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Executives

Tom Ward – CEO

Dirk Van Doren – EVP & CFO

Matt Grubb – EVP & COO

Analysts

Scott Hanold - RBC Capital Markets

Brian Singer - Goldman Sachs

Eric Johnson – Silverlake

Dave Kistler - Simmons & Company

Eli Cantor – Pritchard Capital Partners

Jeff Robertson – Barclays Capital

[Matthew Lemy] – Highland Capital Management

David Heikkinen - Tudor, Pickering

Joe Allman - JPMorgan

Ellen Hannan – Weeden

SandRidge Energy, Inc. (SD) Q4 2008 Earnings Call February 27, 2009 9:00 AM ET

Operator

Good day ladies and gentlemen, and welcome to the Q4 and year-end 2008 SandRidge Energy earnings call. (Operator Instructions)

Last night, the company issued a press release detailing SandRidge's financial and operating performance for the fourth quarter of 2008 and year-end, and it also filed the 10-K.

If you do not have a copy of the release, you can find a copy on the company's website, www.sandridgeenergy.com. Also, you can sign up for all releases that will automatically be sent to you, and this is located under the Investor Relations tab.

Now, for our forward-looking statements, please keep in mind that during today's call, the company will be making 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.

I would now like to turn the conference over Chairman and CEO, Tom Ward.

Tom Ward

Welcome to our fourth quarter earnings conference call. We have in our office today Dirk Van Doren, CFO, and Matt Grubb, Chief Operating Officer. Once again SandRidge had delivered outstanding results. Our 2008 adjusted EBITDA increased 74% to $688 million. Production increased 58%. Our reserves increased by 42% and our adjusted net income was $151 million before the noncash asset impairment of $1.6 billion.

Operationally we cut our drilling from a high of 47 rigs at midyear 2008 to 13 at the year-end. We now have eight rigs working and plan on going to seven rigs in March. We have given our 2009 CapEx guidance of $500 million to $700 million and production in the range of 110 Bcfe to 120 Bcfe.

As we mentioned when we issued the preferred stock in January, we would only expand our budget to the $700 million level if prices improved and we sold our Pinon midstream assets. Since January oil and natural gas prices have continued to deteriorate therefore we are currently running at a rig level that more closely reflects the low end of our $500 million to $700 million CapEx range for 2009.

We are continuing to negotiate the sale of our Pinon midstream assets with the goal of making a deal in the second quarter. Our budget for 2009 will only expand to the high end of the CapEx range if we see a material improvement in commodity prices.

Even at the low end of our budget we will expect to field the Century Plant phase 1 in 2010. We have a proven track record of delivering consistent production and reserve growth through the drill bit developing multiple reservoirs in the West Texas Overthrust. Production performance data from nearly 150 wells shows that the Warwick thrust is one of the best natural gas reservoirs in the US.

The Warwick thrust continues to expand both from a per well reserve standpoint as well as the reservoir size. This world-class reservoir at approximately 6500 feet produces on average over 7.5 Bcf per well. This is up from 7 Bcf per well that we booked last year. In fact the expansion area to the south shows that our last 17 wells produced over 10.5 Bcf per well.

We cannot produce this zone to its full potential until we complete our Century Plant because of the high amount of carbon dioxide in the gas stream. This reservoir would have been produced decades ago if not for the inability to treat large amounts of CO2. However because of our joint venture with Occidental Petroleum we are now going to be able to fully develop the Warwick thrust within the Pinon field and produce up to 1.1 Bcf a day of total gas from this reservoir starting in 2011.

This will yield about 290 million a day of net methane to SandRidge from the Warwick thrust alone. This is a tremendous amount of gas to come from one field that no one had heard about two years ago and that only one company SandRidge, has the right to more then 95% of the leasehold.

Our next challenge is to continue to explore across our nearly 700,000 net acres of land to see if there can be any other accumulations like the Pinon field. We mentioned today that we have completed our third exploratory well outside of Pinon. The Big Canyon 121-1A is our third well we have tested in the West Texas Overthrust outside of the Pinon field and is located about 25 miles east of Pinon.

