SandRidge Energy, Inc. (SD) Q2 2011 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Second Quarter 2011 SandRidge Energy Earnings Conference Call. My name is Keysha and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, James D. Bennett, CFO. Please proceed.

Thank you, Keysha. Welcome, everyone, and thank you for joining us in our Second Quarter 2011 Earnings Call. This is James Bennett, Chief Financial Officer. And joining me today are Tom Ward, Chairman and Chief Executive Officer; Matt Grubb, President and Chief Operating Officer; and Kevin White, Senior Vice President of Business Development. 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 measures we discuss can be found in our earnings release and on our website. Also note that today's call is intended to address SandRidge Energy and not the Royalty Trust, Sandridge Mississippian Trust I, ticker SDT. SDT will have a separate earnings call at 8 am Central time on Friday, August 12. Now, let me turn the call over to Tom Ward.

Thank you, James. Welcome to our second quarter operational and financial update. As you've read, we've had a busy few weeks. I'll use this small amount of time to update you on our progress from the last quarter and give you a glimpse of our new acreage play in the Miss plus develop the development of our 3-year growth plan. Yesterday, we announced the signing of a joint venture with Atinum Partners, a highly respected financial partner and energy investor based in Seoul. The joint venture encompasses the original Mississippian idea that we've been developing over the last few years. SandRidge will receive $500 million in consideration, composed of $250 million in cash at closing and $250 million in a carry structure over a 3-year drilling term. We will deliver 113,000 net acres of our greater than 900,000-acre Mississippian position. With this sale, we will have monetized $580 million of cash and $250 million of additional carried interest on an initial investment of approximately $200 million and continue to own our nearly 90% of our acreage. The transaction further substantiates that the Mississippian carbonate play is considered one of the best areas to drill in the U.S. today. There have now been 92 wells operated by SandRidge with at least 30 days of production history. These wells have a 30-day rate of 297 barrels of oil equivalent per day compared to the 244-barrel of oil equivalent per day rate used in the Netherlands Sewell type curve that has an EUR of 409,000 MBoe per well. We have information on a total of 136 total wells with at least 30 days of production, and these wells have a 30-day rate of 284 barrels of oil equivalent per day. We calculate our type curve well to have an excess of 100% rates of return using a $3 million well cost. The play in total now has over 250 horizontal wells that have been drilled. Given the positive performance of our wells, we are now increasing guidance to 24.1 million barrels of oil equivalent in 2011, which is a 20% production increase over 2010, and we're projecting a corresponding 20% production increase in 2012 to 29 million barrels equivalent. We have also announced our second horizontal Mississippian Play, in which we have purchased over 200,000 net acres with a plan to be at 1 million acres by the end of this year. We do not anticipate spending any more, per acre, than we did for the original Mississippian acreage bought in Oklahoma and Southern Kansas. This new play has all the same characteristics of our original Mississippian play. We are focusing on shallow carbonate, low-cost oil that can be acquired and drilled for approximately the same amount as we have invested in the current Mississippian play. We also have and focus on thickness of reservoir and have chosen to stay in areas that have at least 250 feet of Mississippian thickness. We like carbonates because of the matrix porosity and permeability. However, maybe the most important factor in describing what we look for in a play is history. We want to understand what production decline will look like several years into the play. The original Miss Play had 7,800 vertical wells drilled within our buy areas. The new Miss play has over 8,500 vertical wells drilled by -- with very similar EURs to current Miss but even at shallower depths. We also continue to believe that 3 wells per section is the appropriate estimate for wells in the Mississippian formation. The storage capacity to find 400 to 500 Mboe per well is found through matrix porosity, fracture porosity and higher perm rock. Therefore, we are hesitant to drill too close as we want to spend the least amount of capital to get the most oil and gas from the reservoir. It is also impossible to predict, with any accuracy, how a reservoir will decline over a long period of time without some history of production. Within our areas of focus, carbonate wells have been drilled for decades, giving us confidence in that future well performance. We want to manage and minimize risk by investing in plays that will allow us to drill and complete wells with equipment that is plentiful and developing reservoirs that have a proven production history. The abundance of low horsepower drilling and completion equipment has allowed us to keep our drilling cost relatively flat during the last 2 years, at a time when the industry's drilling cost have risen quite dramatically. In summary, our strategy is quite simple: drill in areas with historically proven production and keep our costs down while taking advantage of high oil prices to create strong rates of return. We then lock in these rates of return by hedging future oil production. We have already hedged over 30 million barrels of oil for the next 3 years and continue to be willing to hedge more. Lastly, we're announcing a 3-year plan, which by the end of 2014, we would have a self-funding capital program, debt-to-EBITDA ratio of less than 2x and maintain double-dip -- double-digit production growth. This plan incorporates bringing NAV forward by narrowing our drilling inventory in the Mississippian to approximately 10 years from the 25-year inventory we had in the 1st of this year and keeping our Central Basin Platform inventory and drilling schedule as it is today. This goal is achievable with a capital budget of about $1.8 billion to $2 billion per year and would generate EBITDA over $2 billion in 2014. The outcome will be a company that doubles our 2012 production, a continued large inventory of drilling opportunities and a very strong balance sheet with best-in-class results. Lastly, our 2014 plan does not assume any success we may have with our new Mississippian play. I'll now turn the call over to Matt to further describe our plans into the quarter.

