SandRidge Energy, Inc.
Q2 2010 Earnings Call Transcript

Published: 5 Aug 2010

[Operator:]

Good day, ladies and gentlemen, and welcome to your Quarter Two 2010 SandRidge Energy conference call. My name is Denise, and I’ll be your event manager today. [Operator Instructions] And now I would like to hand the presentation to your host for today's call, Mr. Dirk Van Doren.

[Dirk Van Doren:]

Thank you very much, Denise. Last night, the company issued a press release detailing SandRidge's financial and operating performance for the second quarter of 2010, and we'll file our 10-Q on Monday. If you do not have a copy of the release, you can find a copy on the company's website, www.sandridgeenergy.com. Now for the forward-looking statement. Please keep in mind that during today's call, the company will be making forward-looking statements, including statements about our acquisition of Arena Resources and the anticipated benefits of the transaction, which are subject to risks and uncertainties. Actual results might differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed on the company's filings with the SEC. Today's presentation will include information regarding adjusted net income and adjusted EBITDA and other non-GAAP financial measures. As required by SEC rules, a reconciliation to the most directly comparable GAAP measures are available on our website under the Investor Relations tab. Now let me turn the call over to Chairman and CEO Tom Ward.

[Tom Ward:]

Thank you, Dirk, and welcome to our second quarter operations call. We also have in our office today, Matt Grubb, COO; and Kevin White, Senior VP, Business Development. SandRidge has transformed to a diversified oil and natural gas company with the ability to selectively drill for oil and gas as circumstances dictate. Approximately 70% of our revenues are now generated by oil production. With the increased oil production, we've been able to hedge over $2 billion in future revenues. As a result of our hedges, shallow drilling opportunities and certainty of reserves, we are able to implement a sustainable drilling program that wheeled rates of return in excess of 50% on all of our oil projects. Our goal is to have a company with the appropriate mix of low-risk oil and gas assets that will enable us to drill and create value in a broad spectrum of economic circumstances and achieve industry-leading returns on invested capital. We are now that company. At the end of 2008, we started down a path of hedging our natural gas production, averaging over $8.80 per Mcfe and looking for acquisitions of crude oil. Our total liquids production has risen from 4,000 barrels per day to nearly 24,000 barrels per day today. Let me emphasize that post-Arena, 85% of our liquids production is crude oil. That's an important point, because our industry now commonly uses the term “liquid-rich” to instill value in a particular area or particular a play. As you know, liquid-rich often means natural gas liquids, while currently better than dry natural gas, still sell at 50% to 60% discount to crude oil. Furthermore, even though the price per barrel is more than double for crude versus natural gas liquids, there's a backwardation of the NGO market as compared to a contango in the crude oil market, making it very difficult to effectively hedge NGL prices. We not only look for pure oil plays, but have also focused on the Central Basin Platform of the Permian Basin. We've now amassed over 200,000 net acres here in less than a year. This acreage position, if valued like large shale plays currently getting JV attention, might be worth $10,000 per acre, or $2 billion. However, we do not pay for unproven acreage, but instead, acquired over $2 billion worth of oil production that we've hedged. We now have virtually unlimited oil drilling upside with no acreage costs. Our plan was simple

[Dirk Van Doren:]

Thanks, Tom. For the second quarter, we are continuing to see the impact of our strategic transition as oil revenues, including hedges, accounted for 56% of commodity revenues for the quarter. It probably should come as no surprise to you that our Permian properties continue to be our most profitable producing region. Two numbers in the quarter need explanation. First, LOE was higher because of we're lifting more crude oil; and there were about $4 million of workover expenses in the quarter versus none last year. We were also impacted by lower production in the Gulf of Mexico, which has a high fixed-cost component. The Gulf of Mexico, while it has a high lifting cost, is very profitable because of a large percentage of oil production. Second, G&A increased because of legal and professional expenses related to the Arena transaction and IT expenses related to the Permian acquisitions. Cash employee costs were flat year-over-year, and while we are in compliance with all financial covenants, we are in compliance with all financial covenants at the end of the year, and our revolver yesterday was drawn $400 million, with $5 million of cash. Please keep in mind we expect about $139 million for the Oklahoma property sale before the end of the quarter. Looking at the Arena transaction, it brings to SD a significant amount of cash flow, almost $1.5 billion for book equity and more shares outstanding. So pro forma for the transaction, our LTM EBITDA would be north of 825, and please keep in mind for covenant purposes, that number would be higher. And our debt-to-capital ratio improved to 66%, with the outstanding share count as of July 30 of 405.1 million shares, not including any preferred-stock conversions. We'll be filing an 8-K-A in late September, which will provide more detail in the pro forma financial statements of Arena-SandRidge combination as of June 30. During our last call, we mentioned we had a goal of $3 billion of revenue hedged from the second half of '10 through 2013. For this time period, we now have over $2 billion hedged, with no gas hedges for from now through '13, and we've added about 1.46 million barrels of crude in 2013. So we're well on our way of achieving the goal. If we hedged at the strip today, we could lock in well over $4.6 billion in revenues. And since our last call in May, we've hedged 7.8 million barrels of crude oil from 2010 to 2013 at over $85 a barrel. Looking at guidance, the company has shifted its focus further to oil drilling, as Tom mentioned. Lifting costs have increased, primarily due to higher expenses associated with the company's shift oil drilling and increased workover expenses. DD&A for the oil and gas side of the business has increased to capture a higher rate associated with the properties acquired from Arena. G&A, both cash and non-cash expenses, have increased to account for the Arena acquisition. In total, capital expenditures, as Tom mentioned, have actually decreased about $50 million pro forma for the Arena transaction and our shift away from natural gas. That ends our prepared remarks, Denise. We're now ready to take calls.