All three of these 2008 exploration wells were drilled without the benefit of a continuous seismic data that we have now have across the West Texas Overthrust. In fact we would not have drilled the first two tests after knowing what we know today from our seismic interpretation. The Big Canyon encountered over 500 feet of [pay] from the same zone as what produces in Pinon. This [pay] was approximately the same thickness as our good well from the Pinon field. Our well did not encounter the fracturing that is associated with [prolific] producers in Pinon field.

While the Big Canyon did not test at commercial rates, the gas was sweet with on a trace amounts of CO2 and we’re very encouraged to find [pay] in the Warwick thrust this far away from Pinon field and also encouraged with the progress we’re making with our 3-D seismic work.

We also drilled two vertical wells in the East Texas that penetrated the Haynesville shale section and have tested one. The vertical well that was tested produced an initial rate of 1.5 million a day and encountered 260 feet of Haynesville shale. The second well involved 288 feel of Haynesville shale. These two tests are in the area of very good Cotton Valley production in the Oakhill field in Rusk County, Texas.

We know by offset [log] correlation that we can achieve over 300 feet of thickness by moving into our blocker field acreage where the majority of our HPP acreage is held. Our own drilling results along with the recent discoveries by Penn Virginia, XTO, and others have further substantiated that our East Texas Haynesville acreage holds tremendous value.

In Northern Louisiana we have more then 13,000 acres of Haynesville potential and currently have one well drilling in which we have an non operated working interest. Therefore we should know very soon how the potential of this acreage is for Haynesville development. We are not shale experts but we feel very fortunate to have over 36,000 net acres in this Haynesville play.

Our Haynesville position combined with the Warwick trust make us the only company to have a large exposure to two of the potentially the best natural gas plays in the US. In response to the unprecedented volatility in 2008 we’ve strengthened our balance sheet by substantially reducing our CapEx budget, hedged the majority of our gas for 2009 and 2010, issued preferred stock, and initiated a sell process for our WTO midstream assets.

Our 2009 gas hedge book is now 85% of our low end guidance. Our 2010 natural gas hedges are nearly identical to 2009. Our goal during the last quarter of 2008 was to ensure that we had the ability to sell gas at a profit during a period of low energy prices. We have accomplished this by our natural gas hedges and being at $8.42 in 2009 and $7.70 in 2010.

We have chosen at this time to remain unhedged in 2011 as we expect supply to decrease as more rates continue to roll off and demand to increase. These steps that we have taken make us feel comfortable as we move through 2009 and into 2010 when we look forward to starting a new phase in the life of this company with the opening of the Century Plant.

I’ll now turn the call over to Dirk.

Dirk Van Doren

Thanks Tom, I will focus on a few financial highlights, our current financial position, and our projections. The key things we look at for year end are production operating costs, EBITDA and debt position and are pleased that we achieved our previously stated guidance. Production was up 58% year over year while costs were within our guidance.

Adjusted EBITDA was $158 million for the fourth quarter and in line with our guidance and internal model. Our quarterly capital expenditures were $568 million and we ended the year with $2.375 billion of debt, exactly where we had previously guided. We were in compliance with all financial covenants at the end of December.

For 2009 as Tom just mentioned, the financial mission is to create financial flexibility for the next two years via hedging to protect cash flow, some capital raises, the preferred was completed in January, asset sales, and to reduce leverage. As illustrated in our press release our current hedge position for 2009 is 85% of our natural gas and 73% of total company production at 859 per Mcfe.

For 2010 we have 80 Bcf hedged at 770 per Mcfe. At year end our hedges were worth $247 million and using the strip today, the value is $392 million and January and February are now closed out. This is important when considering the current PV-10 and our current asset value. Our current PV-10 which includes hedges and uses the commodity strip price is $4.33 billion versus the PV-10 used in the 10-K of 2.259. Thus in terms of financial flexibility our initial discussions with our banks has been extremely positive and we do not see any change in our borrowing base. In fact we believe we’ll be adding a few new banks to our group in April.

Our hedges are combined with the value of the midstream business and the value of our Haynesville [deep] rights are worth over $900 million and provides additional financial flexibility for the company. Let’s look at our guidance that was presented in the press release. As everyone knows the current financial and economic environment has presented challenges for everyone and this is reflected in commodity prices.