Thank you, Tom, and good morning to everybody. I will start with Q2 production and go into drilling performance, 2011 CapEx increase and LOE. We produced 30,400 barrels oil per day and 189 million cubic feet of gas per day for an average of 62,000 barrels of oil equivalent per day in Q2, as compared to 28,700 barrels of oil per day and 192 million cubic feet of gas per day or 60,700 barrels equivalent per day in Q1. This is a 2% quarter-over-quarter production growth considering the impact of 1,500 barrels of oil equivalent per day for the New Mexico assets sales in April. Our quarter-over-quarter pro forma total production growth is nearly 6% and approximately 10% in oil production growth. With the announced 2011 CapEx increase, we have also increased our 2011 production guidance from 23.3 million barrels of oil equivalent to 24.1 million barrels of oil equivalent. This is a 3.4% increase to our previous 2011 guidance and a 20% increase to 2010 production. Again, if we look at it on a pro forma basis for the New Mexico assets sales, this is approximately a 5.2% increase to the previous 2011 guidance, and if we add in the impact of Wolfberry sales early this year, our new guidance represents 25% increase to 2010. With our rig ramp-up plan in the Horizontal Miss, which I will discuss further, we seek to grow total production another 20% in 2012 over 2011, and that represents a 35% increase in oil production over that same period. We anticipate producing about 16.7 million barrels of oil and 75 billion cubic feet of gas for a total of 29.1 million barrels of oil equivalent in 2012. As mentioned earlier, we averaged 62,000 barrels of oil equivalent per day in the second quarter. With the continued success, we are seeing in the Horizontal Miss program, steady results of low-risk drilling and an aggressive work-over program on our Central Basin Platform. We have had a great start into the third quarter. Our total production in July increased to 66,000 barrels of oil equivalent per day where we averaged nearly 34,000 barrels of oil and 192,000 cubic feet of gas per day. During this period, we also saw a one-day high of 68,000 barrels of oil equivalent. From a drilling standpoint, we are running 16 rigs in the Permian Basin and plans to maintain that level for the remainder of 2011. We drilled 197 wells in the Permian Basin in the second quarter, bringing the total to 399 vertical wells drilled in the Permian Basin in the first half of this year. With some movement in the drilling mix, we anticipate to drill a few more wells in the second half of the year. Our new projection is 834 wells drilled in the Permian Basin for 2011. This is 23 more wells than we had previously estimated for the year. Our Permian Basin activity is focused on the Central Basin Platform, where we'd primarily drill low-risk vertical San Andres and Clear Fork wells at depths from 4,500 to 7,000 feet. In the Horizontal Miss play, we currently operate 14 rigs and continuing to ramp up with a goal of exiting 2011 at 18 rigs. We drilled 38 Horizontal Miss wells in the quarter, bringing that totals to 61 new wells drilled in the first half of this year. With our current rig plan, we now project to drill 171 Horizontal Miss wells in a year. That's 33 more than we had initially estimated. As you have seen, we've increased our 2011 budget by $500 million to $1.8 billion total. The allocation for the increase is as follows: $150 million for drilling more wells in the Permian and the Miss wells including saltwater disposal wells. And also, that includes the adjustment of well cost in the Miss from $3.5 million to $3 million. There are also $50 million in non-op drilling in the Mississippian and increased workovers and in recompletions in the company. The biggest part of the increase is in land. $275 million in additional land spending for acquisition of new acreage in the Central Basin Platform in the new Mississippian Play, and $25 million for oilfield services in midstream. We also have guided to $1.8 billion budget in 2012, where we anticipate drilling about 850 wells in the Permian Basin and about 350 Horizontal Miss wells in the Mid-Continent next year. We ended the quarter at $14.51 per BOE on LOE. This is $1.41 per BOE higher than the high end of our guidance of $13.10 per BOE. The higher LOE is due primarily to higher cost associated with the rapid growth of the Horizontal Miss play in the Central Basin Platform. Securing right-of-way and equipment have been slower than we anticipated for electrical infrastructure build-out in the Miss play, and as a result, we have had to rely on excessive use of rental generators and diesel fuel. This increased our LOE in Q2 by about $3 million or $0.53 per BOE. In the Central Basin Platform, where we have drilled -- added nearly 400 new wells in the first half of this year, we've outpaced our saltwater gathering and disposal capacity and have had to rely more on trucking. This resulted in an LOE increase of about $0.32 per BOE. During Q2, we also had some unscheduled operated and nonoperated maintenance expenses in the Gulf of Mexico in amount of $2 million or $0.35 per BOE, but we don't expect this to be a recurring event. Lastly, we have embarked on aggressive workover and maintenance initiative in the Central Basin Platform to restore inactive wells, reduce wellhead pressures and refrac in oil wells. These are typically quick payout, high ROR projects that would create long-term value. We increased spending in Q2 by $2.6 million in that area, and that represents a $0.46 per BOE cost increase. In total, this adds up to $1.66 per BOE. We are working aggressively to get ahead of our saltwater disposal and electrical issues in the Central Basin Platform in the Miss play. But we anticipate it will take several more quarters to resolve. As a result, we have increased our LOE guidance to a range of $14.10 per BOE on the low side to a high of $15.50 per BOE with the midpoint of $14.80 per BOE. At this time, I will turn the call over to James for financials.

Thanks, Matt. Our second quarter is very positive and eventful for SandRidge. Our production was on target, results in our 2 oil plays continued to meet or exceed expectations. And our confidence in our asset base continues to grows. We continue to have success in raising capital, this year, and announced 2 very significant transactions this week: the launching of the second Royalty Trust and our joint venture in our Mississippian play. The combination of our large, high-quality asset base and the ability to raise funds around these assets allow us to increase our capital program and bring forward the NPV of our drilling inventory, while at the same time, adding another potential oil play. Regarding our balance sheet liquidity, we will continue the monetization of assets and adhere to our goal of funding CapEx with non-debt sources of capital. Touching on a few of our financial results. For the second quarter, adjusted net loss was $2 million or $0.00 per diluted share. Adjusted EBITDA was $156 million or $182 million including realized gains on out-of-period hedges, and operating cash flow was $134 million. Recall that in April, we completed the IPO of SandRidge Mississippian Trust I, which is being consolidated into the financials of SandRidge. So in the second quarter, you will see net income attributable to noncontrolling interests on the income statement, which reflects the impact of the 62% of the trust owned by the public. Also the actual quarterly EBITDA impact from the trust can be found in our reconciliation of adjusted EBITDA tables in our earnings release. SandRidge's second quarter adjusted EBITDA is up 7% over the first quarter 2011, and 18% versus comparable period in 2010, as a result of higher oil production and higher realized oil prices, somewhat offset by a decline in gas production, and as Matt discussed, an increase in lease operating expenses. Capital expenditures for the quarter were $454 million and $874 million for the year-to-date period. In terms of leasehold, as Tom mentioned, we launched a new Mississippian play and began acquiring acreage in the play. In the second quarter, we also added to our acreage positions in the original Miss and the Central Basin Platform in the Permian Basin. In our earnings release, we have updated full year guidance and included initial production in CapEx guidance for 2012. In terms of 2011, we are increasing our production guidance by 3% or 800,000 Boe to 24.1 million Boe. We're also increasing 2011 CapEx by $500 million to $1.8 billion reflecting the increase in the rig count in Mississippian play and leasing efforts in our second Mississippian play. Recall that 100% of our drilling expenditures this year are directed towards oil, as returns on our oil projects are superior to those on our gas assets. Other per-unit measures, including LOE, DD&A and G&A have also been updated. As Matt discussed, we are seeing higher lease operating expenses and have guided that range up to $14.10 to $15.50 per Boe. While we think over time we can bring these per-unit costs down, as we achieve scale in Mississippian play, for now we feel it's prudent guiding at this higher level of LOE. In terms of our capital-raising efforts, this week, we issued press releases for 2 pending and important components of our capital-raising program. First on August 1, we launched the IPO of our Second Royalty Trust, which we expect to close in mid-August and net proceeds to SandRidge were approximately $600 million. Second, this week we signed definitive agreements to enter into a joint venture and development agreement in our original Mississippian play. As discussed in more detail in the press release issued yesterday morning, this $500 million joint adventure consists of $250 million of cash at closing and $250 million in the form of a drilling carry, which is expected to be utilized over a 3-year period. Generally for transfer of 13.2% working interest and approximately 860,000 acres or approximately 113,000 net acres. Also note that in the JV, we're not selling production or conveying an interest in any proved assets or HBP acreage. All of this is included from the AMI. The JV is expected to close in the fourth quarter. The pending closing of these 2 transactions, combined with $800 million in year-to-date closed asset sales, will fully fund our revised $1.8 billion 2011 capital budget and also begins to fund our 2012 capital needs. With the continued success of our capital-raising efforts, we feel very comfortable raising our 2011 and 2012 CapEx guidance to $1.8 billion. Turning to our liquidity and balance sheet, at June 30, we had total debt outstanding at $2.9 billion, consisting of $80 million outstanding under our credit facility and $2.8 billion senior notes. This represents a $280 million reduction in total debt from March 31. As of August 1, we had $195 million outstanding under our $790 million credit facility and available liquidity of $573 million. Pro forma for the over $800 million of proceeds from our 2 pending capital raise transactions, we'll have approximately $600 million of cash on the balance sheet, no debt outstanding under our credit facility and we'll have reduced our leverage by over a turn of EBITDA. In terms of our hedging position, we continue to hedge our oil production, to summarize our updated derivative position which is outlined in our earnings release. Since our second quarter earnings, we have added oil hedges in the form of swaps for 6.4 million barrels at an average price of approximately $102 per barrel. For the remaining half of the year, we have approximately 71% of our guidance liquid production hedged at $88 dollars per barrel. And through 2015, we have 32.5 million barrels of oil hedged at approximately $93. This concludes management's remarks. Keysha, let's -- I'd like to open up the call for questions.

