Filed by SandRidge Energy, Inc.
pursuant to Rule 425 under the Securities
Act of 1933, as amended, and deemed filed
pursuant to Rule 14a-12 under the Securities
Exchange Act of 1934, as amended
Subject Company: Arena Resources, Inc.
Commission File No.: 001-31657
IMPORTANT ADDITIONAL INFORMATION WILL BE FILED WITH THE SEC
Portions of this communication are made in respect of the proposed business combination involving SandRidge Energy, Inc. and Arena Resources, Inc. In connection with the proposed transaction, SandRidge Energy, Inc. has filed with the Securities and Exchange Commission (the “SEC”) a Registration Statement on Form S-4 containing a Joint Proxy Statement/Prospectus (Registration No. 333-166141), and each of SandRidge Energy, Inc. and Arena Resources, Inc. may file with the SEC other documents regarding the proposed transaction. The definitive Joint Proxy Statement/Prospectus will be mailed to stockholders of SandRidge Energy, Inc. and Arena Resources, Inc. Investors and security holders of SandRidge Energy, Inc. and Arena Resources, Inc. are urged to read the Joint Proxy Statement/Prospectus and other documents filed with the SEC carefully in their entirety when they become available because they will contain important information about the proposed transaction. Investors and security holders will be able to obtain free copies of the Registration Statement and the Joint Proxy Statement/Prospectus (when available) and other documents filed with the SEC by SandRidge Energy, Inc. and Arena Resources, Inc. through the web site maintained by the SEC at www.sec.gov. Free copies of the Registration Statement and the Joint Proxy Statement/Prospectus (when available) and other documents filed with the SEC can also be obtained by directing a request to SandRidge Energy, Inc., 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102, Attention: Investor Relations, or by directing a request to Arena Resources, Inc., 6555 South Lewis Avenue, Tulsa, Oklahoma 74136, Attention: Investor Relations.
SandRidge Energy, Inc., Arena Resources, Inc and their respective directors and executive officers and other persons may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding SandRidge Energy, Inc.’s directors and executive officers is available in its Annual Report on Form 10-K for the year ended December 31, 2009, which was filed with the SEC on March 1, 2010, and its proxy statement for its 2009 annual meeting of stockholders, which was filed with the SEC on April 22, 2009, and information regarding Arena Resources, Inc.’s directors and executive officers is available in its Annual Report on Form 10-K for the year ended December 31, 2009, which was filed with the SEC on March 1, 2010 and its proxy statement for its 2009 annual meeting of stockholders, which was filed with the SEC on October 29, 2009. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the Joint Proxy Statement/Prospectus and other relevant materials to be filed with the SEC when they become available.
Safe Harbor Language on Forward Looking Statements:
This communication includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include statements relating to when the companies expect to close the proposed transaction. The forward-looking statements also include statements about anticipated timing for filings with regulatory agencies, stockholder meetings and closing of the proposed merger. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the ability to obtain governmental approvals of the merger on the proposed terms and schedule, the failure of SandRidge Energy, Inc. or Arena Resources, Inc. stockholders to approve the merger, the risk that the businesses will not be integrated successfully, credit conditions of global capital markets, changes in economic conditions, regulatory changes, and other factors, many of which are beyond our control. We refer you to the discussion of risk factors in Part I, Item 1A - “Risk Factors” of the Annual Report on Form 10-K filed by SandRidge Energy, Inc. with the SEC on March 1, 2010 and in Part I, Item Safe Harbor Language on Forward Looking Statements: 1A - “Risk Factors” of the Annual Report on Form 10-K filed by Arena Resources, Inc. with the SEC on March 1, 2010. All of the forward-looking statements made in this press release are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to update or revise any forward-looking statements.
The following is a transcript of the conference call held on May 7, 2010.
