So we can comfortably go higher than that, but again, just don’t see the need to now. How far comfortable into the revolver do we feel? It depends on where we are in our growth. If we’re at a stage where we’re cash flow neutral, then I think we’d be more comfortable if the stage were still burning cash, I think once you get halfway into it or something, you want to make sure you’re looking at alternatives or terming it out.

James Spicer – Wells Fargo

And then just a question on your, the royalty trust structure, are royalty trusts simply a financing alternative? And in your view, if you were fully funding within cash flow, there would be no reason to do any more royalty trusts, or are there other strategic reasons why that could be, continue to be a preferred alternative, even over the long term?

James Bennett

Sure. I think it’s primarily to fund our business. I think if we were mature and cash flow positive, you’d see a lot, you’d probably see us not doing, or doing a lot less in terms of the trust. It is an attractive cost to capital, and we are able to monetize (PUDs) at the public’s cost of capital, which is not easy to do.

So it’s an attractive form of financing, but I think it’s one that gets us through this period until we’re a more mature company. So I think down the road you’ll see a lot less of us doing trusts.

James Spicer – Wells Fargo

Thank you.

Operator

And your next question comes from the line of Omar Jama, with RBL Capital. Please proceed.

Omar Jama – RBL Capital

Good morning, guys. By the way, James, I like the disclosure on the trust. It’s very clear and easy to understand, and kind of highlights the value in financing that way. So, I compliment you on that.

James Bennett

Thanks so much.

Omar Jama – RBL Capital

I had a question about the, I believe it was last year, maybe you can help me with the history there, there was a lot of concern about the, the water disposal wells, and having to front-end load the costs, so can you remind me what the history was, whether it was last year or the year before?

And can you kind of help us understand looking ahead like how many years will this, or months even, will this increase in infrastructure spending kind of carry us for?

Tom Ward

Well, (Omar), I think that the thing to look back historically is that one of the reasons that the Mississippian was slow to have competition and how we were able to put together 2.2 million acres of land that ultimately we keep 1.7 million acres was because of the question around disposal.

And so we had to make an early commitment to upfront put in a disposal system. Now some of the other companies might choose to not put in a disposal system but there – it would show up in LOE on exceptionally high cost due to hauling water.

So it's really not an option to not put in a disposal system if you want to have an ongoing program in the Mississippian. We've just been much more aggressive and it has been an effective barrier to entry for us on competition in our areas.

So the way we look at it is it's a blessing in disguise to have – to deal with water to make oil and that the oil – the shallowness of the zone, the amount of oil we can make offsets, more than offsets the amount of infrastructure cost to put in saltwater disposal systems and that's through the savings on the drilling of the wells and then just how much we're finding.

Then as far as now moving out into the future, we will continue to have infrastructure cost. We should just be able to maybe maintain those going forward or have them come down slightly. We haven't proposed our 2013 budget yet.

Omar Jama - RBL Capital

And then just a couple of other quick follow ups on the same topic, can you give any other understanding just to help people have some comfort of what exactly the spending is? It's not cost inflation, that it really is infrastructure. Can you give any other information like, for instance, in the extension (miss), I mean, are you putting in more water disposal wells there just because that's a new area or is this really just true step out drilling in kind of the ....

Tom Ward

It's more in the original. I mean the extension in the Mississippi is just getting started. So the extra costs go into across this 150 miles from Grant county to Comanche county. It's a big area. We have a lot of acreage and every time we drill in a new township, we have to go put in a disposal system and not only a disposal system. We have to run electricity to it.

It's the prudent thing to do rather than – we can save CapEx in the short run and haul water and rent compression but it's not the right thing to do. So the – what I think is being missed here is that it's good that we're spending on infrastructure because we're finding production. And the production, so far in Kansas, out of the 50 wells we've drilled, is exactly like the production we found in Oklahoma. So I want to keep on spending on infrastructure.

Omar Jama - RBL Capital

That does seem like a good thing but there's so many earnings reports people see.

