SandRidge Energy, Inc. Q4 2009 Earnings Call Transcript

| About: SandRidge Energy, (SD)

SandRidge Energy, Inc. (NYSE:SD)

Q4 2009 Earnings Call Transcript

February 26, 2010 9:00 am ET

Executives

Dirk Van Doren – EVP and CFO

Tom Ward – Chairman, CEO and President

Matt Grubb – EVP and COO

Rodney Johnson – EVP, Reservoir Engineering

Analysts

David Heikkinen – Tudor Pickering Holt

Dave Kistler – Simmons & Company

Brian Singer – Goldman Sachs

Joe Allman – JPMorgan

Eric Anderson – Hartford Financial

Wei Dow [ph] – Stone Harbor

Jeff Robertson – Barclays Capital

Brian Kuzma – Weiss Multi-Strategy

Andy Rob [ph] – SPR

Philip Dodge – Tuohy Brothers Investment

Gregg Brody – JPMorgan

Operator

Good day ladies and gentlemen, and welcome to the fourth quarter 2009 SandRidge Energy earnings conference call. My name is Jeanette, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. (Operator instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr. Dirk Van Doren, Chief Financial Officer. Please proceed.

Dirk Van Doren

Thank you, Jeanette. Good morning. Last night, the company issued a press release detailing SandRidge's financial and operating performance for the fourth quarter of 2009 and we will file a 10-K on Monday. If you do not have a copy of the release, you can find a copy on the company's Web site, www.sandridgeenergy.com.

Now for our forward-looking statement; 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, adjusted EBITDA, and other non-GAAP financial measures. As required by the SEC rules, a reconciliation to the most directly comparable GAAP measures are available on our Web site under the ‘Investor Relations’ tab.

Now let me turn the call over to our Chairman and CEO, Tom Ward.

Tom Ward

Thanks Dirk. SandRidge remains flexible in our plans and has demonstrated that we can move quickly and efficiently to execute ideas that will enhance the long-term value of the company. This is evident by the Forest Permian acquisition that we closed prior to year-end.

As natural gas prices remained soft in 2009, we decided to re-risk our portfolio by lessening our exposure to natural gas and increasing our position in oil. We are today a company that is over 50% oil on a PV-10 value basis and have hedges in place to deliver $9.15 per Mcfe for 80% of our 2010 production.

We are poised to move forward with a model that provides growth through a diversified portfolio of both oil and gas opportunities in areas of proven production, utilizing conventional drilling and completion procedures that keep our long-term cost structure low.

We’ve also locked in over $1.1 billion of oil revenue from the sale of oil through 2012, and currently have six rigs running in the Permian Basin focusing on the Clear Fork formation but also developing low risk San Andres and Spraberry reserves. We continue to expand our drilling in the Pinon Field and now have 12 rigs drilling. The Century Plant construction continues to go well and we are slated for a summer 2010 startup.

As we were exiting 2008 and entering 2009, we were well aware of the challenges that face SandRidge and took some timely, critical and successful steps through cash flow protection and strengthening the balance sheet. We hedged the majority of our 2009 and 2010 gas production at prices that have proven to be well above cash prices. In fact, our gas hedges increased the $3.36 realized field price by $3.84 resulting in a $7.20 per Mcf net realized price. Similarly, our average gas hedge price of $7.70 per Mcf for 2010 is well above the current 2010 strip.

These hedges were significant in protecting and generating $584 million of adjusted EBITDA for a year in which the commodity prices dropped so dramatically. To strengthen the balance sheet, we reduced our exploration and development budget from $1.9 million in 2008 to less than $600 million in 2009. Additionally, we bought stable, predictable oil production with low risk upside opportunities in the Permian Basin for $800 million, completed the sale of some non-core assets preferred stock and common stock bringing $1.5 billion of capital to SandRidge.

As a result of these transactions and a couple of senior notes offerings during the year, we were able to exit 2009 with no borrowings on our $850 million credit facility. Our 2009 full-year production of 105 Bcfe was 4% higher than 2008’s 101 Bcfe. With our reduced drilling budget in 2009, we did not expect significant production costs. As the year progressed and wellhead gas prices weakened further we did not expand our gas drilling efforts in the second half of the year as we initially planned after determining that the incremental production volume would have a negligible rate of return or contribution to EBITDA growth while spending CapEx.

We ended the year 2008 with 2.16 Tcfe of total proved reserves and 2.26 billion in PV-10 value at the SEC December 31, 2008 flat spot price of $5.71 per Mcf and $41 per barrel of oil. Applying the same rule for 2009, our reserves and PV-10 value would have been 2.57 Tcfe and 3.59 billion at the December 31, 2009 flat spot price of $5.79 per Mcf and $79.34 per barrel of oil. However, under the new SEC 12-month average price rule of $3.87 per Mcf and $57.65 per barrel of oil, our reserves and PV-10 value are 1.31 Tcfe and $1.56 billion.

This low flat price scenario, while we don’t believe is a realistic price going forward, forced us to write off virtually all of our gas PUDs on a PV-10 basis. We have provided a table in slide 4 of the presentation summarizing our reserves and PV-10 value at different price scenarios for your convenience. We believe that a price scenario that is more reflective of the current strip, such as the December 31, 2009 spot prices, would be a better measure of our company’s reserves and PV-10 value. In fact, at this price, we would have had a 20% reserves increase and a replacement ratio of 489% as shown in slide 5.

With that said we do recognize the need for the change in the SEC price methodology, and believe that the magnitude of the negative impact on our reserves revision as a result of that change is an anomalous event for our company.

I will now walk you through the numbers so that everybody can understand these revisions. For more clarity, I will separate the major buckets into price-related revisions and performance-related revisions.

