Good day, ladies and gentlemen, and welcome to the third quarter 2008 SandRidge Energy Earnings Call. My name is Eric, and I will be your coordinator for today. (Operator Instructions) I would now like to turn your presentation over to your host for today's call, Mr. Dirk Van Doren, Chief Financial Officer. Please proceed.

Thank you, Eric. Good morning. This is Dirk Van Doren. Before I turn the call over to Tom Ward, our Chairman, CEO and President, I need to make a few opening remarks. Last night, the company issued a press release detailing SandRidge's financial and operating performance for the third quarter of 2008, and we also filed our 10-Q. If you do not have a copy of the release, you can find it at the company's website, www.sandridgeenergy.com. Also, you can sign up for releases that will be automatically sent to you, and this is located under the Investor Relations tab. Today, we will use a few slides that are also available on our website. Now, for the forward-looking statements. Please keep in mind that during today's call, the company will make forward-looking statements, which are subject to risks and uncertainties. Actual results might differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed in the company's filings with the SEC. Today's presentation will include information regarding adjusted net income and adjusted EBITDA and other non-GAAP financial measures. As required by SEC rules, a reconciliation of the most directly comparable GAAP measures are available on our website under the Investor Relations tab. Now let me turn the call over to Tom Ward. Tom?

Thanks, Dirk, and welcome to our third quarter earnings conference call. We have in office today Matt Grubb, our Chief Operating Officer, with Dirk and me. As you have read, we had another very good quarter executing our business plan. I will now quickly run through the highlights of the quarter and turn it over to Dirk. As you're aware, the world is focused on access to capital. SandRidge is also focused on access to capital and has made this our number one priority in the last 90 days. We have cut our 2009 budget to $1 billion from the $2 billion budget guidance in the second quarter conference call. We started the process of selling our East Texas assets during the second quarter and are now working with several interested investors to include the selling in the fourth quarter. We plan to completely pay down our revolver by the end of this year and are currently reviewing additional avenues of funding, including further asset allocation and developing a capital plan that will fund us through 2010. SandRidge continues to grow the Piñon field. We drilled 76 wells in the quarter, and our company reserves grew to over 2.1 Tcf of gas. Our production was curtailed by about 33 million cubic feet a day on average. And at times, as much as 60 million cubic feet a day was shut in during the third quarter because of the fire at Grey Ranch, our CO2 plant, the well work in the Gulf Coast and hurricanes Ike and Gustav in the Gulf of Mexico. We restored production at the Grey Ranch plant earlier this month, but currently still have about 20 million cubic feet shut-in in the Gulf due to the storms. The total estimated production loss in the third and fourth…

Thanks, Tom. I will focus on a few third quarter highlights, our confidential position and projections. The key things we look at are production operating costs, EBITDA, free cash flow and funding needs. Production was flat because of shut-ins, while costs were within our guidance with the exception of G&A, again, as a result of the shut-in of production. Adjusted EBITDA was $180 million for the third quarter, which is above our guidance and our internal model. Our quarterly capital expenditures were $675 million and the shortfall was covered by our cash position, cash flow and borrowing on our revolver. Something that I get a lot of questions on, we were in full compliance with all of our covenants at the end of September. Additionally, since our last call, we've got into our hedge position. We are now 72% hedged for the fourth quarter of 2008 at an equivalent price of $9.20 per MMBTu. And for the full year 2008, we will have been hedged 77% at $8.97 per MMBTu. Looking at 2009, we've added significantly in the past three months to our hedge position, and we are now 57% hedged for 2009 at $8.88 per MMBTu. In August, we were 19% hedged for 2009 at $10.50 per MMBTu. Let's look at our guidance that was presented in the press release. For 2008, the only change was a mix of capital expenditures. And for 2009, we had previously changed production and capital expenditures in early October and have made some minor changes to costs. Looking through the reminder of the fourth quarter, we will be at two conferences in November. So, please see our website for the times and dates of these presentations. We also included in the press release that we plan to release our fourth quarter and yearend results on February 26th, and we will file the 10-K that day with our conference call the next day at 9 A.M. Our second annual investor analyst meeting will be on Tuesday, March 3rd, in New York at 8 A.M. at the Grand Hyatt. So, please mark the calendars. That ends our prepared remarks. Eric, we're ready to open the call for questions.

(Operator Instructions). Your first question comes from the line of Joe Allman with JPMorgan.

