SandRidge Energy Inc (SD) 2011 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2011 SandRidge Energy, Incorporated earnings conference call. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. James Bennett, Chief Financial Officer.

Welcome, everyone, and thank you for joining us on our first-quarter 2011 earnings call. This is James Bennett, Chief Financial Officer. With us we have 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, today's call will contain forward-looking statements and assumptions which are subject to inherent risks and uncertainties. The actual results may differ materially from those projected in these forward-looking statements. Additionally, we'll 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 in our earnings release and on our website.

Now let me turn the call over to Tom Ward.

Thank you, James, and welcome to our first-quarter financial and operations update. I'll lead with a few opening remarks and turn over to Matt and James.

For the last 2 years, we've had a very simple and focused strategy of acquiring and drilling for shallow conventional oil and carbon at reservoirs. We initiated our acquisition of oil by focusing on the Permian Basin because of the tremendous source rocks and production that have been developed over the last 80 years. The Permian Basin is the largest oil-producing basin in the Continental US, with over 29 billion barrels of oil produced.

After focusing on the Permian, we decided to further focus on the Central Basin Platform as our core area of interest. The CBP has produced over 12 billion barrels of oil from only 3 million acres, defining the best oil-producing area within the best oil-producing basin.

We made 2 acquisitions with a net investment of $1.8 billion that's now worth over $3.2 billion, showing a growth of investment of nearly $1.4 billion in less than a year. Not only have we made tremendous value growth, we now have nearly 10 years' worth of drilling, even though we drill over 800 wells per year and own over 185,000 acres of prime land. Plus, we did not have to spend capital on expensive non-EBITDA-producing acreage.

At the same time, as we're acquiring on the Central Basin Platform, we targeted another shallow carbonate oil play in the Mid-Continent. The horizontal Mississippian Play is now recognized as one of the premier shallow oil projects in the US.

SandRidge started to work this area in 2007 by drilling less than a dozen vertical wells. However, as we developed the idea that there were tremendous amounts of oil in place over a very large area, we stepped out and drilled horizontally nearly 30 miles away and found the same great reservoir.

This gave us confidence to buy 1 of the industry's leading acreage positions at a very low cost. We now have 12 rigs drilling and are projecting to double our rig count in 2012.

We have said that we can only hold approximately half of our projected 1 million acres over the next 5 years if we keep our CapEx flat at its current level. Therefore, we're now reviewing 3 ways to fund the doubling of our rig count next year.

We can either sell a portion of our acreage or joint venture with another entity, form additional royalty trusts, or raise CapEx within SandRidge. We've not decided which way or ways that we will fund the drilling, but we are now planning for increased Mississippian rig count in 2012. We currently are spending approximately $300 million per year drilling in the Miss in our $1.3 billion budget.

The Mississippian continues to gain traction as 9 operators are now active in the Play with 24 total rigs running. SandRidge has drilled 72 horizontal wells to date and our average 30-day IP has increased versus the 244 barrel a day equivalent type curve that produces 409,000 barrels equivalent of reserves.

It is also important to note that our drilling now spans across an area greater than 100 miles east to west, and industry drilling has proven up the Play beyond that distance. Vertical well performance suggests the western portion of the Play to be statistically better, but we don't have enough horizontal well information to verify at this time. This is important, as most of our acreage is in Grant County, Oklahoma and west.

We also believe reservoir thickness is good, and we have kept our acreage acquisition in the region of the Play with anticipated gross thickness of 200 feet to 800 feet of Mississippian reservoir. Both of these areas we drill in have tremendous rates of return because we drill for oil and because the costs are low due to the shallow reservoir depths.

We continue to see very little pressure on overall costs in these plays due to the current availability of equipment in both drilling and stimulation services. We believe this is one of the distinguishing factors of our company. Even though we do not see the potential for material increases in costs today, we believe there will be competition for drilling services in the next year as we anticipate a continued ramp-up of industry activity in the Mississippian Play due to robust economics and strong oil prices.

Therefore, we are moving ahead aggressively to lock in rigs for our 24-rig program next year. Perhaps even more important than any slight increases in cost is that we want the assurance that we can accelerate drilling for each type curve well as a PV10 of nearly $7 million at the current oil and gas strip.

The other distinguishing factor is the development of our business units that have size and scale, along with shallow carbonate oil and, in the case of the Central Basin Platform, no ability to duplicate the assets that we have assembled. We have successfully integrated our company into a business with high rates of return with very little pressure of cost inflation and very little reservoir risk.

We believe we are singular in our ability to make this claim. We also believe that if a company has this ability, we should hedge to lock in rates of return and drill as aggressively as possible. So you've seen us hedge nearly 25 million barrels through 2013, and we're now starting to hedge even further out and move forward with our plan to raise capital to meet the growing drilling schedule.

The focus for SandRidge during the rest of 2011 is to fully fund our 2012 drilling plans and ensure we can capitalize on their tremendous rates of return we realize in both the Central Basin Platform and the Mississippian Play.

I will now turn the call over to Matt for an operational update.

Thanks, Tom, and good morning to everybody.

I will elaborate more about our production and drilling performance, CapEx and LOE. First, I will walk through reconciliation of our Q1 production. If we can start by going back to Q4 of 2010, we produced 28,400 barrels a day and 204 million cubic feet of gas per day for a total of 62,400 barrels of oil equivalent per day in Q4.

In Q1 of 2011 we produced 28,700 barrels of oil a day and 192 million cubic feet of gas per day for a total of 60,700 barrels of oil equivalent a day. Q1 2011 production was slightly lower than Q4 of 2010 production, due to the sale of the Wolfberry assets and the severe freezing weather that SandRidge and other operators experienced in west Texas.