First, there are 1.12 Tcfes of downward revisions related to price. This is a direct impact of writing off our gas PUDs using a flat SEC 12-month average price of $3.87 per Mcf and $57.65 per barrel of oil for natural gas and oil. 130 Bcfe of the 1.12 Tcfe price-related revisions is attributable to losing the economic tails of the reserves. The remaining 993 Bcfe is the elimination of gas PUDs that do not run positive on a PV-10 basis. That is, if we use a very low gas price and do not have contango in the gas market, the economic life cuts off rates return lower than 10% and we don’t book the reserves; however, this scenario is unlikely and we show that with a more reasonable pricing all of our reserves come back. On flat price assumptions, however, we do start adding PUDs back at $4 an Mcf, and at $5.25 per Mcf about 90% of the PUDs are back on the books.

I will now move to performance-related revisions. We had 313 Bcfe of negative revisions and 255 Bcfe of positive revisions, resulting in net non-price-related negative revisions of 68 Bcfe or about 3% of the year-end 2008 reserves.

Let’s start with the negative performance revisions of 313 Bcfe. Please refer to the Warwick Thrust type curve on slide 6. The current range of the Warwick Thrust type curve is 6.6 Bcfe to 8.4 Bcfe of wet gas. The historical performance of PDP wells dictates the shape of the type curve and may change from time to time based on operating conditions.

In 2006, the Warwick Thrust type curve was 5 Bcfe of wet gas. Our wet gas EUR refers to ultimate estimated recovery of CO2 plus methane. At that time, a large portion of the Warwick Thrust wells float into a 1,100 pound gathering system. As we’ve built out our infrastructure and installed compression in 2007 and in 2008 to lower the field pressure from 1,100 pounds to 500 pounds, Netherland and Sewell increased our type curve to 7.5 Bcfe of wet gas based on performance response of the wells to the lower pressures.

We had planned to further reduce the field pressure in 2009 to 200 pounds, but these plans were put on hold as part of our budget cutting and that consequently had a negative impact on Warwick well performance. As a result, at year end 2009, we collaborated with Netherland and Sewell to book our Warwick PUD reserves at 6.6 Bcfe EUR of wet gas. This is down from 7.5 Bcfe of wet gas at year-end 2008. The negative revisions that Warwick Thrust high CO2 wells resulted from the change in the type curve along with other proved developed performance revisions relating to the high pressures amount to a 177 Bcfe. However, we believe that these reserves can be put back on the books.

In 2010, we are planning to install two new compressor stations and converting existing stations to reduce the field pressure for the Warwick wells from 500 pounds to 200 pounds. This should allow us to re-book these reserves once we finish our field work later this year. An additional 91 Bcfe of negative performance revisions are related to about 65 Warwick Thrust suite gas wells that were drilled in 2008. Please refer to slide seven of the presentation.

These wells highlighted by the dark blue colored dots produced from the same thrust as the high CO2 wells, but over time had not performed at a level of the high CO2 Warwick type curve. The sweet Warwick wells were mostly on the fringe of the reservoir on the northeast and eastern flank of the Pinion Field, isolated by small fault blocks as evident by the lack of CO2 and subsequently confirmed by seismic interpretation.

Fortunately, this only impacted a few sections in the field. The remaining 45 Bcfe of negative performance revisions are spread across all other areas of the company. While we had 313 Bcfe of non-related negative revisions, we also had 255 Bcfe of non-price related positive revisions. These positive reserve adds are as follows – 102 Bcfe in the test for sandstone in the Pinion field; 47 Bcfe in the Permian Basin; 48 Bcfe in the East Cotton Valley play; and 58 Bcfe across all other areas for the company.

In summary, our 2008 year-end reserves were 2.16 Tcfe. We had a performance negative revision of 313 Bcfe. Our performance positive revision was 255 Bcfe; pricing negative 1.12 Tcfe; production was a 105 Bcfe; our Permian acquisition was 440 Bcfe; our year-end 2009 reserves, 1.31 Tcfe.

This earnings season has brought much confusion to the marketplace in terms of reserve booking. We observed that one company booked Cotton Valley reserves and wrote off Haynesville reserves, while another company did the exact opposite. We observed another company booked twice the reserves we did and yet reported about the same PV-10 as ours. This implies to us that companies may be booking reserves at no or even negative value on a PV-10 basis. All in all, it has been very difficult to understand the meaning of the reserve bookings and the quality of the reserves being booked.

Referring to page eight on slide presentation, our reserves fared a very well at $1.20 per Mcfe on a PV-10 basis; while many others are far less than $1 per Mcfe. The primary reason, we fared so low on the PV-10 to Mcfe ratio at low gas prices is because of the oil in our product mix.

Slide nine shows that the PV-10 value generated by investing in an oil well of comparable cost to reserves is about 10 times that of gas well. The difference between the old SEC price rule and the new SEC price rule for our company is 1.3 Tcfe and $2 billion in reserve value on a PV-10 basis. While the SEC allows reserves to be booked if they cash flow positive at 0% discount, we have remained consistent with our booking methodology and only book the PUDs that cash flow positive at a 10% discount. Our reserve booking is consistent with our business practice and daily decision-making process to always maximize our cash flow.

The table on slide four of our presentation is a good summary of the reserves and PV-10 of our company at different price scenarios. At the December 31, 2009 price held flat, our reserves would have increased to 2.6 Tcfe and a PV-10 of $3.7 billion. And at the year-end strip average price, we have reserves of 2.7 Tcfe and a PV-10 of $5.2 billion.

Before turning the call over to Q&A, I want to recap a bit and emphasize that as an investor in the company, I am very excited about the future of SandRidge for the following reasons.

Our increased exposure to oil and the flexibility of the product mix within our company. The Century Plant gives our flexibility to accelerate drilling of the Pinion field as gas prices and economics dictate. Our exploration efforts and the size of price if we find commercial production on one of these large structures that we’ve identify from our 3D work, and we anticipate having minimum downside reserves price risk going forward with significant opportunities for reserve growth as gas prices improve.

Finally, it is my belief that the natural gas industry is non-economic at today’s price, excluding hedges if we account for G&A and interest. Service costs are starting to climb and will continue to do so as more rigs come back into the market, and the supply of natural gas will drive the price down.

