Edgar Filing: ARENA RESOURCES INC

Form 425

Filed by SandRidge Energy, Inc.

pursuant to Rule 425 under the Securities

Act of 1933, as amended, and deemed filed

pursuant to Rule 14a-12 under the Securities

Exchange Act of 1934, as amended

Subject Company: Arena Resources, Inc.

Commission File No.: 001-31657

IMPORTANT ADDITIONAL INFORMATION WILL BE FILED WITH THE SEC

Portions of this communication are being made in respect of the proposed business combination involving SandRidge Energy, Inc. and Arena Resources, Inc. In connection with the proposed transaction, SandRidge Energy, Inc. has filed with the Securities and Exchange Commission (the “SEC”) a Registration Statement on Form S-4 containing a Joint Proxy Statement/Prospectus (Registration No. 333-166141), and each of SandRidge Energy, Inc. and Arena Resources, Inc. may file with the SEC other documents regarding the proposed transaction. The definitive Joint Proxy Statement/Prospectus was mailed to stockholders of SandRidge Energy, Inc. and Arena Resources, Inc. Investors and security holders of SandRidge Energy, Inc. and Arena Resources, Inc. are urged to read the Joint Proxy Statement/Prospectus and other documents filed with the SEC carefully in their entirety when they become available because they contain important information about the proposed transaction. Investors and security holders may obtain free copies of the Registration Statement and the Joint Proxy Statement/Prospectus and other documents filed with the SEC by SandRidge Energy, Inc. and Arena Resources, Inc. through the web site maintained by the SEC at www.sec.gov. Free copies of the Registration Statement and the Joint Proxy Statement/Prospectus and other documents filed with the SEC can also be obtained by directing a request to SandRidge Energy, Inc., 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102, Attention: Investor Relations, or by directing a request to Arena Resources, Inc., 6555 South Lewis Avenue, Tulsa, Oklahoma 74136, Attention: Investor Relations.

SandRidge Energy, Inc., Arena Resources, Inc and their respective directors and executive officers and other persons may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding SandRidge Energy, Inc.’s directors and executive officers is available in its Annual Report on Form 10-K for the year ended December 31, 2009, which was filed with the SEC on March 1, 2010, and its proxy statement for its 2010 annual meeting of stockholders, which was filed with the SEC on April 26, 2010, and information regarding Arena Resources, Inc.’s directors and executive officers is available in its Annual Report on Form 10-K for the year ended December 31, 2009, which was filed with the SEC on March 1, 2010 and its proxy statement for its 2009 annual meeting of stockholders, which was filed with the SEC on October 29, 2009. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the Joint Proxy Statement/Prospectus and other relevant materials to be filed with the SEC when they become available.

Safe Harbor Language on Forward Looking Statements:

This communication includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include statements relating to when the companies expect to close the proposed transaction. The forward-looking statements also include statements about anticipated timing for filings with regulatory agencies, stockholder meetings and closing of the proposed merger. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the ability to obtain governmental approvals of the merger on the proposed terms and schedule, the failure of SandRidge Energy, Inc. or Arena Resources, Inc. stockholders to approve the merger, the risk that the businesses will not be integrated successfully, credit conditions of global capital markets, changes in economic conditions, regulatory changes, and other factors, many of which are beyond our control. We refer you to the discussion of risk factors in Part I, Item 1A—“Risk Factors” of the Annual Report on Form 10-K filed by SandRidge Energy, Inc. with the SEC on March 1, 2010; Part II, Item 1A – “Risk Factors” of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 filed by SandRidge Energy, Inc. with the SEC on May 7, 2010; and Part I, Item Safe Harbor Language on Forward Looking Statements: 1A—“Risk Factors” of the Annual Report on Form 10-K filed by Arena Resources, Inc. with the SEC on March 1, 2010. All of the forward-looking statements made in this press release are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to update or revise any forward-looking statements.

