SandRidge Energy Inc (SD) 2010 Q4 法說會逐字稿

Good day, ladies and gentlemen. And welcome to the fourth quarter and year-end 2010 SandRidge Energy earnings conference call. My name is Caris and I will be your coordinator for today. At this time all participants in a listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this call is being recorded for replay purposes. I would now like to turn the call over to your host for today, Mr. James Bennett, EVP and Chief Financial Officer. Please proceed, sir.

Thank you Caris. Welcome everyone and thank you for joining us on our fourth quarter and full-year 2010 earnings call. Please note that today's call will contain forward-looking statements and assumptions which are subject to risks and uncertainties and actual results may differ materially from those projected in these forward-looking statements. Additionally, we may make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures. A reconciliation of any non-GAAP numbers that we discuss can be found on our earnings release and on our website. Now let me turn the call over to our Chairman and Chief Executive Officer, Tom Ward.

Thank you, James. And welcome to our fourth quarter financial and operational update. Also present with me are -- Matt Grubb, President and Chief Operating Officer; as you know, James Bennett, EVP and Chief Financial Officer; Rodney Johnson, EVP, Reservoir Engineering; and Kevin White, Senior VP, Business Development and Investor Relations. As most of you know, we have completed the transition to crude oil that started two years ago. While challenging during the process and viewed by many as contrarian move, we can now look back and see that we not only made the right call on commodities, but did so in size and scale that transformed our Company. Only two years ago, our revenue consisted of over 80% natural gas and now is more than 80% oil. We remain true to our conviction on developing shallow, low cost, proven carbonate reserves.

First, we expanded our holdings in the Central Basin Platform with the acquisition of assets from Forest and Arena and now we have 780,000 acres in the horizontal Mississippian carbonate play in Oklahoma and Kansas. These two areas have the important characteristics we require in all of our plays -- low cost, low reservoir risk, scalability and repeatability. Key infrastructure is in place for oil and gas development, rigs are readily available, shallow reservoirs mean fewer drilling days and low horsepower requirements for hydraulic fracturing all contribute to low costs and very high rates of return. Furthermore, because we work in areas that have been proven by thousands of vertical wells over decades of drilling, we take on little reservoir risk in generating these high rates of return. We also have a drilling inventory in place to continue this type of drilling success for many years to come.

Another advantage to our Mississippian play is our low entry cost. We've now basically shut down our leasing efforts but once all the numbers come in, we expect to have spent less than $200 per acre and should have over 900,000 net acres leased. This is in stark contrast to the entry cost of many of the recent high-profile plays where acreage costs have been 10 times to 100 times higher. We could only accomplish putting together our holdings in the Central Basin Platform by being ahead of the industry, and deciding to make this a core area in early 2009. Today, it would be impossible to duplicate. Also, it would be impossible to have our acreage position in the Mississippian play had we not moved aggressively during the last year. We spent two years acquiring oil production and oil drilling locations in areas that most others have overlooked.

These areas are traditional carbonate reservoirs with better permeability than most plays being developed today. It takes less horsepower to frac due to the rocks' characteristics. In fact, we have seen almost no increase in overall service costs since mid-2009 because an average Central Basin Platform well is shallow and there's an excess of shallow drilling and completion equipment. The entire industry has moved to tight deep plays that require high pressure drilling and completions. Consequently, there's an abundance of low pressure equipment as virtually no one drills shallow vertical wells anymore and these shallow traditional reserves are what the industry was built on over the last several decades. Production history is the other key variable in deciding what kind of play to be involved in. We want to know our wells -- how they'll perform in future years, the EUR rate of decline and profitability.

Again, this is in stark contrast to much of the industry that appears comfortable with the first year decline of 80% to 90% and little certainty of the subsequent years' decline because there is very little vertical or horizontal well production history.We decided to build our oil asset base with much less risk in areas where there were decades of producing wells that show how the reservoir will perform. So, finding shallow predictable carbonate reserves with certainty of economic outcome and little service cost inflation has been our strategy. Even though we continue to be bullish [on] oil for the long-term, to further mitigate economic risk, we have hedged a significant portion of our production into 2013, and we are now locking in some more oil at above $100 per barrel.

We continue to drill aggressively in our 2 core areas, the Central Basin Platform and the Mississippian. The Central Basin Platform will receive 65% of our total drilling budget this year and the Mississippian, the rest. We have also drilled 14 disposal wells and have increased our rig count to 12 as we now plan to increase our CapEx to $1.3 billion and increase our production to 23.3 million barrels equivalent.

As I discussed earlier, we've been in a mode of buying land and acreage for the last 2 years and we will use 2011 as a time to use our rich oil properties as a source for raising capital. We already have a clear path to more than $700 million of capital raises in the first half of 2011. Our goal will be not only to fund the shortfall in 2011, but to move EBITDA up and begin to fund our 2012 drilling program. We've been very clear that we will search for more ways to monetize a portion of the Mississippian acreage holdings.

We love the Royalty Trust structure as we not only get to sell undeveloped acreage into the trust but also receive the drilling capital upfront, providing a tremendous acceleration and net present value to us. The horizontal Mississippian has performed better than we expected a year ago. If you were at our Analyst Day presentation last year, you would have seen a slide that expected a 235 MBOE EUR. We have since moved the EUR to more than 300 MBOE to 500 MBOE and our latest type curve from Netherland Sewell is 409 MBOE per well with 52% crude oil, not liquids, but oil, an important distinction when NGLs are trading at less than 40% of crude.

Our drilling time and costs have come down from 30 days to 21 days, and our well costs have moved down from $3 million to $2.5 million. All of this in an area that has known oil in place across 6.5 million acres with over 17,000 vertical wells drilled in the last 30 years. Therefore, we believe the play has scale and our 780,000 acres would represent the largest land position of any operator published to date. As you have seen, our reserves are up 149% over last year. Excluding price revisions, our finding costs was $9.04 per BOE. When price revisions are included, the finding costs moves down to $3.61 per BOE. SandRidge has also has a proved developed finding costs of $13 per BOE. The proved developed finding costs is important because it includes acreage costs without the benefit of booking PUDs.

Given the different ways the companies may add undeveloped reserves, we view this as the most consistent and conservative way to think of finding costs and believe we have a best-in-class number. I'm very happy with the changes we've incorporated during the last 2 years and this is an exciting time for SandRidge. Our steadfast belief and proven shallow conventional oil targets has now given us the luxury of having tremendous margins for years to come. I'll now turn the call over to Matt for the operational update.

