SandRidge Energy Inc (SD) 2010 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to your Q2 2010 SandRidge Energy earnings conference call. My name is Denise, and I will be your event manager today. Throughout the conference, you will remain in listen-only.

(Operator Instructions)

Now I would like to hand the presentation over to your host for today's call, Mr Dirk Van Doren. Please proceed.

Thank you very much, Denise.

Last night the Company issued press release detailing SandRidge's financial and operating performance for the second quarter of 2010, and we will file our 10-Q on Monday. If you do no 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 in 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.

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 of 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 have been able to hedge over $2 billion in future revenues. As a result of our hedges, shallow drilling opportunities and certainty of reserves, we're able to implement a sustainable drilling program that will yield rates of return in excess of 50% on all 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 play. As you know, liquid rich often means natural gas liquids; while currently better than dry natural gas, they still sell at a 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 NGL market as compare to a contango in the crude oil market, making it very difficult to effectively hedge NGL prices.

We not only look for fewer oil plays, but have also focused on the central basin platform of the Permian Basin. We have now amassed over 200,000 net acres here in less than a year. This acreage position at values like large shale plays, currently getting JV attention, might be worth $10,000 per acre or $2 billion. However, we did 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 cost. Our plan was simple -- find an area with scale for growth, opportunities for high rates of return on drilling, low reservoir risk, and hedge and commodity prices to sustain that rate of return. We have achieved that goal.

SandRidge currently has 28 rigs drilling. We plan to reduce the gas rig count from eight current to five, and could further reduce as natural gas prices dictate. We will maintain 19 rigs drilling for oil.

Our 2010 CapEx will increase to $875 million from $800 million, incorporating the increased rig count from the Arena acquisition. We will spend about $125 million the remainder of this year drilling those wells, and installing associated facilities. As you can see, we would have had a decrease in CapEx if not for the Arena acquisition.

We maintain our production guidance at 120 Bcfe. That is, we project to produce 6.8 Bcf less gas than previously, but 7.2 Bcfe or 1.2 million barrels more of oil. The value per Mcf equivalent of oil is about 17 times that of gas today. We will generate $50 million more EBITDA with the gain in oil than loss of gas. This is a very clear example of the switch from gas to oil, with the focus on EBITDA growth. Assuming that we keep our rig count around the current level, we could reasonably expect our net oil production to approach 30,000 barrels per day at the end of the year, and see oil production increase by more than 30% next year.

We continue to look for ways to expand our oil footprint, and capital on the best margins. We also do not like competition, and feel very comfortable working in areas that others are not. Competition leads to higher costs. Two cases in point, our acreage costs and service costs in highly competitive plays. With regard to service costs, we have hedged both sides of our business, as we own a large amount of our services. SandRidge employs over 12,000 in West Texas, through our wholly-owned service company, Lariat Services. We have 33 drilling rigs, 30 pulling units, 81 pieces of dirt-moving equipment, and over 100 trucks to offset the higher costs of outside service providers, and maintain timely delivery of services.

We do not incorporate large, high-pressure frac procedures; therefore, we're not seeing lost time to bring wells on. In fact, we are completing three wells per day in the Permian basin. We also do not like to drill in highly populated areas, due to the higher costs and operational risks associated with those areas.

Our Pinon field in the West Texas Overthrust continues to be a premier natural gas asset. But the simple fact is that we make more money drying for oil today, and are fortunate to have oil or gas optionality that unique to SandRidge.

We also have drilled our third exploration well in the WTO, and will begin testing soon. We are fracking the upper sands in our Owens Well on the Magnolia Structure, and continue to believe we have potentially found a major gas build when the market comes back, to allow natural gas to be competitive with oil. We have also spud the fourth exploration well on a new structure 30 miles east of Pinon and south of the Magnolia Structure.