Yes, thank you. Good morning, everybody.

Good morning.

Hey, Joe.

Hey, Tom, maybe you said this, but how many wells at this point have you drilled in the Frog Creek thrust and where are those located?

The Frog Creek thrust is mainly if you look north to south on that slide we presented. The Dugout Creek is the furthest north. The Warwick is the center. And that's on page three. And the Frog Creek sits south of that. So, by definition, the Frog Creek wells are at the south end of the field. We're not going to get into specifics of how many wells were drilled, but you can see on our website where we are drilling wells and can maybe come to some conclusions. We have several wells that have penetrated Frog Creek and several that wells that have tested the Frog Creek. We don't know today what type curve to put with the Frog Creek wells on whether they are a Dugout Creek type curve or a Warwick type curve. We feel comfortable that they will meet or exceed our PUD average type curve.

Okay. But in all the wells, you are seeing sweet gas?

Yes.

Okay. And then, in your prepared remarks, you mentioned further asset allocation. Could you elaborate on that some?

I won't elaborate very much other than to say that we do have assets that we have available to us that if we need to we can monetize. We'll talk to several different types of companies. For example, if someone wanted to look at our midstream system, where we still had control of that, because it's very important to us, we're thinking that we could monetize some value there.

Got you. And then lastly, the Big Canyon well is drilling. I know it's still drilling. But what are your thoughts so far as you are drilling that and what are you seeing?

We're pretty encouraged that of the three exploration wells, this is the only one that's hit our targeted zone in the overthrusted chert. We have good shows, and we'll test them out in the year.

Okay. Thank you.

Thank you.

Next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed.

Thanks. Good morning.

Good morning.

Tom, you indicated obviously you're looking at plans to have full availability of your credit facility by the end of the year. Can you kind of, I don't know if it's better for Dirk as well, just kind of address where we are at right now and the most likely options to get there?

The most likely option is the sale of assets. And that should be done by the end of the year. I'll let Dirk hit on anything else.

Yes, I can get into some more details. Let me walk you through from where we ended the quarter to where we are now on the revolver. We ended the quarter at $166 million on the revolver. We also had some one-time items that created cash that during the quarter if we didn't have those we really would have ended the quarter at $212 million. So, let's say the quarter really should have ended at $212 million. We had a big interest payment in October of 34. We bought the Well Participation from Tom for $67 million. That gets you up to $313 million. We had a $10 million type deposit during the quarter. That's $323 million. We had $25 million of working capital. As the business is slowing down, some working capital should be coming out of the business. That makes sense. And we had $57 million cash flow shortfall based on CapEx over EBITDA. These are rough numbers. We've pushed accounting pretty hard on that. We're not going to have the real numbers for another week, but that's a rough idea. That gets to us $405 million at the end of the month. It says $415 million, $416 million in the Q on page 45, but you get hit with some [AP] checks early in the month. So, we are in pretty good shape. We are certainly tracking where we thought we'd be on the revolver. And we plan to be out of it by the end of the year.

Okay. Thanks. And, Tom, I'm going to push a little bit harder here. But on the potential sale of East Texas, how should we think of it in terms of how confident you feel you can get something done? Obviously, there is a few packages out there at this point in time. And can you kind of give a little bit of color how that process is going now that, I guess, the data room is closed?

Sure. Like I said, we plan to be out of our revolver by the end of the year at zero. I think the data room process went well. We had a lot of interest, and we plan to close out our revolver.

Okay. And then moving to some of, I guess, the step-out activity out in South Sabino, you said, I guess, you didn't hit the chert zone. And was that basically because you didn't have the seismic available and do you plan on drilling some step-out wells in that area again with the different areas targeted?

That's a good question. When we drilled all three of these wells, when we started those, we did not have the seismic shoot over the Piñon field. So we didn't know how the thrust systems were laying on top of each other. What the wells have done is give us indications of where we should go. For example, in the furthest well east in South Sabino, we actually drilled very far down depth in the Warwick thrust. And so, we could actually move to the south and cross over into Frog Creek thrust or we could go to the north and drill at a better structural position inside the Warwick. So, we did not have the seismic control that we needed to start those initial wells, and that was based off the seismic that was shot before we shot the Piñon field. So today, using that well control is very helpful. It's encouraging that even though you didn't have the chert sections there that you can hit the [Woods hollow] sands and still have production, even though it's not economic to drill those wells for that depth for that amount of production. The key point is that there is gas saturation all the way across the West Texas Overthrust and now all we have to do is find where the potential chert zones are, the overthrust in the Warwick especially. If we can find that outside of the Piñon field in 100% sweet position, we feel like that would be the biggest prize we could find.