[Operator Instructions] And our first question comes from the line of Neal Dingmann with SunTrust.

Tom, maybe could you address a little bit more on this new Horizontal Miss play? Obviously, with the amount of money it seems like you've set aside with the new CapEx, is it safe to say that you've already kind of earmarked some acres that are likely to be picked up for the remainder of the year... Or and then if so, any color you can give in relation to -- I understand it has a Horizontal Miss perspective kind of location versus some of these existing plays?

Sure. We won't get into location because we're still actively leasing. We've said we're at 200,000 acres. We think we can be at 1 million acres by the end of the year. That is all in our budget of the -- increasing in our budget $$1.8 billion. The key is that it has tremendous history. So in any play, whether it is sandstone, carbonates or shale, the key to the play, for Sandridge, is that you have some kind of a history in place that you can estimate what the future production will look like. And then keeping your costs down is the second thing that we look at. So being shallow and being able to drill in areas that don't have tremendous service costs pressure is the second criteria. Then you look at shallow, as we've talked about carbonates we like, we know these types of reservoirs. So we're very comfortable with that. And then the other very important part of this is that it's oil. So for all those criteria plus having more vertical wells in our original play at the same type of EURs, make us very comfortable. Just as where we're comfortable in doing the step-out program that we did inside our original Mississippian play.

And then Tom, it's either for you or Matt. Just wondering you mentioned, I think the CapEx went up a little bit for the new drilling costs, a little bit more, Matt maybe you could suggest around [ph] what you're assuming for well cost. I think he'd addressed that a little bit. But obviously with the slightly higher CapEx, is that safe to say that what -- cost will continue to creep up through the remainder of the year? Or what are you seeing around the Horizontal Miss in the Permian cost?

Keep in mind that our cost inflation has stayed relatively flat, so -- in service cost. What we did as we went in to a drilling in one specific area in Alfalfa county where we already had a saltwater disposal system in place, and we drilled those wells fairly close together and became very efficient at drilling. And so we had service cost or well cost, if you might remember over the last year, started at $3 million and went down to the $2.5 million range. And so we made an estimate that we wouldn't be able to drill wells as we became more efficient at $2.5 million per well. What happened as we moved into different areas with different types of rock, even though it's in the Mississippian, and brought in new rigs, our efficiencies actually went the other way. So we moved back our cost to $3 million and we feel like we'll be able to hit that number. Also in the Permian, we aren't really seeing any service cost increase either. It's been relatively flat. So the way to justify that is to say, look back at our June of 2009, we were locking in rates at what we thought were recession lows on service cost. And we estimated the cost of the San Andres well to be $500,000 per well. And this year, or just now, when we've launched our Permian Trust, the S-1 has in that $513,000 per well.

So even the fracs you're staying pretty stable in that, Tom? Frac cost?

Yes. Basically, all our service costs are relatively stable compared to the rest of the industry.

Okay. And last quick question just on that assumption you have for the 2014 sort of cash flow, what type of oil and gas prices are you assuming in there?

That was as of the strip.

And our next question comes from the line of William Butler, representing Stephens.

Can you all talk a little bit about the current production rates on the Mississippian line right now?

Yes, as a whole or on per well basis?

As a whole versus the 8,400 average for the quarter.

Yes, give me just a second here. Right now, the Miss play is producing 15,720 barrels of oil equivalent per day.

Okay. And where was it? At the end of the quarter?

At the end of Q2 in June, we were probably right at just around 13,000.

Okay, thank you. And then your CapEx that you've got outlined for 2012, that is already net of the $250 million or part of that carry, correct?

That's correct.

And what about just help me on the current production coming out of the Permian Basin, if you would, also?

Yes. Let me pull that up. The Permian Basin is currently producing, on a BOE basis for July, it averaged 29,300.

And our next question comes from the line of Joe Allman representing JPMorgan. Joseph Allman - JP Morgan Chase & Co: Tom, just wondering on the new Mississippian play, why announce it now and why give the details that you've giving including the formation that you're targeting ?

Because we were including the -- in our CapEx the spending of for acreage. Joseph Allman - JP Morgan Chase & Co: That's okay, all right. I guess the reason for not giving more details is just you think you would invite competition and raise their costs up. Is that right?

That's right. We wouldn't have announced it at all if we didn't need to disclose that we're going to be spending more acreage on land. Joseph Allman - JP Morgan Chase & Co: Got you. And then in terms of your screening process for looking at new plays. So could you just describe that somewhat? And then are you looking at additional plays in addition to this new Mississippian?

No, we're not looking to add additional plays. But the screening process is just what I've mentioned. First of all, you need vertical well production, you need it to be shallow, it needs to be oil. And in our case we like permeability and porosity. But if other plays that didn't even have perm and porosity have good well-control and you can make high-rates return, we'd look at those types of rock, too. But in our case, we would tend to like carbonates because of their permeability and porosity. Joseph Allman - JP Morgan Chase & Co: Okay, that's helpful. And then with the Permian Trust that you launched, when do you expect to close that?