The Century Plant is mechanically complete, and should have gas flowing and performance testing this quarter. Our natural gas inventory is large, conventional, and less expensive to drill than new types of plays that are being developed today. However, we will remain patient until the natural gas market becomes competitive to oil, as we have no lease issues and control the proprietary seismic.

Lastly, we continue to look for additional assets to monetize, as we did with the $140 million deep rights over our Western Oklahoma leases. We have an established track record of monetizing noncore acreage, as evidenced from our Rockies acreage sale in 2008, our East Texas deep rights sale last year, our midstream assets in Pinon, and now our Western Oklahoma Woodford-Cana package. We have raised about $550 million from these sales. Once we closed transaction this month, we see potential to monetize another $300 million to $400 million of additional noncore asset sales in the next 12 to 18 months. We have also amassed a sizable acreage position in the Bone Springs play in the Delaware Basin to further evaluate.

I'll now turn the call over to Dirk for comments about the quarter's financial results.

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 are about $4 million of work-over 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 lift in costs, is very profitable because of the large percentage of oil production.

Second, G&A increased because of legal and professional expenses related to 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 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 LPM EBITDA would be north of $825 million, and please keep in mind for covenant purposes that number would be higher; and our debt to capital ratio improves to 66%, with the outstanding share count as of July 30th of 405.1 million shares, not including any preferred stock conversions. We will be filing an 8-K/A in late September, which will provide more detail on the pro forma financial statements of the Arena/SandRidge combination as of June 30th.

During our last call, we mentioned we had a goal $3 billion of revenue hedged from the second half of 2010 through 2013. For this time period we have over $2 billion hedged, with no gas hedges for -- from now through 2013, and we've added about 1.46 million barrels of crude in 2013. So we're well on our away 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 it focus further to oil drilling, as Tom mentioned. Lifting costs have increased, primarily due to higher expenses associated with the Company's shift to oil drilling, and increased work-over 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 noncash expenses, have increased to account for the Arena acquisition. And 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 Instructions) Your first question comes from the line of Dave Kistler. Please proceed, sir.

Hey, guys.

Good morning.

Real quickly, trying to tie a few pieces together, if I look at the reduced drilling activity in the Pinon, do I have to get concerned about your obligations as far as gas that you would be running through the Century Plant, and ultimately Oxy, realizing 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 the ultimate economic effect of that overall decision is, because running five rigs would lead me to believe 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?

The net/net to both of us is positive. Bringing on the Century Plant, we have 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.

But 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?

Sure. That's exactly it. If there are penalties -- 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 underdelivery of CO2 volumes, yet that is offset with efficiencies and tax credits, and we see it still as a net positive to our Company.

Okay, okay. Appreciate that.

I believe Oxy would say the efficiency gains are also -- and the tax credits are positive for them, but I can't talk for them.

Okay, I appreciate that clarification. And just, as long as we're looking at decreasing the rate count in the Pinon, 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 help me understand that, monetizing hedges strikes me as bullish thing to do, as sort of a call on gas; but cutting rig count, you know, makes me think that, you know, your view on gas longer term is a little bit suspect?

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 price is obviously at a place that it's -- 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, did not have hedges in place post-2010, but did feel 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, whenever we pulled some gas off in 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 there is still in the market today a perceived thought that gas supply will be higher than we think it will be end of October. We're more in the 3.75 to 3.76 TCF range. We think there's some constraints out of the Haynesville and maybe in the Marcellus, and that might not be end of the marketplace and -- 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 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 have not 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 in, I think, 2006. So it isn't something we do very often, but in the short term in both of these cases, we felt it was the appropriate thing to do. And that doesn't mean we won't be putting back on gas hedges by the end of the year.

And -- but I should think about the cutting of the rig count in the Pinon 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 --

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. That's kind of the parameters that we've had in the past for running gas rigs, and we're kind of 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.

Great, thank you for that. One last quick clarifying question. 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?

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, which -- diesel. And then pressure pumping, but as we described, we don't have the same type of pressure pumping needs the rest of the industry does, so we're able to get equipment. Matt?