Following is the transcript of a presentation made by SandRidge Energy, Inc. CEO Tom L. Ward at the UBS Global Oil and Gas Conference on May 27, 2010.

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

Speaker ID 28

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SandRidge Energy, Inc.

May 27, 2010

9:40 AM ET

Bill Featherston:

Okay. We’re going to move on to our next presentation. I want to quickly introduce Tom Ward, who’s Chairman and CEO of SandRidge. Tom?

Tom Ward:

Thanks, Bill. I have a presentation that is a little bit stale, but one with regard to our transaction with Arena Resources that we didn’t want to change until after the transaction is made, and that vote is June 8th.

So, the transaction summary, just to give you a little bit of background on SandRidge and why we chose Arena Resources as an acquisition or merger partner, is that we have a strategy of increasing our oil exposure. And we started that strategy in late 2008. We started moving towards hedging our natural gas as we saw the world crumbling just a bit in the fall of 2008. We decided to hedge our gas through 2010. And so, this year we have a hedge book, corporate hedge book of $9.15 an Mcfe for our gas, and now have moved forward also with hedging oil, and I’ll talk about that in just a second.

But in 2009, along with the hedging of our gas, we moved towards a strategy of diversifying from a totally natural gas company in the West Texas Overthrust into a more balanced oil and gas company in the Permian Basin. So, both of these properties are next to each other. Fort Stockton, Texas in the center with the Permian Basin 60 miles north and the West Texas Overthrust 35 miles south.

The Arena properties are in the Central Basin Platform of the Permian Basin. We focused on the Central Basin Platform due to our legacy field, the Goldsmith Adobe Unit in the Central Basin Platform. And then, in 2009, as I mentioned, started moving forward with buying oil properties in the platform, culminating with an $800 million acquisition of Forest Oils, three fields in the Central Basin Platform, along with a Wolfberry play in the Midland Basin, a Bones Springs play in the Delaware Basin, and then one water flood in Lee County and Mexico.

So, when our — when Arena came on our radar it was because the Fullerton field sits adjoining Fuhrman-Mascho. And Arena is a larger producer in Fuhrman-Mascho and a very active producer. And in fact, this company moved their production over five years from 200 barrels a day to now I think publicly 9,000 barrels a day with a two-rig schedule and didn’t issue any debt. And had built up to $65 million of cash.

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

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So, obviously a great asset. And they’d gotten to a size that it was more difficult to not be raising debt or changing the structure of the company and growing. And so, I think both of us had a reason. We loved the area. We have the ability to put more rigs to work in the Arena properties and grow that asset. And so, that is why we chose Arena. The Central Basin Platform, as I mentioned, as single asset focus. Very rare. And then a company that also didn’t have any debt and on — for us, the main criteria was the asset. But then, secondly to that is it is a deleveraging event for us.

Very easy to integrate these properties with us, as I mentioned. We have worked side by side in the same area. And I’ll get to a map in just a second to show everything lines up with this acquisition.

The other thing that we did, as we looked at 2009 and saw that there was a move away from drilling conventional wells in the United States into drilling shale wells, is that it left a void in the acquisition market. So, for the first time since 1998, the major participants over the last 10 to 12 years were gone from the acquisition side of the business. That left an ability to go in and find properties that you could basically buy for PDP, which is nothing I’d seen since 1998. And then with that, hedge in the PDP and have upside with the developed properties.

And in our Forest acquisition that’s what we did. And what we call our one-two-punch is not only decide to move to oil at a time of high oil prices, but to hedge in that oil price. And we have today $2.5 billion worth of revenue hedged out through 2012. Our goal of pre-acquisition of Arena is to have $3 billion revenue hedged through ’13 and we’re on our way to doing that.

So, there is more to the story here than just saying we moved to oil. And so, we moved to oil and we locked in rates of return that are very hard to achieve. And the reason that — we’ll look at all of our Permian Basin properties and say we have an 85% rate of return, if you take all of our undeveloped properties in the Permian Basin, we think we can do better than that by cherry picking which ones that we’re going to drill.