This is James. I can't really comment specifically on the Permian trust. We launched the road show, and we would hope that in mid-August, that's closed. Joseph Allman - JP Morgan Chase & Co: Okay, that's helpful. And then in terms of your guidance that you gave, just to clarify, does that already includes the production in CapEx related to the JV?

Yes, that's correct. Joseph Allman - JP Morgan Chase & Co: That's okay. And then lastly, in terms of financing needs, this $500 million is helpful. What do you view as additional financing needs? Do you feel like you need to go out and potentially do another royalty trust? Or you need to do something else to help cover any cash flow shortfall?

What we've said, we raised $800 million in proceeds this year. The Royalty Trust is pending and the joint venture will fully fund all of -- all of these revised 2011 $1.8 billion plan and also carry over into '12. So we have a deficit in '12 that we'll start to fill, and we've always said we have several ways of doing that.

And Joe, keep in mind, we wish to have 90% of our -- basically 90% of our Mississippian -- the original Mississippian, that we own. And we like the way, absolutely, that we have chosen to finance so far.

And our next question comes from the line of Dave Kistler, representing Simmons & Company. David Kistler - Simmons & Company: Following up on Joe's question there. Looking at the JV, you guys announced yesterday, no production was sold into that. How many PDP wells have you guys built up year-to-date? And what does the balance look like for the rest of this year in the Miss line? Rationale for the question being that certainly would set up to support another royalty trust. And could you give us an idea of the magnitude of that royalty trust?

Sure. I think what I had was only numbers with 30-day.

We've drilled a total of 111 wells, Horizontal Miss wells, that's company-operated wells. And so the first Miss Trust, Mississippian Trust, I believe, had a 37 PDP wells in it. And so if you can do the math there and you can see what's available for another trust if we decide to do so. David Kistler - Simmons & Company: Wouldn't a portion of that, though, been captured in PUD drilling for the trust as well?

A portion of it is, yes, you're right. And I don't have that number on top of my head how many wells that is.

And Dave, you'd also have to decide how large of a trust that you want to do if you chose to do one. David Kistler - Simmons & Company: Exactly. And that's kind of what I'm getting in. It looks like certainly, there'll be enough PDPs not associated with the royalty trust to maybe have a royalty trust 2x the size of the first one. Is that unreasonable?

We would have more than enough available today to do one at least as large as the first. David Kistler - Simmons & Company: Okay.

We do -- I do want to comment, we do have a royalty trust call next Friday that will go into details on exactly how many wells we'll drill in the trust and so forth. David Kistler - Simmons & Company: Okay, that's helpful. And then just on the financing line as well. Looking at the revolver right now, I know in the past you've had the opportunity to take it higher. But now with these trust vehicles falling into place, can you guys comment a little bit on how reserves, associated with the trust work, as far as a credit facility? And whether or not those fall into reserve-based lending?

Yes, Dave, this is James. It's a good question. The reserves associated with both trusts were -- have always been excluded from our credit facility in terms of the borrowing base. So the borrowing base has an interest and really collateral in all of the assets of the company. But the reserves associated with those, we pulled those out before we get any of our redetermination. So even the spring redetermination didn't include any of the reserves for the pending royalty trust. So that will have no impact on our borrowing base. And if you recall in the spring, we were almost 3x over-collateralized on a PDP, PV-9 basis in our revolving bar credit facility. So if we wanted to, we feel we could have increased it but really didn't plan to be in our revolver much this year. David Kistler - Simmons & Company: Okay. And then, I guess, kind of the last question on financing would be, clearly, it looks like a royalty trust is still on the table. JV market, as of yesterday, still seems robust. Where do we stand as far as thinking about equity as well?

Well, as you know, what I've always said is that we have there basically 6 types of financing that we could do. We have -- we feel like that we have enough debt, as we want to grow into our debt, that's why we have debt-to-EBITDA goal of less than 2. We feel like we have enough preferred out. We'd rather not sell gas assets in a depressed gas market. So that kind of left us with the 3 options being joint ventures and the royalty trust and equity. Now, I've never said we're going to issue equity. I've just said that they were the last 3 options that we have.

And our next question comes from the line of Mark Hanson representing Morningstar.

Would you mind talking a little bit about what backlogs look like right now in Central Basin, Permian and Horizontal Miss? Just wondering wells waiting on completion and then waiting on tie-in and what normalized run rates might look like.

Backlogs for Sandridge, is what -- I assume that's what you're asking about?

Yes.

Yes. I mean in the Permian Basin, we're always running about 30 wells that are rig release waiting on frac, and that number really hasn't moved much in the last 6 months. And in the Mississippian, we usually frac these wells within 7 to 10 days after we rig release. And there may be 5 or 6 wells out there that's waiting on fracs right now.

So I think, maybe your question is, are we being backlogged by infrastructure or services? And no, we're not.

Okay. And then beyond 2012, do you anticipate holding the rig count in the Horizontal Miss at 24?

No. We anticipate -- in this growth environment or growth strategy that we have, we would end 2012 at 30 rigs. Now keep in mind, if the world were to change, we have an excellent hedge book and we can always move that back. So the plan today is to add a rig a month in the Mississippian to be at 30 rigs at the end of 2012.

Okay, great. And then, what is your current [indiscernible] interest?

That gets us to what we've mentioned as an average 24 rigs during year at 2012. That's what's in our budget.

Okay. And then accounting for the JV here, can you give us what you're working interest right now is across all your Horizontal Miss position?

Yes. Counting the JV, we'll probably be around 70%.

And our next question comes from the line of Gil Yang representing Bank of America Merrill Lynch.

The workover activity that you talked about is in the Permian, I presume?

Yes, that's correct.

The saltwater disposal issues, should we think of that as an ongoing somewhat perpetual issue? Or do you ever catch up in terms of the infrastructure that you can build out? And does it peak? Does that infrastructure peak long before you peak on the well activity?

I really think we will catch up. I think part of it was -- the part that takes the longest is waiting on a disposal permit from the Railway Commission in Texas, that's taking some extra time. But from a planning process, we have gone out there and planned ahead, going through the end of this year and the end of 2012. So to the extent we get those permits in the next few months, we should be able to catch up at least on the 10,000 barrels a day right now that we're having to truck. And I think we'll probably -- knowing that has taken long enough for permits, we should be able to plan ahead and do better job going forward.

I'm sorry, you just spoke about -- you said they're in Texas?

In the Permian Basins. Yes, the Permian Basin's in the West Texas.

No, no, no. I thought that Permian -- the saltwater disposal issues were in the Mississippian area.

