SandRidge Energy, Inc. (SD) Q1 2010 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the First Quarter 2010 SandRidge Energy Earnings Conference Call. My name is Josh, and I'll be your coordinator for today. [Operator Instructions] I'd now like to turn the presentation over to our host for today's call, the Chief Financial Officer, Dirk Van Doren. You may proceed.

Thanks, Josh. Last night, the company issued a press release detailing SandRidge's financial and operating performance for the first quarter of 2010, and will file the 10-Q this afternoon. 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 the forward-looking statement. Please keep in mind that during today's call, the company will be making forward-looking statements including statements about our proposed acquisition of Arena Resources, and the anticipated benefits of the transaction, 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 differences is detailed on the company's filings with the SEC. Today's presentation will include information regarding adjusted net income and adjusted EBITDA and other non-GAAP financial measures. As required by SEC rules, a reconciliation of the most directly comparable GAAP measures are available on our website under the Investor Relations tab. Now let me turn the call over to our Chairman and CEO, Tom Ward.

Thanks, Dirk, and welcome to our first quarter earnings and operational call. In addition to Dirk, we also have Matt Grubb, Chief Operating Officer; Kevin White, Senior Vice President, Business Development; and Todd Tipton, Executive Vice President, Exploration, on the call today. As our press release indicated, we have some exciting news to share with regard to our exploration activity in the West Texas Overthrust, as well as an update on our oil activities as we integrate the Forest acquisition and move more rigs to the Permian Basin. As we continue to execute our strategy to increase oil production, we will be reducing gas-drilling-related CapEx and shifting more capital to the Permian Basin and accelerating the development of our oil plays on the Central Basin Platform. With this said, we will continue to develop the high CO2 Warwick Thrust reservoir in the Piñon Field with the 10-rig program. EURs for the Warwick wells with Tesnus is 7.3 Bcfe and $1 finding cost. We're excited about the Century Plant coming online later this summer, as that will only improve our Warwick well economics. As a result of these changes, we will cut our 2010 capital expenditures by $60 million, while increasing 2010 oil production guidance by 600,000 barrels. We embarked on exploration of the West Texas Overthrust in early 2007 by starting a 3D seismic shoot that will be the largest proprietary contiguous onshore 3D seismic acquisition in U.S. history. This 1,300 square mile shoot was completed in 2008. As a result of the 3D seismic work, we have drilled the first two of six exploration wells planned for 2010, and have seen positive results on both. For a little background, the Piñon Field sits in the Northwest quadrant of the West Texas Overthrust. We believe that this areas in an area where the CO2 content will be some of the highest in the WTO. We have contended that as we move south or east of the Piñon Field, we will have less CO2 or even no CO2 if we find a reservoir. The Piñon Field is projected to produce more than 15 Tcf of gas from less than 15,000 acres, making it one of the best gas fields in the U.S. Piñon also sits on a very large structure that can only be found using 3D seismic. Therefore, our belief has been, if we have the proprietary data to look for those structures with reservoirs that can be drilled convincingly where CO2 is less, we'll have a definite competitive edge because of the amount of gas that can be found at relatively low cost. This theory of drilling conventional structures with porosity and permeability has almost become a lost start in our business today. The storyline is that all of these have been found. While we agree that it's more difficult to find fields conventionally today than previous decades, we also adhere to the thought that less competition and more science is good, and we'll be rewarded for our efforts. SandRidge now stands to reap the benefits of these ideas, as we continue to seek large gas-bearing structures on our more than 500,000 acres in the West Texas Overthrust. Now I'll talk about the Owens 103-1A well. This well, located 35 miles East of the Piñon Field, was drilled on a Magnolia Structure to a depth of 12,000 feet and encountered three separate sands that appear productive. We're in the process of testing the lowest sand at 10,400 feet, which is called the "Owens" sand. This reservoir is flowing at a rate of over 2 million cubic feet of gas per day at 1,400 pounds flowing tubing pressure, and the gas contains less than 1% CO2. We have two additional sands up-haul at 8,300 feet and 6,400 feet that are waiting to be tested. These upper sands are the same reservoirs as Tesnus sands that produces in the Piñon Field. We believe that the Tesnus sands and the Owens well will contain little to no CO2 as well. If all three sands prove to be productive, the Owen structure may contain as much as 1.5 Tcf of recoverable gas reserves. The King 9 23-1 was drilled to a total depth of 9,620 feet, and encountered 900 feet of the Warwick chert. This was our second exploration well. The Warwick chert is a prolific high CO2 reservoir in the Piñon Field. This zone tested tight but has been interpreted to be 2,000 feet down dip to the top of the structure. We have, on several occasions, in the Piñon Field, moved from down dip tight wells to up dip producers. While the King 9 well did not prove to be economically productive, we did establish that the gas contained in this reservoir is 