Tom Ward

I mean, you guys just get so locked down on the month-to-month equation of what happens. It's just – it's difficult for a management team to have conversations like this when it's so obvious that what we're doing is correct but yet we have to maybe sit and defend ourselves putting in infrastructure.

Omar Jama - RBL Capital

Yes, no, I think you've explained it pretty clearly now. What is the payback on something like this? When do you get to use this infrastructure? Is it two years from now?

Matt Grubb

No, we use the infrastructure right away. Just to understand the play, it's a low-cost play from a drilling standpoint. It's a low-risk play because on our 1.7 million acres, there's 17,000, 18,000 vertical wells that's been drilled amiss but you just have to handle the water.

And so what we're looking at is (puring) 75 barrels of oil equivalent IP but you may have 2500, 3000 barrels of water that comes along with it. And what makes the play work is having cheap water disposal. So you have 3000 barrels of water, you're looking at 100,000 of water or so a month at a $2 a barrel, right.

So you could have a couple hundred thousand a month just in the water trucking, if you're not careful with this thing. And so when you drill a disposal well and spend a couple million dollars, you can see it's a pretty quick payback, about a year or less.

Omar Jama - RBL Capital

And a last quick one, when do we get to see some leg on the extension (miss)? Are you going to wait until next year? Yes, I believe we also want to monetize some of that at some point. Is that a 2013 event?

Tom Ward

Yes, we don't think – we might choose to monetize some, we might not. But that's a next year event and we won't have enough wells drilled to delineate the play until the end of the year.

Operator

Your next question comes from the line of David Snow with Energy Equities Inc. Please proceed.

David Snow – Energy Equities Inc

You were modeling an eventual three wells per 640. Have you done anything in this science area that would confirm that or indicate whether you maybe ought to be doing more or how do you get that number?

Tom Ward

Well, we drilled over 40 wells that are closer that they're actually on four wells per section or at least they're not actually in the same section but are close enough to be called four wells per section and haven't seen interference. So we feel comfortable with three wells.

David Snow – Energy Equities Inc

It sounds like you may at the end of the day do four.

Tom Ward

I feel comfortable with three.

David Snow – Energy Equities Inc

How much of the original oil in place do you feel you're getting with the three?

Matt Grubb

Well, typically primary recovery is probably in the 5% to 10% for this. It's just on a bigger spacing. A vertical well you get similar recovery, it's just during a lot smaller area.

David Snow – Energy Equities Inc

Primary being your horizontal, is that what you're saying?

Matt Grubb

Well, primary being there's no water flow, there's no enhanced recovery with it.

David Snow – Energy Equities Inc

That from in your horizontal drilling.

Tom Ward

We don't anticipate water flooding.

David Snow – Energy Equities Inc

And to what extent do you think your – from the vertical wells, your percent oil in the extension are is going to differ from the 45%, 55% in your acreage today?

Tom Ward

I’m sorry, what difference do we anticipate in the extension between what?

David Snow – Energy Equities Inc

Oil and gas? Do you think you'll be over 50% for example based on vertical and oil?

Tom Ward

Yes.

David Snow – Energy Equities Inc

55%?

Tom Ward

Well, I think the vertical wells are nearly all oil. What you don't know is how much oil you're going to find. We could find just the same amount of oil as in the original and not have any gas.

David Snow – Energy Equities Inc

So how much of the vertical is in the 850,000?

Tom Ward

Well, the vertical wells in the 850,000 in the original area do produce gas, so that's part of the – I think you're trying to get to the extension. We will know a lot more at the end of the year.

David Snow – Energy Equities Inc

But vertical wells, are they mirroring the overall 45%, 55% ratio that you're looking at now?

Tom Ward

No, not necessarily.

Operator

And with no further questions in queue, I'd like to turn the call back over to Mr. Tom Ward for closing remarks.

Tom Ward

Thank you for joining us on the call this morning. We do look forward to seeing many of you at the conferences this fall and, as always, we welcome any questions in their interim. Thank you for your continued interest in SandRidge.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect and have a great day.

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