Yes, Dave, I mean, we drill as well as -- pretty quick, you know, the bulk of our drill between four days and about nine days. We get off over to the Wolfberry and they are a little 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 would say probably in general when you look at fuel, you look at high-pressure pumping, mud, you know, wire line work, probably depending on which area and which type of well you drill, probably a third to half your cost is exposed to service costs.

However, out here in the Permian, 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 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 costs, we are locked in through the end of 2010, and we are working on longer-term high-pressure pumping, especially right now, we're work on longer-term agreements now, and I think costs will be very reasonable going forward, as I can see it today.

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

Great, guys. Well, thank you very much for all the additional details there.

Thank you. Next question.

Operator?

Your next question come from the line of Neal Dingmann. Please proceed, sir.

Good morning, guys. Tom, I was wondering if you could give us a little breakdown, 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 in regional?

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

Correct.

Okay, yes, we can do that. Our guidance for gas is basically 78 Bcf of gas production for 2010. I'll give you a breakdown, and tell you where we may be conservative there. In Pinon, Q2 2010 was the first quarter in awhile where we actually increased gas production. We started -- we drilled as high as 34 or 35 rigs in Pinon a couple of years ago, and production really ramped up quickly. As Tom mentioned, last September we went down to about four rigs, so we a had rapid decline, and we had a quarterly decline. But from Q1 to Q2, we had a slight increase from 115 million a day to about 118 million a day. With the ramp down in rig in the Pinon, we're projecting about 122 million a day in Q3 and Q4; the difference there is in a year when we're envisioning running ten rigs in Pinon, we were envisioning going from 115 million a day in Q1 to about 135 million or 136 million a day in Q4. So with the new guidance there, and with the new program, we're looking at about 43.5 Bcf of gas produced from Pinon.

East Texas, this is where I believe we are conservative. We ran a couple rigs in East Texas in Q1; because of 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 go on 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, in 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 on the Gulf Coast that -- these are water dry reservoirs; the water started to come in, so we had to choke them back pretty severely to maintain production. That's one well on 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 Breaks 165 platform, the other two Chevron operates but we have high interest, a 66% working interest. So the combined result of some well performance issues there were 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.

Mid-Continent, we expect 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 are 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 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-offs], et cetera, about 1.4 Bs, so that takes up to 78 Bs.

Okay. Go ahead, I'm sorry.

So anyway, I think where we are conservative, right now we're a little bit conservative in Pinon, I believe, in that we do have a compression project going on, where we are going to draw the field pressure down from -- 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. We've seen a 5% to 10% increase so far. And then in East Texas, I believe we're conservative there by 3 or 4 million a day. So I think the 78 Bcf is maybe a little bit light on the gas side.

Pretty confident on the Gulf Coast, Gulf of Mexico? The problems, are those past now, what do you think going forward on those?

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

What about over -- now that you have Arena, over there, the previous problems they had with some of the [case and head] gas and other infrastructure, have you already addressed that, and how quick can you ramp those properties up, much like you have over the [Forest] properties.

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 tight now, to look at options to have primary processes and secondary processes, so that we don't have down time. You know, Arena's production was really very flat. They produce about -- just from an oil standpoint, not counting any gas, 85% of production is 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. A lot of that had to do with not being able to move some of that gas, due to electrical or processing issues.

So we are 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 million, 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.

Got it. And one more, if I could. In the Perm, with your Forest properties, I assume most of the production is coming from that shallow or that San Andres formation. Are you also -- it sounded like, I had heard that you drilled some deeper wells, wonder if you will continue to do that, if you are having some success there with some of the deeper zones?

We are having some success. We are 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, the Fuhrman-Mascho Field, the San Andres is a very prolific zone. However, we are going 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.

So all active, how many wells have you drilled in the deeper zones, you think?

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, and is currently producing about 300 barrells 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 good zones, and these are all fairly shallow.