78% methane. We are currently evaluating an up dip location in the King Structure for future drilling. We are also continuing to expand our asset base and transform our company into more oil production. We have chosen the Central Basin Platform and the Permian Basin as our focus area for oil, because of its proven historical performance and their tremendous geological and economic advantage of being able to drill thousands of low-risk vertical wells and shallow carbonate oil reservoirs. We are very fortunate to have been a first mover into oil starting in early 2009, as we now are starting to see the benefits of that decision. The majority of our wells take less than one week to drill, and our entire Permian Basin inventory has a rate of return of more than 80% based on today's oil strip. While we believe in the long-term viability of oil as a premier commodity, we also want to lock in this rate of return for as long as possible. Therefore, we have chosen to hedge the majority of our oil production through 2012, and are evaluating hedging 2013. The type of wells we drill do not have as much sensitivity to service cost because of the shallow depths. Few days on location and a majority of the expense drilling versus completion where we own our own drilling equipment. Therefore, we have an effective hedge already in place on the service side. As a result of the Forest Permian asset acquisition, total oil production increased by 66% quarter-over-quarter. Organic growth in oil production since the end of 2009 is about 16%. Oil accounted for 28% of our total production in the first quarter of 2010. We have moved from five oil rigs in January, to 13 today, drilling for oil. We plan to be at 18 oil rigs by the fourth quarter without Arena. Therefore, we're increasing our oil guidance by 600,000 barrels this year on a stand-alone basis. We will discuss different oil guidance post-Arena transaction. We will also cut our total CapEx by $60 million due to less natural gas-related drilling than earlier projected. Our focus is to maintain a disciplined approach to capital expenditure, maintaining EBITDA and not chase low-value production growth. As we have discussed in recent quarters, money is best spent today in drilling oil wells that have shallow dependable production profiles with certainty of economic returns. However, we are also pragmatic to believe that we cannot keep 80% rates of return forever, and have therefore embarked on a plan to lock in as much oil production as possible to fully insure those certainties of future profit discussed earlier. We have announced that we intend to close our Arena acquisition in early June and look forward to the continuation of their activities and success in the Central Basin Platform with ours. There are no issues of this integration as we operate right beside each other. The Century Plant is still on track to start this summer. We're projecting an August start date. We have moved down our Piñon ramp up from our projected 18 rigs to 10 rigs, and will maintain that amount through 2010. Piñon continues to perform very well and we look for a time of better gas prices to increase activity in the field. Remember that we had 34 rigs running in Piñon just 18 months ago. However, with the current 10-rig program and potential ramp up in the future as gas prices improve, we plan to grow our production and fulfill our obligations to the Century Plant. We started to move towards drilling and acquiring oil assets in early 2009. We also hedged our natural gas production in the fall of 2008 for two years, and are enjoying $9.15 per Mcfe prices on nearly 90% of our production this year. As we have decided to focus on EBITDA, our move to oil allows us to be much more patient, waiting on the natural gas market to come back to a higher price than today. We continue to be a company that focuses on growth through the execution of low-risk opportunities. That is, we focus on shallow conventional reservoirs that have decades of production history, low-cost vertical drilling and certainty of economic returns. Our newest field in West Texas, the Piñon Field, was discovered in 1981, and now has over 750 producing wells. The discovery of commercial production on the Magnolia Structure culminates three years of exploration work. Our next step is to test all three zones in the Owens well as soon as possible and determine its potential reserves and flow capacity. We are also evaluating a delineation well or two to verify the size of the structure and how it ties into our seismic picture. This will help us to generate a development plan and gain a better understanding of the infrastructure build-out requirement to commercialize this gas. The speed of execution here is predicated on gas prices, but we want to have a plan and be prepared to move forward on this exciting discovery as soon as appropriate. The Owens well is 11 miles from pipeline, and we can build a pipeline out, designed to 100 million cubic feet of gas a day capacity for $5 million. In regard to our additional exploration wells, we're in the process of updating our geological and geophysical model, incorporating the latest information we obtained from our first two wells. We are still committed even more confident now about our program. To spud at least four exploration wells this year, which one may be to drill the top of the King Structure where we encountered over 900 feet of chert in the King 9 23-1. Lastly, the Arena transaction allows us the flexibility to continue exploration without the need for a JV partner. Each time we spud a well on a new structure, we're looking for multiple Tcfs of gas for the cost of one well. Therefore, we will drill some more structures, then decide how best to monetize for development. I will now turn the call back over to Dirk.