In the month of February, we had below freezing temperatures for about two weeks, and single-digit temperatures and rolling blackouts for several days during that period. We believe these extreme conditions were 30-year, if not 50-year, weather events in the Permian Basin.

The sale of the Wolfberry assets account for about 1,600 barrels of oil equivalent per day, and the weather-related down time amounted to another 1,900 barrels of oil equivalent per day, for a total impact of 3,500 barrels of oil equivalent per day in Q1.

If we add this back into our Q1 production, we would have produced 64,200 barrels of oil equivalent per day and would have seen a 2.9% production gain quarter-over-quarter instead of a 2.7% production loss. As a result, there was a nearly 6% production swing due to the sale and the weather.

In regard to oil production, we produced 28,400 barrels of oil in Q4 2010 and -- I'm sorry, we produced 28,400 barrels of oil in Q4 2010, and 28,700 in Q1 2011. Despite the Wolfberry sale and the ice storm, we were still able to increase oil production quarter-over-quarter.

The impact on oil production due to the sale and the weather was about 2,900 barrels of oil per day. If we add this back in we would have produced 31,600 barrels per day in Q1 of 2011 or about an 11% growth in oil production quarter-over-quarter.

I would also like at this time to comment about Q2 production. As you are aware, we closed on the sale of our New Mexico assets April 1 of 2011. As you are also aware, West Texas was plagued with wildfires in early April. We estimate the net impact on Q2 production from these events to be about 1,770 barrels of oil equivalent per day, of which about 1,500 barrels of oil equivalent per day is from the asset sale.

At this time, all the fires are out, and production has been restored to normal on the Central Basin Platform. I'm pleased to say that within only about a month of selling our New Mexico assets we have already made up the 1,500 barrels of oil equivalent per day of production that was associated with that sale through our drilling success on the Central Basin Platform.

The average production for the first 4 days of May, or our current production, is running 62,400 barrels of oil equivalent per day, which matches our Q4 2010 production. Not only are we on track with our 2011 production plan, but we are -- but we have also already made up the 3,100 barrels of oil equivalent per day that we sold in Q1 and early Q2 of this year.

With that said, at this time, despite the set-backs due to the bad weather and the fires, we are reaffirming our 2011 production guidance of 23.3 million barrels of oil equivalent, of which 12.3 million barrels is oil.

The strong growth in oil production is a result of our continued commitment, focus, and execution on our 2 core oil plays in the Central Basin Platform in West Texas and the Mississippian Horizontal Play in the Mid-Continent.

We drilled 199 wells on the Central Basin Platform with 16 rigs in the first quarter. Q1 capital spending in the Permian Basin was about $173 million, of which $33 million was carried over from prior-year spending. Netting out the carried over capital, we spent about $700,000 per well. This is in line with our expectations to spend $760,000 per well on the Central Basin Platform.

The cost number may move from quarter to quarter on a per well basis as our drilling mix of wells may change from quarter to quarter. However, at a cost of $760,000 per well and a type curve EUR of 83,000 barrels of oil equivalent per well, the rate of return is about 100% at current commodity prices. We plan to continue with 16 rigs and project to drill 811 oil wells on the platform this year.

In the Mississippian Play, we drilled 23 horizontal producers and 14 saltwater disposal wells in the first quarter of 2011. We plan to drill 138 horizontal producers and 24 saltwater disposal wells for the year.

In the first quarter, we had 8 rigs running, drilling horizontal wells and 4 rigs drilling vertical wells. Currently, we have 11 rigs drilling horizontal producers and 1 rig drilling saltwater disposals wells.

We plan to add 1 more rig at the end of the month to drill the horizontal wells, bringing the total to 12 rigs drilling producers. This is in line with our Mississippian drilling plan that we set forth at the beginning of this year.

Excluding land, we spent $102 million in the Mississippian Play in the first quarter 2011. Approximately $26 million was spent on saltwater disposal wells and associated facilities. As you can see we have very much front-loaded the CapEx in this play with aggressive drilling of the saltwater disposal wells to facilitate implementation of our development plan and minimize LOE going forward.

Of the remaining $76 million, approximately $18 million can be attributed to prior year carryover and non-op capital. This leaves us spending $58 million drilling and completing 23 gross wells or 20 net wells. Thus, an average of $2.9 million per well.

We began the Miss program in early 2010, drilling horizontal wells in about 30 days and was consistently spending $3 million to $3.5 million per well. We've made significant strides in 2010, bringing the average down to about 22 days, and drilled a number of wells under 20 days and hit a record 14 days on 1 well from spud to rig release.

During this time, our costs began trending down to about the $2.7 million range. I believe had we kept a constant rig count, we could have brought our costs even lower. However, as we started ramping up our Miss drilling program going into 2011, our well cost crept back up.

We believe that in time we can again lower the well cost in the Miss Play, but today we still have inefficiencies associated with bringing on new rigs and new crews into the Play.

To date, we have not seen material increases in service costs in the Miss Play. This is due to the fact that activity in the Miss is driven by smaller rigs, lower horsepower requirements for stimulation, and simple fluid and prop systems in the fracs.

However, due to the robust economics of the Miss Play, the scale of the Play, and increased interest from other industry participants, we do expect increasing rig count and some cost pressure going forward, but not to the extent that our industry has experienced in other horizontal plays around the country. However, in anticipation of this, we are proactively locking in rig rates, frac rates, and putting a plan together to move in more company-owned rigs to hedge against potential inflation and service costs as we begin to plan for 2012.