But, that’s — it’s very hard to do, obviously, to have those kind of rates of return. And we don’t believe that they can be sustainable because capital will flow to those types of deals. So, we think that this is a window of time when you could have made those types of acquisitions and it is fast closing, if it hasn’t already closed.

And in order to have wells that you drill in four to six days, the service costs can’t change very much because of just the time involved that you have a rig on location. And you don’t use large completions. By locking in the price of the oil, it does allow us to keep that rate of return.

Oops, go back there.

I’ve basically mentioned these, but 86% oil on Arena. And the Permian Basin is, again, where we’re looking at. Now, the Fuhrman-Mascho is being developed in the San Andres, which is 4,500 feet deep. Basically, it takes four days to drill a well. And we’re going to also start looking at the Clear Fork formation of what we drill in the Fullerton Field just to the north.

As we look at Arena — and I’ll just — here’s a map of the Central Basin Platform. You have the Midland Basin where the Wolfberry’s being drilled, to the east in the Delaware Basin where the Bone Springs is being developed to the west. And the Central Basin Platform, the reason that it’s called a platform, it sits up. So, the same Spraberry rock that’s being developed as a sandy — or a silty sandstone in the Eastern Midland Basin, as you move up on the platform that becomes the geological equivalent of the Clear Fork, which is a limestone or a carbonate.

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

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And then moving down into the Delaware Basin, the same geological equivalent as it turns back into a sandstone as the Bone Springs. So, two basins with a Central Basin Platform, called platform because it sits up a couple of thousand feet above the two basins. That’s the area. So, you can see where Fort Stockton, Texas is with the star. And then the Pinon Field just to the south. So, the same rigs that are working in the Permian Basin can also work in the West Texas Overthrust. About the same depths, 6 to 8,000 feet.

Here’s the slide I wanted to show where we’re talking about Arena in green with the Fuhrman-Mascho fitting in-between the three Forest acquisition properties, Fullerton, Robertson, and Tex-Mex. And then you see Goldsmith Adobe. We’ve been drilling in the Goldsmith field since 2007. And even at higher gas prices, we were noticing that our Clear Fork wells in the Goldsmith Adobe were having superior rates of return back in 2007 and 2008.

And by the time we bought Forest properties, we’d drilled about 125 of these Clear Fork wells. They were averaging over 100% rates of return. And so, that’s why we were so aggressive to get in and get this property bought whenever it came available. And then with Arena then tying directly into Fullerton with Fuhrman-Mascho, and then actually also with Goldsmith Adobe. So, it fits in perfectly along the Central Basin Platform. We’ll be in basically all of the major fields.

The other great thing about this is that Arena brings 2,700 low-risk locations on 10-acre spacing. The Forest properties were spaced in-between 50 and 60 acres. So, we have a tremendous down-spacing opportunity in those three Forest properties. And that’s what Arena was getting into when their — Fuhrman-Mascho was producing at the 200 barrel a day range. So, we have a lot of opportunity on the Forest properties to move forward with down-spacing and continue to downs-pace the Fuhrman-Mascho area. There have been — well have been drilled on five-acre spacing. Energen has a property that was developed by Range and then water flooded that was on five acres in the Fuhrman-Mascho field.

Here’s just a combined assets of the Company. One of the things that I’ll just point to here to save a little time is just look at the SandRidge standalone PV10 and SEC at the end of the year. We wrote off all of our gas PUDs at the end of the end of the year at the $3.87 price. We didn’t see PV10 value at end of year for drilling gas wells, so we didn’t think we should carry them at PUDs with no value. So, we wrote those gas PUDs off and now look at — as the gas price moves up, even to end-of-year pricing, we’ll add nearly $2 billion worth of reserves back on our books, just with gas price movement back up to where it was. And then if you see the 10-year strip, obviously moving that to over $5 billion just on our proved reserves. Standalone. And then you can see the combination of Arena in the post-acquisition.