Thanks, Tom. 2010 has been an eventful and transformation year for SandRidge, and we have only completed a third of the year. For the first three months, we recorded EBITDA of $141 million, with 8% sequential production growth, and oil comprised 28% of production compared to 18% in Q4 2009. Looking inside revenues including hedges, oil and NGLs accounted for 47% of commodity revenues for the quarter. And it probably should not surprise you that our Permian properties were the most profitable producing region within the company during the quarter. Two numbers in the quarter need explanation. First, LOE was higher because of the impact of lower volumes and $3 million of workover expenses, while we had no workover expenses in the first quarter of 2009. Second, G&A increased because of legal expenses related to the Arena acquisition and IT expenses related to the Permian acquisition. Cash employee cost were flat year-over-year. We have made great progress since we announced the acquisition of Arena Resources on April 4. We received early termination of Hart-Scott-Rodino on April 30, our S4 was declared effective by the SEC on May 5. The record date for shareholder vote has been set for May 5, and the shareholder meetings will be held on June 8. As part of our 2010 financial plan, we extended the maturity of our bank credit facility to April 15, 2014, from November 2011. We were significantly oversubscribed in the transaction and brought in three new banks as well. Thus, we were able to lower largest exposure to SD to 5.9% from 6.3%. We thank the 27 banks that participated, and we're in compliance with all bank covenants at the end of the quarter. Since our last earnings call, we have added about 3.4 million barrels of oil hedging to our portfolio at a price of $84.40 per barrel. The bulk of the hedges were added in 2011 and 2012. Natural gas at Waha averaged $5 per Mcf during the quarter and $4.22 per Mcf during March and $3.93 per Mcf in April, and it's lower now in May. The recent levels did not make for attractive returns, so we responded by reducing capital expenditures and moving more capital toward oil drilling. Because of this, our guidance has changed, with more oil production and lower natural gas production. Our costs are going to be slightly higher on a unit basis to reflect the lower overall production. We expect to provide new guidance shortly after we close the Arena transaction in June. That ends our prepared remarks. Josh, we'd like to open the call up for questions.

[Operator Instructions] And our first question comes from the line of Dave Kistler of Simmons & Company. David Kistler - Simmons & Company: Real quickly, just thinking about the CapEx reduction and where capital is going to be directed now. Of the $800 million that's going to be spent, how does that split between oil and gas? And what was previously targeted on the gas side? So thinking about it both from the reduction and from reallocation.

Dave, on our revised drilling schedule this year, we're looking at drilling 146 wells in the Piñon Field and 256 wells in Permian. And about 57 wells in Oklahoma and East Texas. And the bulk of the Permian well, all the 256 wells, that's all oil, and about 80% of the wells in the Eastern division is for our wells in the horizontal mills in Oklahoma, which is also oil. But from a capital standpoint, the total capital allocation just to drilling is about $570 million. Of that, about $330 million -- plus the $330 million allocated to oil drilling. David Kistler - Simmons & Company: And then just thinking about the 3D a little bit and what you guys found in both of the wells, and most specifically, the sands that you found in the Owens well. I would imagine when you're targeting that, you are assuming it was going to be chert. Is there anything we're learning relative to finding a big sand pay as opposed to how the 3D was imaged, and maybe that you thought it was chert, but it's sand. Are there any takeaways yet or is there stuff that has to be reinterpreted in the 3D to refine it to be able to track how the structure moves?