We have shown in our presentations that at $2.7 million CapEx, which includes saltwater disposal facilities, the rate of return is about 150%. Even at $3.1 million, which is $2.9 million to drill and $200,000 for saltwater disposal facilities, the rate of return is very robust 115%. The economics here are very good, and we don't see a service cost scenario that would have us altering our business plan in the Mississippian Play.

We are still using the Netherland, Sewell-type curve with an EUR of 409,000 barrels of oil equivalent and a 30-day IP of 244 barrels of oil equivalent per day. We have drilled 72 horizontal Miss wells to date, and the average 30-day IP of the last 50 well is 270 barrels of oil equivalent -- I'm sorry, 250,000 barrels of oil equivalent per day. That's slightly higher than 30-day IP of the type curve.

It should also be noted that we have expanded our program east into Grant County. While the data set is still limited, as we only have 13 wells on line, it appears that these wells are statistically as good as the ones we've drilled in Alfalfa and Woods County.

Lastly, LOE for the quarter, excluding production taxes, was $13.55 per barrel of oil equivalent. This exceeded the high range of our LOE guidance of $13.10 per barrel of oil equivalent. We discussed earlier about production downtime due to the severe cold weather in the Permian Basin.

The production loss due to the winter storm was 174,000 barrels of oil equivalent in Q1. The associated LOE to restore production was about $300,000. Notwithstanding this loss and the associated one-time expenses to restore production, our LOE would have been $13.08 per BOE and within our guidance range.

At this time I will turn the call over to James for financials.

I don't plan to recite every number in our release, but I'll touch on a few of the items warranting further discussion. For the first quarter, adjusted net loss was $10.1 million or $0.02 per diluted share. Adjusted EBITDA was as $146 million, and operating cash flow was $100 million.

EBITDA is up 12% versus the fourth quarter 2010 and 4% versus the comparable period in 2010 as a result of higher oil production and higher realized oil prices, somewhat offset by decline in gas production and lower realized gas prices.

On the expense side, total lease operating expense increased approximately $24 million over the first quarter 2010 as a result of the Arena acquisition, which closed in July of last year, as well as an increase in total production and a higher percentage contribution from oil.

Oil production in the first quarter of 2010 was 47% of the total versus 28% in the first quarter of 2010. On a per unit basis, lease operating expense of $13.55 per barrel of oil equivalent was approximately $2.00 per barrel higher than the 2010 comparable period and slightly above our guidance of $13.10 per barrel.

As Matt discussed, the primary reason for this higher per unit LOE in the first quarter was an interruption in production and increase in one-time costs due to the severe weather and associated freeze in the Permian Basin. Excluding the weather-related impacts, LOE would be right at the high end of our guidance. All other expense items were in line with the guidance range, and we are reaffirming our full-year guidance.

Our earnings release includes an updated guidance table. The only 2 changes to note in the guidance are slightly higher oil differentials, due to a higher production contribution from NGLs, and the impact of SandRidge Mississippian Trust I, which I will review later. Matt addressed Q1 production detail, so I won't spend any more time except to reiterate that we remain comfortable with our full-year guidance of 23.3 million barrels of oil equivalent.

Let me touch on first-quarter CapEx, which totaled $420 million. When we gave our 2011 guidance, we knew the CapEx would be front-end weighted with a disproportionate amount of the spend in the first quarter. This was due to carryover CapEx 2010, the fact that we're drilling a disproportionate number of our Mississippian saltwater disposal wells earlier in the year, and our acreage leasing program in the MIssissippi.

In the first quarter we had $52 million of drilling CapEx carryover from 2010, mostly in the Permian and Mid-Continent. We also had $26 million related to the drilling of 14 saltwater disposals wells. Our guidance assumes 24 saltwater disposal wells will be drilled in all of 2011, so you can see this was heavily weighted towards Q1, as we operationally wanted to get the saltwater disposal infrastructure in place prior to re-drilling a majority of the producing wells.

On leasehold we did spend just over $100 million, which is essentially our full-year guidance. 95% of this spend was in the Mississippian Play, where we continued to see opportunities to pick up good acreage and acreage offsetting our existing production.

We have slowed the pace of our land purchases but do expect to spend additional dollars on acreage, and we will revisit land CapEx guidance around the time of our mid-year earnings call.

We remain very active in terms of our capital raising program. Recall that our 2011 guidance called for CapEx of $1.3 billion on cash flows from operations of approximately $470 million. Our intent remains to fully fund any shortfall with non-debt sources of capital. In the IPO of our first royalty trust, our capital raising efforts are ahead of schedule, as we have raised approximately $800 million year to date.

To review the royalty trust, in April we closed the IPO of 62% interest in SandRidge Mississippian Trust I, which trades under ticker SDT. The IPO is upsized 20% and priced at $21 per unit, the high end of the range, netting proceeds to SandRidge of $334 million after fees. Having almost fully funded our 2011 CapEx plan, we'll continue our capital raising efforts and are now focused on funding our 2012 program, which we will also accomplish through additional asset monetization.

Turning now to our liquidity and balance sheet, at March 31 we had a total of $3.2 billion of debt outstanding, consisting of $2 8 billion of senior notes, $324 million outstanding under our senior credit facility, and $17 million of other debt. As I discussed earlier, in April, we raised $534 million in proceeds from asset sales and the SDT IPO. Proceeds from these transactions were used to repay revolver borrowings and have put us in excellent liquidity position.

As of May 3, we had $62 million cash on the balance sheet and 0 outstandings under our $790 million credit facility, giving us total liquidity of $828 million. This $534 million debt paydown in April also reduced quarter-end leverage by three-quarters of a turn of EBITDA. While we still have improvement to make in terms of our financial leverage, we are now moving in the right direction, and we'll continue to address this.