CORPORATE PARTICIPANTS
Dirk VanDoren
SandRidge Energy - EVP, CFO
Tom Ward
SandRidge Energy - Chairman, CEO
Matt Grubb
SandRidge Energy - EVP, CFO
Todd Tipton
SandRidge Energy - EVP of Exploration
CONFERENCE CALL PARTICIPANTS
Dave Kistler
Simmons & Company - Analyst
Joseph Allman
JPMorgan - Analyst
Brian Singer
Goldman Sachs - Analyst
Jeffrey Robertson
Barclays Capital - Analyst
Phillip Dodge
Tuohy Brothers - Analyst
Ellen Hannan
Weeden & Company - Analyst
Edward O’Kine
Basso Capital Markets - Analyst
David Heikkinen
Tudor Pickering Holt - Analyst
PRESENTATION
Operator
Good day, ladies and gentlemen and welcome to the first quarter 2010 SandRidge Energy earnings conference call. My name is Josh and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions). I would now like to turn the presentation over to our host for today’s call, the Chief Financial Officer Dirk Van Doren. You may proceed.
Dirk VanDoren - SandRidge Energy - EVP, CFO
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 dot not have a copy of the release, you can find a copy on the Company’s web site, www.sandridgeenergy.com. Now for the forward looking statement. Please keep in mind that during today’s call the Company will be make pick forward-looking statements including statements about our proposed acquisition of Arena Resources and anticipated benefits of the transaction, which are subject to risks and uncertainties. Actual result might differ materially from those projected in these forward-looking statements.
Additional information concerning risk factors that could cause differences is detailed in the Company’s filings with the SEC. Today’s presentation will include information regarding the 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 web site under the Investor Relations tab. Now let me turn the call over to our Chairman and CEO Tom Ward.
Tom Ward - SandRidge Energy - Chairman, CEO
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 expiration on the call today.
As our press release indicated we have some exciting news to share with regard to our expiration activity in the West Texas Overthrust as well as an update on our oil activity as we integrate the forced 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 in accelerating our oil plays on the Central Basin Platform. With this said we will continue to develop the high C02 Warwick thrust reservoir with a ten rig program. EURs for the Warwick wells with tesnus is 7.3 BCFE and $1 Fining cost. We are excited about the century line coming on line later this summer as that will only improve our Warwick well economics. As a result 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 expiration of the West Texas Overthrust in early 2007 by starting a 3D seismic chute that will be the largest proprietary contiguous on shore 3D seismic acquisition in US history. This 1300 square mile shoot was completed in 2008. As a result of the 3D seismic work we have drilled the first two of six expiration wells planned for 2010 and have seen positive results on both. For a little background, the Pinyon Field sits in the northwest quadrant of the West Texas Overthrust. We believe that this area is 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 Pinyon Field, we will have less CO2 or even no CO2 if we find a reservoir.
The Pinyon Field is provide gentlemenned 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. Pinyon also sits on a very large structure that can only be found using 3D seismic therefore, our belief that is been if we have- the proprietary data to look tore those structures with reservoir that can be drilled conventionally 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 art in our business today. The story line is that all of these have been found. While we agree that it is 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 will be rewarded with it for our of the. 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 will talk about the Owens 1031A well.
This well, located 35 miles east of the Pinyon Field, was drilled on the 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 2 million of gas per day at 1400 pounds flowing pressure and the gas contains less than 1% CO2 2. We have two additional sands at 8300 feet and 6400 feet that are waiting to be tested. These upper sands are the same sand as the tesna sand produces in the northeast. We believe that the at the tesnu sand and the Owens little to no CO2 as well. If all three sands prove to be productive, they could produce as much as 1.5 TCF of recoverable gas reserves. The King923-1 was drilled to a total depth 9620 feet and encounter he had 900 feet of the Warwick. This was our second exploration well.
The Warwick is a prolific high C02 reservoir in the Pinyon 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 Pinyon Field moved from down dip tight wells to up dip producers. While the king9 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 in the Permian Basin as our focus area for oil, because of its proven historical performance and the tremendous geological and economic advantages of being able to drill thousands low risk vertical wells in shallow carbinet oil resevoirs.