[Operator:]

[Operator Instructions] And your first question comes from the line of Dave Kistler.

[David Kistler:]

Real quickly, trying to tie a few pieces together. If I look at the reduced drilling activity in the Piñon, do I have to get concerned about your obligations as far as gas that you'd be running through the Century Plant and ultimately delivering to Oxy, realizing that Century Plant probably has a higher BTU content out of the gas stream, also has lower costs and you're getting a benefit from tax credits? Just trying to understand what the ultimate economic effect of that overall decision is, because running five rigs would lead me to believe that the gas running through may not be sufficient to, on a long-term basis, supply the Oxy contract. And I could be off base with that.

[Tom Ward:]

The net-net to both of us is positive. Bringing on the Century Plant, we've already said, has an efficiency gain for us of about $30 million. It also has an efficiency gain for Oxy. Combining the net gain efficiencies with tax credits, it's a net positive for us.

[David Kistler:]

Will this impact, ultimately, the delivery obligations? I guess what I'm trying to get at is, will you guys be having to pay a penalty? And I guess as you're indicating, the economic benefit will offset any penalty that might have to be paid.

[Tom Ward:]

Sure, that's exactly it. If their penalty is settled, when penalties, if we didn't meet -- as you know, the contract is confidential, but if we did not meet guidelines, it is public that there is a $0.25 per Mcf penalty on under-delivery of CO2 volumes. Yet that is offset with efficiencies and tax credits, and we say it still is a net positive to our company.

[David Kistler:]

Okay, okay.

[Tom Ward:]

I’d also add, I believe Oxy would say that the efficiency gains are, also, and the tax credits are positive for them. But I can't talk for them.

[David Kistler:]

Okay. I appreciate that clarification. And just, as long as we're looking at decreasing the rig count in the Piñon, I’m trying to tie that with your decision to monetize hedges. Obviously, you guys treat hedges as a financial instrument and separate them a little bit from your operating decisions. But if you could kind of help me understand that, monetizing Hedges strikes me as a very bullish thing to do as sort of a call on gas. But cutting rig count makes me think that your view on gas, longer term, is a little bit suspect.

[Tom Ward:]

Sure. That’s fairly easy to walk through. Today, we've hedged in oil at $86 and change, close to $87 per barrel, and we make very high rates of return on every oil well we drill. Today's gas prices is, obviously, at a place that you can make some rates of return on a well basis, but it's hard to project real high rates of return. What we did was, as you know, we did not have hedges in place post-2010 but did feel that the market was overly bearish on natural gas and even, for a short period of time, oil and pulled off hedges on natural gas early through the rest of 2010. The reason to do that is just that we're making a long-term call on natural gas being higher, but we were making a short-term call that, looking out through the August through December period, when we pulled some gas off of June, that the prices would be higher than what they were in June when we thought it was an overly bearish situation. We still believe the market is overly bearish, and therefore we have not hedged any of our 2011 gas yet. That doesn’t mean that sometime this year, we won't hedge 2011 gas. We think that there is still, in the market today, a perceived thought that gas supply will be higher than we think we’ll be end of October. We're more in the 3.75 to 3.76 Tcf range. We think there's some constraints coming out of the Haynesville and maybe in the Marcellus and that, that might not into the marketplace, but still believe that 2011 could be challenged as you bring on Tiger out of the Haynesville and have other capacity constraints relieved. And also, we think wells aren't coming on quite as quick as the market might be believing, in the gas market, anyway, for 2010. So if you look at a harder time to bring gas wells on, just because of -- in the Haynesville, especially, having a longer time to bring wells on because of fracking, and then maybe some pipeline challenges, we believe it was a good time to take off gas. If you look at our history, we haven't done that very often. In fact, only one other time in the history of the company have we pulled any hedges off, and that was, I think, in 2006. So it isn't something we do very often, but in the short-term in both of these cases, we felt that it was the appropriate thing to do. And that doesn't mean that we won’t be putting back on gas hedges by the end of the year

[David Kistler:]

But I should think about the cutting of the rig count in the Piñon as something completely separate. The economics there, even if there is a little bit of a bounce in the gas price, probably don't necessitate keeping the rig count where it is. Is that...

[Tom Ward:]

Well, yes, we just look forward with about 80% of our budget going to oil drilling, and that's just because we can lock in higher prices for oil. If you look back at the history of the company, when you had gas over $8, we had 37 gas rigs running. When gas got down to $2 and change or $3, we had four gas rigs running. So that's the kind of the parameters that we've had in the past for running gas rigs, and were kind right in the middle of that right now. We're just over the four with running, projecting to go with five if gas prices don’t improve somewhat going forward.