Thanks, Tom, and good morning. Tom has hit on many of the points I'm going to talk about. I just want to elaborate on a few important ones. First, I want to start out with 2010 production and the 2011 production guidance. For the year ending 2010, we produced 7.4 million barrels of oil and 76 billion cubic feet of natural gas for a total 20 million barrels of oil equivalent or 120.5 cubic feet of natural gas equivalent, all of which are new highs for the Company and represents a 15% increase over 2009. Since embarking on our strategy to move to oil, we have now increased oil production every quarter dating back to Q3 of 2009. We began 2010 producing about 13,000 barrels of oil per day, and exited 2010 at about 30,000 barrels of oil per day.

The bulk of that growth in 2010 was in the Permian Basin, where we went from about 8,500 barrels of oil per day to about 23,000 barrels of oil per day from the beginning of 2010 to the end of 2010 as a result of the Arena acquisition and drilling. Significant production growth also took place in the Mid-Continent region as a result of the Mississippian oil play. In 2010 we grew production from about 3800 barrels of oil equivalent in the Mid-Continent to about 7,000 barrels of oil equivalent as we exited 2010. We look for continued healthy growth in both of these oily areas in 2011 as we have ongoing active drilling programs in each.

As for 2011, our production guidance is 23.3 million barrels of oil equivalent. We're projecting to produce 66.5 cubic feet of natural gas, and 12.3 million barrels of oil. This is about a 16% increase -- I'm sorry, this is about a 13% increase in gas production from 2010 and a -- I'm sorry, this is about 13% decrease in gas production in 2010 and 67% increase in oil production. Overall, we're looking at year-over-year production increase of about 16% in 2011 over 2010. Reserves, the Company total proven reserves essentially doubled from 219 million barrels of oil equivalent at year-end 2010 to 546 million barrels of oil equivalent in year-end 2010 -- I'm sorry, 219 million barrels of oil equivalent, 2009 to 546 million barrels of oil equivalent, 2010. We produced 20 million barrels of oil equivalent during the year and added 347 million barrels equivalent.

Extensions accounted for 105 million barrels equivalent, and acquisitions, 85 million barrels equivalent and revisions 157 million barrels equivalent. The present value of the reserves on a 10% discount increased nearly threefold from $1.6 billion at year-end 2009, to $4.5 billion at year-end of 2010. The reserves replacement ratio, excluding price revisions and acquisitions, is 521%. As for the finding costs analysis, our 2010 drilling CapEx is $947 million, so our drill bit proven reserves finding costs excluding revisions was $9.04 per barrel of oil equivalent and if we include the reserves revisions, it was $3.61 per barrel of oil equivalent. While those metrics are very good, it is important to understand the proved developed finding costs.

Our proved developed reserves increased from 137 million barrels of oil equivalent in 2009 to 222 million barrels of oil equivalent in 2010; thus, a difference of 85 million barrels of oil equivalent. If we add back in 20 million barrels of oil equivalent for the production during the year, and subtract out the 27 million barrels of oil equivalent for acquisitions, we get a net proved developed reserves increase of 78 million barrels of oil equivalent. That is the true organic movement in proved developed reserves year-over-year. With the drilling CapEx of $946 million, the proved developed reserves finding costs was $12.06 per barrel of oil equivalent. And with addition of land and seismic costs of about $103 million, that number moves up to $13.37 per barrel of oil equivalent.

I'm going to hit on the 2011 E&P CapEx guidance. James will hit on the corporate guidance. But I just want to start out with our drilling budget. We're looking at running 28 rigs in 2011 on average of which 16 rigs will be in the Central Basin Platform and 12 rigs in the Mid-Continent drilling horizontal Mississippian wells. We look to drill 138 horizontal Miss. wells in 2011, for cost of $248 million. Along with the Mississippian program, we're going to also accelerate our drilling and completion of saltwater disposal wells. We will drill 24 of these SWD wells and that will not only allow us to dispose the water through the year of 2011, it will also take us into 2012 and that will be another $45 million.

We plan to drill a little bit over 800 wells in the Central Basin Platform for a cost of $582 million. And we have $27 million allocated to East Texas Gulf Coast, Gulf of Mexico and tertiary for miscellaneous projects; that adds up to $902 million. We have $64 million budgeted for workovers and recompletions and $6 million for non-operated drilling. And we also have budgeted $55 million of capital carryover from our 2009 -- I'm sorry, our 2010 program for a total of $1.027 billion for the E&P CapEx.

Lastly, I want to talk about how we have improved our -- or how we have increased our value in the Permian Basin just in a very short time. At year end of 2008, our Permian Basin assets had a value of about $150 million. We bought the Forest assets in late 2009 for $800 million. We bought Arena in 2010 for $1.4 billion and since then we've spent about $500 million drilling new wells. The total investment is about $2.7 billion. We have cash flow at about $300 million, and have divested, including our announcement last night of the New Mexico assets, divested a total of $465 million. This gives us a net investment of less than $2 billion at year end of 2010. Our Permian assets are now worth $3.8 billion on the [trip]. So essentially we have nearly -- we have added nearly $2 billion in value in the Permian in just 18 months. Now, I will pass the call over to James for financing.

Thank you, Matt. Reviewing 2010 results as Matt mentioned, total production was 20.1 million BOE, right on top of our guidance of 20 million BOE. Adjusted net loss was $35.4 million for the fourth quarter and adjusted net income was $42.4 million for the full year. Adjusted EBITDA totaled $130 million for the fourth quarter, and $465 million for the full year, and for the full year, capital expenditures were $1.13 billion, versus our guidance of $1.1 billion. The slight variance from guidance is primarily the result of an increase in drilling and leasing activity on our Mississippian play in the fourth quarter of 2010.

Touching on a few of the numbers that warrant further explanation, on a per unit basis, LOE and production taxes continue to trend slightly higher as oil constitutes a greater percent of our production mix. Regarding cash G&A, included in the $7.06 per BOE of actual G&A, is approximately $35 million of costs associated with the Arena acquisition and legal settlements. Excluding these two items, G&A would be $5.28 per BOE. Finally, recall that the Arena acquisition and release of the valuation allowance against our deferred tax asset resulted in a $446 million tax benefit in 2010.

As an update on hedges, consistent with our history of managing our commodity price exposure, we continue to actively hedge and lock in cash flows on our high rate of return oil projects. For 2011 we have over 75% of our guidance production hedged at prices just over $86 a barrel and $4.69 for gas. If we take our hedges out through 2013 whereas Tom mentioned we continue to add hedges at over $100 a barrel, we have approximately $40 million BOE hedged at an average price of $67 per BOE. That represents about $2.7 billion of future revenue.