Given the uncertainty in commodity prices as Tom mentioned we are presenting a range of capital expenditures for 2009 and right now we’re looking at the lower end of the range in CapEx. In terms of capital we raised $244 million net to the company in preferred stock and look towards a midstream transaction with a goal of closing in the second quarter.

We hope to reduce debt by over $200 million by the end of 2009. Our second annual investor analyst meeting will take place in New York on Tuesday, March 3 at 8 AM at the Grand Hyatt and we plan on reporting first quarter results on May 7. As for conferences for March, it’s a busy month. We’ll be at the Simmons Energy Conference on Thursday, March 5 in Las Vegas, Howard [Wheel] in New Orleans on March 23 and 24, and the Barclays Fixed Income Energy Conference on March 25 in New York.

That ends our prepared remarks, we are open to take questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Scott Hanold - RBC Capital Markets

Scott Hanold - RBC Capital Markets

Could you remind me and I think you’ve addressed it before but given the change in the spending plans, and the flexibility, looking at the Century pipeline, when that does get up and running, are you going to have volumes that are going to be ready to flow on that to increase your net production, are you going to start to drill into that as we get closer, how should we look at that.

Tom Ward

We will start in 2010, actually in the last half of 2009 we start adding to the volumes that will fuel Century in 2010, but the majority of the ramp up is in the first half of 2010.

Scott Hanold - RBC Capital Markets

And so you will be actively drilling high CO2 wells to prepare for that coming on line, is that sort of the thought process here.

Tom Ward

Its most of the wells that we drill, in fact six out of the eight rigs we have working today are in the high CO2 area.

Scott Hanold - RBC Capital Markets

On the Big Canyon well, with the fact that I guess its not fractured, like you see in parts of the Pinon, is that something you can identify with seismic or when you say if you would have had the seismic you may not have drilled certain wells. What aspects do you see there that help direct where and how you drill.

Tom Ward

We actually, I can explain that a couple of ways, inside the Pinon field itself we have wells that aren’t fractured very well. So its not that unusual even though we have wells that average 7.5 Bcf per well. We have four wells and then we have very good wells and this well on a log characteristic looks like it would be a well in the Pinon field however it did not have access to fracturing. That doesn’t mean that you couldn’t drill another well in this same field and have fracturing within it.

It gives us a lot of hope in that aspect to answer your first question, as no you can’t tell off seismic whether you’re going to have fracturing or not. You can see where you are in relationship to faults and you can tell whether you have the zone in place or not but even down to trying to depict whether you have fracturing in a well, we can’t do that.

Scott Hanold - RBC Capital Markets

So what aspect on seismic do you see that will help direct your drilling going forward.

Tom Ward

What we see is that in large areas we feel now we know what the Warwick thrust looks like or even the Dugout Creek and the Frog Creek and you can put yourself in areas that you can encounter the Caballos chert that produce in formation and then you still have a risk of whether you have fracturing or not in the well board but in Pinon field for example we have statistically once you find gas you find it over a large area and that’s what we continue to believe here.

Operator

Your next question comes from the line of Brian Singer - Goldman Sachs

Brian Singer - Goldman Sachs

When you look across 2009 and 2010 what do you see as the minimum number of rigs and investment needed to meet the Occi contract and I guess based on where gas prices go how do you think about the timing and ability to drill more or fewer of the lower CO2 wells.

Tom Ward

I’ll let Matt hit on the exact numbers, I know that we plan on being able to meet the Occi commitment just with the $500 million that we’ll spend in 2009.

Matt Grubb

I can’t talk specifically but the Occi commitment year by year, I can tell you that right now we have 350 million a day of treating capacity in our legacy plants and our plants are virtually running at capacity. And that generates enough CO2 to meet the first year Occi contract in 2010. So it doesn’t take a lot of rigs, basically we’re going to drill approximately 55 wells this year and that’s based on our [inaudible] million, part of our [inaudible] million in our budget as Tom said, six rigs running at WTO drilling the Warwick thrust. That’s about 55 wells and about 35 of those wells are to keep the legacy, the existing plants loaded.