What we'll do is just come up with a [type curve] for the Permian Basin, because there's so many opportunities to drill from Bone Springs 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 drilling in the Bone Springs 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 much -- 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.

Great color, guys, thanks.

Thank you.

Your next question comes from the line of Scott Hanold. Please proceed.

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 that decision, I want to be clear -- was it a call that gas has bottomed in your Pinon, or was there some sense that you're just trying to capture some extra liquidity? And I guess the hedge position that you do put in your presentation, obviously, you know, is not the current one but, you know, you also took off some things, you know, post the quarter?

Yes, it was just -- in both cases, it's a call on gas bottoming in 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 little 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, so that was the reason we decided to make the call.

Okay. On the Permian, you know, I think you stated that you hope to grow that asset by, I believe you said 30% -- or was it total oil volumes by 30% next year. When you look at some of the infrastructure and logistical constraints in the field, 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 in early 2011?

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

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

You can get that on -- several of the reservoirs we drill for individually have those types of returns. In fact, higher than that.

Okay, so --

We just took an average of all of our locations across the Permian Basin.

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

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

Okay. Okay. And then one last thing, on the Century Plant, you know, 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?

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

There's no issues. The commissioning process of going through each [vessel] and each [pipe] is taking a little longer than we had planned. But, you know, we're -- the mechanical -- we have mechanical completion, and really we're just going through all the systems now, and that will take four to eight weeks. So we're projecting a start-up in the middle of September.

Okay, okay, and actually, one last question if I can, and maybe this is for Dirk. When you look at you -- you know, your revolver and your capacity, and your spending over the next 12 to 18 months, you know, how have your conversations with the rating agency and the banks regarding your revolver, how have those gone?

Sure. A couple of things. We have -- let's just take the rating agencies first. We see the rating agency 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, 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 to 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 the standpoint of getting better ratings. But I think the conversations with both of those groups have been excellent. We will see them again in the Fall in one of our usually scheduled meetings. So that's great.

As far as the banks go, you know that we re-did the revolver in April, and that was very good. We are adding in Arena. You may not have been aware, the banks have taken down their price decks across the board, so that will take cash flow away, PB away. Hedges, a lot of the banks roll forward six months, so they would go through 2010 and start using 2011. So many banks roll -- if you don't have hedges in 2011, 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. You know, we have done 7.8 million barrels in the last three months and we continue to have line at 17 of our counterparties. So overall, the credit markets -- if you paid attention to the high-yield market in the last two, three weeks, the thing's on fire. So credit is on fire right now. 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.

Do you all think the rating agencies may be concerned with you taking off the gas hedges at this point?

No, I spoke to them about it. That money was going to be coming in, in 2010; whether it came in June or it came 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 would make money. If we wait a few weeks, we'll probably make more money. So no, it's not an issue.

Thank you.

Your next question from the line of Amir Arif. Please proceed.

Good morning, guys. A few questions here. First, on the oil side, just to clarify, that 30% production growth potential that you're talking about, is that full-year 2011 over 2010, or is that pro forma your current production with Arena versus where you think you can be in a year from now?

Yes, pro forma with Arena.

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

Yes, projecting 19 rigs.

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

Yes.

Okay. And switching over to the gas side, any update -- you might not fill off Century Plant one, or you will have excess capacity; phase two third quarter 2011?

I think phase two is now looking out into 2012, in the first half of 2012.

2012, okay. And then you commented on the breakdown of the gas volumes a little bit. Just curious, just taking the Pinon count down from 8 to 5, will gas volumes -- will gas volumes be declining in 2011, if you don't increase the rig count from there?

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

Okay. Let me just ask it a little differently then. Previously when you went down to four or five rigs, production was declining in Pinon; has anything changed, where if you were at five rigs, production would be flat?

Matt, do you want to --

Production, like we say, it increased slightly from Q1 to Q2, and we project it to increase slightly from Q2 do 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.