One item I think worth -- is worth noting in terms of hedging and I think it's important, as producers, we all assume a heightened cost risk when we place hedge bets in the out years as service costs can rise and compressed cash flows and reduce our expected returns. It's our ability to control the cost side of our business that allows us to be comfortable hedging out 2 years to 3 years of production. We know what our costs will be and are comfortable locking in the out year revenue and returns.

Turning our liquidity in the balance sheet, the year-end 2010, our credit facility balance was $340 million and of February 22, it was $382 million. With our borrowing base of $850 million, our current availability under the credit facility is $433 million. This does take into account some outstanding LCs. Additionally, given our proven and PDP PV-10 at year-end 2010, we feel very comfortable with the asset coverage under the credit facility, and the upcoming April borrowing base redetermination. Our total debt at year end was $2.9 billion, at an average interest rate of 7.5%. We're in compliance with all covenants under our debt agreements. We have no debt maturities until 2014 and our year-end debt to adjusted EBITDA for covenant calculations is 3.75 times.

Importantly, looking at our leverage relative to our asset base, debt to proved reserves has improved from $5.30 per BOE, to $11.80 per BOE at year-end 2009. Debt to proved developed reserves is now $13 per BOE versus $18.80 per BOE at year-end 2009 and debt to SEC PV-10 is now 0.65 times versus 1.65 times in 2009. While we're currently levered on a cash flow basis, we do feel that our large and oily asset base and hedge positions provide further support for our level of debt. When we outlined our initial guidance in November 2010, our goal was to raise between $600 million and $800 million in proceeds from sales of non-core assets in order to fund the shortfall between our cash flow from operations and our capital expenditure budget.

Reviewing where we are in terms of these asset sales, in December 2010 and early '11, we closed $265 million in sales of non-core assets. Yesterday, we signed an agreement for the sale of our New Mexico assets for $200 million which we expect to close in April. The combination of these brings us to $465 million of closed or signed asset sales. If you combine that with the expected proceeds of the Mississippian Royalty Trust we filed in January, we have closed or pending cash proceeds of over $700 million. This is versus our original goal of between $600 million and $800 million. Given this, we're now increasing our expected proceeds to an excess of $900 million and anticipate funding the remaining with further monetization of our assets. It's our success in these asset sales and monetizations, coupled with our opportunities in our two primary plays that gives us the ability to increase our development pace and raise our 2011 CapEx budget to $1.3 billion.

Turning to guidance, as outlined in our earnings release, we're increasing our projected 2011 production guidance to 23.3 million BOE, which represents a 16 million BOE production growth over 2010. Of course, when the oil and gas ratio is trading at 22 to 1, looking at the absolute volume growth based on a 6 to 1 equivalent becomes a lot less meaningful. In this commodity market environment, growth in oil production is just much more valuable. As I mentioned, we're forecasting CapEx of $1.3 billion, up from our previous guidance of $1.1 billion. And 100% of our drilling expenditures for the remainder of the year will be dedicated to oil projects as we develop our assets in the Permian and the Mississippian.

As Matt mentioned, the first quarter, we're wrapping up our leasing activities in the Mississippian and we're also front-end loading some of our saltwater disposal drilling activities in Q1.So we do expect the first quarter CapEx to be the highest of the year. Production costs, production tax, DD&A and G&A per BOE are all in line with Q4 2010 actual results. As I discussed earlier in the call, we're making significant progress in terms of the capital raising efforts and feel confident we can fund our $1.3 billion capital program for 2011.

In conclusion, 2011 has potential to be a very transformative year for SandRidge. We have amassed two sizable oil plays in areas of the country with decades of known production history and a large inventory of high return oil drilling opportunities. We're operating in formations and plays that allow us to control our costs. We are projecting double-digit growth in production, all coming from oil. And we have a clear path to addressing our 2011 funding gap and are setting up nicely to begin to address any 2012 funding needs. We recognize that our financial leverage is high. While our commodity hedges and large asset base somewhat mitigates this, we do believe reduction in our financial leverage over time is prudent. SandRidge will be hosting annual Investor and Analyst Day Meeting in New York at the Grand Hyatt on Tuesday, March 1 at 8 AM.You can see our website for details on the Investor Meeting and a copy of the presentation. Now, I'd like to ask Caris to open the call for questions.

Wonderful. (Operator Instructions) Your first question comes from the line of Neal Dingmann with SunTrust. Please proceed.

Good morning, guys. Great quarter, great transformation. Say, Tom, just a question first on the Permian. We've obviously continued to hear a lot more chatter on the horizontal wells there. Just wondering, again, if you could comment around prospective acres on your Permian and how soon you would start looking at something like this?

Sure, Neal. We have, as you know, a lot of acreage, about 200,000 acres in the Permian and some of that acreage is now being offset by horizontal wells being drilled and they're mainly in the San Andres. And so we're looking at it and hopeful that there's a lot of success with the idea, just like most of the reservoirs that we look at, we tend to wait and make sure that the extra cost that's incurred with drilling horizontal wells meets what the expectations we can have with drilling vertical wells. The best area for us to look at horizontal wells is where we have more San Andres only type reservoirs or where the Clear Fork and Wichita-Albany and the Fusselman aren't as prospective so that you're not giving up deep hole rights to recomplete in whenever we drill a well.

Keep in mind, just because we drill a well and bring on a deeper zone, we do keep very good shallow zones behind pipe so you can bring those on later with recompletions and one of the things that Matt I'm sure will talk about is we continue to have excellent results with recompletions in the Permian Basin. But to answer your question, yes, we do keep notice of and visit about horizontal activity near our acreage.

Neal, I just want to add that we're currently seeing nearly 90% rate of return on our vertical wells on the Central Basin Platform, so certainly the horizontal well may be a good idea but only time will tell. It's not imminent. It's not anything we need to go out and do right away but like every other program, we'll watch it very carefully. We'll study and if it's the right thing to do, we'll certainly give it a try.

Got it. And then Tom, looking over at the horizontal Mississippian, with that, obviously the size of acreage you have there, if you could comment a little bit on as that play goes from east to west, your thoughts on the prospectivity of that play? I guess not just east to west, even as you go north to south, et cetera, I guess that [Quinn] prospect area, over at Dacoma, all those areas, one going to be as good as the other, just wondering your thoughts.

On the horizontal play?

Yes.

Frankly, the San Andres produces all across the areas that they're looking at, so -- .