No, no. We don't have any disposal issues in the Mississippian. We're just waiting on some electrical infrastructure to be built there.

So what is the misnomer is that the Mississippian is the only place in the country that produces water. Today, we produce about 150,000 barrels a day of water in the Central Basin Platform on wells we operate. So we take care of the vast majority. We just have been drilling at a very fast pace and have out run that for the near term. We'll be able to drill disposal wells over time and catch that up.

Okay. And in terms of the well cost, you went from $3 million to $2.5 million to $3 million with the new rigs that are maybe less efficient and new areas that you're less experienced in. Do you think that you'll go back down to $2.5 million at some point?

I think that's our goal. But right now, we're just seeing that the play is so new, that you're going to keep on bringing in new rigs and you're going to keep on drilling new areas. And when I say a new area, that's really township by township. So across 6.5-million-acre play, there are a lot of townships to drill in. So for the near future, as we go out through our plan, we don't anticipate cutting that well cost.

And our next question comes from the line of Craig Shere, representing Tuohy Brothers.

Tom, you rightly mentioned again that you all have no interest in selling the gas properties. And you've recently been commenting about an expectation with maybe with the Haynesville and Barnett rolling over the 2012, we might see a nice recovery there. And you might get some good value in a year or 2 out of that kind of a, ace up your sleeve, so to speak. But more recently unfortunately, we're seeing an impact on demand with economic conditions. I just wonder if you could comments about your perspective on the gas market and the value that's kind of hidden in your portfolio today.

Sure. I can give a perspective. Keep in mind it's just my perspective. But I believe that we are -- we do have a lot of supply of natural gas. And that at these prices and bringing on new capacity in the Haynesville, that you'll still see higher supply here in the near term. But we believe 2012 will be a better natural gas market than it is today. I don't believe it will compete with oil in the future. And so we'll continue to concentrate on oil and look for a time to be able to do something with our gas assets. And we think -- we don't know when that is, but I don't think it is necessarily out of the question that we couldn't start looking at that in the next year or so.

And I think you've mentioned before you wouldn't initially jump right into a sale on properties you haven't worked on for a while. So it'd be a little CapEx ahead of a final sale, is that correct?

Well, we haven't even anticipated it. So a speculation would be is that you would want to, at any field that hadn't had any work on it at some time, we'd want to spend some capital with the idea of selling it, so that could be.

And our next question comes from the line of Duane Grubert representative of Susquehanna.

Guys, I'm impressed you get remarkable consistency production across the Oklahoma Mississippian well. What do you guys envision is going to be the driver of efficiency improvements in terms of the wellbore? We always want you to have lower well cost through drilling times and all that. But is there anything about the physical design of the well or the frac that you see as a particular focus area going forward?

Yes, I think as we -- our drilling so far from end-to-end is probably somewhat something anywhere of 130, 140, 150 miles apart. And so as we know, as we learn more about the geology in each of the different areas will look better on a granular basis, if you know exactly what kind of rock we're cutting, we'd do a better job of bit selection in those areas. And I think I could add a day or 2 there, save you a trip or 2 during the process. And as we move up and do more drilling in Kansas in 2012, that is probably -- we'll have an opportunity to drill 500 feet to 1,000 feet lower, so that's going to add up, take off a couple of days also. We continue to try different types of completions. We've gone from 14, 15 stages at the beginning of this play in early 2010, and we went into 11, 12 stages and we went to 8 stages, and we're continuing to break that down. We'd pump probably 1/2 dozen wells with 6 stages of fracs and have not seen any difference in the IP, so that will cut some costs also. So yes, there are things that we're continuing to learn and continuing to do that I think over time, we'll continue to improve on the cost side.

And Duane, even as we have again, this is 150 miles of a part of wells, you're going to have some wells that have higher GOR than others who have more oil. And we'll continue to work on our types of lifting, whether it's ESPs or gas lift. The ways that we drill wells in different areas will improve for the production side out in the future. So we still are very early in the play. But you're right that consistency across the play has been very good.

Okay. And kind of a related question. You're about to spend a lot more money and granted a lot of it for land. What kind of staffing up do you need to do? And how has SandRidge fundamentally changing culturally and technically in terms of its mix with your go-forward plans?

Well, we already had have a great staff in place. And we've move from drilling gas wells into drilling oil wells and have moved the appropriate people into new areas. So keep in mind in 2008, we had 47 rigs running. So the staffing here has been good. We do continue to hire new people, great people, and so we don't see staffing as an issue.

Okay. then sort of related again in terms of vertical integration with your rigs fleet, do you intend to pick up any more rigs or any other kinds of service investment with your increased activity?

We've mentioned in the last call that there -- we anticipate, we haven't seen it yet, but we anticipate there would be an increase in drilling in the Mississippian play in Oklahoma and Southern Kansas. And with that, we thought there might be a tightening in the 1,000-horsepower rig fleet, but so far, we haven't seen that. And we've been able, over the last quarter, to go out and make contracts and so far haven't had the necessity to be buying equipment. So it looks like -- if it looks like we can continue to fund, take/keep the rigs that we have and not have to increase, that's our goal.

Okay. And then one final one, just a real short answer to definitively on the joint venture, you just did. So I heard you say you sold no wells, no production. Is it also true there's no PUDs on the books that got sold with the transaction?

No, that's not correct. So the joint venture would be outside of units that are producing. So there would be some PUDs that could -- in the joint venture and some PUDs that might not have been.

And our next question comes from the line of Peter Kissel, representing Howard Weil.

Most of my questions have been answered, but I had a quick question on the natural gas production. Guidance got a nice little bump, and the quarterly production looked a little bit better than what we were looking for. And my question is, is that more due to a shallower decline than expected in the West Texas overthrust? Or is it more just associated gas in the Permian and Mississippian?

Yes. Are you talking about for 2011?

Yes, exactly.

It's really -- our gas decline outside the Permian and the Mid-Con and the non-active areas have been fairly consistent with what we predicted earlier in the year. But what we are seeing is more gas in the Mississippi drilling, not at the expense of oil, but certainly a higher gas rate than what we have in projection on the type curve.

As you think about that, this -- in looking at the 30-day rate, it's above the type curve and that's mainly with gas.

Your next question comes from the line of Hsulin Peng representing Robert W. Baird. Hsulin Peng - Robert W. Baird & Co. Incorporated: This is Hsulin. My question is regarding your 3-year strategic plan. Can you talk about the growth rates that you're assuming for production in 2013 to '14? Is it similar to the 20% for '11 and on 2012?

Well, we just said it'll be -- that we will be comfortable with double-digit production growth. Hsulin Peng - Robert W. Baird & Co. Incorporated: Okay. And then in terms of your targets set to EBITDA of less than 2x, is that a goal for by the end of 2014? Or would like to see that earlier, say next year or '13?