We are very fortunate to have been a first move into oil starting in early 2009 as we are 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 pre mirror 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. A few days on location, and the majority of the expense is drill willing 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 forced 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 are increasing our oil guidance by 600,000 barrels this year on a standalone basis. We will discuss different oil guidance post Arena transaction. We will also cut our total CapEx by $60 million due to less natural. Our focus is to maintain a disciplined approach to capital expenditures, 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 embark owned a plan to lock in as much oil production as possible to fully ensure 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 Pinyon platform from a predicted 18 rigs, to 10 rigs and will maintain that amount through 2010.
Pinyon 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 Pinyon 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 prim CFE prices on nearly 90% of our production this year. 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 reservoir that have decades of production history, low cost vertical drilling and certainty of economic returns. Our newest field in west Texas, the Pinyon 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 expiration 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 a volume the delineation well or two to verify the sides 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 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 capacity for $5 million. In regard to our additional expiration wells we are in the process of updating our geological and geophysical models incorporating the latest information we obtained from our first two wells.
We are even more confident now about our program. Despite at least four expirations wells this year, which one may be to drill the top of the King Structure where we encounter he had over 900 feet of chert in the King923-1. Lastly, the arena transaction allows us the flexibility to continue exploration without the need for a JV partner. Each time we spread a well on a new structure with other’ looking for multiple TVFs of gas for the cost of one well. Therefore, we would drill some more structures then decide how is best to monetise for development, I would now turn the call back over to Dirk.
Dirk VanDoren - SandRidge Energy - EVP, CFO
Thanks, Tom. 2010 has been an eventful and transformational 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 of 2009. Looking inside revenues, including hedges, oil and NGLs accounted for 47% of commodity revenues for the quarter. It probably shouldn’t suprise 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 work over expense while we would no work over expenses in the first quarter of 2009. Second, G&A increased because of legal expenses related to the Arena acquisition an IT expenses related to the Permian acquisition. Cash employee costs 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 Hartscott Radina on April 30, our S4 was declared effective by the FCC on May 5, February and the date for shareholder vote has been set for May 5 and the shareholder meetings will be held on June 8th. As part of our 2010 financial plan, we extended the maturity of our bank holder facility to April 15, 2014 from November 2011. We were significantly over subscribed in the transaction and brought in three new banks as well. Thus, we were able to loafer the largest expose 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 8440 per barrel, the bulk of the hedgings were added in 2011 and 2012. Natural gas at Waha averaged $5 per MCF during the quarter and $422 for MCF during March and $393 per MCF in April and it’s lower now in May. The recent levels do not make for attractive returns so we have 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 slide higher on a units basis to reflect the overall production. He shortly after we close the Arena transaction in June. That end our prepared remarks, Josh. We would like to open the call up for questions.
QUESTION AND ANSWER
Operator
Certainly. (Operator Instructions). And our first question comes from the line of Dave Kistler of Simmons and company. Dave, you may proceed.
Dave Kistler - Simmons & Company - Analyst
Good morning, guys.
Tom Ward - SandRidge Energy - Chairman, CEO
Morning.
Dave Kistler - Simmons & Company - Analyst
Real quickly just thinking about the CapEx reduction and where capital is going to be directed now of the $800 million that is 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.
Tom Ward - SandRidge Energy - Chairman, CEO
Sure. Let Matt take that.
Matt Grubb - SandRidge Energy - EVP, CFO
Yes, Dave. On our revised drilling schedule this year we’re looking at drilling 146 wells in the Pinyon Field and 256 wells in Permian. And about 57 wells in Oklahoma and east Texas and the bulk of the Permian, the 256 wells, well that’s all oil and about 80% of the wells which is also oil. So from a capital standpoint the total capital allocation just in drilling is about a $570 million, of that about $330 million, plus $330 million allocated to the oil drill.
Okay. That’s helpful. 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 were targeting that, you were 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 is has to be redetermined in the 3D to define it to be able to track how the structures moves?
Tom Ward - SandRidge Energy - Chairman, CEO
I’ll take a little bit of that and then let Todd Tipton discuss, also. With each of the structures that we try to dril, l or that we do drill ,there will be an interpretation risk that the image that we see doesn’t exactly correlate tens of miles of away to the Pinyon Field. We have 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 a through drilling, but then the bottom area that we thought was going to be a Pinyon type with chert is a sand stone. Now, all things being equal and over pressured sand stone 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 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 as far as looking at the seismic and interpretation.
