SandRidge Energy Inc (SD) 2009 Q4 法說會逐字稿

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

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

Thank you Janaida. 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 the 10-K on Monday. If you do not have a copy of the release you can find a copy on the Company's website, 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 SEC rules a reconciliation of the most directly comparable GAAP measures are available on our website under the Investor Relations tab.

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

Thanks, Dirk. SandRidge remains flexible in our plans and have 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 remain soft in 2009 we decided to de-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 have 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 Sprayberry 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 summer 2010 start-up.

As we were exiting 2008 and entering 2009 we were well aware of the challenges that face SandRidge and took some timely, critical, and successfully 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 to $3.36, realized field price by $3.84, resulting in a $7.20 per Mcfe --or 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 developmental budget from $1.9 billion to -- 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 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 rates 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 31st, 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 31st, 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 four 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 31st, 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 replacement ratio of 489% as shown in slide five. 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 numbers so 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 Tcfe 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 of 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 six. 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 it 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 flowed into an 1,100-pound gathering system. As we 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 corroborated 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 to the 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 177 Bcfe. However, we believe that these reserves can be put back on the books. In 2010, we're planning to install two new compressor stations and convert an existing station to reduce the field pressure for the Warwick wells from 500 pounds to 200 pounds. This should allow us to rebook these reserves once we finish our fieldwork later this year. An additional 91 Bcfe of negative revisions are related to about 65 Warwick thrust sweet gas wells drilled that were 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 have not performed at the 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 Pinon Field isolated by small fault blocks as evidenced 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 had 255 Bcfe of non-price related positive revisions. These positive reserve adds are as follows. 102 Bcfe in the test and sandstone in the Pinon Field. 47 Bcfe in Permian basin. 48 Bcfe in East Cotton Valley play. And, 58 Bcfe across all over areas of 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 105 Bcfe, our Permian acquisition was 440 Bcfe, and our year-end 2009 reserves 1.31 Tcfe.

This earnings season has brought much confusion to the marketplace in terms of reserved 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 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 in the slide presentation, our reserves fair 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 fair so well 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 10 times that of a 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 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 in PV-10 of our Company at different price scenarios. If the December 31st, 2009 price held flat our reserves would have increased to 2.6 Tcfe and a PV-10 of $3.7 billion. At the 10-year strip average price we have reserves at 2.7 Tcfe, and a PV-10 of $5.2 billion.

Before turning the call over to Q and 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 us the flexibility to accelerate drilling of the Pinon Field as gas prices and economics dictate. Our exploration efforts and the size of the prize if we find commercial production on one of these large structures that we have identified from our 3-D work and we anticipate having minimum downside reserve 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're not incentivized to cut back drilling and take some supply off the market even if there's little to no return on this investment. Therefore, I remain cautious on natural gas prices for the foreseeable future. It is inevitable that over time the price of natural gas will move back to a level that will generate a positive rate of return on an all-in finding cost basis. When the 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 contract to fulfill our obligations on CO2 delivery and enough gas in 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 drilling in the west Texas overthrust at that time. Dirk?

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 original estimate assumed $5 per Mcf natural gas prices for '09 on an unhedged portion and the actual price was $3.36 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 that time fourth quarter we had EBITDA of $150 million which was above our internal model, and we were cash flow neutral during the quarter. We ended the year with nothing drawn on the revolver and we're in compliance with all our financial covenants. As we look at 2010 we have 106 Bcfe hedged at $9.15. Thus a significant amount of our EBITDA is locked in for 2010. Our focus has now shifted to 2011. While we have 4.9 million barrels of crude oil hedged at $86.52 we are unhedged 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 $8.50 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? Proved reserves or present value? Slide eight in the slide presentation on our website includes SandRidge PV value per Mcf of proved reserves at different prices held constant as well as some of our peers. We chose 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 the group average of $0.67. Some companies have more reserves booked at lower -- 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 would 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 into the borrowing base redetermination period so let's chat about that. Looking at our reserve valuation relative to the bank credit facility is very favorable. The value of our reserves 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 in 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 the new SEC pricing rules, we had to book the value of the reserves at $3.86 per Mcfe -- per Mcf -- and $61 per barrel, resulting in a write-off of about a quarter of the purchase price in nine days. This illustrates some of the accounting oddities we all endure as we locked in the purchase price of three years and had to charge shareholders' equity account about $200 million -- go figure.

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

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

I guess I'll get the use of that some day. 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?

David, we'll pull together something here real quick. I'll probably let Matt take that question.

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?