Unfortunately, as an industry, we are incentivized to cut back drilling and take some supply off the market even if there is little to no return on this investment. Therefore, I remain cautious on natural gas prices for this foreseeable future. It is inevitable that over time the price of natural gas will move back to a level that would generate a positive rate of return on an all-in finding cost basis. When a change does occur, our company will be prepared to move back towards a more aggressive mix of natural gas to oil drilling as we have a 30-year contact to fulfill our obligations on CO2 delivery and enough gas on the ground and now capacity with the Century Plant to do so.

Our management team will be in New York City next Tuesday to discuss all of our areas of interest in detail during our third annual analyst and investor day. We will also give an update on the two exploration wells that we are drilling in the West Texas Overthrust at that time. Dirk?

Dirk Van Doren

Thanks, Tom. 2009 was spot on based on our financial projections in terms of EBITDA of $584 million compared to our estimate of $595 million from our investor analyst meeting in March of ‘09. Our regional estimate assumed $5 per Mcf natural gas prices for ‘09 on an unhedged portion and the actual price was $336 per Mcf. This cash flow plus capital we raised, which Tom spoke about earlier, made the year highly successful from a financial viewpoint.

Looking at the fourth quarter, we had EBITDA of $150 million, which was above our internal model, and we’re cash flow neutral during the quarter. We ended the year with nothing drawn on the revolver and we are in compliance with all our financial covenants.

As we look at 2010, we have 106 Bcfe hedged at 950, thus a significant amount of our EBTIDA is locked in for 2010. Our focus in now shifted to 2011. While we have 4.9 million barrels of crude oil hedged at 86.52 per barrel we are un-hedged for natural gas. Based on the current strip price for natural gas, in 2011, we should be able to hedge a significant portion of our production and achieve a blended price north of 850 per Mcfe. Why is that possible, because oil will become a larger percentage of our production in future years.

The new SEC reserve rules have caused investors difficulty understanding the impact across the industry. The SEC rule changes increase the likelihood of companies booking no value to negative value PV-10 reserves. So what is important; crude reserves or present value?

Slide 8 in the slide presentation on our Web site includes SandRidge PV value per Mcf of proved reserves at different prices held constant as well as some of our peers. We choose these companies because they provided a significant amount of information in their press releases.

For SD, the calculation of SEC year-end 2009 prices is $1.19 versus a group average of $0.67. While some companies have more reserves booked at a lower relative or actual PV-10 than SandRidge. So what is important; proved reserves or PV-10? We believe value is important. If we were to use year-end 2009 prices or roughly $7 and $92 flat, our PV-10 to proved reserves is the same as our peers.

However, would you think at higher prices some peers would add reserves and they do not. This is because of the SEC rule change for increased PUD bookings this year at higher prices, not a significant incremental amount of reserves will be added, so just PV-10 improves. This is how we make sense of all the SEC modifications; we think value matters.

We are coming to the borrowing based redetermination period, so let us chat about that. Looking at our reserve valuation relative to the bank credit facility is very favorable. The value of our reserve including hedges using the bank base case is over 50% better than mid-year 2009. This is roughly 2.7 times the value of our $850 million borrowing base. The bank market has improved dramatically in the last year and we see no issues for 2010. In fact, we have a few banks that would like to join our facility and we hope to be able to accommodate them during the year.

I want to take a quick look at the Permian acquisition. We spent $795 million and locked in via hedges $1.1 billion of revenues and roughly $800 million of EBITDA, and we really like the acquisition. The transaction closed on December 21, 2009 and because of new SEC pricing rules, we had to book the value of the reserves at $3.86 per Mcfe and $61 per barrel resulting in a write-off of about a quarter of the purchase price in 9 days.

This illustrates some of the accounting oddities we all endure as we lock in the purchase price of three years and had to charge shareholders’ equity account about $200 million.

Tom Ward

We will be in New York on Tuesday for our annual investor and analyst meeting, and we look forward to provide an in depth look at SandRidge. This ends our prepared remarks. Jeanette, we are ready to take questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) Your first question comes from the line of David Heikkinen with Tudor Pickering Hold. Please proceed.

David Heikkinen – Tudor Pickering Holt

I guess I'll get the use of that someday. Aus think about the proved developed reserves going from 943 Bcf at year end to the 978 Bcf at the $5.79 price deck can you reconcile production acquisitions, revisions, and additions to proved developed?

Tom Ward

David, we will pull together something here real quickly. I will probably let Matt take that question.

David Heikkinen – Tudor Pickering Holt

Okay. And then as you think about the hedging, Dirk, you mentioned that you could get a blended price of $8.50. Are you thinking about structures that would include crude oil volatility or more complicated structures or do you just think of a flat swap?

Dirk Van Doren

No what we’ve done before. We don’t plan it doing it. That would be straight swops. That would be – priced yesterday at $83 per barrel for the 11 oil trade and it would be a 585 for the natural gas trade, straight swap.

Matt Grubb

We continue to be slightly bullish right now as I think we are seeing a tightening in the market on natural gas for the near term. But the problem is as we all know, that the gas rig count continues to climb and we are afraid as we move over the 900 to 950 range of gas rigs, that will ultimately have the negative impact on future prices and in think that’s what the markets worried about also. So it is a kind of a time here that we are saying we are going doing time to date, but we will look forward to the next couple of months of layering on our 2011 hedges.

David Heikkinen – Tudor Pickering Holt

On the guidance, while Matt still looks at the proved development side, your oil volume guidance came down. Can you reconcile what changed from post-acquisition to now around the oil volumes?

Matt Grubb

Sure. That really was not meant to be a change in guidance other than taking away the high end of guidance. So we didn’t change the oil to gas ratio and there has not been an official change in guidance.

David Heikkinen – Tudor Pickering Holt

Okay, so basically just expect to stay at the time low end, not – and if you think about activity levels, if you shifted more towards oil, I'm trying to read into, is there an opportunity to drive oil towards that high end of guidance if you shifted more activity there, or how much oil volume could you hit this year or next year if you were to shift that direction?