I'll take a little bit of that, and then I'll let Todd Tipton discuss also. With each of the structures that we tried to drill or that we do drill, there will be an interpretation risk that the image that we see doesn't exactly correlate tens of miles away to the Piñon Field. We've done a great job of nailing down structures. In the King well, we actually placed the chert into the structure. However, the structure came in lower than we anticipated as we drilled the well. In the Magnolia Structure, the structure held up all the way through drilling, but then the bottom area that we thought was going to be a Piñon-type forward chert is a sandstone. Now all things being equal, an overpressured sandstone is a very, very good reservoir to drill for. And ultimately, might be better than drilling for a fractured chert, because you have less risk of the fracturing. So in my opinion, if we can find sand charged reservoirs, that is going to be equally as good as drilling for chert, because it takes away a risk of fracturing. I think I'll let Todd talk a little bit about as far as looking at the seismic and interpretation.

Tom addressed that very well as far as the sands that we're looking for and the structure. The key point that we find in Magnolia, we cannot, actually from the seismic, determine chert versus other reservoirs. What was important in the sands that we did find in the Magnolia Structure, you have to remember that those sands are within an overall thrust fault. So that's very important, that we're still looking at the same structure and the same mechanism that puts those reservoirs in those structures. What we will find -- your reinterpretation, your comment about reinterpretation, that's absolutely what has to be done to be able to calibrate that seismic to what we found in both those wells. We do still see potential on the east side of WTO, not only for other structures that would contain these Pennsylvanian aged sands, but also still have the possibility of finding chert on the East side.

The key risk has always been CO2 in the West Texas Overthrust. So finding a gas-bearing reservoir at depth that's overpressured on a structure that has no CO2 is an incredibly exciting happening for the company. And especially, if you think of, we're the only company that owns a basin. We have 500,000 acres. We have the sole ability to look for structures, because it's very complex and you have to have 3D. We own proprietarily the 3D, and we're close to infrastructure. So it's much like drilling a foreign concession, except for having infrastructure in place that you can lay and sell in a matter of months. So that's very big news for us to discover gas on one of our first two tests. David Kistler - Simmons & Company: Stepping up to the shallower sands in the Owens well that correlate with the Tesnus. Can you just compare, in terms of thickness, of what you saw there versus what you guys have in the Piñon? I know you haven't floated back, so there isn't a way to tell maybe if it's commercially viable. But is it fair for me to think of it from a thickness perspective and be able to correlate it back to the Piñon and realize that Tesnus is commercial in the Piñon?

Sure, and I'll also let Todd chime in with me. The two sands that we see also appear in the Piñon Field. So that is very good in that you can correlate sands across a 35-mile area and put them on structure. The good thing about Magnolia Structure is it appears that our gas shows were better, and it appears while drilling through that the structure has more pressure in it. We don't know that, but the zones that we see are favorable to what we have in the Piñon Field. And I think we had already shown a log over the top sand, and it appeared in size and porosity, thickness, to correlate to a well in the Piñon Field that would -- our average Tesnus, well, makes about 7/10 of a B, and it looked like one of the better wells in the Piñon Field. So we haven't tested it. But we feel comfortable that there should be gas in place and these zones should be sweet.

Just adding to that, the thickness in both of those sands comparable to their better thickness in a majority of the Tesnus wells in Piñon Field. Comparable porosity, but very encouraging because we had gas shows throughout both zones. And typically, we don't see that at Piñon Field. It's not until you go ahead and frac those sands that you see the gas. So this is encouraging. Both at 6,400- and 8,300-foot sands, are slightly deeper than what we see at Piñon, which could also mean a little bit better pressure and more gas that could be stored in those sands as compared to Piñon Field. David Kistler - Simmons & Company: Just in terms of thinking about the leasing side of things. In your release, you talked about these being long-term leases in nature. Can you just walk through what the obligations are in order to hold these leases?

Sure. In both of these structures, the leases that we have, have long-term terms, and we're under no issues in the next few years as far as just holding acreage on the two structures.

And our next question comes from the line of Joe Allman of JPMorgan. Joseph Allman - JP Morgan Chase & Co: So back to the question about the Owen sand. Todd, what does that correlate to in the Piñon Field?

The Owens sand, we feel it's a lower Pennsylvanian sand. So it may be, right now, until we can tie everything in, and you know, Joe, that especially in that southern part, we have very few wells. We think we may have found a totally new stand than what's been seen, at least in this area. It may correlate to something up in the Permian Basin. But we think it's a new sand and doesn't correlate directly over into a Piñon Field.