That's not what we've done before. We don't plan on doing. That that would be straight swaps. That would be -- I priced it out yesterday at $83 per barrel for the 11 oil trade, and it would be at $5.85 for the natural gas trade, straight swap.

David, we continue to be slightly bullish right now as I think we're seeing a tightening in the market on natural gas for the near term. The problem is, as we all know, is that the gas rig count continues to climb, and we're afraid as we move over the 900 to 950 range of gas rigs that that will ultimately have a negative impact on future prices, and I think that's what the market is worried about also. So it's a time here that we aren't saying we're going to do anything today, but we will look forward to the next couple of months of layering on our hedges.

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

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's not been an official change in guidance.

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?

Today we won't 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 EBITDA as we can. If you switch to oil it's not as easy to grow production but easier to make the cash flow. So that's what the goal is, 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.

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 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?

David this is Matt. On that question, the capital for compression is actually in the midstream capital. It's not running the Aries case -- so basically -- we didn't burden the wells with compression capital and we didn't show any increase in reserves due to lowering the pressure.

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

Well, no, in the 7.5, let me just back up a little bit on that reserve. We started out about three years ago at 5 Bcf, and all these wells were flowing in to about 1,100 pound pressure system. And as we drill, as we increase our drilling activity, we also did a lot of fieldwork. We added in a lot of new pipes and compression, and we lowered the field pressure from 1,100 pounds to about 500 pounds. And all the PDP wells respond to that lowering of field pressure, and therefore move the type curve up from 5 Bcf to 7.5 Bcf.

As we ended '08 we had plans in 2009 to continue to lower the field pressure from 500 pounds to 200 pounds. But as part of our budget cuts we decided to hold off on those projects. So as we didn't lower the field pressure, the wells suffered from the 500 pound line pressure so we came off a 7.5 Bcf type curve.

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.

What we couldn't tell at year end '08 was how those wells -- they may have went fine and not go off the curve in '09 but unfortunately they did due to the higher pressure, so at year end '09 that's where we made that change.

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

That's right. And that's the plan this year is to drop it to the 200 pounds. We would expect the type curve to get back to where it was.

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?

Let me walk through the prove developed here. We started -- we ended the year end 2008 at 943 Bcfs, and we had 223 of total write-offs. Then we added, through drilling, 137 Bcfs, and then we had additional write-offs in what we call tails of 130 B's, and then we produce 105 B's. Then we added the Forest -- yes, the Forest deal was 204 B's in PD reserves -- 440 total, but 204 was in PD. So we ended the year at 823 Bcfs of PD. If you had add the tails back in, because of pricing improvement, we would be at 953.

Okay, that's all. Thank you.

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

Looking real quickly at the 102 Bcf that was added from the [Testnes] 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?

Sure. We'll discuss a Testnes type curve at the analyst investor day. Rodney will have that, and what we'll 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 as well.

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?

Yes. But here's the way we'll discuss today is not change of budget from what we had because we're looking at moving from more gas rigs to oil rigs, but we haven't made that change yet. So there's no official change in the budget. But we do have the ability to speed up or slow down our drilling.

There's a 30-year commitment of 3.5 Tcfe -- or Tcf -- of CO2 across the Pinon Field. We haven't lost that CO2, either fortunately or unfortunately the gas has a tremendous amount of CO2 in it. And we still have those reserves in place. That's why Oxy and us together made a very long-term contract so we could be flexible in the amount of gas we want to bring on in one particular year or maybe a span of years. And there are penalties that can be incurred, but they are not to a point that it wouldn't -- if you made that choice, you'd be much better off today drilling oil rather than gas. Remember, we do have a substantial amount of gas that's already flowing into existing plants that we can move other to the Century, which we plan to do.

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

$430 million is what our current budget is.

$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?

Yes.

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?

I'll let Matt take the specifics, but we love the acquisition that we made, and we love being in oil and there is -- we continue to see a lot of upside in the properties that we acquired, and Matt can go through the specifics. You have the specific locations, Matt?

On the Permian, the good thing about the Permian, is when we bought it, we bought it at a higher oil price than what we book at the year end because the year end was 12-month average. But at the acquisition price, we basically bought it for very close to PDP value. As it turns out, we have roughly 2,700 locations out there to drill -- about 800 PUDs, close to 1,900 what we call resource locations. So there's 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're running six rigs, and we're looking at potentially ramping up to eight rigs as the year moves on down towards maybe the middle of the year.

Okay, great.