[David Kistler:]

Great. In the Permian, where you talk about having 50% rates of return and using your own rigs, it kind of keeps you vertically integrated. How much of your well cost is kind of variable there or is exposed to service cost inflation, as we're seeing a number of people ramp up?

[Tom Ward:]

I'll let Matt take the direct question, but the areas that we are exposed to that I can think of off the top of my head are fuel, diesel, and then pressure pumping. But as we described, we don't have the same type of pressure-pumping needs that the rest of the industry does, so we're able to get equipment. Matt?

[Matthew Grubb:]

Yes, Dave, I mean, we drill those wells pretty quick, the bulk of our drill between four days and about nine days. We get off over the Wolfberry, and they’re a little bit longer, about 14, 15 days. But we do use our own rigs out there, and so we’re pretty much locked in on the drilling side of it. I want to say probably, when you look at fuel, you look at high-pressure pumping, mud, wireline work, probably depend on which area and which type of well you’re drilling, like probably a third to half your cost is exposed to service costs. However, out here in the Permian, we do the type of high-pressure pumping, the type of equipment that's being run out here, in general is not going to be taken and moved to the Haynesville or other areas because of the lower pressure that we pump and the type of fluid and the type of prop. So I think the service side is pretty good. The cost, we are locked in through the end of '10. We are working on longer-term high-pressure pumping, especially right now. We're working on our longer-term agreements now, and I think costs will be very reasonable going forward as I can see it today.

[Tom Ward:]

And then, just to address that rate of return, the question you had, was that we looked at all of our locations across the Permian Basin and said that if, without high-grading, we can be in excess of 50%.

[David Kistler:]

Great, guys.

[Tom Ward:]

Next question?

[Operator:]

Your next question comes from the line of Neal Dingmann.

[Neal Dingmann:]

Say, Tom, I was wondering if you could give us a little breakdown of -- obviously, it looks like the gas projections were down just a little bit, as you mentioned -- an idea of the regional breakdown of gas production right now. You mentioned a little bit on the oil side, but I didn’t see in the press release anywhere where, I guess, the production is broken out on regional.

[Matthew Grubb:]

Hey, Neal, just to repeat the question, you're asking for a breakdown of the gas production regionally, is that correct?

[Neal Dingmann:]

Right.

[Matthew Grubb:]

Okay. Yes, we can do that. Our guidance for gas is basically 78 Bcf of gas production for '10. I'll give you a breakdown, and I'll tell you where we may be conservative there. In Piñon, Q2 of '10 in Piñon was the first quarter in a while where we actually increased gas production. We drilled as high as 34, 35 rigs in Piñon a couple of years ago, and production really ramped up quickly. And as Tom mentioned last September, we went down to about four rigs. So we had a rapid decline, and we had quarterly decline. But from Q1 to Q2, we had a slight increase of 115 million a day to about 118 million a day. And with the ramp-down in rig in the Piñon Field, we're projecting about 122 million a day in Q3 and Q4. The difference, there, in a year, when we're envisioning running 10 rigs flat in Piñon, we were envisioning going from 115 million a day to about 135 million, 136 million a day in Q4. So with the new guidance there and with the new program, we're looking at about 43 1/2 Bcf of gas produced from Piñon. East Texas, this is where I believe we are conservative. We ran a couple of rigs in East Texas in Q1. Because of the low gas prices, we’ve dropped off those two rigs. We produced about 34 million a day in Q1 and 34 million a day again in Q2. However, we're projecting East Texas wells will go on a pretty steep hyperbolic. They’re Cotton Valley wells. We're projecting 26 million a day in Q3 and 24 million a day in Q4, which, I believe, are probably 3 million to 4 million, conservative, and that even today, right now, we’re producing still about 32 million a day, and we're halfway through Q3. So I think there's a chance for a bump in East Texas production. But the way we have it modeled right now, we will produce about 10.8 Bcf of gas. Gulf Coast and Gulf of Mexico, those are areas that we are not active in. Unfortunately, out there, we had some well performance issues that were unforeseen. We had a big well in the Gulf Coast -- these are waterdrive reservoirs, so water started to come in, so we had to choke them back pretty severely to maintain production. That's one well in the Gulf Coast. And we had three wells in the Gulf of Mexico with the same type of event, one that we operate on our East Brae 165 platform and the other two that Chevron operates, but we have high interest, 66% working interest. So the combined result of some well-performance issues there, we're below our forecast probably 5 million to 6 million a day in the Gulf Coast and Gulf of Mexico that was just unforeseen, and we didn't know the time of when that would happen. So in those two areas combined, we predict to produce about 6.5 Bcf of gas. Midcontinent, we predict to produce about the same, about 6.3 Bcf of gas. And then the Permian, about 8.5 Bcf of gas. That will be a steady increase of gas from Q1 through Q4 as a result of drilling, but we're projecting pretty moderate increases, 21 million a day in Q1 up to 25 million a day in Q4. And that excludes Arena. For the Arena gas, we're estimating about 5 million a day in Q3 and 7 million a day in Q4, for a total of 1.1 Bcf. And then all the other areas, non-ops, et cetera, about another 1.4 Bs. So that takes us to 78 Bs. Yes, so anyway, I think where we're conservative right now, we’re a little bit conservative in Piñon, I believe, in that we do have a compression project going on where we we’re going to draw the field pressure on our high CO2 gas down from 1,000 pounds to about 500 pounds. We haven't fully migrated all the wells over yet. We’re about halfway through that process, and we've seen a 5% to 10% increase so far. And then in East Texas, I believe, we're conservative there by 3 million to 4 million a day. So I think the 78 Bcf, it may be a little bit light on the gas side.