Todd Tipton - SandRidge Energy - EVP of Exploration
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 it’s very important that we’re still looking at the same structure and the same mechanism that 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 the WTO not only for other structures that would contain these Pennsylvanian age sands, but also still have the possibility of finding chert on the east side.
Tom Ward - SandRidge Energy - Chairman, CEO
The key risk has always been CO2 in West Texas Overthrust. So finding a gas bearing reservoirs divorce at depth that’s over pressure 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 base in that 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 proprietary the 3D and we’re close to infrastructure. So it’s much like drilling a foreign concession except for having the infrastructure in place that you can lay and sell in a matter of months and so it’s very big news for us to discover gas on one of our first two tests.
Dave Kistler - Simmons & Company - Analyst
That’s helpful clarifications. I appreciate it. Stepping up to the shallow other 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 Pinyon. I know you haven’t flowed it back, so there isn’t a way to tell maybe if it’s commercially viable, but did far for me to think of it from a thickness perspective and be able it correlate it back to the Pinyon and realize that Tesnus is commercial in the Pinyon.
Tom Ward - SandRidge Energy - Chairman, CEO
I’ll also let Todd while in with me, but the two that we see also appearing in the Pinyon 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 that while drilling through the structure has more pressure in it. Now, with he don’t know that, but the zones that we see are favorable to what we have in the Pinyon Field, and I think we had already shown a log over the top sand and it appeared in size of and prosite, thickness to, correlate to a well in the Pinyon Field that our average testing well makes about one of the better wells in Tesnus, or in the Pinyon Field. We haven’t tested it yet but we feel comfortable that there should be gas in place and that these zones should be sweet.
Todd Tipton - SandRidge Energy - EVP of Exploration
Just adding to that the thickness in both of those sappeds comparable to our better thickness the majority of the Tesnus wells in Pinyon Field comparable porosity, but very encouraging because we had gas shows that throughout both zones and typically we don’t see that at Pinyon Field. Its not until you go ahead and crack those sands that you see the gas, so this is encouraging. Both at 6300 and 8300-foot sands are slightly deeper than what we see at Pinyon, which could also mean a little bit better pressure and more gas that could be stored in those sands as compared to Pinyon Field.
Dave Kistler - Simmons & Company - Analyst
Great. That’s very helpful. One last question 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 those leases?
Tom Ward - SandRidge Energy - Chairman, CEO
Sure. In both of these structures the leases that we have long term terms, and we’re under no issues in the next few years as far as just heading acreage on the two structures.
Dave Kistler - Simmons & Company - Analyst
Great. That’s helpful, guys. I appreciate it, thanks so much.
Operator
And our next question comes from the line of Jo Allman of JPMorgan. Joel, you may proceed.
Joseph Allman - JPMorgan - Analyst
Thank you. Good morning, everybody.
Tom Ward - SandRidge Energy - Chairman, CEO
Morning, Joe.
Joseph Allman - JPMorgan - Analyst
So back to the question about the Owens sand, Todd, what does that correlate to in the Pinyon Field?
Todd Tipton - SandRidge Energy - EVP of Exploration
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 sand than what’s been seen at least in this area and 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 Pinyon Field.
Tom Ward - SandRidge Energy - Chairman, CEO
And, Joe, outside of the Pinyon Field across all of the west Texas Overthrust there are just about 50 wells that have been drilled through to this depth and most of them not on structures. There are only a couple of deep wells that are produced outside of Pinyon.
Joseph Allman - JPMorgan - Analyst
Okay. That’s helpful. I suppose you didn’t drill deep must have it find some of these other intervals that you have over in Pinyon like the Cabias as for example? Potentially they could be much deeper here in this location?
Tom Ward - SandRidge Energy - Chairman, CEO
Yes. That’s correct.
Joseph Allman - JPMorgan - Analyst
Okay. And then related to the down restriction, could you expenses related to the plain what is that and why is it causing lower production than you otherwise would have?