And Joe, outside of the Piñon Field, across all of the West Texas Overthrust, there are just about 50 wells that have ever drilled through this depth. And most of them, not on structures. There are only a couple of deep wells that produce outside of Piñon. Joseph Allman - JP Morgan Chase & Co: And I suppose you didn't drill deep enough to find some of these other intervals that you have over at Piñon, like the Caballos, for example. Potentially, they could be much deeper here in this location.

Yes, that's correct. Joseph Allman - JP Morgan Chase & Co: And then related to the downhaul restriction, could you explain what is that and why is it causing lower production than you otherwise would have?

Yes, Joe, this is Matt. The well that the perforations in this Owens sand, the overall purse is about 10,460 feet to 10,700 feet, and it's in a 4.5-inch liner, that's a 7-inch casing. And we went in on a wireline set of packer at about 10,400 feet. And when we tried to leave the well down to pack in and plug it in, when we tried to bleed the well down, the run tubing, the well never bled down. And so we feel like that the packing elements fell in this packer. And so what happens is it leaves you the internal diameter of the 4.5-inch casing is 3.92 inch. And the outside diameter of the packer is 3.75-inch. So you sort of have a flow, an annular space there of about 3/16 of an inch, beyond the 10,400 feet that you try to flow gas up through. And so if it lifts any kind of sand from the frac at all, it wouldn't take very much. A cup of sand will plug that off. We feel like we're continuously having to fight that annular restriction, plus any sand that we're getting in the flowback now. But I think once we can get in here and we're going to sub in tubing and work on trying to pull this packer out of the hole and go back in, dress off and reset it. And so we can get a regular flow test up through the tubing. Joseph Allman - JP Morgan Chase & Co: So it sound as if it could be severely restricted actually?

It could be, yes. We still don't have a good feel right now. We still don't. Joseph Allman - JP Morgan Chase & Co: And what does the pressure there tell you?

Well, the pressure, actually, the reservoir pressure appears to be over pressured normal gradient, call it .45. This had a gradient of about 0.75. So at least in the Owens sand, we feel like we're in an over pressured situation there. Joseph Allman - JP Morgan Chase & Co: And then a separate topic, onto the Century Plant. Do you expect to meet your obligations this year in the Century Plant? And if not, are you planning on paying the penalty? And also, are you planning on taking any CO2 from the existing plants and channel those over to the Century Plant?

I'll chime in first and then let Matt and Kevin discuss a little bit. The Century Plant allows us many things. One is, efficiencies. And so we have over 300 million a day of gas currently that we can switch from our current locations of our existing plants over to the Century Plant and we'll be picking great efficiencies, and Matt can talk a little bit about that. But we have a 30-year contract with Occidental Petroleum and over that 30-year contract, we have to deliver 3.5 Tcf of CO2. And we have enormous amounts of gas in the Piñon Field and we'll be able to meet our obligations moving forward in filling the Century Plant and meeting those obligations. So Kevin, I'm going to let you hit it and Matt as far as just as yearly basis and how we want to discuss it.

Well, yes, what Tom's talking about inefficiency is if you just look at the Century Plant as a stand-alone project and whether you're making an investment or not, we would probably do it. What's happening now is in the legacy plants that we process gas, we lose upwards of 7% or 8% just out of the stack losses. We have very inefficient compression and fuels. They've yet to burn to run the plants. Fits in an efficiency savings and a reduction stack losses going to Century. We would gain about $10 million per 100 million cubic feet of gas processed per day, the $10 million being the annual savings. So if we switch over this 300 million cubic feet of gas into Centric from our legacy plant, then which we'll gain about $30 million per year, and that would more than offset any filling that we're caught playing right now with Oxy. Those actually -- a moneymaking event for SandRidge. Now from a penalty standpoint, Joe, we would not have any penalty due until 2012 on this day. We also have been sending Oxy CO2 all this time, so we are banking CO2. I think with the banking, we would not have any penalties in 2010. We didn't do anything but kept our production flat in Piñon. We would standing them something in the order of 70 to 75 Bcfs in 2011, okay? Now you know, we are running 10 rigs so that production would go up. Yes, we're sending them 70 to 75 Bcfs, so our penalty probably would be in the $10 million range. But we'll still be ahead from our efficiency savings of switching over from legacy to Century.