As we have noted, we're out spending our cash flow this year. We are doing so from 100% non-debt sources and don't look to increase our aggregate debt levels in 2011.

Two other items to note in terms of our liabilities. Our senior credit facility borrowing base was reaffirmed in April at $790 million, and our next re-determination will be later this fall.

Also in March, we refinanced our $650 million 8.625% senior notes with a new 10-year $900 million issue of 7.5% senior notes. This transaction enabled us to extend our weighted average maturity of our bonds to 7.5 years from 5.8 years and also reduced our weighted average cost of debt. We now have a staggered maturity schedule with only $350 million in bonds maturing in the 2014-2015 time frame.

We continue to actively hedge our out years oil production. To summarize our updated hedge position, which is outlined in our earnings release, since our Q4 earnings call, we have added oil hedges in the form of swaps for 4.5 million barrels at an average price of $102 per barrel. In March and April, we also monetized approximately 42 BCF of our 2011-2012 gas hedges as we entered a trough in the natural gas market.

For the remaining 3 quarters of the year, we have approximately 80% of our guidance liquids production hedged at just under $87 a barrel and 39% of our gas production guidance hedged at $462 for a total of 55% of our remaining total expected production hedged.

A couple of notes regarding SandRidge Mississippian Trust I. In terms of accounting for the trust, beginning in April 2011 the activities of the Trust will be consolidated into SandRidge's financial statements.

The public's interest in the net assets of the Trust, which consist of 17.25 million units or about 62% of the total units, will be reflected in the non-controlling interest line item of the balance sheet, and the public's interest in the earnings of the Trust will be reflected as net income attributable to non-controlling interest in the income statement. As outlined in our updated guidance table, we estimate this net income attributable to non-controlling interest to be approximately $26 million in 2011.

There's an additional disclosure regarding the accounting for the Trust in the SandRidge 10-Q, which will be released on Monday, May 9. Later this month, we'll be filing a first-quarter 10-Q for SandRidge Mississippian Trust, and beginning with the second quarter, we will release earnings for SDT and will be hosting a separate SDT quarterly conference call.

This concludes management's prepared remarks. I would like to ask the operator to open the line for questions.

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

A question, Tom. You mentioned about going to Grant and Woods, obviously besides Alfalfa County and the horizontal Mississippian. Just wondering, I know it's early, but how are you seeing that, maybe if you could give a little more color as far as how you're seeing that play out as far as thickness, liquidity, et cetera on that.

Sure. We target between 200 feet to 800 feet of total thickness in the Miss. Grant, as we've talked about, has a little bit vertically from the vertical wells, has a little bit higher oil ratio than further west. However, the estimated ultimate recoveries are somewhat better vertically to the west. So we've -- but the value between oil and gas on the verticals wells is about the same. So we've always looked at Grant, Alfalfa, and Woods as -- and even clear out to Comanche in Kansas, as being basically the same type of reservoir to drill for. And so far in the wells we're drilling, statistically it looks like the other areas we're drilling in. It is early, but we've now drilled over a dozen wells or are producing over a dozen wells, and it appears that they're tight curve type wells.

Great to hear. And Tom, at one point, I think maybe at the analyst day, you talked about, given what's going on in Cushing, about trying to divert some of your take-away. Just wondering about take-away, pipelines, et cetera. If you could comment there.

Sure. The only place that we look to divert away from Cushing is out of the Permian Basin, and that is still ongoing with discussions. Matt, do you want to address that?

Yes, Neal, unfortunately there's not any short-term solutions. What's going on at Cushing right now is, as you know, there's 50 million barrels of oil storage capacity and just in the last three years, we've gone from about 17 million to about 40 million barrels inventory. So storage is filling up. By the end of this year, there are 4 companies adding storage, so we should see about -- that 50 million going to about 65 million of storage capacity. That will give us some relief. However, as far as pipe coming out of Cushing, I know Enbridge is looking at projects as well as TransCanada and some other parties. We're probably a realistic 2 years out from being able to haul more oil out of Cushing into the Gulf Coast via pipeline. We are looking at a project that Magellan is looking at, potentially reversing what they call their Longhorn line from Crane County back to the Gulf Coast, and that may -- I think there's a lot of interest in that. We're certainly interested in doing that just to get a little bit of oil away from Cushing, but still that's probably 18 months out.

Got it. And then, last question, maybe back to you, Tom, just on -- or maybe for Matt, just on service cost in general. Obviously yours are much lower than a lot of the other regions out there. But are you doing anything to lock in longer term contracts, like a lot of others out there, just on completions in general? If you could comment.

We are effectively hedged on the drilling side with the rigs that we own, and we look at the areas a little bit differently in the Central Basin Platform. We use even less horsepower on our fracs than even in the Mississippian, but both of them are low horsepower fracs. The Central Basin Platform has really very little service cost creep, especially the very shallow vertical wells we drill. As you get into horizontal wells and move up from the 500 to 750 horsepower rigs up into the 1,000 horsepower rigs, we think there could be, as we look out into the future, some future cost creep in that area. That's what we're going to try to keep away from.

Think about this. We're planning to go from 12 rigs to at least 24 rigs next year. We know that other people in the play have bought very large amounts of acreage, and we assume that they will be moving up rig counts either through private equity or public companies as they start to develop the play. All of the Mississippian isn't that much different in this respect, in that you only have a certain time period to get wells drilled. Now, for us, fortunately, we were there early and have three years with two-year options on very inexpensive leases. But, lately, companies are having to take shorter and shorter term in order to get ahold of leases, and that will require more rigs to come into the area.