Most of the locations are Clear Fork locations. That's something we've been drilling for the last three years in the [Netric] county area.

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?

Yes, I think the break-even -- well, our PUDs being run at $3.87, but out there in the Pinon Field at a little bit over $4, you start adding PUDs back in. At about $5, $5.25, they're pretty much back on the book, and so I think you're in this $5 range for break even.

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

That's right.

Thank you guys.

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

Perfect. Thank you guys so much. I really appreciate your time.

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

Thank you. Good morning.

Good morning.

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.

The borrowing bases would stay at $850 million. 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.

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

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

Yes, we do have. We'll be addressing those on Tuesday of analyst day.

Great. Thank you.

Thank you.

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

Thank you, good morning.

Good morning.

Hey, 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?

Our type curve is 6.6 Bcf. I believe that whenever we put in the compression we'll be back to the 7.5 Bcf per well, and the upside what we show is 8.4 Bcf. What we'll 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 I still look at this as a 7.5 Bcf type of well.

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

That's really not changed any, Joe. As we've always looked at 62% to 65% CO2, and that's still fairly consistent. It might change from, over time from it, we might have been as low as 60% to as high as 65%, but give yourself a 5% range in there for CO2 across the field.

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?

Yes, on a 6.6 type curve, you're right it at 2 Bcf. That's netting out CO2, then netting it back to -- netting out the royalty. Probably about 23% out there. On -- and these are net Bcf. Gross Bcf, basically you just take the amount of methane content, multiply it by the your whole EUR.

I think that's the difference we came up with. Some people, and maybe some of the slides we've had, we talk about gross gas without -- net of royalties. So I think that's maybe the difference that we're talking about.

That's exactly the difference.

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

That's right.

Okay. 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.

And that's a little bit dangerous to look at it that way because you have a preponderance of your wells at the front end of the curve. So I think the type curve -- they do follow the type curve.

Got it. 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?

We should have that handy, don't we? We're going to flip to that.

On a volume basis?

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

Gas was 52%, and oil was 48%.

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?

That was really just tail effect from running lower gas price where you go negative cash flow a few years earlier.

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

Well, it would be across the board.

Across the board.

You're cutting off at -- I can't remember the exact price, but you ran $75, now you're cutting it off at $57.

Got it. Thanks. Very helpful.

Thank you.

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

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.

Sure.

On the gas side that. The Pinon types.

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

Okay, fair enough. Thank you.

Thank you.

Your next question comes from the [Wei Dow] line of Stone Harbor.

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?

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

Yes. You started with 943, then the second number you were running through -- you're saying some write-off related to -- what write-off?

Those are just our revisions due to type curve changes, high line pressures that stuff.

And what number was that?

That number is 223 B's.

Okay.

Then we added 137 B's in PUD conversions and new drill, and then we lost 130 B's due to the tail impact of lower pricing.

Okay.

And then we lost 105 B's due to production, then we added 204 B's of PD reserves from the Forest acquisition. That gets you to 823. As prices have improved -- price already higher than year end, so what you could do is add that tail back in, so that guess you back up to 953.

Okay.

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

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.

Want to grab the press release?

Let me get to where you're at.

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?

I'm sorry. The net revisions was -- when we talk about a net revision, the total of performance, going through all the numbers, it comes out to 313 B's of negative revisions, and 255 B's of positive adds. So that is, I think, 58 B's differential, or call it 60 B's. Some of this has some rounding impact. So when you look at the page nine, it shows revisions of 69 B's and extension of discovery of 9 B's. That's the difference right there. The two 60s in net revisions match up.

Okay.

Those are performance revisions. The 1.123 negative revision is all due to pricing. That's the 130 B's in tail write-offs, because of lower -- because of higher economic limits -- because of lower prices. Then the 993 B's remaining are the gas PUDs write-off due to pricing. So basically you have 1.123 T's of write-offs that are attributable to pricing, and net 60 B's write-off that are attributable to performance. 105 B's of production.

Okay. Thank you.

Thank you.

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

Thanks, Tom. Back to the high CO2 gas and Warwick thrust -- if you moved all of your gas -- or do you have the flexibility, I guess to move all of your current production into the Oxy plant when that comes up?

Yes.

Is that -- 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 have out now?

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.

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

Sure, Matt, you got that?

From an efficiency standpoint, one of the problems we have now is that the plants that we're operating through, the technology that we're using, are dated. These plants -- these legacy plants were processing CO2 -- were built in the late '60, early '70s. And as an absorption process with the proprietary chemical called Selexol. When we flash the gas from 1,100 pounds down to [two] pounds to extract the CO2 we lose probably six to eight, maybe 9% of our methane out the stacks right now.