Joe, even a more important point is that at any time as a gas price move up, Piñon Field, even with high CO2, and it has about $1 finding cost. So let's assume we find an even more than one big structure that lets say, at Owens field, you could have a finding lower costs than that and it would be more efficient for us to drill wells in a different place. There still would be ample opportunity for anyone else to join us even if we couldn't fund it all ourselves to -- we could do a JV in the Piñon Field at almost anytime because of how good it is to drill wells there. So I don't look at us as having any issue with filling up a plant going forward. Joseph Allman - JP Morgan Chase & Co: And then just lastly on CapEx, so you're dropping CapEx by about $60 million. Just help us reconcile that because I know you were dropping some gas rigs, you're dropping gas rigs and you're also not ramping up as much as you previously thought to the 18. But you are adding a bunch of oil rigs. So how is it that you're only dropping CapEx by $60 million?

Yes, I can go with CapEx numbers in more detail, Joe. We're going to drill a total of 459 wells, that's our projection and spent $570 million drilling, okay? And so in that 459 wells, we have 146 in Piñon, 356 in Permian and 57 in East Texas and Oklahoma. And the associated spending there is about $340 million. $3 million in Piñon, $330 million in Permian and right at near $100 million in the Oklahoma's East Texas area. $570 million for drilling. And then we have $110 million budgeted for carryover of work from last year, the carryovers into 2010, non-op activities, workovers and recompletions. And all that adds up to $110 million. And then we have $30 million in the leasehold in geology and geophysics; seismic, leasehold and seismic, $30 million; $80 million in midstream spending; $5 million in oil field services. We expect to spend about $35 million in tertiary this year. About $21 million just in the general corporate. So that adds up to about $851 million, and we credit back $50 million for pre-bought pipe that we bought back in '08. And so our budget comes down to about $800 million. $60 million, the initial budget we had $60 million, and this a moving parts. But we are adding more rigs to the Permian and we can start going up to 18 rigs in the Piñon. We're going to keep it at 10. We had two rigs running in East Texas that we're going to run for an entire year. We've since dropped those two rigs. And so when you add the rigs, you take off the rigs at Piñon, take off the rigs in East Texas, net of about $60 million savings overall.

And as you know, it's easier if you're looking to grow production, it's easier for us to grow our production drilling, gas wells rather than oil wells. But what we're really doing is chasing the EBITDA.

And our next question comes from the line of Brian Singer of Goldman Sachs.

Can you talk a little bit more about the King well and more specifically the potential for the up dips? And kind of what you're seeing there relative to the non-commercial quantities that you saw down dip? And then how you're thinking about future seismic and additional testing in the King area?

Sure, I'll hit it first and then turn to Todd. The King well, when we spud the well, we thought that we were on top of the structure. And after we drilled down to the point that we thought it was the top of the structure, we were still in the Pennsylvanian section. So we continue to drill and found the reservoir at a structurally low position. However, the good point was that the reservoir was very thick, over 900 feet thick, which puts us in the upper quartile of pay in the Piñon Field. And then ultimately, the second good thing was, that while tight, we ran an FMI log and still have fractures. So then, lastly, the third good thing is when we tested the well, we saw gas, and it was 78% methane. So that helped us in our belief that as we moved away from the northwest part of the West Texas Overthrust that we would have less CO2. This was one of the more risky locations that we have as far as the structure that would be high CO2. So we've really thought that there could be a high chance here to have as much CO2 as Piñon if we were off just a bit in the way we looked at the West Texas Overthrust. So it's very encouraging that we have a majority of methane and that we have the thickness and fracturing. And also, we needed to just get more up on structure. And as we do our reinterpretation, it appears that we can move 2,000 feet up dip. And then you still have to make sure that you have the gas in place. But it does give us more encouragement that this would be a less risky place to drill. Well, it wouldn't be a delineation well, another test to test the structure. And so there is still some risk that you could have a seismic interpretation, could be off a little bit, or maybe we didn't see commercial quantities of gas here. So there is still risk to the structure, but it's much more diminished in my opinion.