So we anticipate that the Mississippian will have some kind of a pressure going forward in service cost but not from high pressure equipment that's being pressured around the United States in a lot of different areas. So it's different but still we'll have some -- the Central Basin Platform, we just don't see anything other than labor and fuel as being an issue.

Got it. Good answer. Thank you.

And our next question comes from Scott Hanold with RBC Capital Markets. Please proceed.

Tom, you all talked about three options to fund a much higher level of activity next year. When you look at those options, can you just broadly give us a description of how you think of each one of those and maybe your preference at this point?

Sure. The royalty trust structure we like a lot. We continue -- if you have rates of return in excess of 100%, and you have willing buyers at 10% rates of return, and if you can do in that more scale, that would be our preference across the whole play. The problem is, as you know, that only -- we only had 42,000 acres in our AMI on the royalty trust that we just did. We will continue to look at that as an alternative moving forward, and along with that, we're interested in talking to potential partners for joint venture. We don't know in what size that would be, but that's something that we'll evaluate, and then the third option is that we keep more ourselves. So everything we're doing is with the idea that we like the play more than we did the last quarter, and we want to own more of this ourselves. So that is what we're trying to move towards.

When do you feel you all need to make a decision on which way you go? Should we expect some time in the early second half of the year? Is it something closer to the end of the year? When do you think -- when do you want to have financing taken care of?

We want to have financing taken care of for 2012 before the end of 2011. So, I think will you start to see us be active throughout the rest of the year, just like we are at the beginning of this year or the last of last year. What I focus on the most is making sure that we fund next year's drilling program.

Okay. Good answer. And on the -- I think you mentioned you're going to move some more company-owned rigs into the Mississippian. Would those be coming from the Permian? Because, correct me if I'm wrong, but you're operating all of your owned rigs, correct?

We have some that are working for other parties right now. We have 10 rigs that are working outside.

Okay. So you'd be able to take those back, is that right?

We can do that, or we can also -- you have the same effective hedge as if you hire somebody else and leave your rigs in the Permian, but we are planning to move some rigs up.

Okay. And one last question, if I could. When do you plan to start stepping out to the northwest, like in Comanche County, when is that first well going to be drilled?

Now.

Now, okay.

Yes, we have one well drilling in Comanche County, or completing.

Great,

Our next question comes from David Heikkinen with Tudor Pickering Holt.

Tom, just on the rig commitment and services side, can you talk about the duration or type of commitments as you go to 12 rigs? And then the last question was getting into the vertical integration and desire to vertically integrate the Mississippian as well, just general thoughts.

Sure, I'll take the vertical integration. When we came into the company, we already had a number of rigs. We still have 31 rigs today that have been very efficient for us, to have our own people working in the same area for long periods of time in the Permian Basin. We've brought some of those rigs up. We have 6 of our 12 rigs working, our Lariat rigs, which are company owned, and we've been happy with that model of owning some of our own rigs. However, at that time same time, we have other rig companies that are working for us that are, as they move into the play and work for awhile, are also very efficient. And I'll let Matt address how we're planning to move forward with the rig count.

Yes. Right now, we have about half the rigs drilling in the Miss play we do own. So we have about 6 rigs out there that are third-party. And they're on various contracts. We have some that are six-month contracts to a year contract, and we're continuing to renegotiate or negotiate those for 2012 already. We've also have some 24-month contracts that we're working on for the 2012 program. So they're different contracts, but I'll tell you the rates are still very good, and they haven't materially increased very much.

So just have a ladder of 6, 12, 24-month rolling contracts on the next 12 rigs?

It is a ladder, and when we're trying to source rigs today, for our 12 program, those are the ones that are coming in at 24 months. Because what they're aiming to do is take off whatever program they're on now and commit them to us starting in January, first quarter 2012.

And Dave, think of this too. We use a range of 750-horsepower to 1,000-horsepower rigs. So our preference is not to have bring out rigs that are stacked and put them to work. We have done that, but our preference is to keep rigs that have been working other places and bring them into the Play, so that our efficiencies are good. I don't think we'll have an issue getting rigs unless other companies move up to 25 or 30 rigs. Then that's where we worry. Today there's not an issue with getting rigs. It's just that we know that there's a lot of acreage being bought by several different companies, and we just assume that rig count will be going up. If you look at that time market of 750-horsepower rigs, heavy 800's to 1,000-horsepower rigs, today there's ample rig capacity. All we're doing is looking out to 2012, making an assumption that the Mississippian grows rather than stagnates.

Then on the water disposal side, these water disposal wells take a lot of fluids. As you double your activity level, how much capital would you have to put into water disposal next year? Can you talk about that?

I'll address that a little bit. It depends a lot on where we drill, because right now even with one or two wells, we're drilling disposal for it, so we minimize LOE, and we'll grow into the disposal plan. Right now we have 24 disposal wells in operation and by the end of this year, we should have around 30. Currently, our current disposals volume is 150,000 barrels of water per day. The disposal capacity we have is over 400,000 barrels per day. So the main reason we up-front loaded our disposal well is so we can continue to develop these wells and not have -- not be behind in disposal wells. I think by the end of this year we should be pretty good for 2012.

And think too, David, is we drilled new areas. That requires a new disposal system. So we will continue to have some up-front costs as we continue to look into new areas. As you think of Alfalfa to Grant, those are all in one disposal system that the pipeline system can be connected in between disposal wells, so it really depends how successful we are in all the other areas. We assume we're going to have success, so maybe I could even say it depends on how quickly we decide to step out into different areas and test new areas, even though there's vertical well production there, we probably will move around and drill horizontal wells in different areas. So that's -- it's not set in stone as to how many disposals we'll have, because it depends where the horizontal well program goes.