The Permian Basin production moves dramatically up. We were at 13,000 barrels at the time of this graph. Continue to move rigs into the Permian Basin today, drilling oil wells. We’re growing our production rapidly. And you notice that almost 22,000 barrels a day post-Arena for the Permian Basin. A lot of acreage. Continuing to think if you’re drilling down to 5 and 10-acre spacing that we have 205,000 acres of land to prospect for in the Permian post-Arena.

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

Speaker ID 28

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A financial review. I basically went through this. It increases our exposure to oil. We’ve already hedged most of that. We’ve hedged through 2012. We’ll be looking at 2013 as soon as prices move back up just a bit. And that gives us a lot of balance sheet improvement. The vote is June 8th.

Hedge review I’ve already talked about. Just these to — the balance sheet I could go into if anybody has a question on it.

Now, I’ll kind of flip through to who we are as a standalone company. SandRidge is a traditional driller of conventional reservoirs. So, something I didn’t used to have to stand up and say is that we drill vertical wells and we drill them in mainly sandstones and limestones, (inaudible).

We focus on cost. That’s another thing the industry doesn’t talk a whole lot about is that we — our cost per well is between $450,000 to $2.1 million as we look at both sides of the equation of drilling a well, how much it costs versus how much you find.

We have predictable production profiles. I’ll show a slide in a little bit that shows that our newest field was found in 1981. So, we have fields that have been producing since 1930 that we’re a part of in the Permian Basin.

We have low acreage cost in proven acres. As we develop areas in the Permian Basin, the West Texas Overthrust, we don’t have additional hundreds of millions of dollars per year that we’re trying to put into acreage. That comes with the properties that we’ve acquired or that we’ve bought or have held by production in the West Texas Overthrust.

It gives us certainty of economic returns. Anytime you deal with a reservoir that’s been producing for decades, you know what ultimately — whenever you find the first month’s production, you know ultimately what that’s going to produce. I think the industry is in a little bit of a change now. That there’s — what I’ll show is that I believe there’s some risk going on across the industry, that all reservoirs aren’t the same. That this isn’t necessarily a manufacturing business, and that you should know what company produces what type of reservoir and how come some are better than others.

The red flag basically tells it all for me. It’s that I believe that the industry over time has been drilling conventional reservoirs from 1900 through 2005 within the advent of the Barnett Shale, which has some very unique characteristics, is — have brought on a new type of play. I’ll not say that I don’t believe in shale plays; I do. They’re great places to drill within each of these, especially if you look at plays that have other types of dimension other than shale.

For example, the Bakken has great reservoir characteristics with (inaudible). But to say that all shale gas is the same is not correct. And so, what I believe is that anytime that you move your cost up to $10 million and you’re drilling at ever harder reservoir, you’ve got risk. And I don’t think that the industry is looking at all of the risk that’s entailed in our business.

And so, my belief is, why we have chosen to go with older reservoirs and conventional type plays, is it gives us that certainty of economic outcome. The reservoirs we produce from were found, as you can see, in the Permian Basin from 1930 on. And then the Pinon Field was discovered in 1981. We know when we drill a well basically what that type curve is going to look like.

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

Speaker ID 28

Page 5

The other problem in the natural gas business today is that we have a rig count that has been moving up at very low prices. And if you look at basically anyone’s 10-K, you’ll see that, if it’s a natural gas company, at the end of the year that it’s very, very difficult to make money. And in fact, you can see with the very best play, the very best gas companies in our business have PUDs on their books at the end of the year, but they’re not worth anything. So, that doesn’t include G&A and it doesn’t include interest. It just means that it’s very difficult at $4 gas, or even $5 gas, to have a property in — just drilling natural gas that makes a lot of money.