Matt Grubb - SandRidge Energy - EVP, CFO
Yes, Joe. This is Matt. The well that the perforations in this Owens sand, the overall is about 10,460 feet to 10,700 feet and is in a four and a half inch liner that’s set inside of a 7-inch casing and we went in and on a wire line set a packer at about 10,400 feet, and when we tried to lead the well down to target in a plug in it, when we tried to bleed the well down, the well never bled down and so we feel like the packing elements fail in this packer, and so what happens is it leaves you the internal diameter of the four and a half inch casing is 3.92-inch in the outside diameter of the packer is 3.75-inch. So you sort of have a flow, an anulare space there of about 3/16th of an ensure down there at 10,400 feet and you trying to flow gas into, and so if it lifts any kind of sand from the track at all it wouldn’t take very much you know a cup of and would plug that up. We feel like we are continually having to fight that annular restrictions. The flow back now. So I think once we can get in there and we work on trying to pull this packer out of the hole and go back in and reset it and see if we can get a regular flow up through the tubing.
Joseph Allman - JPMorgan - Analyst
Okay. So it sounds as if it could be severely restricted actually?
Tom Ward - SandRidge Energy - Chairman, CEO
It could be. Yes. We douse don’t have a good feel right now. We just don’t know stand.
Joseph Allman - JPMorgan - Analyst
Okay and what does the pressure there tell you?
Tom Ward - SandRidge Energy - Chairman, CEO
Well, the pressure it all owe the reservoir pressure appears to be over pressure normal gradient call .4 or 5. This had a gradient of about .75. So at in Owens sand least sand we feel like we’re in an over pressure situation there.
Joseph Allman - JPMorgan - Analyst
Okay. And then separate topic on to the Century Plant. Do you expect to meet your obligation this year in the century plants 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?
Tom Ward - SandRidge Energy - Chairman, CEO
I’ll while 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 planned and will be picking up great efficiencies in the make and talk and Matt can talk a little bit about that, but we have a 30 year contract with coal petroleum and over that 30 year contract we have to liver 3 and a half TCF of CO2, and we have enormous amounts of gas in the Pinyon Field and will be able to meet our obligations moving forward in filing the Century Plant and meeting those obligations. So, Kevin I will hit you and, Matt, as far as just a yearly basis an how we want to discuss it.
Todd Tipton - SandRidge Energy - EVP of Exploration
Well, what Tom is talking about efficiency if you look at the century plant as a standalone project whether you make an investment or not 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 losses. We have very inefficient compression and fuels that you have to burn to run the plants. Just in efficiency savings in reductions back loss that’s going to century, we would gain about $10 million per hundred million cubic feet of gas processed per day. The $10 million being annual savings. So, if we switch over this 300 million cubic feet into centry from our legacy plant, Endridge would gain about $30 million per year. That would more than offset any that we’re contemplating right now with objection owe. It’s actually a money making event for SandRidge. Now, from a penalty standpoint, Joe, we would not have any penalty due until 2012. 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 and if we don’t do anything but kept our production flat in Pynion, we would send them something in the order of 70 to 75 TCF in 2011, okay no now you know we are running rigs, there’s a production but if we accepted them 70, 75 BCS or penalty probably would be in the $10 million range.
Joseph Allman - JPMorgan - Analyst
Okay.
Todd Tipton - SandRidge Energy - EVP of Exploration
So we would still be ahead from our efficiency savings switching over to legacy to century.
Joseph Allman - JPMorgan - Analyst
Okay. So it sound as — so it sounds — I’m sorry.
Matt Grubb - SandRidge Energy - EVP, CFO
Joe, even a more important point is that at any kind of a gas price move up, Pinyon Field, even with high CO2 in it, has about a $1 finding cost. So let’s assume we find even more than one big structure that let’s say an Owens field you could have a lower finding cost 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 you are satisfies we could do a JV in the Pinyon Field at almost any time because of how good it is to drill wells there. So I don’t look at us as having any issue why filling out plant going forward.