The broader structure that Tom referred to and as we -- you have to remember we correlated the chert chart, the main reservoir from miles away from outcrop. And again, we cannot directly detect it on the seismic, and we do not have any chert in any others wells in the immediate vicinity. So part of our model and our interpretation had potential for two zones of chert in this particular well. And that's why our position on the structure was a little bit further to the south than optimal to be at the crest of the structure, trying to encounter the multiple chert packages. As Tom said, the upper portion, a little different than our modeling, was an extended section of the Pennsylvanian. But what was encouraging is that the chert section that we did encounter was nearly twice as much as what typically is found in that region. So even though it may not have been exactly at the crest of that structure, valuable information and what we were able to gain from that well. But also, as Tom had mentioned, moving 20 miles away strictly on the modeling and the 3D that we had to try to define that structure and the reservoir in that particular case, the chert reservoir, very exciting, especially as we look forward to additional wells in that area.

And then secondly on Permian, I think you had indicated that you'd added about 36 wells during the quarter. Can you just talk about the well results there? And to what extent, if any, is the increase in oil production guidance, so are the result of increased rig count versus any changes in well results productivity?

Sure. The well results are in line with what we projected and what we think they should be, remembering that the Permian has a long history of decline curve. So once we drill a well, we are fairly confident with what we're going to be able to find. The good thing is there does appear to be additional work to be done in some other limestones, some other carbonates on the Central Basin Platform that we're starting to work on. If you look at what we'll do, post-arena, is just give a tight curve for all Permian wells, because as we look at a four-day well to drill a San Andres well, or a six- or seven-day well to drill a Clear Fork well, you might drill some Wolfberry wells in the Midland Basin or Bone Spring's well, wells in the Delaware Basin. All of those added together are going to have north of an 80% rate of return. And so what we really trying to do was to focus on making sure that we hedged in that production and that rate of return, because our service costs can't change very much with us selling our own rigs and spending very little on completions. So what our goal is, is to maintain the drilling, and when we bring the well on, knowing how much we're going to produce, but then to hedge in on that rig return.

[Operator Instructions] And our next question comes from the line of Jeff Robertson of Barclays Capital.

Tom, can you all talk a little bit about the King Structure and the context that if you get up dip and make a discovery, what kind of options might that give you since you're 10 miles away from Piñon with putting a higher methane stream through the Century Plant?

Well, it's 20 miles away from Piñon, but still an area that's very easy to lay pipelines. So if we did have a discovery there, we would have a lot of options. We can bring gas north of, not only into the Century Plant, but we have our existing plants that you can take less CO2 through. And if we found, if you're only looking at 20% CO2, we might even have some options with regard if we may want to do rather than to bring gas north. That is still a long way from having to discuss that. But having 80% methane, if you have the same type of reservoir, is obviously good. We would have a lot of options.

Can you all also talk about what the LOEs are on these higher methane wells versus what you're doing at Piñon?

Yes.

As he's looking for that, I'll take the -- your thought -- I mean, the question was that the higher -- the LOE on high methane wells versus having to deal with CO2, correct?

Yes.

LOE in the Piñon right now is, just looking at strictly LOE alone without processing and gathering, is $0.71 per Mcf. Then when you add in process and gathering, which is a lump number, it adds about another $0.85 to $0.90 per Mcf. So if your gas is pure methane, you're probably looking at, say, $1 per Mcf LOE versus $1.30 for a well that you have to run through a processing plant. So you have about $0.30 differential there between a sweet gas and a high CO2 gas.

And our next question comes from the line of Philip Dodge of Tuohy Brothers.

Sort of related to earlier questions, but have you selected the locations for the two other exploration wells in the WTO later this year? And has or will information from the King or the Owens help you in selecting those locations if they haven't been selected?

We are actually are going to drill four other locations in the West Texas Overthrust this year. We have not yet selected which structures that we will plan to drill. However, we're doing that as we speak. So in the next few weeks, maybe even the next week or so, we'll make decisions as to where to go with our next two locations. And they usually, what we did the first quarter is just take in two rigs and drill two wells, simultaneous. I think we'll probably do that again. The King well actually it has -- well, both wells help us tremendously. And one of our options might be to drill back on the same King Structure. And on looking at the Magnolia Structure, that opens us up for even more drilling looking for Pennsylvanian, as well as Warwick. So even though we talk about having, and we still have even just a shallow structures, we have 18 more structures to look at. So it does take a little bit of time to interpret the data that we have from the wells that we've drilled and then try to choose what type of well we might want to drill for. Having the Owens sand gives us another target, so it does -- it gives us more upside, but also complicates what we're going to drill for.