When looking at the 3-D, can you identify on that 3-D where the chert may or may not be?

You can see thrust, and you cannot isolate down less than about 200 feet. So, what you look for are packages. And then the well control is very important for you to determine back to the seismic on which package you are in. So, for example, in the Big Canyon area, you are over 30 miles away from the Piñon field. It's very important for us to get well control. We believe we are in the Warwick thrust, because we're offsetting another well that was drilled by Conoco in 1992. The confirmation is correct that we were able to move up dip from this well and hit our pay zone at approximately the same spot that we thought we would, within 50 to 100 feet. So that's very encouraging, and it ties us back into the Piñon field.

Okay. So this is just a process of basically sticking a lot of holes in the ground and using your seismic and reading a lot of the date and then becoming more surgical. Is that a fair statement?

Well, if you find the thrust that's productive, you don't have to do much more searching, because like the Piñon field, once you find the productive thrust, all the wells are productive from that point forward.

Okay. Got it. I appreciate it. Thanks.

Thank you.

The next question comes from the line of Brian Singer with Goldman Sachs. Please proceed.

Thank you and good morning.

Good morning.

To push even further in terms of the revolver and the asset sale process, if $445 million is currently the number, what is your expectation for CapEx versus cash flow for the remaining two months of the quarter and should we just take that difference versus $445 million as expectation for assets [on sale]?

This is Dirk, Brian. On page 45 of the Q, the revolver as of November 3rd is $415.6 million. Okay? I don't know if we want to get into monthly cash flow statements. I don't know if anybody models on a monthly cash flow statement. I would just say if you run your model, you're probably going to come pretty close to where we are as far as you're plugging the price, you're plugging the EBITDA. You've got what our CapEx is. You sort of know where we are now. The business is slowing down. You can get through probably a pretty good number. You will certainly get to a number on the line if it was drawn at the end of the year of certainly way under 600.

Okay. And would there be any taxes paid on the East Texas sale?

No.

Great. On the Frog Creek, can you just talk about how you are thinking about additional drilling there over the next couple of quarters and how you think about prioritizing the various Piñon thrusts and wells throughout each one?

Sure. It was important for us to drill through the Frog Creek, because we continue to want to explore for the Warwick, which is our most prolific reservoir. However, now we've tested a few Frog Creek wells. We are now comfortable to go to some rigs just drilling for the Frog Creek. And keep in mind it doesn't take very many rigs to drill wells there, because of how shallow the zone is. So right now, we do have one rig that is getting ready to start drilling at Frog Creek. What we have to offset is it's better to have a wellbore that drills to 7,500 feet and combines the two reservoirs or is it better to have one reservoir that's shallow. And we know we can produce it, because it's sweet. And even if the Warwick produces 10% or 15% CO2, we can't produce it. So that's the kind of things we wrestle with is where is the best use of our capital. And once we get the Century Plant on, that will all change, because we can drill every well and determine whether it goes through the plant or doesn't. So the CapEx allocation during 2009 is going to be a little bit dicey just because we are very restricted on our CO2. I hope that's helpful.

It is. Thank you.

You bet.

(Operator Instructions). Your next question comes from the line of David Heikkinen with Tudor, Pickering. Please proceed.

I'm always going to be Heineken.

It might not be a bad thing.

I might need one tonight. Just thinking about the Century Plant commitments, how much capital do you need to invest between now and the middle of 2010 to meet the commitments?

Dave, I think you are asking how many wells we are --.

Drilling, yes, exactly. Number of wells there, that would be perfect.

For '09, we'll start ramping up drilling for the high CO2 gas. We will ramp up from 4 rigs to about 11 rigs. 4 rigs starting out in January, it goes to 11 rigs drilling high CO2 gas. The first phase of the Century Plant is expected to start up in the second quarter of 2010. You're looking at about 75 wells there in '09. And then we have 400 million (inaudible) come in at the second quarter of 2011. So, between starting that up in 2010 and 2011, we are looking at about 75 to maybe 95 wells in 2009. It will be another 100 wells in 2010.