So, what I say is that how can you have a gas rig count continuing to move up in an environment where it’s been publicly stated that we just don’t make very much money, if any money, on a cash basis, let alone trying to charge any G&A or interest. And have service costs be moving up by 30% at the time that gas prices are going down, and continue to see a rig count move up. It doesn’t make sense to me.

So, that’s the reason I stay fairly bullish long term and why we continue to keep gas assets. Because if I had a belief that, overall, that this business had fundamentally changed in the last year or two and you could find gas for $3 or $4 and have a rate of return and cover your G&A and interest, then I would be looking for a way to exit the gas business. But I don’t believe that. And in fact, I believe that most plays that are drilling gas wells today need a much higher price than what we need. And I’ll talk about that more as I get into Pinon.

My simple macro Oklahoma oil theory is that it’s hard to find. That, why does PG and BP, Devon, Exxon-Mobil, Mitsui, StatOil and Total look to come to the US natural gas business. And my belief is that, at this time, oil was $85 or $90. And if it were so easy to go around the world and find oil, there’s no reason to be coming here and be looking for natural gas. So, I just think that over a long period of time oil is still difficult to find in difficult areas, and will continue to command a higher price. And if you’re drilling for oil and you find the same amount of oil as you find gas, it’s basically worth 10 times more to drill for oil wells.

We do combine, as I mentioned, hedging along with acquisitions. So, if you see — as you see here, we have nearly, on a standalone basis, just SandRidge has nearly 20 million of barrels of oil hedged out through 2012 at very attractive prices. And again, that ties back to having wells that can be drilled in four to six days with very small completions. So, we’re not in the competitive side of the business on cost. We don’t have to have top drives. We don’t have to have large rigs. We own our own rigs. And it takes just a few days to drill a well. So, we don’t think service cost can move up enough to ruin our rates of return. That’s why we want to make sure we lock in very high rates of return.

If you look at our operating areas, West Texas in the Overthrust, we have 550,000 net acres. Only one field that has been developed yet but now — I’ll talk more on exploration, but we think the entire area is gas charged. What is — our goal is to go find structures to be able to drill, that we don’t believe that Pinon is geologically unique, that there can’t be other structures, or there aren’t other structures that produce. In fact, we found — out of the first two wells we’ve drilled, we found one that does produce 100% methane. And I’ll talk more about that.

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

Speaker ID 28

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The Permian Basin, over 150,000 acres with 2,700 drilling locations. Again, those drilling locations are not down to the 10 and 20-acre spacings. We have tremendous amounts of land left to drill. Clear Fork, San Andres, Wolfberry and Bone Springs type wells.

In Oklahoma we do have a developing play in the Mississippian in Northwest Oklahoma. This does — it’s a carbonate that has poor volume. So, we won’t drill wells every 28 acres that are horizontal, but we do see wells that can drain a large area through fractures that maybe could be either drilled on 320 or 640 acre-spacing. We’re hopeful 640 acres so it takes less cost to drain a large area of oil. That’s early in the life of these, but we have acreage in place and we do have three rigs that are working there now.

And then we have one well — or one rig that’s working in a developing play in the Western Oklahoma Cana Woodford play. And I do see a little different decline profiles on this than most of the shale plays. And the companies that are around us know a lot more about this than we do. We’re just in the early stages of developing 45,000 acres.

The Century Plant. We get a lot of questions about the Century Plant. It’s our joint venture with Occidental Petroleum. $800 million project that Oxy is funding. And for that funding they get the CO2 out of the Pinon Field for free. We deliver — or we drill the wells, we spend the money to drill the wells, we deliver gas to the processing plant. I t gets stripped and they take the CO2 for their EUR project in the Permian Basin and we get the methane.

So, it’s a very simple, good long-term project for us and Oxy. A 30-year contract in place. We have to deliver 3.5 Tcf of gas over 30 years, so it’s CO2 gas. And for that, they’ve built us the ability to expand our reservoir. This was the only thing that hindered Pinon Field from being exploited over the years is how do you get out the CO2.