Another 20 wells are to build towards filling the Century phase one as it comes online in Q2 2010. So its kind of a short answer to your question is we have more then wells planned to meet the Occi contract plus starting to fill up Century.

Tom Ward

And I’d say right now we’re not budgeting a different budget from 2010 then we do in 2009 until we see an increase in pricing.

Brian Singer - Goldman Sachs

Would you generally think you’ll need the same level of commitment in terms of dollars in 2010 to be able to source the plants relative to 2009 or is there a disproportionate amount of spending in 2009.

Tom Ward

No I think right now as we look and model we’ll say that we’ll keep the same budget, we just model the same budget in 2010 as we do in 2009, $500 to $700 million range.

Brian Singer - Goldman Sachs

And where is the CO2 going now from the wells that are producing.

Matt Grubb

The CO2 is going over to the permiam basin for tertiary.

Brian Singer - Goldman Sachs

What are you seeing in terms of price realizations and you’re mostly hedged on the [basis] side but how do you think about based on your unhedged both [Henry hub] and basis, what are you thinking about those volumes depending on where gas prices go.

Tom Ward

As far as basis?

Brian Singer - Goldman Sachs

Both basis and Henry hub, what are you seeing in terms of overall realizations given that it seems that Henry hub prices have come down in basis and West Texas and is there some point at which you would further restrict your unhedged production.

Tom Ward

I think right now we’re comfortable with the 110 basin being [night] and being 85% hedged. Overall we model $0.70 on basis for the company. I think that’s been a fair amount because of our hedges. We’ve even hedged basis now out into 2011 so that is an area that we watch very closely and want to make sure that we hit on model. We try very hard whenever we have swaps on to match those with basis so I think in looking at our production you could stick with that $0.70 to $0.75 basis number overall for the company.

Operator

Your next question comes from the line of Eric Johnson – Silverlake

Eric Johnson – Silverlake

First I want to congratulate you on getting the convert done and really making steps to sure up the balance sheet in what’s been arguably, be deemed as one of the worst markets we’ve certainly ever experienced. I know its been a tough road. Talking more about the balance sheet though, given plan of call it $600 million spend this year, where do you anticipate the total debt to be year end.

Dirk Van Doren

In my discussion I said it would be down $200 million. I think when you, we’ll post the slides to the investor analyst day on Tuesday morning, at the bright hour of 4 AM your time, we’ll have the full model up and it shows it down north of $200 million by the end of the year.

Eric Johnson – Silverlake

So it will be, where do you stand right now given the preferred.

Dirk Van Doren

As far as what?

Eric Johnson – Silverlake

Total debt.

Dirk Van Doren

Total debt, I don’t really think of it that way, let me just, I think of it as bank debt and the rest of the debt, total debt right now is standing at, basically 2350, a little bit less then where we ended at year end. Right now we’re really tracking exactly where we thought we’d be. Really taking a closer look at the balance sheet and what most PMP companies have been faced with and the slowdown is that working capital is coming out of the business. If you look at the balance sheet on page F4 of the 10-K, you’ll see that our accounts payable at the end of 2008 was up $150 million relative to 2007 and essentially that money has come out of the business in the first two months of the year.

So we’re basically a little bit less then where we were year end but we expect to be down probably another $200 million from here.

Eric Johnson – Silverlake

And you anticipate the borrowing base to go up just have no clue of what you’re looking at—

Dirk Van Doren

No I think the borrowing base stays the same. I think in this environment asking for a borrowing base increase, I guess its, one company I’m aware of has did it in December but I don’t think a lot of companies are asking for that. I think internally what we’ve modeled and what we’ve assumed is that the borrowing base stays flat. Rodney and his guys have done a lot of work on that and has worked a lot with our lead bank to make sure we understand exactly how they look at things and we’ve been pretty comfortable with the PV-10 value being north of 4 billion and our initial discussions with them, it looks like its going to be flat.

Plus we’re adding some banks too so we shouldn’t have a problem with that.

Eric Johnson – Silverlake

Is that a semiannual redetermination or annual.

Dirk Van Doren

Yes, I mean it will be April and September this year.