Horizontal Mississippi. I'm sorry, Tom.

So your question, again, is then moving from east to west are we seeing -- I thought you were talking about the Permian. The prospectivity of east to west in the Mississippian, so -- .

Correct.

I was off thinking about the wrong thing. Yes, across the play and in the Mississippian and you need to think of this not only in SandRidge's wells but the other operators that are drilling, we're seeing type curve wells in and around all across our acreage but not only across our acreage, in other areas as well. So far, there's been not a way to choose one place or the other that might be better or worse. So we're -- we continue -- we have a lot of acreage over many, many counties so I don't know. That's the reason we keep a range of 300 MBOE to 500 MBOE, even though Netherland Sewell has us at 409 MBOE per well, as we don't know from one section to the next or one area to the next which ones might be better or worse. But we're comfortable with the type curve currently. Does that answer it?

That does. And then just last question on, I think you said in the past, frac or other completion costs, it doesn't seem like you're seeing virtually any uptick like much of the rest of the market there. Does that still continue to be the case? You and Matt and the guys continue to think that will be the case for the remainder of the year?

Yes. We don't see any appreciable move in service cost, again, like I mentioned, it's because there is an excess amount of frac capacity with low horsepower frac fleets. So if the industry continues to do like it appears it's going to, it fits perfectly with us and what we like is, is that as other plays have 50% increases in service costs, we don't. And so it just makes us have better rates of return in our play.

Great color. Thanks.

Thank you.

Your next question comes from the line of Pearce Hammond with Simmons & Company. Please proceed.

Good morning.

Good morning.

On the potential for future royalty trust, what's the current appetite for either additional trusts and what would you think is the limiting factor from SandRidge's perspective?

Well, unfortunately I can say that we like royalty trusts but we are in registration in one right now so I'm limited on how much I can talk about royalty trusts. I'll just -- I'll leave it that we like the idea.

I understand. I understand. And what service cost inflation is baked into your 2011 CapEx guidance or correspondingly, what efficiency improvements might you think you might be able to get to offset some service cost inflation?

Sure. I'll pass that to Matt.

Yes, we -- actually, service costs, like Tom mentioned, the type of fracs that we pump, that's a big part of your completion costs, drilling completion costs, is a very simple system in the horizontal Miss. It's a fresh water system and really all we put in is a [fresh and] reducer and we use fairly low strength sand and so there's an abundance of those type of material that's going to keep service costs in check. In the Permian, our wells, we continue -- the Fuhrman-Mascho, we continue to drill those for about $500,000 in Clear Fork in the range about $800,000.Again, those are one or two stages per well on the frac and again, it's a low strength prop and fairly conventional fluid. I think the thing that keeps us -- keep our service costs low is the horsepower requirements that we bring on location. Today, as we step out away from the conventional reservoirs, a lot of those fracs are requiring anywhere from 25,000 horsepower to maybe 40,000 horsepower just to get them -- just to get the fracs pumped.

In the Central Basin Platform everything we do is a fraction of that, it's between probably 3,000 horsepower and 7,000 horsepower and then in the Mid-Continent we're in the 10,000 horsepower, 11,000 horsepower, 12,000 horsepower range. So there's an abundance of those types of equipment around to do what we need to do. Rigs, we own 31 rigs in the Company and 20 rigs of 31 rigs are running for us and some of the things we've done there, certainly diesel costs have gone up. Labor costs have gone up a little bit. We've went from five million crude to four million crude to offset some of those costs. But those types of costs I'm talking about, they are less than 5% of your total well cost. So from that standpoint, we just don't see any appreciable movement, upward movement in cost this year.

Keep in mind that the two types of reservoirs that we chose for our core areas for oil are very different than the majority of companies are drilling today. So they're shallow and they're carbonates. And just the carbonate reservoir in itself is easier to frac than tighter, denser formations like shales because it's a better rock, better reservoir, and so it just doesn't take as much horsepower to frac it. And as the other service costs continue to go up, we're just not seeing that because for decades, this gas industry, the natural gas industry in the United States was built on these type of reservoirs. And so that equipment that's having to be built out to do higher -- excuse me, higher and higher horsepower and deeper drilling in tighter rock is now the other type of equipment that the foundation of the industry's been built on is available. So we have an excess capacity of equipment when other people don't.

Great. And thank you for that excellent detailed answer. And then my last question is, what's your current cost basis and your acreage position in the horizontal Mississippi and where do you think current leasehold is right now there?

Well, our current leasehold is 780,000 acres. We said that we've stopped -- pulled in our brokers in just through the oral or written commitments that we have in place, we should end up between 900,000 acres and 1 million acres. Our cost basis when we're all said and done will be less than $200 per acre.

Where do you think acreage goes right now?

Well, it would be different acreage costs. Keep in mind, there's 6.5 million acres. So the prices per acre has tended to move up but there's many different acreage costs in different areas of the play.

Thank you, Tom.

Thank you.

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

Thanks. Good morning.

Good morning.

Can you talk to your thoughts on future asset sales potential and how aggressively you're looking at that relative to additional acquisitions?

Brian, the question is the future asset sales, what we might do?

Exactly.

The -- we've made it very clear that we have bought more of the Mississippian acreage than what this current CapEx budget would allow us to drill. We could hold basically about 500,000 acres in the next five years with this 12-year program that we have and most of our leases have a five year term. So what we look at then is having about half of the acreage that we'll either choose to pick from or find a partner to move forward and we still anticipate selling more acreage in the Mississippian past our first asset monetization in -- that we project to have in April.

And do you expect to sell assets beyond the royalty trust market either through a joint venture or just a straight sale?

Yes, we leave -- all those options are available, either the asset monetization we've already done or looking to do in the royalty trust. There could be joint venture. There could be just a straight sale of assets. There might be some partnership made in some other way. We're open to other ideas if you have any. So any type of monetization that is the best rate of return for the Company is what we'll try to do.

Great. Thanks. Then secondly, can you just talk to take-away for your oil production, particularly in the Permian and whether you see, A, any backups or potential for any backups as industry grows production?And B, whether there's optionality to move into some of the currently higher priced oil markets?

Yes. I'll say that currently -- I'll let Matt address this, too. We don't have take-away issues but we are looking for alternative ways to move oil away from Cushing.

Brian, I'd just like to add that currently out of the Permian, about 60%, 65% of our oil's being piped out there to Cushing and the remainder being trucked. The issue right now is not an issue for us. Getting oil out of the Permian as much as an issue that everybody's facing, that's the storage inventory going up in Cushing.I think there are pipeline projects in place now that we're looking at, Magellan recently announced that they may reverse their Longhorn line which would take oil from Crane County down to the Gulf Coast, which would certainly help.