Joseph Allman - JPMorgan - Analyst
Okay. Okay of the that’s helpful and the sands just last lay CapEx by about $60 million, just help us reconcile there because I know you were gross margining some gas rigs, you’re dropping gas rigs an 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 cap peeks by $630 million?
Dirk VanDoren - SandRidge Energy - EVP, CFO
I can go over the CapEx numbers in more detail, Joe. We’re going to drill a total of 459 wells. That’s our projection and spend $570 million drilling okay? From and so in the 459 wells we have 146 in Pinyon, 256 in perp January, 57 in east Texas and Oklahoma, and the associated spending there is about $243 million in Pinyon, $230 million in Permian, and right at near $100 million in the Oklahoma east Texas area, $570 million for drilling. And then we have $110 million budgeted for carryover of work from last year, the carryover in 2010, non-op activities, work overs, and recompletions. All that ads up to $110 million and then we have $30 million in leasehold and geology and geophysics, seismic $30 million. $80 million in mid stream spending, $5 million in oil field services. We expect to spend about $35 million in tertiary this year, about $21 million in general incorporate. So that ads up to about $851 million and if we credit back $50 million for pre-bought pipe that we bought back in 2008 and so our budget comes down to about $800 million.
Joseph Allman - JPMorgan - Analyst
Okay.
Dirk VanDoren - SandRidge Energy - EVP, CFO
$60 million the initial budget we had $60 million and there’s a lot of moving parts but you know we are adding more rigs to Permian and instead of going up to 18 rigs in Pinyon we’re going to keep it at 10. We had two rigs running in east Texas that we were going to run for the entire year. We since dropped those two rigs, and so when you’d a the rigs an you take out the rigs at Pinyon and the rigs in east Texas you net out about $60 million in savings overall.
Tom Ward - SandRidge Energy - Chairman, CEO
And as you know, it’s easier if you look looking to grow production, it’s easier for us to grow our production drill in gas wells rather than oil wells, what we are really doing is chasing the EBITDA.
Joseph Allman - JPMorgan - Analyst
Got you. Okay. Very help of. Thank you.
Tom Ward - SandRidge Energy - Chairman, CEO
Thank you.
Operator
And our next question comes from the line of Brian Singer of Goldman Sachs. Brian, you may proceed.
Brian Singer - Goldman Sachs - Analyst
Thank you. Good morning.
Tom Ward - SandRidge Energy - Chairman, CEO
Good morning.
Brian Singer - Goldman Sachs - Analyst
Can you talk a little bit more about the King well and more specifically the potential for the up dip 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?
Tom Ward - SandRidge Energy - Chairman, CEO
Sure. I will do 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 was the top of the structure we were still in the Pennsylvanian structure so we continued to drill and found the reservoir at a strictly low position. However, the good point was that the reservoir was very thick, over 900 feet thick, which puts us in the upper core file of the pay in the Pinyon Field, and then ultimately the second good thing was that while tight we ran an F MI 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, then so that helped us in our belief that as we moved away from the northwest part of the that we would have less CO2
This was one of the more risky locations that we have as far as a structure that would be high CO2. So we really thought that there could be a high chance here to have as much CO2 as Pinyon, 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 all we need to do is get more up on structure and as we do our re interpretation, 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 there wouldn’t be any well another test to test this structure, and so there is still some risk that you could have the seismic interpretation could be off a little bit or that it shall that maybe we didn’t see commercial quantities of gas here. So there is still risk to the structure, but it’s much diminished in my opinion.
Todd Tipton - SandRidge Energy - EVP of Exploration
The broader structure that Tom referred to and as we have to remember we correlated the chert, the main reservoir, from miles away from out crop, and again we can not directly detect it on the seismic, and we do not have any chert in any of the wells in the immediate vicinity. So part of our model and our interpretation had the potential for two zones of chert ii 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 expand the 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 and that particular case, the chert reservoir very exciting and especially as we look forward to additional wells in that area.
Brian Singer - Goldman Sachs - Analyst
Great. Thanks .Ed and then secondly on Permian I think you had indicated you had 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 solely the result of increased rig count versus any changes in well results or productivity, thanks.