Eric Johnson – Silverlake

Just regarding the picks, 858’s, remind can you only pick that for two years, is that—

Dirk Van Doren

You can pick it for four years, there’s only two years left. So we didn’t pick it for the first two so we could pick it, the October payment of 2009, the two payments in 2010, and the April in 2011. Just so we’re clear, we have to tell the trustee five business days before the beginning of the pay period what we plan to do so that would be sometime in late March, and you can go back and forth so you could pick one time and not pick another time and as we’ve said, that’s a Board decision and we’ll be making that here in the next couple of weeks.

Operator

Your next question comes from the line of Dave Kistler - Simmons & Company

Dave Kistler - Simmons & Company

Real quickly thinking about the ceiling test impairment can you give us some color on different gas prices and what that would have done to the impairment given the kind of a one time static issue.

Matt Grubb

As part of the ceiling test impairment at the year end we ran reserves of the gas prices 571 and we had a write-down, we ran another case with the year end reserves in February here at the strip which start out at about $4.00 and with our, given credit to our hedges and let the strip run out, we would not have had a ceiling test impairment so really that tells you how close it is between having an impairment and not having an impairment.

Dave Kistler - Simmons & Company

Then with your $500 million CapEx when we look at that as the low end of guidance does that incorporate any service cost declines since you last updated CapEx or even since you—

Matt Grubb

Service cost has declined, just to give you an example, the $500 million CapEx this year primarily we will be drilling the Warwick [Tobias] wells in Pinon. Right now we have six of the eight rigs running in that reservoir and just to give you a perspective on drilling costs, that’s just drilling completion costs, in Q3 of 2008 these wells were costing $3.3 million to drill and complete and today we’re running at $2.8 million so they’ll drop off quite a bit.

Dave Kistler - Simmons & Company

Was that factored in though into your $500 million.

Matt Grubb

Yes, that’s factored into our budget.

Dave Kistler - Simmons & Company

And then with respect to the exploratory well, as you think about other wells that you’re going to drill now that you have the 3-D, will you step away from that well or given what you found and what you saw on the log and trying to understand if there are pockets that are fractured around there, will you drill in closer proximity to kind of get a better handle on it, I’m just trying to understand your thinking of where next—

Tom Ward

We feel like we are very close to a reservoir there that could be productive and be economic however we have also multiple areas across a 700,000 acres of [contiguous] acreage plots that we can test so one of the challenges for the company obviously is in a $500 million CapEx we don’t have anything budgeted for exploratory wells. So the good thing is is that we have long-term leases and a large acreage plot put together and we’ll have to wait until we have a more robust budget to move out and drill a lot of exploratory wells. So yes, we feel like we’re very close to having production here.

Keep in mind there are other fields that produce sweet gas to the east of the Pinon field. They just haven’t been explored and with as many wells as Pinon has. So we’re confident that we can find gas out across the West Texas Overthrust however we do need a larger budget to have that exploration activity.

Operator

Your next question comes from the line of Eli Cantor – Pritchard Capital Partners

Eli Cantor – Pritchard Capital Partners

In terms of drilling activity in Pinon for this year, what’s sort of the rough percentage breakdown between drilling the Warwick Dugout and Frog Creek, is it pretty much 100% Warwick.

Tom Ward

Yes, basically in the budget model we have moving forward until we move into the Century Plant we’re focused on the Warwick. And that’s the area of best [funding] cost.

Eli Cantor – Pritchard Capital Partners

At the beginning of the call I think I heard you mention that planned to potentially monetize the midstream West Texas Overthrust assets and the Haynesville deep rights for about $900 million, is that right, and if it is does that essentially mean you’re putting a $400 million value on the Haynesville deep rights.

Dirk Van Doren

No, I think my comment was our hedges plus the midstream plus the Haynesville if the hedges are worth 392, and the what we said in the press release is that the midstream could be worth 500 between what the proceeds we get in and the CapEx that this person would cover that would leave $8 million left and I said 900 plus. So we’ve left that sort of vague.

Tom Ward

And I think what we’re trying to say is that we have some flexibility in moving forward throughout the year with different options to look at as we move forward that we do have some financial flexibility especially with this lower CapEx budget.