But that's probably 18 months out at best and then also, there are several pipeline projects in the talks of taking Cushing oil down to the Gulf Coast, increasing capacity there but that's also probably 18 months to 36 months out. So I think going forward, I don't see a problem getting oil to Cushing Also, there's projects at Cushing right now where I think the storage capacity is going to go up probably another 15% this year. So from a standpoint of getting oil out, I don't see a problem. It's just more of a concern going forward, whether it's going to be a spread from WTI to Brent or not.

Thank you.

Thank you.

Your next question comes from the line of Dave Heikkinen with Tudor, Pickering, Holt.

I have a question, first, Tom, as you think about -- or Matt, as you think about operational governors on your activity levels, both in the central basin and in the Mississippian, can you just talk through that?

Sure. The operational governor in the Central Basin Platform is just logistics. We have plenty of rigs we can get. We have plenty of ability, corporately, to drill more. However, logistically, it's difficult to drill more than about 16 rigs to 20 rigs at a time in the Central Basin Platform, just because the number of wells that you're bringing on. So this year, we'll complete over 800 wells in the Central Basin Platform and I think there is logistically a cap on how much we can do in the Central Basin Platform at one time. In the Mississippian, that's really a different story. It's more related to just capital and we could double our rigs with no issue at all operationally and so that's not an issue for us as far as there's really no logistical issues in the Mississippian. Both areas, we have great midstream.

Okay. Maybe that actually segue ways, then. James, as you think about your role as the CFO, how do you think about establishing guidelines and framework for appropriate leverage, access to capital markets and then any governors on capital access given that the Mississippian could go faster?

Sure. We mentioned in the call that on a cash flow basis our leverage is high. We think our asset base supports it and hedges also help. But we don't comment specifically on capital markets transactions but we'll look to raise enough proceeds from monetizations to fund our cash flow gap and we think we've got a path that we're setting up where we could start to fund that 2012 cash flow gap. As you look out longer term, I think given the capital that we're spending on the Mississippian and the Permian and the growth we're seeing, we can see in growth in production and EBITDA, we can position ourselves to really grow into our debt load and look longer term. I think -- comfortable saying we would love to be below or around that 3 times debt to EBITDA range. It's going to take us a little time to get there. But we're comfortable saying that.

Okay. So debt to EBITDA, debt to reserves are two primary thoughts. That's good.

Yes.

On the other side, just maybe getting in the weeds a little bit on both the Mississippian and then the Permian, first on the Mississippian, can you talk about -- trying to break down fixed monthly operating costs per well and where are the variable costs to try to get into the overall aggregate of what goes into your operating expenses and taxes and the like?

Yes, in the Mississippian, the monthly average cost is about $7,300 a month. Really the fixed component of that, we have a compressor for gas lift operations, that's probably accounts for about half of that cost. And then you have water disposal which is power cost. That's a variable cost because as time goes by, and you have depletion, your water production well goes down so that cost goes down over time. But those are really two primary costs. Of course, you have your pumpers, that's a fixed cost and you have some chemicals for erosion control and things like that. But essentially, it's about $7,300 a month and about probably $4,000, $4,500 a month is a --for compressor rental and that's going to stay pretty constant. Where that could go down over time is when we have enough wells out there drilled and we can start centralizing the gas lift -- our gas lift operations. We'll have a significant savings if we get to do that probably in the next year or so.

Okay. And then Tom, I know in the Permian you like to discuss average wells including Clear Fork, San Andres, Fusselman and other zones. How do you split the 16 rigs running now between those areas?

They go back and forth. Most of the locations are going to be San Andres and Clear Fork. Those are the real bread-and-butter reservoirs. We drill a lot of Wichita-Albany locations also but that's why we keep an average is because you might have at some point more San Andres drilling, less Clear Fork and then another time, more Clear Fork and less San Andres or more Wichita-Albany. There's no way that we can give you guidance that keeps a rig constant in any one reservoir.

Okay. And then just Pinon -- trying to get an idea how much CO2 do you think you'll produce this year?

Well, right now, we're going into the plan from high CO2 gas is about 200 million -- about 230 million, 240 million a day, and 65% of that is CO2.

Okay. Thank you. That's it.

Thank you.

Your next question comes from the line of with Noel Parks with Ladenburg Thalmann. Please proceed.

Good morning. Had a couple of things. My apologies if some of these were covered already and I just happened to miss them. In the Permian at Fuhrman-Mascho, can you talk about the five acre downspacing out there and whether you had any locations that were booked this year for five acre?

Sure. Matt?

In the past year, there's probably 200 acre, 255 acre wells that's been drilled and there's been no -- we've seen no degradation from the type curve from the standpoint of IP or decline or otherwise. So they look very solid. I don't know off the top of my head how many five acre locations we have booked. We do have an Analyst Meeting coming up next Tuesday that we'll go details -- we'll go into detail into all these different bookings of locations in the Permian.

I think you can suffice to say that we did add some five acres.

We did add a tremendous amount of five acre wells. I just don't have that number off the top of my head.

That's fine. Also, at Fuhrman-Mascho, where do you guys stand as far as looking towards water flood out there? I know there have been some planning in the past under the old owners but just wondered where that stood.

Go ahead, Matt.

I mean right now there are no plans for water floods. We have so much primary reserves yet to recover and being able to drill down to five acres and get very good rates of return, I think that's the way to go today. And if there is a water flood potential, I think it will be years down the road.

There was a successful water flood in the unit, not just operated by Arena or us. So there has been -- you're exactly right, there has been water flooding in the Fuhrman-Mascho unit in the past. Water flooding and tertiary is really not something we'll focus on as much as drilling for primary production.

Okay. And actually, also looking out to the future a bit, in the Permian, of course the possibility of other zones, deeper zones and I guess also some shallower behind pipe zones that might not be as prolific as your main target. What oil price environment determines red light or green light in terms of putting energy into evaluating those? Is there -- if we stay headed into a less volatile oil price environment where, say, we could count on the number $70 for the long term, are there things that come on to the plate that say, $60 or $50 wouldn't enable?

I think you're asking is what price gets down to where the red light comes on? Was that -- ?

Yes, especially as far as pursuing some of the, maybe more elusive, deeper targets in the Permian.