Matt Grubb

And today we want to talk about volumes changing any. But we will say that we are driven by EBITDA and if we move towards more of a mix of oil, you could assume that our goal is to spend the same amount of money and make the most of EBITDA we can. Now if you switch to oil, it is not as easy to grow production, but it is easier to make the cash flow. So that’s what the goal is, it is really to create value and not be held by this magic number of growth that sometimes can be meaningless, but yet the industry continues to be fixated on only volume and not on EBITDA.

David Heikkinen – Tudor Pickering Holt

And then on the reserve reporting, the performance revisions going from 7.5 Bcf down to 6.6 Bcf, as your pressures were 500 pounds, had Netherland Sewell or had you all built in a future capital into your year-end '08 reserve report – to drop pressures ¬2010 Thomson Reuters. All rights reserved. Republication or redistribution of Thomson Reuters content, including by that would have maintained that 7.5 Bcf, or whenever we get the 10-K and look at the future development costs is there something that was in the proved side that said there was a compression component of future capital built into that 7.5 curve?

Matt Grubb

Yes, David this is Matt. On that question, the capital for compression is actually in the midstream capital. It is not running the Aries case. So basically what we decide – we didn’t burden the wells with the compression capital and we didn’t show any kind of an increase in reserves due to lowing the pressure.

David Heikkinen – Tudor Pickering Holt

But in the 7.5 you had on assumption that you had lowered to 200 pounds, just so I understand that?

Matt Grubb

No. In the 7.5 – let me just back up a little bit on that reserves, we started out at about three year ago at 5 Bcf and all these oils were flown into about 1,100 pound pressure system. And as we increase our drilling activity, we also do a lot of field work, we had in lot of new pipes and a compression and we lowered the field pressure form 1,100 pounds to about 500 pounds. And all the PDP wells response to that lowering of field pressure and therefore moved the type curve up to 5 Bcf to 7.5 Bcf. As we ended our way, we had plans in 2009 to continue to lower the field pressure from 700 pounds to 200 pounds. As part of our budget catch, we decided to hold off on those projects. But as we didn’t lower the field pressure, the wells suffer from the 500 pound line pressure. So it came up to 7.5 Bcf type curve.

David Heikkinen – Tudor Pickering Holt

So at a 500 psi system, you really should have been booking in the 6.6 B's, not the 7.5. Is what you are saying now on performance? Just making sure I'm getting that.

Matt Grubb

What we couldn’t tell at year end of ’08 was how those wells – they may find and not go up the curve in ‘09, but unfortunately they did due to the higher pressure. So at the yearend of ’09 that’s why we made a change.

David Heikkinen – Tudor Pickering Holt

So you really aren't going back up to – the way would you go back up to 7.5 Bs is because of dropping to 200 pounds, not just maintaining 500.

Matt Grubb

That’s right. Our plan this year is to drop it to 200 pounds and we would expect the type curve to get back to where it was.

David Heikkinen – Tudor Pickering Holt

Then would you have a capital investment for that midstream to take it back up to where it was. So your capital efficiency per well is a little higher. I just wanted to make sure I reconciled that. That's helpful. Do you have the proved developed?

Matt Grubb

Yes, let me just kind of walk through the proved developed here. We ended the yearend 2008 at 943 Bcf. And we had 223 of total write-offs and then we added through drilling a 137 Bcfs and then we had additional write-offs in what we call hails of a 130 Bs and then we produced a 105 Bs and then we added the Forest cycles – the Forest deal was 204 Bs in PD reserves, 440 total, 204 is in PD. So we ended the year at 823 Bcf of PD. And if you add the tails back in because of pricing improvement we would be at 953.

David Heikkinen – Tudor Pickering Holt

Okay, that's all. Thank you.

Operator

Your next question comes from the line of Dave Kistler with Simmons & Company. Please proceed.

Dave Kistler – Simmons & Company

Good morning guys.

Matt Grubb

Good morning.

Dave Kistler – Simmons & Company

Looking real quickly at the 102 Bcf that was added from the Testnes [ph] on the performance revisions is that going to be – are you guys going to start putting that out as separate type curve coming from the Testnes, or is that going to be something that's going to be comingled with the Warwick thrust production as type curve? Can you just help us there? Then what would that type curve look like?

Matt Grubb

We will discuss the Testnes type curve at the analyst investor day. Rodney will have that and what will also show is that on most of the wells we can comingle, it's actually not comingle, it's dual complete the Warwick thrust with the Testnes and we'll have a separate type curve for that also.

Dave Kistler – Simmons & Company

Looking at the capital budget of about $750 million going to exploration and production, can you break that up between the Pinon and the Permian side of things. And then as step 2 of that, what level would the Pinon to have stay at to honor obligations to Oxy, just to your comments on gas prices and wanting to maximize EBITDA is there an ability to take that portion of the budget even lower?

Matt Grubb

Yes. But here is the way we will discuss today is not change of budget from what we had because we were looking at moving from more gas rigs to oil rigs. But we haven’t made that change yet. So there is no official change in the budget, but we do have the ability to speed up or slow down our drilling, as you know there is a 30 year commitment of 3.5 Tcf of CO2 across the Pinion field. We haven’t lost the CO2, either fortunately or unfortunately the gas has tremendous amount of CO2 in it, and we still have those reserves in place. And that’s why we opt CNS together made a very long-term contract so that we could flexible in the amount of gas we want to bring on in one particular year or maybe a span of years. There are penalties that can be incurred but there are not to a point that it wouldn’t – if you have made that choice, you would be much better off today drilling over the gas, and remember, we do have a substantial amount of gas, it is already flowing into existing plants that we can move all to Century which we plan to do.

Dave Kistler – Simmons & Company

Okay. Just for a little clarification on that, Tom, I'm sorry, so what percentage of that $750 million is allocated to Pinon?

Tom Ward

$430 million. That’s what our current budget is.