So, we’ll be moving gas from our existing plants over to the Century Plant. This should come online in — I think now we’re saying late August. We’ll start commissioning the plant in June. So, we’re giving ourselves two months to commission. Oxy is projecting the fourth quarter, but I think actually we’ll get done in the third quarter, either late August or maybe the first week of September. So, that’s back about a month from the last time you would have heard me say that. But I think that — there’s an outside chance we could commission in 30 says, but probably it will take us 60 days.

Here’s the reason I say that the Pinon Field can compare with any play in the United States. And I won’t say that it can beat any gas play. I won’t say that it can beat any one area. There might be dozens of wells that can be drilled in an area that would compete with this, or I won’t say it’s better than Pinedale. But if you look at this versus a large area that is being — considered to have a manufacturing plant that’s shale today, I think we compete very, very well.

A very low decline curve. We started out first year declines at 30% that goes to a 7% final. And you can basically work that out to almost a 13.5% exponential. It has a very, very shallow decline curve.

The ability to make 7 Bcf per well at 7,000 feet with normal pressure just gives you the idea of how good this reservoir really is. The — on this decline curve, it’s 6.6 Bcf coming out of the Warwick Caballos and the remainder coming out of the Tesnus, which is (inaudible) sandstone. So, we developed 7.3 Bcf per well and have that 2.6 — 4.6 Bcf of that being methane, with a finding cost of $0.99. Today we have 10 rigs working in the field.

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

Speaker ID 28

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We see no issues with meeting our Oxy requirements. Get a lot of questions about what happens if we don’t meet an Oxy requirement. We have every intention of fulfilling any obligations to Oxy. They’re a great partner of ours. We have a 30-year commitment with them. And so, we continue to drill wells that can — at even low prices, can at least on a cash-on-cash basis carry through with drilling in Pinon.

Here’s just a map of the field and the infield development. The field has really been defined. We continue to see geological changes within the field that allows us to have more locations as we drill and enhance the 3D. But that’s — the size of the field is about between 35 to 50,000 acres and it’s fairly well defined.

Here is a map that we just talked about earlier about Arena, the Central Basin Platform area. And no reason to really go through that other than — I’ve already discussed the SandRidge standalone. Our growth in oil on a standalone basis is still very impressive as we move on to the Forest properties. Again, we’ve moved from 2 rigs to 14 rigs drilling oil wells in the Company.

This was the Mississippian project I talked about in Oklahoma. Our first well came on at 350 barrels a day. I think we’re looking here at about 160,000 barrels and 450 million cubic feet of gas per well. Still too early to give you a firm definition on whether that’s being achieved or not. We think it is so far so good, but I don’t like to make claims after the first month or so that a well’s online.

Here’s just an area that we’re just starting to work. And we continue to look at this as maybe an opportunity in 2011 for a divestiture. We’ll make sure that our property is situated in the right area and then, if so, this could be an area for us to look at further. It’s just a very good area to be drilling in, but maybe one that we could use to drill more, either in the West Texas Overthrust or the Central Basin Platform.

Here’s the exploration ideas we have. You can see where Pinon Field is in the northwest corner of the West Texas Overthrust. We think that’s the area of highest CO2. So, as you move south and as you move to the east, the source rock is a shale. And so, those shales are letting gas out to go into a trap and the trap’s a structure. And four-way closure on Pinon Field. And as you drill into that field it is vertical fracturing that creates the volume, the poor volume for it to be able to get out the gas. So, what we see there is an average of 7.3 Bcf per well. There’s been over 800 wells drilled in the Pinon Field to date. And we’ve now moved over to some of these other ideas. We shot our 3D.

And this is the largest proprietary onshore contiguous 3D shoot in US history. 1,300 square miles. It’s proprietary. Nobody else owns the whole data. And we see a lot of structures at the Warwick Caballos depth. In fact, about 20 different structures that we’re going to be wanting to test. Testing six of them this year. So far, we’ve drilled two wells, testing two separate structures.