[Neal Dingmann:]

Are you pretty confident on the Gulf Coast, Gulf of Mexico? I mean, the problems, are those past now? Or what do you think going forward on those?

[Matthew Grubb:]

Yes, I think we've stabilized production. We look at that every day. They were stair-step drops, as opposed to a normal decline that we would project. And as you know, Neal, these high-perm reservoirs, once you get water breakthrough, you just have to manage that process and choke your well back.

[Neal Dingmann:]

Right. Okay. And then, what about, now that you’ve got Arena over there, the previous problems they had with some of the case and [ph] (0

[Matthew Grubb:]

Yes, with our experience that we have in Permian and in those exact areas, I think we'll be able to resolve those issues. However, timing is difficult. We are working on electrical infrastructures. We are talking to various processors right now to look at our options to have primary processors and secondary processors so that we don't have down time. Arena's production was really very flat. They produce about, just from an oil standpoint, not counting any gas, 85% of their production in oil. But in Q4, they produced about 7,000 barrels a day, and in Q1 of 2010, they produced about 7,200 barrels a day. And a lot of that had to do would not be able to move some of that gas due to electrical or processing issues. Though we are a little bit conservative on our Arena projection, even though we’re going to drill probably close to 200 wells from here on out to the end of the year, we're pretty much saying that we’re going to keep that production flat, and that's why our total oil production is 7 million barrels a day. I really think, realistically, we’ll have probably a 20% increase, and that could get us to 7.15, 7.2 million barrels. But that has to do with our ability to resolve those issues, which I feel that we’ll get them done.

[Neal Dingmann:]

Got it. It seemed in the Perm with your Forest properties, I assume most of the production’s coming from that shallow, that San Andres formation. I’d heard that you you’d drilled some deeper wells. I was wondering if you were going to continue to do that, if you were having some success there with some of the deeper zones.

[Matthew Grubb:]

We are having some success. We’re drilling some of these zones that really were not exploited by the previous operator. The Clear Fork has been our bread-and-butter. And now, certainly, with the Arena asset, Perm and Moscow Field, the San Andres is a very prolific zone. However, we are going on down in certain areas to the Fusselman and the Wichita-Albany zone, down below the Clear Fork, and having very good success with those zones. And we’ll continue to exploit that effort.

[Neal Dingmann:]

So how many wells have you drilled in the deeper zone, do you think?

[Matthew Grubb:]

I don't know off the top of my head. Probably in the order of a dozen, I would guess. We had a Fusselman well that came on at 500 barrels a day that’s currently producing about 300 barrels a day. We had several Wichita-Albany wells down below the Clear Fork that are coming in at about 100 barrels a day. So they're very good zones, and these are all fairly shallow.

[Tom Ward:]

And Neal, this is Tom, what we'll do is just come up with a type curve for the Permian Basin, because there are so many opportunities to drill from Bone Spring and the Delaware Basin over to the Wolfberry. Those will have less rigs than our Central Basin Platform, but we will move some rigs back and forth. We have a vertical rig going in the Bone Spring area now. The Central Basin Platform, also, has tremendous reserves moving from the San Andres, which is the shallowest zone that Arena drilled for, all the way down to the Fusselman. And that's only the difference between 4,500 to about 8,000 feet. So to get to the deeper zones doesn't require many days or much expense. So that's how come we're evaluating the whole sector or the whole strat column and looking at each one of these can bring on multiple thousands of barrels of oil with not too much additional cost. That's what we're evaluating now in each of the areas.

[Operator:]

And your next question comes from the line of Scott Hanold. RBC Capital Markets.

[Scott Hanold:]

Back to sort of your plan on monetizing some of the gas hedges. It looks like in June, gas did have a little bit of a bump. So when you made the decision, I just want to be clear, was it a call that gas has bottomed, in your opinion? Or was there some sense that you were just trying to capture some extra liquidity? And, I guess, the hedge position that you do put into your presentation, obviously, is not the current one, but you also took off some things post-the quarter?

[Tom Ward:]

Yes, in both cases, it's a call on gas bottoming an overly bearish market. And I still believe we’re in that type of an overly bearish market, even though each week, it appears that the market’s a little tighter, the actual supply’s a tighter than what the market believes. I think, as you guys know in dealing with industry and investors, it’s just a very negative time for natural gas, and for good reason on a lot of fronts, but, I think, overly bearish as far as price. And we're only looking at a few months, not years, and so that was the reason we decided to make the call.