Eli Cantor – Pritchard Capital Partners

You have mentioned in the past that you need to drill a minimum of 46 high CO2 wells this year, 64 next year to meet the Century commitment, does that sort of stay flat in 2011 and thereafter or does that minimum well count continue to increase.

Matt Grubb

Yes, 2011 is way up there, but if you’re thinking of a, we’re thinking of having a total high CO2 treating capacity of 1.15 billion cubic feet of gas a day, to keep that flat, you’re probably going to need to run seven or eight rigs and complete these wells, basically call it one well per rig per month something like that.

Operator

Your next question comes from the line of Jeff Robertson – Barclays Capital

Jeff Robertson – Barclays Capital

Just to follow-up on your comments around Big Canyon, did you all have 3-D seismic before you drilled that well when you picked the location.

Tom Ward

We did have, it was in the, what we didn’t have was the connection to the Pinon field. Keep in mind that just in July we had the 3-D that came over the Pinon field and after that we have now connected across to the Big Canyon. So the different phases that we’ve had, or stages from stage one to stage I think we have four or five different stages of seismic that go across to the Big Canyon and just now in fact aren’t even through looking at those as they connect together so you can see the Warwick thrust moving from one area to the next.

While we knew that we could get up dip to the original well that was drilled to the south of us, we didn’t know how that would connect across to the main field of Pinon and how you can see at different areas including this where we believe we can get into the Warwick thrust or the Dugout Creek for that matter and Frog Creek and have potential areas to explore.

Jeff Robertson – Barclays Capital

Can you take the data that you have at Warwick and Dugout Creek and what you think you’re seeing in terms of fracturing and use that as you look at these other fault blocks to help pick structural locations where you have a higher chance of getting into fractures that you need to make reservoir.

Tom Ward

Yes, what we’ll obviously drilling test wells is imperative. And so as you move across we’ll, what we plan to do is to drill a number of wells across a number of areas but we can see structure and we’re seeing sweet gas so yes, I think that we will be able to high grade and the more wells that we drill will give us the keys to tying back into the Pinon field.

We have some very good data today that we didn’t have six months ago and that we hadn’t interpreted three months ago. We continue to have 50 geo scientists that work only on the areas outside of the Pinon field.

Jeff Robertson – Barclays Capital

On East Texas, are the two vertical wells that you all drilled in East Texas are those the only wells that you’ve planned right now.

Tom Ward

Yes, our acreage is held by production and we don’t have anything in our current budget for horizontal.

Jeff Robertson – Barclays Capital

Was your goal there just to help define the thickness of the shale and things like that to help the people understand what you may have.

Tom Ward

That’s correct. Help us understand, yes.

Operator

Your next question comes from the line of [Matthew Lemy] – Highland Capital Management

[Matthew Lemy] – Highland Capital Management

On the 2009 forecast here, the guidance, can you give me a little bit more detail breakdown on your LOE, the 180 to 193.

Matt Grubb

Our LOE the strict LOE runs about $1.00 in Mcf and that includes offshore operations and tertiary. That drives it up a little bit, without those you’re probably down to $0.70 range. So if you take that dollar in Mcf and then you have about a $0.11 or so for transportation and miscellaneous related fees, processing and gathering, in the mid 30’s, low 30’s, $0.30 to $0.35, another $0.10 or so on [inaudible] taxes and then say $0.30 from production taxes, that gets you up to $1.87 for Mcfe.

[Matthew Lemy] – Highland Capital Management

If you could just elaborate, I know someone had asked earlier about basis but if you could just elaborate a little bit more on where you think West Texas basis is going over the next say 12 to 18 months outside of your hedge position, just talking in general, given how much gas is coming on in points east.

Tom Ward

The only thing I know is you can hedge basis today for under $0.80 so I suppose the market is a lot smarter then I am. We tend to try to take those hedges at [Waha] whenever they are $0.75 or so to meet our model and that’s what we’ve done in the past. Today I think the Cal 10 is right at $0.75 and Cal 11 is just under $0.80.

Operator

Your next question comes from the line of David Heikkinen - Tudor, Pickering

David Heikkinen - Tudor, Pickering

Thinking about your credit facility do you anticipate any amendments to the covenants under the new facility.