So thinking about that 24-rig program, how much would be step-outs? Is it a third? A quarter? Just trying to get an idea of how I should allocate capital.

It's hard for me to say, because at one time the Grant County wells were considered step-outs, and now they're not. So when we drilled the disposal system in Grant County, it was considered a step-out, and now it's basically hooking into the Alfalfa County system.

Our next question comes from William Butler with Stephens. Please proceed.

I was wondering if you could provide some more detail on percentage of liquids production that's NGLs?

Sure. I'll let Matt take that.

In Q1, we ran about 18% NGL. We had actually modeled a little bit lower than that around 14% NGL. The reason the NGL was higher, was that it was not at the expense of oil production, but we did renegotiate some contracts in our favor with processors in West Texas, which boosted our NGL netbacks at the tailgate of the plants.

So just to clarify, the 18% is as a percent of total production or of liquids production?

Liquids.

And then on the royalty trust distributions, given the ramp in the current distribution, what's that going to show up in terms of for the year? What do you think the total distributions on the trust will be on SandRidge's cash flow statement?

Sure. I'll point you to the S-1 for SandRidge Mississippian Trust. In there it outlines the distribution schedule by quarter, so that's a really good place to start in terms of what the projected distributions are by year. So you can really pull that rate out of the S-1.

Okay , and then I'll add the percent to the public? I guess I can get back into that. On your rigs, they're running at 100% utilization now, the owned

That's correct.

Has it gotten to a point on the demand, or do you see it getting to the point where you all might actually look to use that as a source of funds? Lariat?

Not necessarily. The rigs are -- when everybody wants a rig, you want them yourself. And when nobody wants them, you can't get rid of them. So, I guess right now we enjoy having our own rigs working for us.

Okay. And given what's going on out in West Texas with the fires and dry weather, do you see any issues for water? For availability for fracking?

No, we haven't had any issues.

And last question, in terms of competition for leasing in the Mississippian [line], what is the current going rate now for acreage?

Well, it's higher. I think that what we have done, and you can look on our presentations, we have a geological model that we have stayed within. And we only are buying within the areas that we have outlined in that presentation. That doesn't mean that there isn't Mississippian outside of that. And so you can have large amounts of Mississippian acreage being bought that might be every bit as good or better than what we have. It just doesn't necessarily fit the geological model that we put together.

I think that, just because people have bigger and bigger acreage positions doesn't necessarily mean that we're competing on that acreage. What we have done is now basically slowed down our acreage acquisitions into the areas that are close to our existing production or inside of that geological model we presented. I think we can say the acreage prices are going up, but that our spending is decreasing fairly dramatically.

And you still anticipate getting up to the roughly 1 million acres?

Yes.

Okay. Great.

And our next question comes from Dave Kistler with Simmons & Company.

Real quickly, just looking at-- you've drilled 72 wells in the Miss. 37 of those are in the royalty trust. Of the balance between that and the 72, how many of those were dedicated to the royalty trust, and when will you have a level sufficient to thinking about doing another royalty trust?

Wow, do you have the number off the top of your head how many in the royalty trust? We're going to talk about those.

We're not.

Oh, we're not going to talk about the trust number of wells on this call. Well, I can tell you this. What's public is that we have dedicated 3 to 4 rigs to drill royalty trust wells.

Okay. So we can --

We talked about that when we did the royalty trust, and we have 12 rigs running. So, I think that you do have to have proven reserves to put into another trust, and that's what we're building on.

Okay. So, just thinking about it from the a run rate then, if 9 rigs are allocated, probably by mid-summer, based on the number of wells that are being drilled, you'd probably have a sufficient number to be able to start having a reserve evaluation and potentially move forward with another trust.

That's fair. As long as the market is still there

Really I'm just trying to lock down thinking about the capital side of it. And as long as we're on that --

I've said publicly that I wouldn't mind looking at $1 billion of royalty trust net to SandRidge this year.

Perfect. Then looking at the revolver, it came down a little bit with the issuance of senior notes, which is to be expected. But there will be redetermination in the fall, I imagine obviously tied very closely to reserves. Too early to say, but maybe looking back at the redetermination you just had, possibility for that to be expanded. Any color you can give us on that would be great as kind of a vehicle to think about 2012 funding.

Sure, Dave. We did just go through our redetermination. We decided to keep it. Remember, we had the revolver at $850 million with the up-sizing of the IPO -- I'm sorry, the high-yield offering. That took it down to $790 million. We decided to leave it there at the redetermination date. I think we had ample room to push it up, but given our sources of capital this year, we really don't anticipate being in the revolver all that much, so we didn't need, say a $1 billion revolver. We'll revisit it again in the fall, but I think this level, $790 million, is ample liquidity for the near term.

Great. Appreciate that. Then a little bit out of the bailiwick, don't know if you guys can comment on it, but I'm guessing you've been watching it. Any kind of update you can give us on the Eagle sale and what the status is of that?

I actually talked to Steve Antry this week, anticipating that we might get a question, and asked him what he might like to say if he had a chance to say on the call. And what he told me, that he would say is that they had decided after their well performance and watching our performance and the performance of the royalty trust, to delay their proposed sale and leave their options open and drill some more wells for the next 6 to 12 months.

Great. Appreciate the color. One last cleanup question for modeling. Natural gas production down 6%, no rigs directed towards drilling that. Is that kind of a decline we should be working in, or when will that abate a little bit in terms of as we model things forward?