[Scott Hanold:]

Okay. And on the Permian. You stated that you hoped to grow that asset by, I believe you said 30%? Or was that total oil volumes by 30% next year? And when you look at some of the infrastructure and logistical constraints in the field, I mean, is this really going to be back-end weighted into the year if this happens? Or do you all think that you could really hit it hard starting early 2011?

[Tom Ward:]

Well, we're hitting it hard now. I mean, just in the projected growth, we have, without even taking into consideration Matt's last comments, we're projecting, since acquiring Arena, of about 16% growth just in the last half of the year. And then moving forward, we think a 30% growth in oil production next year is very achievable. And we have the staff in place to take care of issues, so that, I believe, we'll be able to hit those numbers.

[Scott Hanold:]

Okay. And then you did cite like a Permian Basin rate of return of somewhere around 50-plus percent. If I'm not mistaken, in a prior update, the number was something like 80%-plus?

[Tom Ward:]

Sure. You can get that on several of the reservoirs we drilled for individually have those types of returns. In fact, higher than that. You just took an average of all of our locations across the Permian Basin.

[Scott Hanold:]

Okay, so the prior one wasn't an average? It was just some of the better ones? Is that right?

[Tom Ward:]

If you look at -- the best rates of return we have in the Permian are in the Clear Fork,.

[Scott Hanold:]

Okay. And then one last thing on the Century Plant. It sounds like it's coming on here soon. And so has there been any added issues since the last update? Or is everything sort of on track and on schedule here?

[Tom Ward:]

Well, I think at one time we had scheduled for August, and we have moved that back into September, but the construction’s through, and we're just in the process of bringing the plant on. Matt, do you want to talk about that?

[Matthew Grubb:]

Yes, no, there's no issues. The commissioning process of going through each vest on each pipe [ph] (0

[Scott Hanold:]

Okay. And maybe this is for Dirk, when you look at your revolving your capacity and your spending over the next sort of 12 to 18 months, how have your conversations ranged seeing the banks regarding your revolver? How have those gone?

[Dirk Van Doren:]

Sure. A couple of things. Let's just take the rating agencies first. We see the rating agencies scheduled twice a year. I've actually seen them three times this year. I saw them in March, April and just a few weeks ago, just to keep them updated on the Arena transaction. I know we were upgraded by S&P in late December. Moody's has told us they want to wait and see what's going on with the Century Plant, and obviously, they're concerned about gas prices, so they're not sure what they're going to do as far as ratings. We certainly never push them as far as their ratings. We respect their opinion and don't poke at them from a standpoint of getting better ratings. But I think the conversations with both of those groups have been excellent. And we will see them again in the fall in one of our usually scheduled meetings. So that is great. As far as the banks go, you know that we did the revolver in April, and that was very good. We are adding in Arena. You may or may not be aware, the banks have taken down their price decks across the board, so that's going to, obviously, take cash flow away, PV away. Hedges, a lot of the banks roll forward six months, so they would go through '10 and start using '11. So many banks, if you don't have hedges in '11, that rolls off. But the conversations with the banks have been great. The bank market is incredibly strong. What's fascinating is how strong the hedge market is and the credit there. We've done 7.8 million barrels in the last three months, and we continue to have line at 17 of our counter-parties. So overall, the credit markets, and if you’ve paid attention to the high-yield market in the last two, three weeks, thing’s on fire. So credit is on fire right now, and we're pretty comfortable on that side of the balance sheet. And obviously, Arena does some fantastic things for us across the board on the credit side.

[Scott Hanold:]

You don’t think the rating you received may be concerned with you taking off the gas hedges at this point?

[Dirk Van Doren:]

No, I spoke to them about it. That money was going to be coming in, in 2010. Whether it came in, in June or it came in, in October, it was coming in this year. So there's really no difference. If we were to put those hedges back on right now, we'd make money. And if we wait a few weeks, we'll probably make more money. So, no, that's not an issue.

[Operator:]

Your next question comes from the line of Amir Arif.

[Amir Arif:]

First on the oil side. Just to clarify the 30% production growth potential that you’re talking about, is that full-year '11 over '10? Or is that pro forma your current production with Arena versus where you think you could be in a year from now?

[Tom Ward:]

Pro forma with Arena.

[Amir Arif:]

Okay. And that would be achievable with the 18, 19 rigs that you have running?

[Tom Ward:]

Yes, projecting 19 rigs.

[Amir Arif:]

19 rigs. Okay, so roughly within the same capital expenditure levels that you've laid out?

[Tom Ward:]

Yes.

[Amir Arif:]

Okay. And then, just switching over to the gas side. Any update on, just given that you might not fill up Century Plant 1 or you’ll have excess capacity, on Phase 2? That was going to be planned in third quarter '11?

[Tom Ward:]

I think Phase 2 is now looking out into '12. In the first half of '12.

[Amir Arif:]

2012. Okay. And then you commented on the breakdown on the gas volumes a little bit. I was just curious about that. As you take the Piñon rig count down from eight to five, will gas volumes be declining in '11 if you don't increase the rig count from there?

[Tom Ward:]

Yes, we're not going to give -- we don't have guidance yet to give out on 2011, but we're planning on coming out with that towards the end of the year, towards the November, I believe, call.