Okay.

That would be to keep all of our plant flat. All our capacity is running flat at any given time, plus ramping up for the second phase at Century.

And then once we fill the plant, it only requires us to keep six rigs running to maintain.

Okay.

And we have all of that in our model of drilling these wells in our CapEx and still growing at 20% in 2009.

Okay. Thinking about on the services side and your non-SandRidge-operated rigs, are you seeing any slowdown on the services side, any rigs being put back to you? What are your expectations for '09 for that business?

Well, we are obviously looking at our budget from an earlier guidance of $2 billion to $1 billion in '09. So, we are certainly rolling off our rigs. We will try to aggressively market our rigs out there. But --.

I think we are going to have some rigs that are sitting out.

Okay.

No doubt about that. And we see other people that are doing the same thing. I think it will be a very aggressive roll-off in this last quarter and going into next year as people start to adjust their budgets.

The news I have heard is it's anywhere from 300 to 800 rigs being rolled off in '09.

Just trying to think about how you guys are going to market or do they just sit on the sideline just from kind of a broader picture of West Texas competitive nature and not just West Texas, but where those rigs are?

If oil prices were to increase, we would try to be competitive. But we are not the best people to hire out as our focus is on our own stuff.

I know.

I think that you could just assume we will have rigs sitting out.

Okay. Thank you.

And to put some numbers on it, David, that business probably does everything we do out there. It does about $36 million of EBITDA for us in 2008. So from a cash flow standpoint, while it's important strategically, since we use so many of rigs ourselves, from an EBITDA standpoint, we probably won't be losing too much.

Yes, not a big hit to SandRidge, just more of an industry thought. Thank you, guys.

Thank you.

And your next question comes from the line of Dave Kistler with Simmons & Company. Please proceed. Dave Kistler - Simmons & Company: Good morning, guys. I am thinking a little bit more about kind of vertical integration within SandRidge and services. As we see rig count potentially fall off here and likely fall off pretty dramatically and corresponding services costs fall off, how are you guys thinking about as more vertically integrated company than some of your peers, what cost savings will look like?

Well, on the vertical integration part of it, we only look at it from our side as a savings and finding cost. And we model $0.06 to $0.10 an Mcf for finding cost savings by having our own services. It's really, from the way I look at services internally, is that it's a good thing to have our own rigs out in one place where we are working in one field, because we have our own employees working on our own locations. I don't see much of a change with that, because we will continue to do. But where we see our savings is on the things that don't have of our own pipe, and we are seeing pipe costs come off really dramatically now. We are seeing pumping costs come off fairly dramatically. In places that we do have outside rigs, such as East Texas, I think we are seeing the day rates come off there.

I think being vertically integrated, we do have the most savings as one processor in a high-cost environment, not in a low-cost environment. So I think as rigs get rolled off, everybody is going to benefit on the cost side. Steel costs are going down. Diesel costs are going down. Stimulation costs will go down. Dave Kistler - Simmons & Company: I guess the way I'm thinking about it is more specifically from the standpoint of, because a portion of your business is vertically integrated, you will get the same cost savings as other folks, obviously, as you guys have outlined. But as we try to model out, if we see costs slipping in, say, 20%, based on a portion of your business, it's first vertically integrated, which won't see as much of that, what would be kind of ratio of service costs coming off versus what you guys would likely recognize as far as costs coming off? Am I making myself clear on that?

I mean from my standpoint, the guidance is out there. We haven't modeled any savings in. Could we get something, I mean pressure pumping or something like that?

Yes, I think pressure pumping will continue to go down. That's a big part of our cost component on the drilling and completion side. And steel cost and diesel costs, we have about 800 gallons a day of diesel. So, I think there will be additional savings for us. When we go to a $1 billion budget and kind of estimate how many wells that's going to be and how much that's going to cost, that's just really based on historical cost analysis. We haven't factored in what savings we might get, and we get both on our rigs with a roll off.

And then the other savings will be on the oil field services side which we have a wholesale in. As we drive hundreds of trucks and have our own rigs, there are savings on their side also, just from the pricing standpoint. And if the labor prices go down, they will benefit from that also. I think there are potential savings we just don't model in. Dave Kistler - Simmons & Company: Okay, great. I appreciate that. And then stepping over to F&D a little bit, that's crept up over the last quarter. And just trying to understand the base drivers of that. One would look at the results there, at least be the type curve and the [RORs] and F&D is implied from the Warwick thrust wells. Over time, it looks like that will trend down. But as (inaudible) Warwick thrust and going after these wells probably won't be as aggressive as you can be in the future, can you talk about over the next year or two where you guys see F&D going and just what was the majority driver of it popping up this quarter?