You bring up a good point. We don't know what's going to happen out in the future with oil prices. We continue to be very bullish but the only thing no one is taking into consideration is a dramatic drop in oil and so we hedge. And so whenever we look out in the next three years, we have a tremendous amount of oil that's hedged going forward. And that, yes, we might be giving up some of the upside but we have years and years worth of upside that if we lose $30 or $40 a barrel, you'll probably see us continuing to hedge out into out years and locking in the rate of return. So what we look at and to answer your question, if you -- we're -- we have almost 100% rates of return in the wells that we drill so even down to $50 a barrel, we're going to be where it would be competitive with gas prices today. But what the key is, is that we want to lock in these current rates of return that we have and so you'll just see us continuing to hedge as oil prices go up.

Thanks. That's all I had.

Thank you.

And your next question comes from the line of Duane Grubert with Susquehanna Financial. Please proceed.

Yes, guy. Could you address your booking philosophy year-over-year? When I look at your reserves this year, you do have significant revisions on the gas side and last year you guys were pretty vocal about pointing out the low value gas at other companies didn't really make a lot of sense. So could you comment about the philosophy a bit?

We still believe that. We still believe that a gas -- that a PUD is a PUD when it has PV-10, not PV-0 plus $1. So we were very vocal last year. We're the only Company to write-off all of our PUDs that didn't have PV-10. And then this year, we -- also last year, we were very vocal to say that at $4.25 gas, we start to bring back on our reserves. And a reserve is a reserve is a reserve that once it has PV-10 and so that's whenever we have gas that has PV-10 we'll bring it back on the books.

Okay. So basically that's just how the numbers fell out. Now, the situation with your land position in the Mississippian, you've extended into Kansas and you've got a very large tranche and you're indicating maybe you're done. Is it more that you've got as much as you want to get or is it that the play doesn't seem to extend beyond what's already been locked up?

It's the first. We have really as much as we think that we have said in our capital, the capital we have and keeping 12 rigs working, we can hold about 500,000 acres, and we're going to quit at about 900,000 acres to one million acres and use some of that for monetization.

All right. And the last thing, in the Central Basin Platform, in passing you've mentioned good midstream and you've already told us there's not a take-away problem. Can you specifically talk both about electricity and gas handling since that was a problem for Arena and maybe that would be something investors would like to hear specifically?

One of the things we did that we were very cognizant of when we bought Arena is the issues that they are having with both gas take -- gas processing and also electricity. And prior to buying Arena, after we bought -- even prior to buying the Forest assets, we had decided electricity was a huge problem out here and we built our own 20-megawatt substation back in I believe it was in 2009, late 2009, we started one up. And so we had the experience to do that and knowing that we needed to do the same thing when we purchased the Arena assets. And so we had the experience to do that and knowing that we needed to do the same things when we purchased the Arena assets, and so just last year, we started up another 20-megawatt system for the Fuhrman-Mascho field and what that allows us to do is drill couple thousand wells that we can add on -- to that system.

The other advantage of operating our own substation is we have very short downtime. If there is a problem, we have our own guys come out there and fix it and it's often a 12 hour to 24 hour turnaround as opposed to maybe ten days to several weeks. And so as a result, we've had very little downtime even with the freezing problems here recently. We didn't lose electricity as much as we had wells freezing up but that has helped out a lot. On the processing side, I think what really helps us is that we do have a lot of leverage with the processors out there that Arena didn't have because of our size and our -- the quantity of volumes that we produce.

So we were able to negotiate very attractive contracts for SandRidge that we just currently close our negotiations and it was very successful and not only upgrading our netbacks on both the residue gas and the liquids. But also as part of the negotiations, we had a processor commit to spending a lot of money to upgrade compressors and plant components. And so we continue -- we have a very active midstream group. We continue to not rest on our laurels there but also continue to look at other ways to minimize downtime such as building spillover type facilities to other processors and pipelines as well. So it's an ongoing project but we have made significant strides in the last year.

Great. Thank you.

Thank you.

Your next question comes from the line of James Vasser with Wells Fargo Securities. Please proceed.

Hi. Good morning. Just a couple questions. To begin with, just wanted to follow up on the natural gas reserve revision number. Am I correct in assuming that these are primarily PUDs that were added here and that the primary variable that enables PV-10 to move beyond zero was gas prices basically just moving from $3.40 at year-end 2009 to $3.80 at year-end 2010?

I'm not sure -- you were coming in and out on the -- did you catch the question? I'm sorry, was the -- I heard there was a question about the gas prices, but I -- can you get maybe a little closer to your phone?

Sorry about that.

There, there. Now we can hear you.

I was just wondering first of all, just confirming that those are primarily PUD reserves, that you're adding through those revisions and secondly, that the primary variable there was just gas prices moving from $3.40 at year-end 2009 to $3.80 at year-end 2010?

Yes, the answer, yes, it is exactly a pricing that brings -- the reserves were never gone. They just didn't have PV-10 last year and they have PV-10 this year.

Okay. Thank you.

And they're held by production in the Pinon Field, most of the gas reserves we had.

That's helpful. And then secondly, you mentioned that given all your asset monetization announcements to date, you were increasing your expectations for proceeds from $700 million to $900 million. Do you think that, that additional $200 million fully fills your cash flow shortfall for 2011? And then on a related note, do you have any -- can you give us any idea on potential timing of further horizontal Mississippian monetizations beyond your royalty trust structure?

I'll hit the second part and pass to James for the first. The timing on the Mississippian is that we're -- we just have now just finished buying the acreage so have potentially the first asset monetization in early -- late March, early April. We'll continue to look for ways to monetize but we're in really no hurry because we do have long term on our leases. So I think throughout the year, we'll continue to do several things. We'll look at other asset monetizations like we've already done. We will talk to other people about either joint venturing with us or partnering with us, selling acreage, or we'll decide that we want to develop areas ourselves and maybe look at other ways to bring in capital. So I think that we're wide open to other ideas. I have said that our goal this year would be to not only get to $900 million, but to really start pre-funding 2012.

James, just wrapping up on '11, yes, with $700 million of pending and closed sales, at the end of April, that puts us well on the way to this $900 million goal. So yes, with another very roughly $200 million, that would fully fund us for 2011.

All right. Thank you. That's all I had.

Thank you.

Your next question comes from the line of Dan Morrison with Global Hunter. Please proceed.

Good morning. I think my questions have been answered. Thanks.

Okay.

And your next question comes from the line of Philip Dodge with Tuohy Brothers Investment.

Thank you. First, I would just note that your stock price is up 11% this morning but you're probably not paying any attention to that. Now the questions. The positive reserve revisions have been pretty well covered, but just interested whether there was any performance in that or whether it was all price?