[Amir Arif:]

Okay. Well, let me just ask it a little differently, then. So previously, when you went down to four or five rigs, production was declining at Piñon. Has anything changed, where if you're at five rigs, production would be flat?

[Tom Ward:]

Matt, you want…

[Matthew Grubb:]

Yes, production, like I say, it increased slightly from Q1 to Q2, and then we project it to increase slightly from Q2 to Q3. We have about 20 wells there that we're waiting on completion. That's going to add to the gas production. Also, we have our compression project. And I misspoke earlier, I said we were going to take pressure from 1,000 pounds to 500 pounds. We're actually taking pressure, field pressure, down 200 pounds. So anyway, with the compression project and the wells on their way to completion, we should have an increase going forward this year.

[Tom Ward:]

What we don't know is -- to look out too far ahead on gas production and give you guidance today, we still don’t know how many rigs that we’re going to have running there.

[Amir Arif:]

Fair enough. And then, just a final question on the non-core asset sales that you've laid out, the $200 million, $400 million. Is there any specific areas you’re targeting for that?

[Tom Ward:]

Oh, we own a lot of acreage. We own over 1 million acres in areas that a lot of companies want to have. So I think you can pick, in the Delaware Basin, Bone Spring is an area that appears to have a lot of interest. The Wolfberry in the Midland Basin, both are less attractive to us than the Central Basin Platform. And then we have a tremendous amount of acreage in the midcontinent. So really, we could choose one of several places.

[Amir Arif:]

And I think in your release, you laid out that will happen by the end of ’11. So I guess there's no rush in getting…

[Tom Ward:]

We're not in any hurry. And we won’t, probably, run through any processes. It’s just like we did in Western Oklahoma, we just made a sale.

[Amir Arif:]

Okay. Sounds good.

[Operator:]

And your next question comes from the line of Dan Morrison [ph] 0

[Unidentified Analyst:]

I've got a pretty good flavor for when you were talking about the oil activity in the Permian. But do you have a more specific kind of breakdown of the different play types you’re in?

[Tom Ward:]

Well, there's really several different play types in the Permian Basin, and they range from the shallowest being the San Andres to the deepest being the Fusselman, and that is ranging from 4,500 to about 8,500 feet. That all is in that oil column, and the Central Basin Platform is one of the best oil columns in the United States. So billions of barrels of oil have been extracted from this area. And if you look on our map that we provide in our slide show, you can look from the north at Robertson Field down to Goldsmith Adobe. All of these fields join each other. So it's just a tremendous area of oil production in the Central Basin Platform of the Permian Basin. And then as you move over in the Delaware Basin, the Bone Spring is the main area of interest, and that's sandstone. And then the Central Basin Platform of carbonates, and then as you over to the East in the Midland Basin, you have the Sprayberry and Wolfberry, which is a tight, silty sandstone.

[Unidentified Analyst:]

How would your 18 rigs split out between the three?

[Tom Ward:]

They move back and forth. But the majority of rigs will run in the Central Basin Platform. Today, we have one rig that works in the Wolfberry and one rig that's working in the Delaware Basin.

[Unidentified Analyst:]

And in the Central Basin Platform. Is that infield drilling or ...

[Tom Ward:]

All areas are infield drilling.

[Unidentified Analyst:]

Okay. Great.

[Operator:]

And your next question comes from the line of Jeff Robertson [ph] (0

[Unidentified Analyst:]

Tom, on the asset sales, are you talking about selling acreage, then, and not production reserves?

[Tom Ward:]

Yes.

[Unidentified Analyst:]

And I believe you said earlier that you will have added acreage in the Bone Springs in the quarter. Are you adding acreage in some areas where you think you have critical mass and willing to sell it in other areas where you may not have enough?

[Tom Ward:]

Well, they came with our acquisitions. So we've amassed a nice position in the Bone Springs. And we added just a little bit of acreage through acquisitions, but most of that came through -- acreage acquisition, most of it came through just acquisition we made of properties with Forest and Arena. And it's always surprising what extra little things that you get that other people like.

[Unidentified Analyst:]

Okay. And secondly, maybe this is for Matt, but the compression project you all are putting in place this year. Will that have an impact on the reserves that you lost at the end of 2009, because you didn't do a compression project last year?

[Matthew Grubb:]

Yes, it certainly can. This is a project that we, basically, delay by year. I hope that going down to lower pressure, 200 pounds, that some of this decline -- well, first of all, I hope we get a bump in production. If we do that, certainly, that will impact our forecast. But worst case, I think we should flatten decline more, which will also impact positively on the forecast.

[Unidentified Analyst:]

And then just one last question on the decline, Matt, you’d talked earlier about the decrease in drilling activity that you all started putting in place, I guess it’s almost two years ago now. I guess you've gotten through the flush part of the production profile, and you’re more on a natural decline out there. Is that why it’s starting to stabilize?

[Matthew Grubb:]

Yes. That has a lot to do with it, is getting through the flush part of all the wells that we drilled in 2008. Those wells probably declined, what, 60% in the first year? And you kind of have that again the second year. So we’re getting through some of that. We'll drill. I mean, we have brand-new wells that we’re going to drill this year also, but it's something that we’ll continue to fight. But we are at the level where we can run the number of rigs that we've ran here and actually have a slight increase in production.