That's the goal by 2014. Hsulin Peng - Robert W. Baird & Co. Incorporated: All right, 2014. Okay.

By the end of 2014. Hsulin Peng - Robert W. Baird & Co. Incorporated: The end of 2014, got it.

And our next question comes from the line of Derrick Jumper, representative of DW Investment Management.

This is actually Dan Chandra on Derrick's line. I have a couple of questions. First you went through -- and I've have been on and off the call so I apologize if you've covered this in more detail. In the opening comments, you mentioned that your LOE cost went up $1.66 and you gave different components of it. How many of those are really going to last, are going to be recurring for a long period of time? Are they mostly just onetime things in the next quarter or 2?

Yes, I think what will be there recurring for a long period of time is our workover program as we're drilling -- now you're looking at kind of drilling 1,000 wells a year, you'll have continued workovers and just general well work. What's not going to be recurring, it was the offshore maintenance work in the -- [indiscernible] the BP tragedy there in the Gulf spill. Of course, all the regulatory bodies kind of -- everybody look at our platforms pretty closely, and all that came in Q1, when we're did some corrosion mitigation on our platform as well as our partners in the non-op platform. But I think that's behind us now. And then the other 2 LOE items, 2 items that increased LOE had to do with saltwater disposal and electrical infrastructure then in the Mid-Continent and the saltwater disposal issue in the Central Basin Platform. Those will continue to mitigate over time. We -- really, it's just taking us longer on the electrical side to get it right away and to get equipment order. And so we had to rent a bunch of generators to keep up with the wells we're drilling in the Mid-Continent. And then in the Permian Basin, we just added so many wells so fast this year, we got behind the disposal issue. But we'll be -- I think we're working those off in the next 2 to 3 quarters.

So the $1.66, only really $0.46 per barrel, is what we should expect as long-term increased cost?

Yes. I'm hoping really, by the end of this year to say that $1.66 is down to $1, somewhere in that range. And then going forward from there, should whittle that down further.

Great. Can you give us a sense of like what the absolute minimum CapEx you need to do this in a year? Aside from all these, obviously, very value-added projects. Like, what you really need to do per quarter or per year?

For 2011?

2011, 2012.

Sure. Well in 2011, we're basically on course to do the $1.8 billion because we're buying the acreage for the new play and moving up our drilling as we've mentioned. In 2012, you do have a lot of options ahead of you. And so if things were to deteriorate this fall and we had a reoccurrence of 2008, we went from 47 rigs to 4 rigs in 2008 to 2009. So we have the ability to change. And as we did in 2008, we had a great hedge book in 2008 that allowed us to go through a time of cutting back rigs in most of -- all of the Permian Basin's HBP. And then in the Mississippian, we can cut back to a very, a lot of -- we could cut back rigs even to where we were at the first of the year. That was only $1.3 billion, including land.

Great. That was one I was getting at.

And our next question comes from the line of Dan Morris (sic)[Morrison] representing Global Hunter.

It's Morrison. Most of my questions have been answered, but in terms of the huge ramp coming in the Miss rig count, can you sort of...

I'm sorry, I'm not catching.

You guys, have such a huge ramp coming in the rig count of Mississippi and can kind of walk us through how that's going to scale up?

Sure. It's really a rig a month.

A rig a month, starting now or...

Already started, yes.

And our next question comes from the line of Scott Hanold representing RBC.

Looking at your targets for 2014, I mean how much external capital do you think you need in total? And sort of talk to the timing of when you'd like to see some of this in place to go forward?

Sure. We have 2 transactions pending. As we said, it will fund all of '11 and fund into '12. I don't think we have projected an exact amount of capital that we need to get through '14. You can model it out. And we've said, we continue to say that we don't look to add to our debt load, rather to grow into it. And I think you'll see us use some of the same monetization methods we have this year to fill that funding gap.

And you should also think that we have thought about how we're going to fund that and have plans to move forward into '11 or early part of '12 before it's needed obviously.

Okay. Okay, good color. And then in terms of drilling in the old Miss, can you talk about any kind of like step-out results that you've had recently? And obviously, you guys, were active up in Comanche County and your recent activity is still pretty much focused in, I guess what I would call, sort of the center of the core play? Or what are some of the step-outs look like?

Well, that's in between -- we did 3 step-outs that we gave slides on that were there -- the farthest extent of the play and basically, each direction. So there is nothing in further outs on that we've tested. And so everything, by definition, is inside of the step-outs that we had that were all above our type curve wells. It doesn't mean that everything is -- I don't know how you define a core whenever you have, really, all these vertical wells across the whole play, and we're not -- we're seeing very consistent results across 4 counties. So yes, it's all within the 3 step-out wells.

Okay, appreciate that. Then, have you guys, in the new Miss, have you -- when is the you plan to like spud your first well out there?

The new wells, is that what you said?

No, no, no. The new Mississippian play that at the end of, I guess, where it's undisclosed. When do you plan on spudding your first well?

We don't have plans yet.

Okay. But you'll be active there, I'll assume, some -- by the early part of 2012. Is that a fair statement?

Well, we will be acquiring acres this year.

And our next question comes from the line of Chris Pikul representing Morgan Keegan. Chris Pikul - Morgan Keegan & Company, Inc.: Can I just get a little more strategic color on the JV? Did you have an appetite for potentially bigger transaction? And then just, are you still kind of keep -- looking to hold that 500,000 acres net to kind of SandRidge? Or are you thinking about that extra acreage for monetization possibilities?

Well, it's possible, sure. We like smaller partners, financial partners. And so the idea of one very large partner wasn't as appealing to us. The average JV that's been sold, as James did some work and said is -- approximately 42% so far and ours is 13%. So what we're trying to do is keep as much of a great play as we can and still bring in an AV forward. So that's just the basic 2 reasons. And then to just deal with a great partner and you're going to a very long relationship with and we felt like Atinum was perfect. Chris Pikul - Morgan Keegan & Company, Inc.: As far as the value of the deal, the implied acreage value, this is kind of loaded question. But do you feel like this is a sort of a first step in establishing a potentially higher value as the play gets further proved up and developed or is that part of a smaller...

We continue to feel like the play is meeting to beating our expectations, as we produce more than our type curves. So I can't answer that we'll be able to have a higher price if we chose to do another one -- but we don't think that there's anything deteriorating yet in the play at all.

. We have a follow-up question coming from the line of William Butler representing Stevens.

I just want to get a little more color maybe on the Mississippian line, the ramp that sort of going from the first quarter through the second quarter. It looks like back in mid-May, you were producing over 12,000 Boe a day. Did something happen in June, sort of in terms of infrastructure or services, to sort of slow it down? It seemed like you should have been a little bit north of the 8,400, I guess, is where I'm getting at.