Yes, you know, we -- I think we produced, and this is off the top of my head, Dave, I think 76 Bs of natural gas last year, and we were thinking we were going to produce about 66 Bs this year. Our natural gas in Q1 was actually a little bit ahead of what we had projected for Q1. So, I think we're still right on track to do that.

And that's what I would say, too, that actually we think we're fine on our gas production to date.

Okay, great. I appreciate it, guys. Thanks so much.

Our next question comes from Amir Arif with Stifel Nicolaus.

A couple quick questions. You've mentioned you've got the disposal facilities in place as your volume ramps up, but as you double your rig count is there any other constraint in terms of fracking or anything else you see as you head into '12, pipeline take-aways?

Everything we're working on today is preparing for that higher rig count in 2012. So we think that we'll have ample availability of services.

Okay. And then I think you mentioned that you'll only be able to hold about half your acreage. Is that based on the current rate of 12 rigs, or is that even after you double up to 24?

No, that was the current rate of 12 rigs. That's why we're moving forward with the plan to capture more than that.

Okay. And the 5,300 barrels a day number that you mentioned, is that the exit rate for Q1?

I'm sorry?

The 5300 barrels a day. For the Mississippian.

Net?

No, exit rate for Q1. That is, isn't it? 5,300 barrels? No?

No, I'm sorry, that's current.

That's the current rate. Okay Do you have -- or can you give us a breakdown of how much of that was for the trust versus -- ?

I'm sorry, how much of that was what?

For the trust versus for SandRidge.

Yes. Hang on just a minute. The trust -- yes, it looks like the trust projection was just right around 3,300 barrels. Looks like about 60% of that was trust. Keep in mind that when we did the trust, we had 37 PDP wells, and they all went into the trust. So we just started over on the drilling.

Then, as you ramp up to 130 wells for the year, do you have a rough estimate of where you think your exit rate should be for the year on the Mississippian?

No, we just talk about exit rate company wide. We don't want to give it out play by play.

Okay. For the full year oil guidance, can you give us a sense of how much of that is Mississippian, just not exit rate, but just the full year guidance that you've put out?

No. Again, we're not going to talk about details on play by play. We still look to produce 12.3 million barrels liquids equivalent this year, and the only two areas we're drilling is in the Permian and the Miss, so that's where your contributions are.

Perfect. Thank you.

Our next question comes from Joseph Stewart with Keybanc Capital Markets. Please proceed.

Hey, Tom, just one question from me. Could you talk about your thoughts on timing for the potential JV given Chesapeake's announcement this week? Just considering their expertise in the JV arena, do you think it might be better to wait for their potential deal to kind of set a floor on future bids?

That would assume that we're preparing to do a JV. We are just looking rate now at potential partners, and we've had some conversations, but right now we don't know which way we'll go. I think that in the next few weeks, you will be able to see which way or ways that we're looking at. I guess the easy answer is to say that I'm not sure that we would want to time our proposal around a JV to wait on someone else, assuming that they will get theirs done in a time that fits us, because we want to fully fund our 2012 budget this year, and I'm just not sure that that's their plans. So, no, I don't think we would wait.

Okay, great.

And our next question comes from Duane Grubert with Susquehanna Financial.

Yes, Tom, in terms of rig count, you're already at an aggressive activity level, and you benefit from having your own rigs. Can you talk to us about how you think through whether you should actually purchase more physical rigs?

We haven't purchased any rigs over the last few years, because of the number we had. That doesn't mean that we wouldn't look to purchase rigs in the future if they were the kind of rigs that we needed to have to sustain a play. So the only way I would look at it is to say that, if for us to purchase rigs would mean that-- if that were the way for us to guarantee that we could move forward with our plan to drill, then that would be something we looked at. But if there's ample rigs to lease, and we don't think that there's any -- going to be a call on those rigs, then, no, we wouldn't necessarily look to that to be our favorite way to drill. So, I think we would leave it open.

Okay, and in a related question; with some operators also vertically integrating all the way through frac equipment, have you thought about building out frac fleets, given the multi-year run likely of a frac program in Oklahoma?

No, we're still not seeing any issue with low-pressure fracking. Just remember that we are different, and that the backbone of the US gas industry over the last 4 or 5 decades has been on drilling 8,000 foot to 10,000 foot verticals wells using small equipment, and that equipment is still available, just not all of it in use. We prepare a slide actually that shows how limited the rig usage is in small rigs. That's still the way it is today, but we just assume that there's going to be activity on the rig side that might take away some of the higher end, the 1,000-horsepower rigs out of the small market. So that's the one thing we're most concerned about, not about the frac fleets.

And then on road and pipeline type infrastructure, do you have any cycle time differences from one area to the other in that some of your stuff is in a leasehold that seems to be fairly remote?

In the Mid-Continent?

Yes, in the Mississippian specifically.

Actually not in either one. No. Our lead times for getting wells on have been very quick. Just because there's ample systems in place throughout the Play. We might have one well or one well stranded out that takes a few weeks, but all in all we bring on wells within 21 days after we're through drilling.

And finally, on the intent to double your rig count, does that require changing your personnel quite a bit, or what's the capacity to execute relative to that plan that you have installed right now?

No, we have enough people to be able to execute the play.

Very good. Thank you.

That doesn't mean we don't continue to hire, but we can't do that here.

And our next question comes from Phillip Dodge with Tuohy Brothers Investment.

Good morning. Could you talk about the ramp-up in the Miss rig count to 24 in terms of what it might average for 2012?

That's what we believe we will average in 2012.