On the revisions, it's primarily all price.

Okay. And on the royalty trust, if demand were supporting it would you consider raising the size?

Yes, I don't think we can comment about the royalty trust. Sorry.

Fair enough. Okay. Thanks.

Thank you.

And your next question comes from the line of Richard Tullis with Capital One. Please proceed.

Thank you. Good morning. How do you see the 2011 production growth generally progressing throughout the year? Did you have significant weather impacts in 1Q and taking all that into account?

Sure, I'll pass to Matt.

Well, our guidance, I think, is about 16% over 2010. As far as weather-related problems, we did have a pretty brutal cold weather storm that blew into the -- really across the Southwest here, but it hit our Central Basin Platform production pretty hard in February. And we were basically down from February 1 through February 14 for two weeks there and not down 100%, but down quite a bit and even though our field guys did an excellent job of getting everything back on, we probably lost 100,000 barrels of oil equivalent during that process. But overall, that is built into our guidance model and I, unless -- barring something else that hits us hard, I feel very comfortable about our guidance.

Do you see it evenly growing throughout the year or is it front-end loaded?

Yes, really I think it's going to be a little bit back-end loaded because right now we're getting -- for example, in the Mississippi horizontal play, we have 12 rigs out there but four of them are drilling saltwater disposal wells today, just to get caught up on the need for water capacity but also to set us up for future development. And then in the next two months we'll roll those rigs over into drilling the producer. So, we'll go from eight rigs to 12 rigs, drilling producers, in the next two months to three months. So as we do that, we'll get more of an accelerated ramp-up in probably Q2, Q3. In the Permian, I do see a pretty steady ramp-up there. We have 16 rigs running. We've been running that for a little bit now and with no change in rig count. I think that will be more of a linear growth pattern.

Okay.

Mississippian, it is important to note that we keep rigs working in a rather tight area. Most of our rigs, because of the saltwater disposal systems put in place and that disposal system, while it costs money upfront, it saves about $2.50 a barrel to haul water with trucks. And so we have moved much more aggressively than anyone in the play to make sure we drill disposal wells and cut that cost out.

Okay. And in the Mississippian, with the acreage that you currently have, how much of that do you think has been derisked at this point drilling horizontally?

Well, the whole key to the play was it was derisked because of all the vertical wells. So think about this is, is that in that play in particular, there's been 17,000 wells drilled that are all vertically producing from the same zone. And all you're doing is drilling a horizontal well connecting up the same rock that we already have the type curve on and know that there's oil in the place. So whether it's drilled horizontally or vertically, it's the same rock with just an eight fracs to ten fracs, bringing on eight wells to ten wells instead of one vertical well. But the -- if you look at our presentation, I think on slide 12, you can see that between us and others, there's been horizontal wells now drilled in Payne, Pawnee, Noble, Kay, Grant, Woods and Alfalfa, and Barber County, Kansas.So there's a lot of horizontal activity also.

It's just something to think about is that this play and the Permian Basin, the Central Basin Platform, have decades of production. And so as the industry goes into newer and newer plays without any vertical control, it's not to say they won't be good places to drill, they might be fantastic but there's no way to know until you get two years or three years of production where that decline curve's going to go. One thing about the Haynesville is that it's been -- now it looks like it has a much steeper decline than was projected in June of 2008. And it's really only because there's a couple of years of production history to look at.

The newer areas that you've been adding in the Mississippian, they have as much vertical activity as, say, some of your earlier areas?

Yes.

Okay, good.

If you look across the early areas that we looked at in Woods, Alfalfa and Grant, there were about 1,200 wells across that play that were drilled vertically and that's where we started. But there's tremendous control. In fact, if you look at the map that we provide again on that same slide, you can see that where the vertical well control is to the south and to the north.

Okay. And just finally, with the credit facility, any potential there that you see for increases based on the year-end reserves or PV-10 numbers?

We do have a determination coming up in April and given the increase in our PDP PV-10, we've got plenty of coverage there so we'll work with the banks coming up in April to determine that. But have plenty of room, the facility's $850 million, we have $382 million drawn as of now.

Okay. Thanks very much. Appreciate it.

Thank you.

And your next question comes from the line of Scott Hanold with RBC. Please proceed.

Yes, thanks. Good morning.

Good morning.

(inaudible) know we're at the top so I'll try to be quick. Couple things. First, on the Mississippian play, you talked a little bit about -- you feel pretty good about the delineation from vertical wells control and whatnot. But have you seen any variability in the horizontal wells that tells you what may be better areas than others? What is that specifically? Because I know, for example, like in the Granite Wash, we're now finding that sometimes vertical wells don't tell you where the horizontal wells may necessarily do.And then secondarily, on your production targets that you have for this year, just to confirm, with this royalty trust structure, you'll still report that, the total production combined for both entities and that's what your guidance is set at.

Yes. You're correct, the royalty trust structure does have all the production coming through the Company. With regard to the Mississippian, that's one of the reasons we put down all the wells we've drilled and if you notice, there's a wide variability of production, location to location. So we don't anticipate every well coming on at 800 barrels a day and we don't anticipate every well coming on at 100 barrels per day equivalent. But what we do anticipate that it as over the course of a play that you can have this 240 barrel a day type curve through first 30 days of production. And then you should be able to feel more comfortable in the ultimate decline of the wells because you have all the vertical wells that show basically a 2.5 B factor and we're coming in with a 1.5 B factor in our type curve.

So again, it's just how many years' worth of production, knowing the decline, and then the variability, you really can't tell because it has to do with the permeability across a 4,000-foot lateral in between well to well. So what I always try to say is that we're going to have very good wells mixed with poorer wells or even just good wells across the play. And we don't see yet that there's any certain one spot that is better than others and that includes us or our peers drilling. So we're not claiming our acreage is better or worse than anyone else.

Okay. And you say you're using like 1.5 B factor? And so when I think you said Netherland Sewell gave you 409 MBOE for the total EURs, what is baked into your guidance? What does that B factor imply in terms of a 30 day rate?

It's a 1.5 B factor on the hyperbolic.

I'm sorry, so what would be the EUR on that well that you used in --

Did you ask EUR?

Yes, using the 1.5 B factor.

Yes, the EUR is the 409,000 barrels of oil equivalent.

That's on the Netherland so what we --

At a 1.5 B factor.

Yes, that's correct.