I misspoke earlier, I said we were going to take pressure from 1,000 pound to 500 pounds; we're actually taking field pressure down to 200 pounds. So anyway, with the compression project and the wells that are waiting on completion, we should have an increase going forward this year.

Okay.

What we don't know is what, you know -- to look out too far ahead on gas production and give you guidance today, we just don't know how many rigs we'll have running there.

Fair enough. And then just a final question on the noncore asset sales that you've laid out, the $200 million to $400 million; is there any specific areas you're targeting for that?

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, the Delaware Basin, Bone Springs is an area that appears to have a lot of interest. The Wolfberry in the Midland Basin, both are less -- less attractive to us than the Central Basin Platform. And then we have a tremendous amount of acreage in Mid-Continent. So really, we could choose one of several places.

I think in your release, you laid out that will happen by the end of 2011, so I guess there's no rush in getting that done?

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.

Okay. Sounds good. Thanks, guys.

Thank you.

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

Hi, I got a pretty good flavor for when you were talking about activity in the Permian, but do you have a more specific kind of breakdown of the different play types you're in?

Sure. 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 in 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 Gold Smith Adobe, all of these fields join each other. It's just a tremendous area of oil production in the Central Basin Platform or the Permian Basin. And then as you move in the Delaware Basin, it's -- the Bone Springs is the main area of interest, and that's the Sandstone, and then the Central Basin Platform are [carvenants], and then as you move over to the East in the Midland Basin, you have the Spraberry and Wolfcamp, which are the Wolfberry, which is tight, silty sandstone.

How would your 18 rigs split out between the three?

They move back and forth. 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 is working in the Delaware Basin.

And the Central Basin Platform, is that infill drilling?

All areas are infill drilling.

Great. Thanks.

Thank you.

Your next question comes from the line of Jeff Robertson. Please proceed.

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

Yes.

I believe you said earlier that you all 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?

They came with their acquisitions. We have 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 the -- 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.

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

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

And then just one last question on the decline, Matt, you talked earlier about the decrease in drilling activity that you all started putting in place, I guess it's almost two years ago now. Have you gotten through -- 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?

Yes, that has a lot to do with it. It's getting through the flush part of all the wells that we drilled in 2008. You know, those wells probably declined 60% in the first year, and you know, you kind of have that again the second year, so we're getting through some of that. You know, we'll drill -- I mean, we have brand new wells that we drilled this year also but, you know, 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 ran here, and actually have a slight increase in production.

Lastly, Tom, can you talk about what your follow-up plans are on e the -- as far as exploration in the WTO might be, post some of the results you hope to have here later in third quarter?

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 the natural gas market will come back, whenever operators decide to move off gas some 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 no one else has. We don't have issues with what happened to [HPP] land at uneconomic prices. It just is -- we'll be patient with a great asset.

Thank you.

Thank you.

Your next question comes from the line of Philip Dodge. Please proceed.

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

Oh, I -- I don't know. We don't expect -- it's not -- it's not in, 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 scope of that play. Remember, it's all sweet gas, so even if we found a couple of Bcf per well, it will be the equivalent of drilling wells in Pinon. 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 it 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 -- really any production coming from exploration in 2011.

Okay. Just looking for forward-looking statement, I understand.

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

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

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

We're moving that. It's all a part of our Permian Basin activity so, yes, it is increasing. And yes, it is -- some of those -- it is more drill in the Perm also.

Okay. Thanks.

Thank you.

[Alan Jungworth] is on the line with your next question.

Good morning, guys.

Good morning.

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 without spending cash flow and drawing on the revolver?

Sure. I think I'll let Matt address the payback time. The way we look at this is that it's part of a process that not only do you drill the well, but you lock in future cash flow with hedges. So the two-pronged approach is that you are 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.

Yes, we're looking on average about two-year payback. You know, if you look at just --

Pretty aggressive --

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, each earning $2 million in revenue, you're spending $500,000. So it's kind of 4-to-1.