The first structure we drilled we did find structure. We see the seismic character is the Warwick Caballos, which is important because we had to just look at the squiggly lines of seismic and determine that was the same reservoirs that we had in the Pinon Field, correlate that to where the Warwick Caballos outcropped and move that back down into the place that we drilled a well. And did find 900 feet of reservoir thickness so we can check that one off.

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

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So, we had the reservoir thickness. We saw gas as we drilled through the system. We didn’t make an economical well in the first one, but we did see gas in place. We had fracturing on our FMI log, so it looked like the same reservoir that we saw in the Pinon Field. And then, we did get the well tested and have come up that it had 22% CO2 instead of 62% CO2, which is what we see in the Pinon Field.

Here’s the location of the structure. We were off just a bit. I hope this is a pointer. That’s not. Well, you can see at the top of the green interval, the pin interval, we thought that was the top of the structure when we drilled the well and ended up being a down dip, an off structure. We drilled well access in Pinon where we’re down-dipping off structure and move on structure and find gas. We’re hopeful of doing the same thing here.

So this well, while it tested at an economic, it did test low rates of CO2, so that gives us hope that, on top of the structure, that we’ll be able to find commercial gas and have it also be with much less CO2. This is an area that doesn’t have any people living in it. Fifteen miles — actually, it’s 18 miles away from the south end of Pinon Field and nobody lives there, and the same landowner. So, all we have to do is make a pipeline. If we find gas that has 20% CO2, we can put that in our legacy plants. We have plenty of capacity if a field were found here to get gas out.

This was just a log showing how it compared to the Pinon Field.

And then, as we moved 35 miles east, we chose to try a structure on the eastern edge, or on the eastern side and the western side. The first was on the western side of the Overthrust.

This is on the eastern side, the second structure we tested. Again, a large structure, 23,000 acres in size. We drilled into the structure. It had gas all the way down through it. And so, we are on a structure. We found three potential producing targets. We tested one, as we mentioned. And the initial test on that was 2.1 million a day, 1,400 pounds on a 14/64ths choke. We have not tested the well any further. Moving up to test the other two zones up hole in the well. This is called the Owens Sand and we’re moving up to the Pennsylvanian sands, the equivalent to the Tesnus in the Pinon Field and we’ll be able to have some discussion on our first quarter — or our third — or excuse me, our second quarter call in August.

This was just an early log that we had showing the Tesnus to how it compares to the expiration well. At that time we didn’t have it named, just Expiration Well No. 2. It’s called the Owens Well on the Magnolia structure.

And that’s my presentation. I’m happy to take some questions.

Unidentified Audience Member:

On the Oxy project, how do you look at the breakeven of gas (inaudible)? And what’s the contract relationship that you have that allows you some flexibility to not drill? And I guess then, lastly, how much CapEx is required (inaudible)?

Tom Ward:

Okay. I’m going to try to repeat that so everybody can hear. What’s the relationship with our Oxy contract, the capital requirements on a yearly basis? At what price does it make sense not to be drilling wells? And I think that captures most of it. If not, you can—.

Unidentified Audience Member:

—And what (inaudible).

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

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Tom Ward:

If it doesn’t make economic sense, are we allowed not to drill wells under the contract?

The contract is confidential, parts of it, so I can’t talk about all of that. But I can say that we have a 30-year contract with Oxy and that’s made for both of us to have flexibility. There’s no requirements made on a yearly basis on how much we have to spend or how many wells we have to drill. There is a yearly commitment that is made that’s obviously less than being full, the plant being full. Keep in mind that we already have existing gas in place on our legacy plants that we’re going to move over to the Century Plant whenever it’s brought online and that give us the efficiencies, we’ll say, just between moving from legacy plants into the Century Plant is about $30 million a year net to us. So, we do have an incentive to move forward.