I'm not sure where those numbers are. Let me start with the rig count. In the first quarter this year, we averaged about 8 rigs for that quarter. In the second quarter, we probably averaged 11 rigs. And now, we have 14 rigs running. And so in the first quarter in the Miss play, you had in the first quarter in our Mid-Continent production, which is primarily Mississippian, was 8,200, call it 8,300 barrels equivalent per day. In the second quarter, it was 11,100 barrels equivalent per day.

Okay. And of that 8,400 Boe a day, was Mississippian of the 11?

No, no, no. We're talking about 2 different timeframes, 2 different quarters. The first quarter, the Mid-Continent was 8,300. And then in the second quarter, it increased 11,100. And that's all due to Mississippian, Horizontal Mississippian drilling.

Okay. And, I guess, one other question is, could you possibly -- so in terms of the JVs, you are -- I mean you wouldn't JV any more a higher working interest to a separate party? That's sort of funding method is kind of behind us now in terms of on that, the Mississippian lime [ph] acres in Oklahoma. Is that -- would that be accurate?

No, that's not accurate.

So you could do more there?

We still have that option, yes.

Okay. Well you could do that with a different partner and that would be -- there's nothing that prohibit you from doing that, I assume.

No, nothing that prohibits us.

And also back to your first question about the Mississippian production, we just posted a new presentation in our slide book. And I think on Page 16, it shows how the production is ramped up over time.

. Our next question comes from the line of Richard Tullis representing Capital One Southcoast.

I think a lot of my questions have been touched on. But Matt, I just wanted to go to this spacing issue in the -- or spacing question in the old Mississippian play. I know you guys are using a little wider spacing than what, say, Chesapeake and Range, talked about last week with pretty good success. Could you talk about the difference in your methods there?

Well, I think what it tells you is that we have a lot of upside there, if they're correct. Right now, we have approximately 900,000 acres in the old Mississippian play that we're working on. So there's really no reason for us to go and experiment with increased density drilling on the 640-acre section. And as we know, the tighter the spacing -- before you get a lot of reservoir knowledge and a lot of time on how horizontal well's going to perform, a tighter spacing certainly introduces more risk to reserves. So maybe we're conservative, maybe not. But right now, we feel the correct spacing is 3 wells per section.

Okay. And the last question for me is have you thought about the low end of your EUR range? Is it still in that 300,000-barrel neighborhood, given the performance you've had, I guess, is against your type curve with your first 100-plus wells?

Yes. We haven't changed the range. It's still at 300,000 to 500,000 barrels of oil equivalent per day. We will revisit the type curve at the end of year and make a decision that time whether we want to change the type curve and the range or not. But we're not there yet.

How many of your first wells would you would put, say, in the lower quadrant of that range?

I think the way to, maybe, you can explain that or look at it is, in the first trust that we did, there were 37 wells and one of those we defined as would not pay back.

[Operator Instructions] And our next question comes from the line of Noel Parks representing Ladenburg Thalmann. Noel Parks - Ladenburg Thalmann & Co. Inc.: Just a quick question. Back in the Permian, any update or thoughts on the deeper targets on Central Basin Platform or -- I saw your exploration focus so much on the new plays, Mississippian, that's on the back burner?

No, we drill deeper targets in the Central Basin Platform. I don't know if you mean -- Ellenburger is a deep target and we drilled some Ellenburger wells. We drill switch to Albany, in Clear Fork and San Andres, Grayburg. We do test deeper targets across the Permian. Noel Parks - Ladenburg Thalmann & Co. Inc.: Anything significant as far as representing a new project in your legacy areas there?

No. We just have one type curve for the entire Central Basin Platform, and we continue to work on that.

We have a follow-up question coming from the line of Joe Allman, representing JPMorgan. Joseph Allman - JP Morgan Chase & Co: I love your comments about calling the Mississippian play in Oklahoma, Kansas, the "old Miss". So it's not that old, it seems to me. But I mean, that's just got Hanod [ph], we've got Matt to call it the Old Miss. In terms of the $3 million cost for the old Miss, just to clarify, that does include the saltwater disposal?

That does not.

No. Yes, that does not. Joseph Allman - JP Morgan Chase & Co: Okay. So how -- if you were to allocate the cost to the well, would you make it $3.2 million per well?

That's correct. Joseph Allman - JP Morgan Chase & Co: Okay, that's helpful. And then to the Central Basin Platform could you just describe the water disposal issues you've had up there and what's the solution, what's the timetable?

Really, we just out-drill our disposal capacity with a nearly 400 wells we put online in the first half of this year. And really the issue only is waiting on a permits so we convert some more disposal wells. Joseph Allman - JP Morgan Chase & Co: Okay. So you've got permit applications in you're waiting for the permits to get approved?

Yes. Joseph Allman - JP Morgan Chase & Co: And how many water disposal wells do you need to drill and what's the cost associated with that.

I think we may drill one new one but we're looking at converting 4 or 5 oil wellbores to disposal wells so very quick projects as soon as the permits come in. Joseph Allman - JP Morgan Chase & Co: Okay. So not a big CapEx expense and then not a lot of time and that will take care of you for what period of time?

I think it will take care of us for the rest of this year and then, we'll just have to continue to stay on top of it going forward. Joseph Allman - JP Morgan Chase & Co: Okay, that's helpful. And then back to the type curve question, so I think the type curve you're using is 409,000 Boe. So how much that is oil? How much of that is gas? And then you've talked about wells doing better than type curve, and that incremental volume being primarily gas. Could you describe that for us? So above the 409,000, how much is -- what's the trend above the 409,000? Or what are those wells trending towards in terms of an EUR? And so how much incremental gas are you actually seeing?

Yes, I'll start with the type curve. The type curve that represents 409,000 barrels of oil equivalent is almost 50%-50%. I think it's actually 48% gas and 52% oil. And I can't remember exactly the number, but on the first 30-day IP basis, you're looking at probably 650 to 700 Mcf a day and probably 120 barrels of oil a day, somewhere in that neighborhood. And so as we drill out the wells, and Tom mentioned that the 30-day numbers are higher than the 344 barrels of oil equivalent, most of that is really on the gas side. Instead of seeing on average 650, 750 Mcf a day, we're probably over 1 million a day on average on the gas side. And that's what's driving the initial IPs, the 30-day IPs higher than the type curve. Joseph Allman - JP Morgan Chase & Co: Got you. So I imagine you're seeing your some wells below, some wells above. But on average, you're seeing -- is that right, of the wells you've drilled so far collectively, you're seeing the wells actually doing better than that 409,000 type curve?