Now what we've done is to say this is a very large area and we say 300 MBOE to 500 MBOE. Now, if you were to use a 2.5 B factor in that same type curve you would be above 500,000 barrels a well.

Okay. Got it. And what is the 409 MBOE -- so what would be the 30-day rate on a well that has an EUR of 409 MBOE?

I think it's 244, 245 barrels equivalent.

So what are you using in your guidance? Are you using that 244, 245 barrels equivalent?

Yes, that's how we model it.

Okay. Thank you.

Now currently, we're above that on the wells drilled to date.

On your wells drilled to date. Okay. Good.

Your next question comes from the line of James [Silcock] with [Secure] Asset Management. Please proceed.

All my questions have been answered. Thank you.

Thank you.

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

Thanks Matt. I can't remember if you talked about this in your comments but the guidance increased on oil up about 10%, can you talk about how much of that is due to the increase in capital versus how much of that you all are attributing to the performance uplift in the Miss?

Well, I think I can't break those two apart. I think they're all interrelated. Just oil guidance itself is going to be up 67% from '11 to '10. Overall guidance is up 16%. We'll have a decrease in gas this year still. But it's all driven by number of wells we drill and our model of how quick we put them online. So it's -- I'm not -- what I don't want to do is start breaking out oil guidance by plays and by fill area. But obviously the bulk of our production growth is going to be where we drill and that's in the Permian and in the horizontal Miss. and everywhere else, Pinon, East Texas, Gulf Coast, Gulf of Mexico, will decline.

Then you said on your saltwater disposal you were building in the capacity into 2012 so once you start moving those rigs over to drilling oil wells, they'll pretty much stay drilling oil wells until at some point next year when you need more?

Yes, that's generally correct. We have -- like I said, we have four disposal wells going right now. We're going to three next week. We'll really back that off to one rig is the way we budgeted right now but I can see that one rig going away probably mid-year and going over to drilling producers. So, yes, the plan is to get plenty of disposal wells out there so we can spread out our drilling and then just plan accordingly whether -- when we need to pick up additional rigs to drill disposal wells or convert the rig from a producer to a disposal well.

Jeff, just keep in mind, that can change if we move out and start drilling additional areas inside the Miss. We would need to have more disposal capacity as we bring in new areas.

Okay. Thanks, Tom. And just in terms of the play, with the water handling, I guess the saltwater disposal systems you all are putting in do translate into a cost savings versus the wells. So I guess as you look at newer parts of the play, you have a little bit of variability in the cost until you get those systems in place; is that correct?

Sure, it's front-end loaded to what's putting in disposal.

Thank you.

Thank you.

Your next question comes from the line of Mike Breard with Hodges Capital. Please proceed.

Yes. One problem you had from a stock market point of view in the West Texas Overthrust is that you were the only ones there whereas people drilling in the Haynesville or Bakken you had press releases coming out constantly from other operators. How many people are actively drilling now in the Mississippian and is that -- has that number increased and have you had calls from others looking to joint venture with you in the Mississippian because you were in there early?

Well, let me think about -- they are a number of private operators that are drilling and do we know how many rigs are working in the whole play? 19 rigs in the whole play, which we have eight. Okay, thank you. And then four of ours are drilling disposal wells. There are other operators drilling in the play. I think interest is -- six other operators. Thank you. I'm getting all the numbers given to me. Very nice people here. So we do have other operators working in the play. There is interest in the play and really for us, it's more what -- a question of what brings in the highest rate of return. We made a decision that, for us, a royalty trust idea, if that were to come through, is a better option initially than doing something else. That doesn't mean that our ideas won't change as the year goes on or do a number of things.

Okay. But have people started to have more interest? In other words, has anybody contacted you yet, talking about a joint venture, knowing that you have excess acreage?

I have a lot of discussions throughout the week with a lot of different people. The play has more interest today than it did a year ago.

Okay. Good. I just -- like I said, would be nice to see half a dozen people putting out press releases on the play instead of just you, like what happened in the West Texas Overthrust. With that rate of return, I can't imagine that there won't be quite a few other operators coming in. But thank you for the update.

Thank you.

(Operator Instructions) And your next question comes from the line of Devin Geoghegan with Zimmer Lucas Partners.

Hi guys, congratulations on a nice quarter.

Thank you.

I went to an Acreage Expo recently and a lot of the geologists that I talked to seem to think the drainage is more in 160s even though the rock is permeable, it appears to be compartmentalized, so to speak. So a lot of people I talked to think that it might actually work on 160s.I know you guys have been taking the average of 320, 160 of it. Are you seeing any evidence that would make you more bullish on the density?

We have moved from 320s in the last year down to about 215. So three wells per section. And we're not seeing interference as we've drilled wells that close together. We've done that several times. So there's no argument that I think we -- there we've seen other people drilling 160s and I can't argue that it won't go to that. We're prepared to go to 160s if that drainage is the appropriate drainage. Keep in mind, the vertical wells were drilled on 40s and even 20s. So it's possible that we could move down.

Okay. Great. Thanks, guys.

Thank you.

Your next question comes from the line of Robert Carlson. Please proceed.

Yes, first, congratulations on a great quarter. What's transpired over the last, what, two or three quarters, is short of amazing. Congratulations. I wonder if you could comment on some volume guidance for 2011, '12 and '13 and also updated on your current hedges. I know last night I saw you on Kramer and you mentioned that those hedges had been modified.

Sure. We gave an update on our current hedging and we've also said that we're willing to add 2013 at [carbonate] the $100 range on crude oil, not making a bear case for crude oil by any means but just wanting to make sure we can lock in 100% type rates of return if we're correct and our service costs don't move up in the next couple of years. And I think the preponderance of evidence is that we're not seeing service cost inflation as others do. So and I don't see the industry changing because it is very difficult to move in and buy shallow carbonate reservoirs because they're not as abundant to buy big acreage positions as zones that have never been drilled before in places that have never produced. And so like in the Central Basin Platform it would be impossible for us to have ever gone and bought the acreage and to drill the wells like we are today. So we had to make the acquisitions and we had to be there early to do that. As far as guidance out in the future years, we're only giving guidance out through 2011.

That is what now?

On production [presently]?

On production, right?

It's 23.3 million barrels of oil equivalent.

Did you say we do have some $100 hedges in place presently?

We do have what? Excuse me?

$100 hedges?

We've put on some $100 hedges, over $100 hedges in 2013.

Again, thank you and well done.

Thank you very much.

At this time, there are no further questions in queue.

Well, thank you, as always for joining us for this call. And if there are any additional questions, be sure to give us a call then. Thank you.

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