Dave Kistler – Simmons & Company

$430 million, okay. And the flexibility on that, just so I'm clear about it, is actually pretty large because of the term of the contract. Right?

Tom Ward

Right.

Dave Kistler – Simmons & Company

Okay. So if you want to change that later, you can. And then, thinking about oil inventory and the ability to accelerate there, after having the Permian properties for a couple of months what are you guys thinking about as far as drillable locations there? What upticks are we seeing versus when you originally purchased it? Anything like that?

Tom Ward

I will let Matt this specifics but, we love the acquisition that we made and we love being in oil and we continue to see a lot of upside in the properties that we acquired and Matt will go through the specifics, do you have those specifics locations Matt?

Matt Grubb

Yes, I man on the Permian, you know the good thing about the Permian is when we bought it we really – we bought at a higher oil price than what we booked at the year end, because the year end was a 12 months average. But at the acquisition pricing we basically bought it for very close to PDP value. And as a turn out, we have a roughly 27 hard locations out there to drill, about 800 PUDs and plus 1,900 what we call resource locations. There is quite a bit of room to run there and a lot of that is very low risk, increased density, plus close in extensional type drilling. So it's just a lot of drilling. Right now, we are running six rigs and we are looking to potentially wrap it up to eight rigs as the year move on down towards – maybe in the middle of the year. Both these locations are Clear Fork locations. That’s something we have been drilling for the last three years in Nitric [ph] county area.

Dave Kistler – Simmons & Company

Great. One last, if I may. Looking at the new type curves associated with the Pinon, and realizing they're temporary in nature, as you bring compression back, can you just talk about what the break-even price would be as far as the production associated with those wells, just so we can be think about in terms of, okay, if pricing hits a certain level, as analysts can we expect that we'll see an adjustment to the capital budget?

Matt Grubb

Yes, I think that the break even for the – our PUDs has been running at 387 but out there in the Pinion field at a little over $4, you start adding PUDs back in. At about $5.25, they are pretty much kind of back on the book. So I think, year end, it’s $5 range or break even.

Dave Kistler – Simmons & Company

Okay. And that's at the wellhead in the Pinion, that $5?

Matt Grubb

That’s right.

Dave Kistler – Simmons & Company

Okay great thank you guys so much.

Matt Grubb

That’s just a break even on development costs to drill the well.

Dave Kistler – Simmons & Company

Okay great thank you guys so much, I really appreciate your time.

Tom Ward

Thank you.

Operator

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

Brian Singer – Goldman Sachs

Thank you good morning.

Matt Grubb

Good morning.

Brian Singer – Goldman Sachs

Question on the borrowing base. You mentioned that you're seeing interest of some banks getting into that. I wanted to see where you thought the borrowing base would go, and your interest in tapping that and whether that would be for additional acquisitions versus spending above cash flow to drill more oil versus gas wells.

Dirk Van Doren

The borrowing bases would stay at 850; we really don’t need any more money than that. And right now, we have no plans on acquisitions. So any shortfall, we would just use on a borrowing base.

Tom Ward

I would just clarify that we always look at acquisitions. If we have the opportunity to make another Forest type acquisition, we would probably try to do that.

Brian Singer – Goldman Sachs

Thanks. Then secondly, can you talk about any horizontal opportunities on the Forest properties or any of your other oil properties?

Tom Ward

Yes, we do have. We will be addressing those on Tuesday on the analyst day.

Brian Singer – Goldman Sachs

Great. Thank you.

Tom Ward

Thank you.

Operator

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

Joe Allman – JPMorgan

Thank you. Good morning everybody.

Tom Ward

Good morning.

Joe Allman – JPMorgan

Hi, Tom, looking at slide six in your presentation to try and figure out what's your assumption now for the dry gas EUR in a typical Warwick well?

Tom Ward

Our type curve is 6.6 Bcf. I believe that whenever we put in our compression, will lead back to the 7.5 Bcf per well and the upside what we show is 8.4 Bcf. What we will talk about too also on Tuesday is just if you add the Testnes through this, we can enhance our reserves even more that way. So we just internally ask to look at this as a 7.5 Bcf type of well.

Joe Allman – JPMorgan

Okay. But in terms of just the methane component, the dry gas, I think previously – I'm sorry –.

Tom Ward

Really not changed any Joe. As we have always looked at 62% to 65% of two and that’s still fairly consistent. It might change from over time from – we might have been as low as 62 to as high as 65, where you can give yourselves a 5% range in that CO2 across the field.

Joe Allman – JPMorgan

Previously you were saying just over 3 Bcfe, and then I think in December you were saying something like 2.9 Bcfe or so. So you're still think about those kinds of numbers?

Matt Grubb

Yes. I mean on a 6.6 type curve, you will arrive at 2 Bcf, that’s netting out CO2 as netting back to – netting up the royalty. That’s typically about 23% out there. And then these are net Bcf, gross Bcf, basically you just take the amount of netting content multiplied by your –

Tom Ward

I do think that’s the difference that we come up with, some people and there may be some of the slides we have had, we have talked about gross gas without net of royalties, so I think that’s making the difference that we are talking about.

Joe Allman – JPMorgan

Got it. So when I look at that slide and I see the red line, that's a performance of your wells, right?

Tom Ward

That’s right.

Joe Allman – JPMorgan

So in general, your wells have done better than your type curve. It looks like the most recent wells have been hugging that 8.4 Bcfe type curve.

Tom Ward

That’s little bit dangerous to look at, because if you have a components of your wells at the front end of the curve, I think the type curve led you follow the type curve.

Joe Allman – JPMorgan

Thank you. And then in terms of your year-end he reserves, at the SEC price deck, what was the percentage of gas reserves at year end '09?

Tom Ward

We should have that handy, don’t we? We are going to flip to that, from a volume basis?

Joe Allman – JPMorgan

On a volume basis. We got the PV-10.

Tom Ward

Gas was 52% and oil 48%.