My other question is whether the shift in the budget to focus more on oil than gas has affected your Oklahoma program, particularly the Cana-Woodford?

Well, Cana-Woodford is an area, we have 45,000 acres, and we do have a test going there. More than likely, over the course of time, as that develops, it does look to be a very good reservoir to drill in. And it appears to have a more stable decline than other shale-type plays. We probably will look to divest that at sometime. We'll just make sure that we prove up our acreage first. The Cana-Woodford, I don't see being in our portfolio over to develop it.

And our next question comes from the line of Ellen Hannan of Weeden & Co.

I Just have a quick question for you, when you think about when you're done folding in the Arena acquisition and the Permian assets that you bought last December, what percentage of your liquids production is actually going to be oil versus NGLs, or is that too early to kind of think about that?

As we go forward, Ellen, the percent of total liquid that will be oil will be in the low-80s, 80% to 82%. Right now, we're running about 78%, so that number will go up as were basic drilling -- will be basic drilling all, primarily all the oil in the Permian.

And that's why we're able to hedge at $86 a barrel instead of $36.

And our next question comes from the line of Edward O'Kane [ph] of Basil [ph].

I was just wondering, if you could just take us through the thinking behind when and how you would put on your natural gas hedges?

We're waiting on natural gas hedges for the out years. As you know, we have hedged through 2010. I believe we're kind of a maximum bearishness right now, and so I tended to be short-term, a little more bullish than the rest of the market, not necessarily bullish in general. But I do believe that we've had a tightening coming into the spring and that as summer in Jackson has come forward, that we'll be more in the 3.8 Tcf end of October. Storage rose in 4.01 Tcf or 4.02 Tcf that a lot of people are talking about. So I just believe that over time, 2011 gas will be higher. I don't think that people, my peers, can continue to drill the gas wells as aggressively as we are at these types of prices. So I think the gas rigs will roll over. I'm not sure if that happens in 2010 or 2011, but I do believe it will happen out some time in our future. Because it's still my belief that the industry is sub-economic today with gas prices where they are.

And then what do you see there on the current gas price is on the Piñon Field? I believe you gave that number -- that number was given, but I didn't get it. The Current gas price?

Waha the other day was $3.80.

$3.80?

Yes, I think today's cash prize is just a little bit below that. But that's -- we're trading at Waha about, depending on the day, $0.05 to $0.10 under NYMEX.

Okay. Well, the other thing that I would have to add to this is, that it seems to me like it's very, very of risky with the strategies you've done because when you're thinking about that going to 2010, 2011, you won't get a chance to close [ph] a lot about all this. This year, you got a chance demand [ph] much better hedges than you could have done before. I mean, if that doesn't materialize, then you're going to be exposed and that's my only worry.

Are you saying that we've...

So I guess what I'm saying is that some of your competitors are putting some hedges in 2011 already and...

For our hedges on gas?

Yes, on gas.

Yes, I think that's why we hedged aggressively on oil is that we think that we're going to be able to capture rates of return on oil, we'll drill oil wells. And I think just because my competitors have hedged their 2011 gas, it doesn't mean that we should. So my belief is, that we'll have higher gas prices at some point in the future. I might not be able to exactly pick when that is, but it's never been at least, it's not been my, or the way I would prefer to do things is to hedge prices at a point that I think they're at a low.

And our next question comes from the line of David Heikkinen of Tudor, Pickering, Holt.

Just thinking about kind of, this is post Arena, so you may not be able to answer the question. But getting volumes in the oil side that you kind of run into the 30,000 and 40,000 barrels of oil a day for a combined company in the next 12 to 24 months, is that at all outside the ballpark as far as how you're thinking about putting in SandRidge?

I think publicly, we've said our Permian production, just adding the two companies together, is 22,000 barrels a day. So I think that's fairly easy to say that you're in the ballpark.

And at this time, we're showing no further audio questions available. Tom Ward, you may proceed.

As always, we're thankful for everybody that joined our recall, and we look forward to giving you an update post Arena transaction. Thank you.