I don't know of many plays that will do that.

It's a very good program.

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 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 negotiation, conversation?

I'm not sure where you're going, but from a covenant calculation, we've turned our covenants down more than the terms with the Arena transaction. Our model sees no covenant issues out through 2013, so I'm not quite sure what you've got, but we're not even close to that.

Okay, so pro forma for the arena with the LPM EBITDA credit, is it -- that EBITDA is around 3.4?

Lower. Keep in mind, if you do the debt calculation, you have to read the covenants closely, how we can calculate Arena's EBITDA is not LPM, so we get a bigger bump. We're going to get $181 million to $200 million from Arena.

Okay. And so -- I think you addressed this, but the noncore asset sales, that's not Gulf of Mexico, the CO2 tertiary, that's more acreage that you could get a bigger bang for your buck for, I guess?

Sure. That doesn't mean that we wouldn't also look at having other sales that could have some production tied to it. It's easy to find $300 million to $400 million of just straight asset sales that do not have EBITDA tied to it.

Thank you, guys.

Thank you.

(Operator Instructions) Your next question comes from the line of [Evan Keene]. Please proceed. Your line is open. You may proceed with your question.

Can you hear me?

Oh, yes, we can.

I'm sorry about that. I was getting to the crude hedges. Just trying to find out if there is a level that you want to achieve as a percent of your total production for each year?

Very high rates of return at anything north of $80. The strip is giving us ample opportunity to hedge. We're not even close to being where we'd feel uncomfortable hedging.

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

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

Okay. Okay. Thank you.

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

Okay. All right, great. Thanks.

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

Thanks, good morning. A couple of questions, and apologies if they were asked earlier, but looks like from your $875 million capital budget, it would imply a run rate of about $225 million per quarter for the remainder of the year, and 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 lower run rate next year?

Run rate on -- sorry, run rate on --

Capital expenditures.

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

Yes, exactly. So if we take $225 million and plug through the remainder of the quarter, are we kind of looking at $900 million for -- or greater for next year?

I think we're very comfortable with $875 million we have right now is what we're looking at for next year. We haven't officially made that our -- I think, one we're -- we're thinking about 2011 being basically flat.

Got it, okay. And then I don't know that we heard it earlier, but can you speak to any specific Permian Basin wells that you've drilled, and what you're seeing in terms of decline rates from some of the wells you drilled earlier in the year?

Oh, sure. We drill so many wells, and what we can always pick out three wells and make it look like they're -- all of our wells are doing something phenomenal, but it's easier just to say -- 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%.

Great, thank you.

Thank you.

(Operations Instructions)

Your next question comes from the line of Rhett Bruno. Please proceed.

Hey, guys. Any updates on the Mississippi and the horizontal oil play?

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

Right. Is it still about 115,000 or so acres?

We have a little bit more acreage than that.

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

Second half in the Permian? They move all around. That's how come -- we're really going to look at -- to say we have a Permian-type curve, because logistically when you have -- we're completing three wells day, and so they could be drilling in a number of places, and it would be fairly impossible to keep up. Today, though, we can say that we have -- everything in the Central Basin Platform, with a rig in the Midland Basin and in the Delaware Basin.

The bulk of them will be on the Central Basin Platform, which will be Clear Fork and San Andres, that will be the bulk of your wells.

Right. Okay. So on -- if I'm trying to think of a generic-type curve, it's the one -- 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 still a good starting point?

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

I didn't get that. Can you repeat?

Is this better?

Yes, that's great. Thank you.

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

No. I think that's high, you know, for a Permian, just we're looking at less than 100 barrels per day. Let me make sure of that.

I think we're going to look at basically 70,000, 70,000-odd barrels a well.

Okay.

With spending in the $700,000-odd -- $730,000, and about 75,000, 76,000 barrels. We're going to come out with a detailed-type curve at the next conference we go to.

Okay, great, thanks.

Thank you.

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.

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

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