Joe Allman – JPMorgan

Okay, got it, thanks. In terms of the acquisition, when you put out your press release on the acquisition it indicated you bought 482 Bcfe, and at year-end '09 talking about 440 Bcfe. Was there a 42 Bcfe negative revision?

Matt Grubb

Well, those are really tail effect, and would run at lower gas price where you go negative cash flow a few years are there.

Joe Allman – JPMorgan

Okay, got it. So most of that was the tail effect on proved developed reserves?

Matt Grubb

Well, that will be across the board. But I can't remember the exact price but you know you ran stating $5 and now you are cutting off at $57.

Joe Allman – JPMorgan

Okay, got you. All right. Thanks, very helpful.

Operator

Your next question comes from the line of Eric Anderson - Hartford Financial. Please proceed.

Eric Anderson - Hartford Financial

Yes, good morning. I wonder if you could just take a minute or two and talk about some of the exploration prospects that you've got lined up for this year. On the gas side that is, the Pinon types.

Tom Ward

Yes, we have two rigs that are currently drilling wells that we said will be down in the first quarter of this year. That still is true. We will talk more about those two wells and where there are at, at the analyst day. We continue to have plans to drill six exploration wells across Pinion in 2010. And we haven’t chosen any of the other structures yet, because we want to see these two wells down and get it log. And really there is nothing more to discuss today on those, other than we will talk more on Tuesday.

Eric Anderson - Hartford Financial

Okay, fair enough. Thank you.

Operator

Thank you, your next question comes from the line of Wei Dow [ph] with Stone Harbor. Please proceed.

Wei Dow – Stone Harbor

Yes. I didn't catch the number on the PD you ran through the changes on a proved developed reserve. There was a write-off – hello?

Tom Ward

I think we understood. You want the change in the proved developed reserves that we gave?

Wei Dow – Stone Harbor

Yes, you started with 943 and then the second number you were running through and you are saying some write off; that was related to what write off?

Dirk Van Doren

Well, those just are reversions due to type curve changes, high-line pressures, that kind of stuff.

Wei Dow – Stone Harbor

Okay. What number was that?

Dirk Van Doren

That number was 223 Bs.

Wei Dow – Stone Harbor

Okay.

Dirk Van Doren

Okay? And then we added 137 Bs prior to conversions and new drill. And then we lost 130 Bs due to the tail impact of lower pricing. And then we lost 105 Bs due to production. And we added 204 Bs of PD reserves from the Forest acquisition that gets you to 823. And as price have improved – prices are already higher than year end, so what you could do is add that tail back in so that gets you back up to 953.

Wei Dow – Stone Harbor

Okay.

Dirk Van Doren

So you would potentially have a positive increase in PD reserves, even through all the revisions –

Wei Dow – Stone Harbor

Okay. Just in terms of the way – looking at your press release, page three, where it breaks down the reserve changes, I'm just a little confused. For example, the 223 write-off, is that amounting to the non-price revision, or does that get knocked out with your extensions? Because clearly you added 133 of PDs – just PDs – through drilling, but I'm only seeing a net of nine on that page three.

Dirk Van Doren

I am sorry; let me get to where you are at.

Wei Dow – Stone Harbor

So, If I look at the page three, 9 Bs of reserve under the SEC rule, I'm assuming the revisions are price related, and your PD reserve didn't really go up, then the $800 – or is it $600 million of CapEx, what did that get spent on?

Dirk Van Doren

Yes, I am sorry. The net revisions was – when we talk about a net reversion, the total performance, going through all the numbers it comes up to 313 Bs of net revisions and 255 Bs of positive add. So that is I think 58 Bs differential, or call it 60 Bs, okay, and this is some round impact. So when you look at page 9, it revision of 69 Bs in extensions – this curve you have 9 Bs. That’s the difference right there. The 260 in net revisions match up.

Wei Dow – Stone Harbor

Okay.

Dirk Van Doren

Those are performance revisions. The 1.123 negative revision is all due to pricing less the 130 Bs in tail write-offs because of lower – because of higher economic limits, because of lower prices. Then the 993 Bs remaining are the gas PUDs write-off. They are due to pricing. So basically you have 1.123 Ts of write-offs that are attributable to pricing and net 60 Bs write-off that are attributable to performance. 305 Bs [ph] of production.

Wei Dow – Stone Harbor

Okay. All right, thank you.

Tom Ward

Thank you.

Operator

Your next question comes from the line of Jeff Robertson with Barclays Capital. Please proceed.

Jeff Robertson – Barclays Capital

Thanks. Coming back to the high CO2 gas in Warwick Thrust, if you moved all of your gas, do you have the flexibility to move all of your current production into the Oxy plant when that comes up?

Tom Ward

Yes.

Jeff Robertson – Barclays Capital

Is that – if that plant will be more efficient than your legacy plants, is that plant or the operating costs, is that reflected in the guidance that you all had out now?

Tom Ward

No, we won’t be able to reflect that until next year’s reserve report after we see – we can project efficiencies, but we need to see it before we put it into our reserves.

Jeff Robertson – Barclays Capital

Can you talk a little bit about or put some parameters around what those efficiencies might be?

Tom Ward

Sure. Matt, you take that.

Matt Grubb

Well, from an efficiency standpoint, one of the problems we have now is that the plants that we are operating through, the technology that we are using are dated. These legacy plants were processing CO2 were built in the late ’60, early ‘70s. And it’s an absorption process with the proprietary chemical called Selexol. And when we flashed the gas from 1,100 pounds down to 2 pounds to extract the CO2, we lose probably 6% to 8% maybe 9% of methane out the stacks right now. With the Century Plant, there is two processes there. There is absorption process like the Selexol, I just described, but also there is a refrigeration or fractionation process. It’s a two-step process of extracting CO2, but in doing so you improve your methane losses. It will drop from about 8% down probably in the 2% range. So right there, you should gain about 6% in methane sales just in the process of sale. But that’s not booked, or that’s not mull in our projection nor is it booked in our reserves run.