I will say that, at anything less than $4 gas, it doesn’t make sense to be drilling gas wells in this area in the Pinon. I mean, you can claim that it’s okay, but we don’t think for a long period of time that you’re going to have gas below $4. So, what we didn’t do is move our rig count up to 18 rigs and moving forward with filling up the legacy plants and the Century Plant aggressively through 2012. So, we’ve already done what you’re suggesting, is we moved back to a 10-rig schedule. We have a long-term relationship with Oxy. We have every belief that gas prices will be above $4 in our future. And we’ll continue to deliver them gas. We’ve scheduled through 2010 in our budget to deliver gas, to have 10 rigs running in the Pinon Field.

Unidentified Audience Member:

(Inaudible) on the Century, Tom. (Inaudible), or how does that fit into the Oxy (inaudible)?

Tom Ward:

If the plant performs better than expected, would we become a merchant seller of CO2? The answer is no. We — the CO2 in the Pinon Field is dedicated to Oxy. So, whenever it goes through that plant, the CO2 is Oxy’s to do with whatever they want. They can use it or sell it or whatever they choose to do with it.

Anything else? Oh, sorry.

Unidentified Audience Member:

The hedging costs that we had talked about was the $2.5 billion (inaudible). (Inaudible) you hedge any of the Arena production (inaudible)?

Tom Ward:

And I’ll ask a question with a question. You mean on our books?

Unidentified Audience Member:

(Inaudible.)

Tom Ward:

Okay. Did we hedge any Arena oil in anticipation of buying Arena? The answer is no. We just hedged our projected oil out into the future and we’re not even 100% hedged on that. So in fact, we have a contract in our bank agreement that we can’t be over 85% hedged over what our projections are going to be.

Unidentified Audience Member:

Tom, what are the plans for further prospects for (inaudible) this year? Are you seeing (inaudible) and you’re going to delineate this — that partial discovery or do you plan to put additional rigs (inaudible)?

Tom Ward:

The question is, are we going to add more rigs or what’s the plans for exploration this year in the West Texas Overthrust. We had mentioned earlier in the year that we’re going to drill six wells. They usually — the way we’re doing it now is going out with two rigs at once, drilling two wells, evaluating those and then trying to decide where to go with the next two. We do know that we’re going to drill our next — one of our next exploration wells will be drilled at a structure next to Magnolia, over in the east, to try to find more sweet gas up on structure. And we’ll probably drill another one on the west side during this quarter, also. But planning to drill four more wells this year.

SandRidge Energy Inc.

5/27/2010 – 9:40 AM ET

Speaker ID 28

Page 10

Bill Featherston:

Any other questions for Tom?

Unidentified Audience Member:

Tom, with the (inaudible) transaction (inaudible) transaction, I understand your desire to close it. There have been several proxy advisor groups (inaudible). What is your backup plan should that happen?

Tom Ward:

Oh, our backup plan’s the same as it was before we started to move the Arena. We have a tremendous asset in Forest. As good as the Arena field is, the Fuhrman-Mascho, and it is an excellent field as you — and they’ve done a tremendous job growing oil from 200 barrels a days to 9,000 barrels a day and not have any debt. The properties that we own to the north are even less developed. So, we have all that we need to do just on our Forest properties and our Goldsmith Adobe legacy. So, in the Central Basin Platform we can go spend a tremendous amount of money.

I think the Arena transaction is a great transaction for both companies and I believe it will get done. We’re one and two, so we’re not struck out yet. The three risks, as there was three proxy firms that came out, or advisors, one was for both. Three were for SandRidge shareholders and two were against for Arena shareholders. But I think there are lots of arguments why Arena should be wanting to come into our company and we’ll try to bring those out to shareholders in the next few days. And I’m pretty sure we’ll be successful.

Bill Featherston:

Alright. Please join me in thanking SandRidge.

Tom Ward:

Thank you very much.