Dirk Van Doren

The covenants? No.

David Heikkinen - Tudor, Pickering

There 4.5 to 1 on EBITDA funded debt to EBITDA ratio, 2.5 to 1.

Dirk Van Doren

I guess I need to ask you a question, do you mean that the banks would be asking for or that we would be asking for.

David Heikkinen - Tudor, Pickering

Either way.

Dirk Van Doren

Neither.

David Heikkinen - Tudor, Pickering

On the lending 80% of the discounted present value, you talked about 4.4, 3 billion at the strip, that gets you pretty considerable upside to where your current facility is, are they lending less then 80% of current value.

Dirk Van Doren

I think there is a variety of calculations and while that 80% might be your rule of thumb there’s a variety of different things they are looking at. So do we have cushion? Yes, we have cushion right now. Would I say they’re lending less then that? I really don’t look at it that way. I just think that pretty much anybody wherever you are right now, is where you are given the environment we’re in. And if they get more cushion, they get more cushion.

But I think if you sit down and talk to them, they look at about 7 or 8 or 9 different calculations not only your way, they look at it relative to the line being fully drawn and all the other debt. They’ve got a lot of different ways to look at it. Does the PDP if its produced out cover just the bank debt if its fully drawn, there’s a variety of different calculations they run, just not your one number.

David Heikkinen - Tudor, Pickering

I was just looking through the K and just kind of ticking through and seeing if you were going, other companies have amended so, didn’t know if you would be requesting an amendment is the reason I was hitting those things.

Dirk Van Doren

We have no plans, we had discussions yesterday. We have no plans on asking for any—

David Heikkinen - Tudor, Pickering

Good to know, as you think about the operation side of the business you said basis, you kind of hit your growth rates, set up for 2010, 2011, how do you think about allocating capital, the $500 million, does that mean you don’t do anything in Oklahoma, don’t do the East Texas and basically honor your Pinon commitment, is that the way I should model it where other areas would decline and Pinon would just chug forward.

Tom Ward

If you look at a low CapEx case, yes.

David Heikkinen - Tudor, Pickering

And then given the well results in the Haynesville on the vertical test, that’s very analogous to what vertical tests have done when you’ve had pretty successful horizontals, anything that you see in your fields, additional faulting, any thinning, just trying to think about things that would cause that not to have a similar potential as you look at where your acreage is.

Tom Ward

We have a slide that shows we believe will be over 300 feet thick across the blocker area and so no, we don’t see any difference. I will say too, I’ll just address a little bit more on basis, that we have starting in Q4 of this year the ability to take about 40% of our gas from Pinon to [Katy] and we can do a substantial amount now but it increases to about 40% in Q4 2009.

Operator

Your next question comes from the line of Joe Allman - JPMorgan

Joe Allman - JPMorgan

I think you said you got six out of the eight rigs in Pinon, six of them running in the Warwick thrust, and then where are the other two, and it sounds like you’ve got one outside of Pinon.

Tom Ward

We have one still running in Cotton Valley and the [Minden] field in East Texas and we have one in Hector County, Texas in an oil play.

Joe Allman - JPMorgan

So am I correct, you’ve got six in Warwick, and where would the other one be running in Pinon.

Tom Ward

None, six in Warwick.

Joe Allman - JPMorgan

So you’ve got six in Pinon and that’s it.

Tom Ward

Yes.

Joe Allman - JPMorgan

Okay so eight rigs running now.

Tom Ward

Eight rigs now, going to seven in March.

Joe Allman - JPMorgan

The increase in the EURs with the Caballos wells, I guess that’s an internal estimate, could you talk about what you saw with your year end reserve report in terms of what the independent reservoir engineers gave you for Caballos wells.

Tom Ward

Caballos is, just to be clear, the Warwick thrust is where we’re talking about, and that is an outside reserve.

Matt Grubb

That 7.5 Bcf is an increase from 7, 7.5 and that’s a third party consulting increase, its not an internal increase.

Joe Allman - JPMorgan

And then with the reduced rig count here will that enable you to fill the Century Plant or will that enable you to meet the obligation with Occi, because I think in your previous budget it sounded like you were trying to give yourselves more of a cushion so that you’re not just meeting the obligation but you surpass that, could you address that.