With the Century plant, there's two processes there. There's the absorption process, like the Selexol I just described, but also there's a refrigeration or fractionation process. It's used as a two step process of extracting CO2, but in doing so, you improve your methane losses. It will drop from about 8% down to probably in the 2% range. So right there you should gain about 6% in methane sales, just in the process itself. But that's not booked, or that's not in our production nor is it booked in our reserves run.

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

Sure it could be an impact. I don't know what the magnitude of that impact might be, but any time you can show higher sales there, per Mcf, from the wellhead, because you will have a gain at the tailgate of the plants. They'll certainly help with type curve and with your PDP forecast as well.

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?

Well, let me answer it this way. The annual obligations are confidential due to competitive reasons for Oxy. However, what's public is 3.5 T's over 30 years. You can do some simple math and get around to what an annual obligation might be.

But just with our current production right now on the high CO2 gas, close to 300 million a day of total volume, you're looking at probably 75 or 80 B's 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'm guessing in the 90 Bcf range of CO2, and then there's -- we've also been banking volumes with Oxy to the tune of 30, 40 Bcfs over the last couple years. So I don't think there's going to be a problem at all in meeting the obligation at this point.

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

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

Thank you

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

Good morning, guys.

Good morning.

You guys may have already given this but do you give a production split on production from Pinon versus Permian and on the fourth quarter numbers?

I think we have that. Hold on a second.

Give me just a minute, Brian.

And while you're looking for that, could you also look for just what the proved developed PV-10 was?

Proved developed PV-10.

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.

I can only address what we do, but I can say that a low rate well, if you are forced to have flat pricing forever, doesn't have as good a 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 your gas early in the life of the well. So if you think through that math you can get to the different rates of return that you might have between high rate initial wells and low rate initial wells with less decline.

Okay.

Brian, back to your first question, you're asking about production?

Yes.

And you're wanting the breakout of that, is that correct?

That's right. By as many assets as you're willing to give.

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

Okay. And so --

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

Exactly.

That's about $1.1 billion.

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

I don't remember Forest having that number. But I don't believe there was ever a published number like that for Forest. The only thing -- the only difference we had was that we lost some reserves because of the tail as we mentioned, but that came in -- we only owned it a few days before the end of the year.

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

Got it. That's helpful.

That was moving up from where we were, when we bought.

Thank you.

We bought at 482.

That's right.

Okay, thanks, guys.

Thank you.

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

Quick question on capital allocation. I was hoping you could help me understand why spending up to $100 million on the new SandRidge commons building is a good use of capital for shareholders, particularly if you are cash constrained.

Oh, sure. We had -- you ask about the building, correct?

Yes.

We had an opportunity in 2007 to either -- we were out of space in the existing building that we were in, and we had ten floors there, and were looking to buy land and build or the opportunity came to buy what is potentially here downtown about a million square feet of potential space where we're going to take out some of the buildings so they 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're talking about, but it's -- 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're glad that we made the purchase. I think it's a good asset for us. Gives us ample opportunity for growth in the future, and we own two city blocks of downtown Oklahoma City.

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

And assumes future growth.

Thanks.

Thank you.

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

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

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 it's 67,000 MBO and 115 million cubic foot of gas. Clear Fork wells have just a tremendous rate of return at today's prices. nd especially where we drilled the -- now about 120 wells in the Goldsmith adobe unit -- the rates of return have been phenomenal.

Thanks, Tom.

Thank you.

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

Good morning, guys.

Good morning.

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

I can't hear you, I'm sorry.

How's that?

Better, thank you.

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.

Showing up in our reserve numbers?

That's -- 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?

The 255, why is it so low?

So the expenses and discoveries number, you have 9 Bcf of adds there. Then you mention the 255 showing up 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?

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

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

I think you -- usually, I think in-field drilling would be reported the same way.

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 that up would keep going up. Do you know what's driving that?

Matt's got that one. Are you talking about on the table?

Yes.

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

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

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

What's the oil value?

No, on a percentage of the proved reserves.

Percentage on the end of year case?

Yes.

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?

End of year by volume?

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

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

That's what I thought it was.

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.

Yes, Brian.

Gregg.

Gregg, I'm sorry.

If you follow the extensions and discoveries bucket that is a calculated number. As you move up the price scale what we had identified, as 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 the extensions goes up, the revisions get slightly bigger.

Thank you, guys.

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.

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.

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