[Unidentified Analyst:]

And then lastly, Tom, can you talk a little bit about what your follow-up plans as far as exploration in the WTO might be post- some of the results you hope to have here later in the third quarter?

[Tom Ward:]

Sure. We’ve said that we’ll drill six wells this year. We still plan to do that. We're very encouraged with the first wells that we've seen. And we continue to look at a lot of structures. We control a tremendous amount of natural gas, and I just have to believe that at some point, natural gas market will come back whenever operators decide to move off some gas rigs at these prices. I don't believe this can go on forever, and we're very patient. We control gas, we have the science that no one else has. We have the acreage that no one else has. We don't have issues with half-in-two HBP land at uneconomic prices. So it just is --we'll be patient with a great asset.

[Operator:]

And your next question comes from the line of Philip Dodge.

[Philip Dodge:]

Related to the last question, how realistic do you think it is to expect any production related to the three exploration wells that you have some information on to date in 2011?

[Tom Ward:]

Oh, I don't know. It's not in our plans to really have tremendous production. We have a lot of acreage to explore, and until we see a move in gas prices, we won't be really moving in with too many rigs to do development. That doesn't mean that in the Magnolia structure, for example, that we won't drill delineation wells and try to understand the size and the scope of that play. Remember, it's all sweet gas, so even if we found a couple of Bcf per well, it's going to be the equivalent of drilling wells in Piñon. And that's the great thing that we have across the West Texas Overthrust is that we know there's gas in place. We just have to find that structurally in a place that we can have a reservoir to produce. But to answer your question directly, we don't look at a lot of production coming from, or, really, any production coming from exploration in 2011.

[Philip Dodge:]

Okay. I was just looking for a forward-looking statement that I understand. So other question, I got a little bit lost in the capital expenditure budget changes. Just to understand, you went from 800 from 875 on May 6, and now you've raised the 800 to -- I'm sorry, you went from 860 to 800. Now you’ve raised it to 875. And did I hear that includes $125 million by having Arena?

[Tom Ward:]

That's correct. We’re going to spend about $125 million on the Arena properties that we didn't have last quarter.

[Philip Dodge:]

And just finally, will you be raising the rig count on the Arena properties at some point?

[Tom Ward:]

We're moving that. It's all a part of our Permian Basin activity. So yes, it is increasing, and yes, it is more drilling in the firm Moscow.

[Philip Dodge:]

Okay.

[Operator:]

Philip Jungwirth is on the line with your next question.

[Phillip Jungwirth:]

Can you talk about the payback time on the Permian wells that you’re drilling? And then how you balance kind of the desire to run a lot of rigs there, increase your EBITDA with outspending cash flow and drawing on the revolver?

[Tom Ward:]

Sure. I think that I'll let Matt kind of address the payback time. The way we look at this is, that it is part of a process that not only do you drill the well, but you lock in future cash flow with hedges. The two-pronged approach is, is that you're guaranteeing yourself to have high rates of return and bringing on EBITDA, and then addressing the -- growing that production and growing EBITDA and then making sure that you're not overspending on the CapEx side to be drawing too much on your revolver. So we're looking out towards having -- we've said have a cash burn next year, but after that, being more in line. I don't know if we have a payback period, or…

[Matthew Grubb:]

Yes, we’re looking on average about a two-year payback. If you look at just the San Andres well, and even on a net basis of say, 26,000, 27,000 barrels at $80 oil, now you're generating $2 million in revenues paying $500,000. You can kind of four to one. So it’s a…

[Tom Ward:]

I don't know of many other plays where you can do that.

[Matthew Grubb:]

It is a very good program.

[Phillip Jungwirth:]

Okay. And then also, just given the much larger asset base that you have now following the Arena transaction, with a lot of that being oil. If you do start bumping up against the debt covenants by kind of late 2011 or so, how does that help you in this much larger asset base in obtaining a waiver? Do you think it would be a lot easier in negotiations and conversations?

[Dirk Van Doren:]

Well, I'm not sure where you're going, but from a covenant calculation, we've turned our covenants down more than the turns with the Arena transaction. Our model sees no covenant issues out through '13. So I’m not quite sure what you've got, but we're not even close to that.

[Phillip Jungwirth:]

Okay. So pro forma for the Arena with the LTM EBITDA credit. Is it that debt to EBITDA is around 3.4, is it in that range?

[Dirk Van Doren:]

Lower.

[Phillip Jungwirth:]

Lower?

[Dirk Van Doren:]

Keep in mind, if you just do the debt calculation, you got to read the covenants closely, how we can calculate Arena’s EBITDA is not LTM. So we get a bigger bump. We’re going to get $181 million to $200 million from Arena.

[Phillip Jungwirth:]

And so, I think you already kind of addressed this, but the non-core asset sales, that's not Gulf of Mexico, the CO2 tertiary. That's more acreage that you could get out a bigger bang for your buck for, I guess.

[Tom Ward:]

Sure. And that doesn't mean that we wouldn’t also look at other sales that could have some production tied to it. I’ll just say, it's easy to find $300 million to $400 million in just straight asset sales that do not have EBITDA tied to it.