Absolutely. We drill statistical wells. So, basically every well we drill in the Piñon field is productive. Some wells are better than others. And you will see fluctuations quarter-to-quarter statistically. And that's why we put out a type curve that goes back to 1984 that shows every well that's basically been drilled in the Piñon field. And if we do no worse than the average or that type curve, we will be under $1.70. And so, we run our model at $1.70 finding cost. And therefore, if we beat that in any way, we will come in under our model. So, I think that that's the best way to look at it is just to assume we're going to find $1.70 finding costs.

Just from a numbers standpoint, through the six months, we were at just drilling only $1.43. And for the nine months, we were at $1.49. So, it's up a little bit, but I wouldn't call it dramatic. I think similar to what you saw in there from the all-in cost is we had a couple of land acquisitions in there which clearly, as Tom mentioned, those are going away. So --.

Again, to hit on it, there is nothing really changing. Some quarters will be higher and others will be lower. Dave Kistler - Simmons & Company: Great. That's very helpful. Thanks so much for the clarification, guys.

Thank you.

Your next question comes from the line of Sylvia Chan with Wells Fargo Bank. Please proceed.

Good morning, gentlemen. A quick question on your hedge portfolio right now. The last two months, looking at the natural gas strip price has been in the low 8s and probably 7 from a certain period. I'm wondering how are you guys able to lock in the $8.88 and also any particular provisions to hedges such as lockout and if can you kind of review through the number of counterparties you guys had in the hedge facility.

I'll take the first part and let Dirk talk about the counterparties. Our hedge position, we were fortunate to start with a high 19% and over $10. So, I think the way we have averaged down instead of $8.88 is we started with a high number, and then we, each quarter or each month, tried to hedge whenever there is a movement in price. So, upside rather than the downside. It's really we're just fortunate to be where we are and have been aggressively hedging in the last three months. So, I don't think there is anything. And I can tell that you there is nothing other than straight swaps. We don't have any knockouts. We have done nothing to maneuver the prices higher. So, all of our transactions are straight swaps.

Sylvia, for 2009, we have 11 counterparties. Nobody has more than 25% of our swaps. We don't own our bank group. And because of that, we don't have to post collateral on any of those swaps. So, it's a pretty clean program. And we really sort of look at it as if that gas has been sold. The other thing is we're not looking to trade that position either.

Great.

We really want to protect our cash flow. And that's sort of the way that we look at it. So it's a pretty clean way of doing the business. We also have basis in as well.

Thank you.

And your next question is a follow-up question from the line of Scott Hanold with RBC Capital Markets.

Hey, one quick question for you. If you look at the current presentation that you posted yesterday and compare it to, I guess, the prior one you had out there, looking at the high CO2 gas pricing capacity, it looks like it's been expanded from your prior update. Can you give us a little bit of color on that?

I'll let Matt here. Everyday, we try to find a way to expand.

If you look at the overall number, I think we brought up from 1.1 billion to 1.15 billion a day. And really that 50 million of incremental is what we think we can squeeze out of our two legacy plants that we own now. And we're going to work with Anadarko on the Mitchell plant to maybe squeeze a little more out of their Mitchell plant. We're hoping for that to happen in Q1 where you see we're going from our yearend of 300 to Q1 '09 of 350. That's where the additional capacity is going to come from.

And, Scott, looking at the slide, that assumes that we can't grow; our other production just stays flat. I haven't hit on that, but in the past we've been able to grow it at very high rates on our overall production. So, I think this should be a very conservative case.

Okay. Okay. Got it. This is somewhat optimization of your existing plants.

Also, we're trying to show what happens when the Century Plant comes on if we do not grow our existing production from today.

Yes, the incremental [treating] is optimization of existing plants.

Okay. Thank you.

Thank you.

We're showing no more questions in queue at this time. I would like to turn the call over for closing remarks.

No closing remarks here. We just appreciate everybody being on. Thank you.

Thank you for your portion in today's conference. This concludes our presentation. You may now disconnect. Have a good day.