Tom Ward

The way we talk about it now is that the $500 million this year, if you kept the same budget moving forward the $500 to $700 million in 2010 you’d need to be at the higher end at 2010 to fill, in either case we’ll meet our obligations.

Joe Allman - JPMorgan

So the new budget, basically the high CO2 production with the new budget, the production is roughly going to be the same as it was with the prior budget.

Tom Ward

Yes.

Joe Allman - JPMorgan

And then the midstream sale, so what is the status with the midstream sale.

Tom Ward

Same, we continue to have interested parties and it’s a very big midstream project so we’ll just continue to work through it.

Joe Allman - JPMorgan

How about with East Texas, I know you updated East Texas last time, but what’s the status of selling any East Texas assets.

Tom Ward

We have interest if we want to sell, things just continue to get better as people drill wells closer to our area and then we actually now have tested just to the south of our main area so I think that we use that as still just financial flexibility and in our opinion the Warwick thrust is a superior producing zone then any zone that we know of so if push came to shove we would prefer to have Warwick thrust wells then any other wells.

Right now we don’t have a deal to sell the deep rights, however there’s always a chance that we could if we need to do that.

Joe Allman - JPMorgan

Just going back to the question on the Warwick reserves raising the estimate to 7.5, so in your year end reserve report I know its an average, did you see some reserves booked at greater then 7.5 Bcf.

Tom Ward

Yes.

Matt Grubb

Yes.

Dirk Van Doren

Yes.

Tom Ward

That is the average across the field. Keep in mind that’s not in just a couple of wells, that’s 150.

Operator

Your next question comes from the line of Ellen Hannan – Weeden

Ellen Hannan – Weeden

On the Frog Creek thrust that you discuss in your press release here, is there anything booked in either your proved, probable or poss, or in your probable and possible categories for Frog Creek.

Tom Ward

Just very little. We tested it in just a few wells but if you look at our slide presentation and we’ll talk more about it next Tuesday, but the Frog Creek thrust, the main portion of the thrust is south of where we’re currently developing the Warwick and the Pinon field. So we think the largest upside is yet to be encountered. Its just encouraging that we had the wells we’ve tested are good wells.

Ellen Hannan – Weeden

And you think that you could bring that in at in your lowest finding costs really of anything that you’re doing.

Tom Ward

We don’t know what an average well would be and we don’t know that it would have the same exponential type curve as the Warwick, so I can’t really answer that but I’d say it is shallower and so theoretically you could and getting the Frog Creek thrust isn’t even in our 3P reserves. I’ll just mention too it is sweet gas.

Ellen Hannan – Weeden

Would that be considered exploration and then you really have nothing budgeted for exploration in your CapEx for 2009.

Tom Ward

That is correct. And as you look at the slides I think its on our website now, but it will be updated on Tuesday, you’ll see that the main area of Frog Creek exploration is to the south of Pinon field so it is outside of the field.

Operator

Your next question is a follow-up from the line of David Heikkinen - Tudor, Pickering

David Heikkinen - Tudor, Pickering

Just one comment and question, around the Century Plant and just trying to understand one thing, Occi gets all of the CO2 that is produced, you get all of the methane, you pay royalties on the methane to your royalty holders, Occi doesn’t, just reading through it doesn’t look like they pay anything other then getting all of it, how is that royalty or value of CO2 thought about.

Tom Ward

Its thought about as a waste product as you produce the methane the royalty is all embedded in the methane sales. So in other words you can’t produce the sellable gas without having CO2 be extracted from it.

David Heikkinen - Tudor, Pickering

So the capital Occi is investing is basically allowing you to produce the methane, so you’re in the position where—

Tom Ward

Its not producible if you don’t have that plant.

David Heikkinen - Tudor, Pickering

And that’s why you’re constrained today. Okay thanks.

Operator

There are no additional questions at this time; I would like to turn it back over to management for any additional or closing comments.

Tom Ward

Thank you very much, we look forward to seeing anyone who can make it on Tuesday to our analyst and investor meeting. Thanks again.

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Source: SandRidge Energy, Inc. Q4 2008 Earnings Call Transcript
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