[Phillip Jungwirth:]

All right.

[Operator:]

[Operator Instructions] Your next question comes from the line of Edward O’Keane [ph] (1

[Unidentified Analyst:]

Actually, I was getting to the crude hedges. Just trying to find out, I mean, if there's a level that you will want to achieve as a percentage of your total production for each year.

[Tom Ward:]

We lock in very high rates of return, anything North of $80. So everything, the strip is giving us ample opportunities to hedge. We're not even close to being where we’d feel uncomfortable hedging.

[Unidentified Analyst:]

Okay, so I mean, are you planning to be 100% hedged going into 2011?

[Tom Ward:]

We cannot be 100% hedged, but we can be up to 85% hedged.

[Unidentified Analyst:]

Okay. Okay.

[Tom Ward:]

And I don't know that we'll actually get there or not, but it's desirable for us to hedge in high rates of return and have no risk, or a very low risk.

[Unidentified Analyst:]

Okay. All right.

[Operator:]

Your next question comes from the line of Brian Singer.

[Brian Singer:]

A couple of questions. Probably they were asked earlier. But it looks like from your $875 million capital budget would imply a run rate of about $225 million per quarter for the remainder of the year. And I just wanted to get some color as to whether that's a good run rate as we think about going into 2011 or if you would either A) plan to accelerate activity, or B) if there’s any one-time items that would lead to some kind of lower run rate next year.

[Tom Ward:]

Sorry, Brian, is that run rate on…

[Brian Singer:]

Capital expenditures.

[Tom Ward:]

I'm sorry, the question then is are we looking at anything that might accelerate that?

[Brian Singer:]

Exactly. So if we take $225 million implied for the remainder per quarter, are we kind of looking at $900 million or greater for next year?

[Tom Ward:]

I think we're very comfortable with the $875 million that we've got right now. So what we're looking at for next year, we haven't officially made that. I think one we’re looking at is we're thinking about '11 being basically flat.

[Brian Singer:]

Got it. Okay. And then, I don't know that we heard it earlier. But did you talk about any specific or can you speak to any specific Permian Basin wells that you drilled? And what you're seeing in terms of decline rates from some of the wells you drilled earlier in the year?

[Tom Ward:]

Sure. We drill so many wells, and we could always pick out three wells and make it look like that all of our wells are doing something phenomenal. But it's easier just to say, just to look at our production growth and see that, overall, we have steady production growth. So if you look at the types of wells we drill, they're going to have, basically, first-year declines in the 60%

[Brian Singer:]

Great.

[Operator:]

[Operator Instructions] Your next question comes from the line of Rhett Bruno.

[Rhett Bruno:]

Any updates on the Mississippi in horizontal oil play?

[Tom Ward:]

Sure. We continue to like the play. It's very early in the area. We have a nice acreage position, and we're evaluating it as the play develops a little bit. But it's just very early.

[Rhett Bruno:]

Is it still 115,000 or so acres?

[Tom Ward:]

Yes, we have a little bit more acreage than that.

[Rhett Bruno:]

Okay. And I might've missed this, but could you just give me a real quick breakdown of where the rigs are going to be drilling in the second half in the Permian?

[Tom Ward:]

The second half in the Permian. They move all around. We're really going just to state we have Permian type curve, because logistically, we’re completing three wells a day, and so they can be drilling in a number of places and be fairly impossible to keep up. Today, though, we can say that we have got everything in the Central Basin Platform with a rig in the Midland Basin and one in the Delaware Basin.

[Matthew Grubb:]

But the bulk of them will be on the Central Basin Platform, which would be Clear Fork in San Andres. That’ll be the bulk of your wells.

[Rhett Bruno:]

Okay. So if I’m trying to think of a generic type curve there, you had one, I don't know how long it's been, a month or two or six months ago, that was kind of a 30-day, first-month IP of maybe 130 barrels or so. Is that a good starting point?

[Tom Ward:]

You’re cutting out. Did you hear it, Matt?

[Matthew Grubb:]

No, I didn’t get that. Can you repeat?

[Rhett Bruno:]

Is this better?

[Tom Ward:]

Yes, yes. That’s great.

[Rhett Bruno:]

So I think you had a type curve several months ago in your presentation that was, I think it started a 30-day IP somewhere around 130 barrels. Is that a good starting point if we're thinking about kind of a generic Permian type curve?

[Matthew Grubb:]

No, I think that's high. For Permian, just all of Permian type curve, we're looking at, I think, less than 100 barrels a day. Let me make sure of that.

[Tom Ward:]

I think we're going to look at, basically, 70-some-odd thousand barrels of oil.

[Rhett Bruno:]

Okay.

[Tom Ward:]

And with spending in the $700-and-some-odd thousand. $730,000, and find about 75,000, 76,000 barrels. We are going to come out with a detailed type curve at the next conference we go to.

[Rhett Bruno:]

Okay, great.

[Operator:]

At this time, we have no further questions in the queue. I would like to turn the call back over to Mr. Tom Ward for closing remarks.

[Tom Ward:]

Well, as always, we thank you for your participation and your interest in SandRidge, and we'll talk to you again soon. Give us a call with any questions. Thank you.

[Operator:]

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.