Jeff Robertson – Barclays Capital

Matt, could that an impact then on the overall 6.6 Bcfe to 7.5 Bcfe type curve?

Matt Grubb

Sure, it could be an impact. I don’t know what the magnitude of that impact might be. But anytime you can show higher sales there per Mcf from the well head, because you will have a gain at the tailgate of the plants. That will certainly help with type curve and with your PDP forecast as well.

Jeff Robertson – Barclays Capital

Okay. And, when you do that, if you just – at the end of the year, when you look at moving your current production over, when you move it over, how much CO2 would be coming out of that plant? In other words, how much of the obligation would be satisfied by existing production?

Matt Grubb

Let me answer it this way. The annual obligations are confidential due to competitive reasons for Oxy. However, the outlook is 3.5 Ts over 30 years. You can do some simple math there and get around to what an annual obligation might be. But just with our current production right now in the high CO2 gas, close to 300 million day of total volume, you are looking at probably 75 Bs or 80 Bs right there alone if we didn’t do any drilling of CO2. With the drilling that we are doing this year, we’re probably going to produce, I am guessing, in the 90 Bcf range of CO2. And then – we’ve also been banking volumes with Oxy to the tune of 30 Bcf, 40 Bcf over the last couple of years. So I don’t think there is going to be a problem at all in meeting the obligation at this point.

Jeff Robertson – Barclays Capital

Last question you all before, if I remember right, have talked about some midstream monetization in 2010. Is that still something that's possible?

Tom Ward

Sure. I guess that both of us have an option. I think the way we’d describe it is CCW has an option and SandRidge has an option, and we'll be reviewing that this year.

Jeff Robertson – Barclays Capital

Okay. Thank you.

Tom Ward

Thank you.

Operator

Your next question comes from the line of Brian Kuzma with Weiss Multi-Strategy. Please proceed.

Brian Kuzma – Weiss Multi-Strategy

Hi, good morning guys.

Tom Ward

Good morning.

Brian Kuzma – Weiss Multi-Strategy

You guys may have already given this today. Did you give the production split on production from Pinon versus Permian on the fourth quarter numbers?

Tom Ward

I think we have that. Hold on for a second.

Dirk Van Doren

Just a minute Brian.

Brian Kuzma – Weiss Multi-Strategy

And then just a more conceptual question. I think it's one that everybody is asking themselves here today, is – you guys need $4 to book close to the PUDs in Pinon, and you guys used to have a chart that showed Warwick wells having higher rates of return than all the other plays, and all the other producers booked all those PUDs at $3.87, I'm just curious what your thoughts are on that – versus what other operators are doing versus what you're doing and – if there's something else going on there.

Tom Ward

I can only address what we do. But I can say that a low rate well, if you are forced to have flat pricing for ever, doesn’t have as a good rate of return as a high rate well with flat pricing. A low rate well in a market in contango has a better rate of return than a high rate well that brings on the production early in the life of the well. If you believe that prices are going higher in the future it’s better not to produce as much of you gas early in the life of the well.

So that if you kind of think through that math you can kind of get to the different rates of return that you might have between high rate initial wells and low rate initial wells with less decline.

Brian Kuzma – Weiss Multi-Strategy

Okay.

Dirk Van Doren

Okay, Brian, back to your first question. You are asking about production?

Brian Kuzma – Weiss Multi-Strategy

Yes.

Dirk Van Doren

And you wanted a breakout. Is that correct?

Brian Kuzma – Weiss Multi-Strategy

Yes. That’s right.

Dirk Van Doren

Okay.

Brian Kuzma – Weiss Multi-Strategy

Probably as many assets as you are willing to give.

Dirk Van Doren

Yes, I can give you everything here. You are looking at Pinon is nearly half of our production; and this is a very current data. You are looking at probably, of a total of 300 million a day production, you are looking at 120 million from Pinon, 72 million from the Permian. These are all in Mcfed. 36 million from East Texas, 17 million from the Gulf of Mexico, 28 million from the Gulf Coast, 23 million from the Midcontinent, and about 3.5 million in other, including tertiary.

Brian Kuzma – Weiss Multi-Strategy

Okay.

Dirk Van Doren

And then your other question was the PV-10 of total developed?

Brian Kuzma – Weiss Multi-Strategy

Exactly, yes.

Dirk Van Doren

That’s about $1.1 billion.

Brian Kuzma – Weiss Multi-Strategy

And then one last one from me. When I looked at Forest reserve profile at year-end, it looked like they booked the Permian like they added a whole bunch of PUDs and booked the Permian at, I think like 550 Bs or something like that using year-end pricing. You guys always booked it at 440 Bs. Is there some conservatism there that you guys think that you could be able to book just more PUD reserves out there at year end, you guys versus Forest? I'm confused.

Tom Ward

I don't remember Forest having that number. But I don’t believe there was ever a published number like that from Forest.

Brian Kuzma – Weiss Multi-Strategy

Okay.

Tom Ward

I think we basically – the only thing, the only difference we had was that we lost some reserves because of the tail that we mentioned that came in really just as we booked. We only owned it just a few days before the end of the year.

Dirk Van Doren

What I can say is that we did some sensitivities in that as you can see in that one slide, but if you use the spot price of year-end 2009, of about $78, $79 a barrel, book reserves for Forest would have been very close to that 550. It’s in that 525, 530 range.

Brian Kuzma – Weiss Multi-Strategy

Got it. Okay. That’s helpful.

Tom Ward

That was moving up from where we were.

Brian Kuzma – Weiss Multi-Strategy

Okay. Thank you.

Dirk Van Doren

It was about 482.

Brian Kuzma – Weiss Multi-Strategy

482?

Tom Ward

That’s right.

Brian Kuzma – Weiss Multi-Strategy

Okay. Thank you, guys.

Tom Ward

Thank you.

Operator

Your next question comes from the line of Andy Rob [ph] with SPR. Please proceed.