Tom Ward - SandRidge Energy - Chairman, CEO
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 curves, 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 limestone, some other buy carbonates on the platform that we are a starting to work on. If you look at what we’ll do post Arena is just give a type curve for all Peryian I 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 creek fork drill with you might drill some Wolfbury wells in the midland basin or well in the Delaware basin. All of those added together are going to have north of an 80% rate of return. So what we really tried to do was to focus on making sure that hedged in that production and that rate of return because our service costs can’t change very much with a us selling our own rigs an spending very little on completions. So what our goal is to maintain the drilling and when we bring a well on knowing how much we’re going to produce but then to hedge in that rig return.
Brian Singer - Goldman Sachs - Analyst
Great. Thank you.
Tom Ward - SandRidge Energy - Chairman, CEO
Thank you.
Operator
(Operator Instructions). And our next question comes from the line of Jeff Robertson of Barclays Capital. Jeff, you may proceed.
Jeffrey Robertson - Barclays Capital - Analyst
Thank you. Tom, can you all talk a little bit about the King Structure in the context that if you get up dip and make a discovery, what kind of options might that give you since you’re ten miles away from Pin yon with putting a higher methane stream through the Century Plant?
Tom Ward - SandRidge Energy - Chairman, CEO
Well, it’s 20 miles away from Pinyon, but still in an area that that’s very easy to lay pipelines. So if we did have a discovery there, we would have a lot of options. We could bring gas north up, not only into the century plants but we have our existing plants that you could take less CO2 through and if we found, if you’re only looking at 20% CO2 we might even have some other options with regard that we may want to do rather than to bring gas north. That’s still a long ways from having to discuss that, but having 80% methane if you have the same type of reservoirs is obviously good. We would have a lot of options.
Jeffrey Robertson - Barclays Capital - Analyst
Okay. Can you all also talk about what the LOEs are on outhears higher methane wells versus what you’re doing at Pinyon?
Tom Ward - SandRidge Energy - Chairman, CEO
I think that your question was LOE on high methane wells versus having to deal with CO2, correct.
Jeffrey Robertson - Barclays Capital - Analyst
Yes.
Do you have any numbers on that?
Matt Grubb - SandRidge Energy - EVP, CFO
I mean LOE in the Pinyon right now is, just looking strictly LOE alone without processing and gathering is $0.7 per MCF. Then when you add in processed gathering which is a lunch number it adds about another$.85 cents to $0.90 for MCF. So if your gas is pure methane, you probably looking at say $1 for MCF LOE versus $1.30 for a well that you have to run through the processing plants. You have about a $0.30 differential have between a sweet gas and a high CO2 gas.
Jeffrey Robertson - Barclays Capital - Analyst
Thank you.
Operator
And our next question comes from the line of Philip Dodge of Touhy Brothers. Philip, you may proceed.
Phillip Dodge - Tuohy Brothers - Analyst
Yes. Good morning. Thanks. I was just wondering related to earlier questions, but have you selected a locations for the two other expiration 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 Vice President been selected?
Tom Ward - SandRidge Energy - Chairman, CEO
We 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, and so in the next few weeks, maybe in the next week or so, we’ll make decisions as to where to go with our next two locations and usually what we did the first quarter is just taking two rigs and drill two wells simultaneous, and I think we’ll probably do that again. The King well, 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, 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 we’ve drilled, and then try to choose what type of we will we might want to drill for. Having the Owens sand gives us another target so it gives us more upside but also complicates what we’re going to drill for.
Jeffrey Robertson - Barclays Capital - Analyst
Okay. 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?
Tom Ward - SandRidge Energy - Chairman, CEO
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 place. We probably will look to divest that at some time. We’ll just make sure that we prove up our acreage first because the Cana Woodford for the record I don’t see being on our portfolio over to develop it.
Jeffrey Robertson - Barclays Capital - Analyst
Okay. Thank you very much.
Operator
And our next question comes from the line of Ellen Hannan of Weeden and Company. Ellen, you may proceed.