Average 24 in 2012. Okay. And then what effect do you see that having, Tom, on the production incline when you get to 24?

We don't give guidance out that far, but it's basically doubling what our production incline is today.

Okay. So, yes, that's consistent. Thanks very much, appreciate the comments.

Our next question comes from Dan Morrison with KKR.

It's actually Global Hunter Securities, not KKR. How do you look at allocating capital between the Mississippian and Permian? Is there -- obviously one source of the capital is to dial back in the Permian a little bit so you can ramp up in the Mississippian.

They're both about the same. If you look at our rates of return, both the plays are extraordinary. In the Permian, we have HBP acreage, but up until -- if you're looking out to 2012, we're more like 50/50 on allocating resources. This year we've been more allocated towards the Permian, and I think that's -- we want to continue with both plays. And my thought is, our company wants to drill more and lock in very high rates of return, so that's--. We want to be able to drill and maximize as much as we can. In the Permian at 16 rigs, and drilling 811 wells, it's hard for us to ramp that number up logistically. We might be able to a little bit, but in the Mid-Continent, it's much easier, where you have a larger area to deal with, and you do have leasehold that you have to cover.

Okay, thanks.

And our next question comes from Stephan Caven, a private investor. Please proceed. Stephan you may need to unmute your line?

Yes, I was wondering what caused the EPS miss this quarter?

If you're talking about our $0.02 loss versus the Street, I would say two things. I think people were projecting production, probably to flat line throughout the year instead of ramping, like we had. We ended the year at fourth quarter with production of 62,400 barrels of oil equivalent, and we sold over 3,000 barrel oil equivalent a day, and then we're ramping from there. So, I attribute it solely to people projecting the production flat rather than ramping throughout the year.

Okay. And so you would say that this is temporary?

I'm not sure what you mean by temporary. I'll say it this way. We thought this was a good quarter. We don't really consider it a miss. The fact that people were guiding a little bit higher, we're actually right on track with our plan for this year.

Okay. Thank you very much.

And our next question comes from Noel Parks with Ladenburg Thalmann.

Just a couple questions. Sorry if this was mentioned earlier and I happened to miss it. In the Central Basin Platform, I especially think about the former Arena properties in Furman-Masco, can you talk about how downspacing has been going on out there?

Yes, downspacing, when we talk about downspacing, we're talking about 5-acre spacing. In fact, it's going very well. We've drilled 199 wells in the first quarter in the Permian Basin, and roughly 125 of those wells were in Furman-Masco, of which about 80 of them were 5-acre wells, and they're coming in right at our type curve projection. So the downspacing is working well, and we have plenty more of those to drill.

Great. Going back into last year, one of the things that had been difficult about those properties out there were some various infrastructure issues, thinking about electricity and so forth. Have those been totally resolved at this point? I was wondering, with the weather and wildfires out there if there are any new challenges that had come up on those?

I don't know if they're totally resolved, but I would say that they are substantially resolved. We have not had the down time this year, even with the severe freezing and the wildfires, that Arena had experienced the year before, just due to infrastructure. We've built a couple of our own substations, and that has given us the ability to restore electricity very quickly any time we have a power outage. We've worked with our processors very well. We've had very little plant down time, compression down time. So, I think things are going very well, and the steps that we've taken, operationally, to improve the run time has worked out well for us.

Great. One question on the Mississippian. You've talked about the economics in general, and just thinking that we have now had the luxury of oil prices in and around $100 for a few weeks to months now. When you think about the tail of the production curve, when you make the ROR calculations, can you just give us a sense as to for the reserve life, how to think of the reserve life at sort of a more modest commodity price environment? Like say we're back looking at the $0.70 to $1.00 range for long-term prices.

We show a slide in our presentation that at, I believe it's at $60 oil, how we still after 40% rate of return in the Mississippian Play. It's really all about cost. If you can control costs, and be able to produce oil and lock in that oil at high prices, we're locking in oil somewhere between $90 and $105, there really shouldn't be any issue with the company going forward. So, it's a very simple strategy. If you believe that service costs aren't going to go up, and you believe that you're finding your type curve on your production, you should hedge it and have some of the highest rates of return that I've ever seen in my career.

Okay, great.

Our next question comes from Mike Beard with Hodges. Please proceed.

Thank you. Good news this morning. Just one quick question. Is Occidental putting any pressure on you at all to produce more CO2 for their tertiary recovery?

Well, no, there's no pressure for us. I think that Occi and us look at this as a very long-term project. I can't speak for them, but today it doesn't make very much sense for us to drill gas wells. So, we're looking forward to the time that it does for us or someone else to be able to drill in the Pinon Field.

Okay.

Our next question comes from Thomas Piccirillo.

Yes, my question is, for the derivatives contracts. I noticed in your release that the realized impact per barrel had a negative impact of $7.50. And then in the adjusted earnings, there was a realized gain from out-of-period derivative contract settlements. I was just wondering how you arrived at that with the out-of-period versus the loss within the period?

Sure. The out-of-period is covering some natural gas hedges on, I believe it's 42 BCF of gas during the period. Our belief is that at $4 gas prompt, that signifies, maybe not the low, but that the risk/reward on past that point is negligible, and we decided to take off the gas hedges during the quarter. So that was what the out of contract derivative gain was.

In the period, that's simply the difference between our hedges, which were at $87 a barrel and the (technical difficulty), which was closer to $100.

Okay.

There are no further questions at this time. I will now turn it to Tom Ward, Chief Executive Officer, for closing.

Thank you, and thanks, everybody, for joining us. We look forward to seeing you or talking to you in the quarters to come. Thank you very much.