Andy Rob – SPR

Hi guys. Good morning. Just had a quick question on capital allocation; I was hoping you could just help me understand why spending up to $100 million on the new SandRidge Commons building is a good use of capital for shareholders, particular if you are cash constraint. Thanks.

Tom Ward

Sure. We had – you ask about the building, correct?

Andy Rob – SPR

Yes.

Tom Ward

We had an opportunity in 2007 to either – we were out of space in the existing building that we were in and we had 10 floors there and we’re looking to buy land and build or the opportunity came to buy what is potentially here downtown about 1 million square feet of potential space where we are going to take out some of the building so it won't ultimately be that much, but – for $25 million. And then we built out some of the floors and if we were to move forward over the course of time, you might be able to get up to the price you are talking about. But it is – we felt like, one, it’s a very good investment for us. It was cheap real estate to own. It's great to be downtown. And we are glad that we made the purchase. I think it is a good asset for us and gives us ample opportunity for growth in the future. And we own two city blocks of downtown Oklahoma City.

Andy Rob – SPR

Okay, thanks.

Dirk Van Doren

This is Dirk. I might add that number $100 million is going to be spread out over 5 years to 10 years. So it’s not a huge amount of expenditures that are going on right now.

Tom Ward

And assumes future growth.

Andy Rob – SPR

Okay, thanks.

Tom Ward

Thank you.

Operator

Your next question comes from the line of Philip Dodge with Tuohy Brothers Investment. Please proceed.

Philip Dodge – Tuohy Brothers Investment

Good morning. I just wanted to ask you the current cost of the Clear Fork well, how much that’s gone up from the bottom and what the trend in recovery in one of those wells would be?

Tom Ward

Sure. The cost is basically the same as we discussed earlier. At one time, we got down to where we were drilling wells just under $700,000, it might be just over $700,000 per well now. The type curve is in one of our slides I think is 67,000 MBO and 115 million cubic foot of gas. Clear Fork wells have just a tremendous rate of return at today’s prices. And especially where we’ve drilled the – now about 120 wells in the Goldsmith Adobe Unit, the rates of return have been phenomenal.

Philip Dodge – Tuohy Brothers Investment

Okay. Thank, Tom.

Tom Ward

Thank you.

Operator

(Operator instructions) Your next question comes from the line of Gregg Brody with JPMorgan. Please proceed.

Gregg Brody – JPMorgan

Good morning, guys.

Tom Ward

Good morning.

Gregg Brody – JPMorgan

Just a follow-up question on reserves, just for some clarification. I think I was a little confused on the discoveries on my part.

Tom Ward

I am sorry Gregg, I can’t hear you. I am sorry.

Gregg Brody – JPMorgan

How's that?

Tom Ward

Better. Thank you.

Gregg Brody – JPMorgan

Just in terms of the expenses and discoveries, the number which is nine, is some of your concealed drilling showing up in different category than in the previous? You talked about that 255 number of positive additions that is showing up in the revisions number.

Tom Ward

Showing up in our reserve numbers?

Gregg Brody – JPMorgan

I'm just trying to reconcile that why that extension and discovery number is so low. Is it different from the way other companies report?

Tom Ward

Well, the 255 was it so low?

Gregg Brody – JPMorgan

No. So the expenses and discoveries number, you have 9 Bcf of adds there. Then you mention the 255 of positive adds that’s showing up in the revisions, that's part of the changes to previous estimates. Is that basically in-field drilling that's driving that?

Matt Grubb

Yes, it’s really all in-field drilling.

Gregg Brody – JPMorgan

Is that different from the way other companies typically report it?

Tom Ward

Usually I think in-field drilling would be reported the same way.

Gregg Brody – JPMorgan

And then just a follow-up question on the same line item – revisions to changes to previous estimates. It looks like it goes up and then down as you move the price up. I would think as price goes up that would keep going up. Do you know what's driving that?

Tom Ward

Yes, Matt’s got that one.

Matt Grubb

Are you talking about on the table?

Gregg Brody – JPMorgan

Yes.

Matt Grubb

Hang on. Let me reconcile the math real quick here.

Tom Ward

Do you have any other questions while Matt is doing some math.

Gregg Brody – JPMorgan

No, I think that's it. Just maybe one more. You broke out your oil percentage for the P-10. The value – what is that for the actual proved reserves?

Tom Ward

What’s the oil value?

Gregg Brody – JPMorgan

No, on a percentage of the proved reserves.

Tom Ward

For percentage on the end of year case?

Gregg Brody – JPMorgan

Yes.

Tom Ward

I believe that is – I was going to say off the top of my head. I’ll give you the exact number. We can get that one, too. What's the percentage on oil end of year?

Dirk Van Doren

End of year oil by volume.

Tom Ward

By volume. I think we said that earlier. I thought it was 48%.

Dirk Van Doren

By volume, your end of year reserves is 48% of oil.

Matt Grubb

Brian, I'm going to let Rodney Johnson, Head of Reservoir, answer your last question. He can do a better job than I can on the number movement there.

Rodney Johnson

Yes, Brian, if you follow –

Gregg Brody – JPMorgan

Gregg.

Matt Grubb

Gregg. I am sorry.

Rodney Johnson

If you follow the extensions and discoveries bucket that is a calculated number and as you move up the price scale what we had identified is extensions and discoveries. Some of those didn’t actually run at year-end, at the higher prices those actually run, so you can see a delta from 9 to the 29. What really happens is all the other buckets are calculated as far as price changes, acquisitions, divestitures, and extensions. And essentially that number is the delta that makes up the change in reserves. So as that extensions goes up the revisions gets slightly bigger.

Gregg Brody – JPMorgan

Okay. Thank you, guys.

Tom Ward

Thank you.

Operator

At this time, we have no further questions. I would now like to turn the call back over to Tom Ward for any closing remarks.

Tom Ward

As always, we thank you for joining us and we look forward to seeing you next Tuesday in New York City at the analyst and investor meeting. Thank you.

Operator

Ladies and gentlemen that concludes today’s conference. Thank you for your participation. You many now disconnect. Have a great day.

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