Ellen Hannan - Weeden & Company - Analyst
Thank you Good morning.
I just had a quick question for you. When you think about when you’re unfolding in the Arena acquisition as the Permian assets that you bought last December, what percentage of your liquid production is actually going to be oil versus NGLs or is that too early to think about that?
Tom Ward - SandRidge Energy - Chairman, CEO
As we go forward, Ellen, the percentage that will actually be oil will be in the low 80s, 80%, 83%. Right now we’re running about 78%, though that number will go up as we’ll be basically trialing primarily all oil in the Permyanl.
Todd Tipton - SandRidge Energy - EVP of Exploration
That’s why we’re able to hedge at $86 a barrel instead of $36.
Ellen Hannan - Weeden & Company - Analyst
Great. Thanks it. Thank you very much.
Operator
And our next question comes from the question comes from the line of Edward O’Kine of Basso. Edward, you may proceed.
Edward O’Kine - Basso Capital Markets - Analyst
Yes. Hi, guys. 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.
Tom Ward - SandRidge Energy - Chairman, CEO
We’re waiting on natural gas hedges for the out years. As you know we have hedged through 2010. I believe we’re at the maximum right now, and so I tend 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 in to the spring and that as come projections come forward that we’ll be more in the 3 point ATVF end of October storage, rather than 4.1 or 4.2 TCFs that a lot of people are talking about. So I just believe that over time 2011 gas will be higher. I don’t think my piers can continue to drill gas wells as aggressively as we are at these types of prices. So I think the gas rigs will rollover. I’m not sure if that happens in 2010 or 2011, but I do believe it’ll happen out sometime in our future because it is still my belief that the industry is sub economic today at gas prices where they are.
Edward O’Kine - Basso Capital Markets - Analyst
Okay. And then what do you think thethe current gas price is? I believe the number was given, but I didn’t get it. The current gas price.
Todd Tipton - SandRidge Energy - EVP of Exploration
The other day was 380.
Edward O’Kine - Basso Capital Markets - Analyst
380.
Tom Ward - SandRidge Energy - Chairman, CEO
Yes. I think today’s cash price is just a little bit below that, but we’re trading at way what about o depending on dates about $0.05 to $0.10 under IMX
Edward O’Kine - Basso Capital Markets - Analyst
Okay. The other thing that I would have to add to this is that it seems to me like it’s very, very risky because you’re taking a bet that going into 2011, you would get a chance, this year you get a chance to much better than you could have done before. I mean if that doesn’t materialize than you’re going to be exposed that’s my only worry.
Tom Ward - SandRidge Energy - Chairman, CEO
I mean you’re saying that we’ve - that we’re.
Edward O’Kine - Basso Capital Markets - Analyst
I guess what I am I saying is competitive at least put in some hedges in 2011 already.
Tom Ward - SandRidge Energy - Chairman, CEO
Oh, for hedges on gas?
Edward O’Kine - Basso Capital Markets - Analyst
Yes. On gas.
Tom Ward - SandRidge Energy - Chairman, CEO
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 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 the way I would prefer to do things is to hedge prices at a point that I think they’re at a low.
Edward O’Kine - Basso Capital Markets - Analyst
Yes. Thank you.
Tom Ward - SandRidge Energy - Chairman, CEO
Thank you.
Operator
And our next question comes from the line of David Heikkinen of Tudor Pickering Holt. David, you may proceed.
David Heikkinen - Tudor Pickering Holt - Analyst
Hey Tom and Matt, just thinking about kind of this 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 barrel 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 the new SandRidge?
Tom Ward - SandRidge Energy - Chairman, CEO
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.
David Heikkinen - Tudor Pickering Holt - Analyst
Okay. Thanks. That’s all I needed to know.
Tom Ward - SandRidge Energy - Chairman, CEO
Thank you.
Operator
And at this time we are showing no further audio questions available. Tom Ward, you may proceed.
Tom Ward - SandRidge Energy - Chairman, CEO
Well, as always we’re thankful for everyone to join our call and we look forward to giving you an update post Arena transaction. Thank you.
Operator
Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a great day.