Well, I would say that I'll be comfortable with saying that on average, we're seeing higher IPs than what represents the 409,000 type curve. But I want to hold off in the EUR until the end of year when we revisit everything.

And Joe, on that same Slide Show, Page 16 shows the first 30 days -- or the 30-day rate. Joseph Allman - JP Morgan Chase & Co: Okay, got you. That's helpful. And then, okay. In terms of the new Miss, Tom, you mentioned no specific plans to drill I mean, what's the reason for that? Is that you just don't want to have other co's get data kind of invite that?

It's very simple. We know the oil is in place because there have been 8,500 vertical wells drilled. So why would you need to go out and pinpoint where you're trying to locate the play or where the play is, whenever we already know the oil in place? Joseph Allman - JP Morgan Chase & Co: Okay, okay. I got it. So that's it -- so there's a competition aspect to this thing as well?

Sure. I'd rather we not even talk about it today. Joseph Allman - JP Morgan Chase & Co: Okay, agreed. And then in terms of just in the past, you talked about selling off half of your old Miss position. And that now you're not talking and I understand you want to keep it as much as possible. And I thought that one reason for not -- for selling off half was that you didn't think that you could develop a huge position just optimally within the company. And now you're talking about kind of developing a big position in the old Miss, and then a big position in the new Miss. So can you just talk about how SandRidge can efficiently and optimally develop these 2 big plays, in addition to Central Basin Platform?

Sure. The original thought was we would have to sell half of our acreage because we had -- we were anticipating the up to 1 million acres and we knew the play was working, but it was all around financing. Now we're much more comfortable with financing the play as we move forward. And then the new play, only requires a couple hundred million dollars of capital to, maybe, have something that's worth many billions of dollars ultimately to shareholders. So that's -- and if you think about this, at the time that we moved into the Permian, no one thought it was a good time to be moving in. At the time we moved in into the Miss, everybody questioned why in the world would we be trying to go into a new play. And the answer is if we wouldn't have done it then, it will be gone. And so whenever you find a play that you really believe in, you have to act. And that's why we chose to move forward and luckily now that the play has moved in a direction that's very positive, so we've been able to finance it. So the more we can finance and to do deals like the joint venture or like the royalty trust that allows us to raise capital at a much higher price than we put into the plays, it will allows us to keep more of our cell for ourselves, for the working interest. Joseph Allman - JP Morgan Chase & Co: So for you, it's never about the ability to optimally develop a play from an operations perspective? It's more about the financial part?

Yes. I mean, we couldn't have gone to the 24-rig average if we wouldn't have been able -- well, I'll put it this way. We always assumed we would move up the rig count, the question was how much of it we would own. Joseph Allman - JP Morgan Chase & Co: Okay, that's helpful. And then, if I could ask a question about the WTO, just the more that you're focusing on oil and not drilling gas, the more there's a CO2 liability that grows. And so do you have any update on plans to take care of that liability?

Sure. I'll let Kevin hit that.

Yes, Joe. We've actually put a range around what we would think that 2012 liability would be at the current expected production coming out of -- or CO2 production coming out of Pinon and it would be in the $15 to $20 million penalty range for next year's settlement with Oxy, next year being 2012. Joseph Allman - JP Morgan Chase & Co: So Kevin, is that just kind of the nuisance payment or the late fee you're talking about?

It is and yes, it would due in early '13. Joseph Allman - JP Morgan Chase & Co: Okay. And then I guess as time goes on, you actually have a growing, in addition to the late fee, and the principal isn't changing, right? So I know you're producing some into the plant but, you're going to be having, as your gas production in the West Texas [indiscernible] declines, you're going to have growing liability of CO2 principal, let's call it, that you're going to owe Oxy. And so is there any update in somehow trying to take care of that liability?

As you know, Joe, it's a 30-year contract and so we're still pretty confident that over the 30 years, that field is going to be drilled and there's going to be the CO2 delivered to Oxy that's asked for under the contract.

We have a follow-up question from the line of Dave Kistler representing Simmons & Co. David Kistler - Simmons & Company: One quick one on the new Miss play, and kind of building on what Joe was asking, as well. Aggregating or looking to aggregate 1 million acres there, at this point, based on your appetite, is that what SandRidge ultimately wants to hold? Or is it similar to the new Miss, where you stepped into grab 1 million acres with the anticipation of reducing it over time?

At this point, that is all we anticipate holding. Keep in mind in the old Miss, we went into with the idea of getting up to 500,000 and then, ultimately grew to 1 million. I think that for any company 1 million acres is a substantial amount to try to take care of. So as of today, we'll -- we're safe to say we're -- we've budgeted for 1 million acres. David Kistler - Simmons & Company: Okay. And then also clarification on at what price would you start reducing CapEx? I'm guessing, you guys, have run some sensitivities as part of it this 3-year strategic plan that if oil moves to x, we'll start ratcheting down. What is that specific price?

I think it has more to do with the overall world economy and just if we saw oil go down for a short period of time but to like that the world was in some kind of turmoil, that makes a lot of difference. Keep in mind that we are hedged for the next 3 years so I think we've been the most active hedger of oil in the business and so that is the key. But as -- we will look at this. We visit every day about what we think how many rigs in our budget we met once a month formally to discuss budget so it can be -- we can be very fluid and I think maybe that's due to our size but we can react pretty quickly if we see, foresee problems. But I can go back easily and say a $1.3 billion budget was something we were very comfortable with at the first of the year. That would not ultimately meet the 3-year plan that we have laid but it still would be a very attractive company.

And our next question comes from the line of Craig Shere representing Touhy Brothers.

I think in the old Miss, you all have originally said that you did need to double from first quarter levels to maybe 24 rigs HBP of that property. Can you talk about, or are you willing to discuss, if the new lease terms in the new Miss are similar in terms of HBP obligations to the old?

Yes, it would be. As it's virtually the same type of lease terms. We try or we get 5-year leases.

Great, appreciate it.

Or 3-year with 2-year options.

Wonderful. So basically, it's very similar strategy to the original one because you trued up that acreage before you really started seriously looking at the drilling campaign. And now, with similar leasehold obligations, you're just doing the same thing.

That's correct. And again, the reason you can do that with -- is history of the play. So we didn't mind, at all, going out with 3 rigs and drilling at the furthest extent of our original Mississippian play, because we were drilling offsetting vertical wells and it produced oil. So we know the oil is in place. It's already produced next to us. All we are doing is drilling more efficiently by putting 10 wellbores inside of one.

With no further questions in the queue, I would now like to turn the call back over to Tom Ward for closing remarks. You may proceed.

Well, as always, we're very thankful to have you on the call and we look forward to talking to you next quarter. Thank you.

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