SandRidge Energy Inc (SD) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second quarter 2012 SandRidge Energy earnings conference call. My name is Pam, and I'll be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. James Bennett, Chief Financial Officer. Please proceed.

Thank you, Pamela. Welcome everyone, and thank you for joining us on our second quarter 2012 earnings call. This is James Bennett, Chief Financial Officer, and with us today, we have Tom Ward, Chairman and Chief Executive Officer; Matt Grubb, President and Chief Operating Officer; and Kevin White, Senior Vice President of Business Development.

Keep in mind that today's call will contain forward-looking statements and assumptions which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. Additionally, we'll make reference to adjusted net income, adjusted EBITDA, and other non-GAAP financial measures. A reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website.

Please note that this call is intended to discuss SandRidge Energy and not our royalty trusts. The trusts will be addressed on separate calls on August 10. Also, SandRidge will file its 10-Q on Monday, August 6. Now, let me turn the call over to Tom Ward.

Thank you, James. Welcome to our second quarter operational update. As you've read, we announced another very solid performance this quarter driven by the growth in oil production. The key themes I will discuss this morning that differentiate SandRidge are as follows -- low-risk shallow carbonate drilling with low costs, willingness to lock in future profits through hedging, and our increasing balance sheet strength. The SandRidge management team has operated differently than most of our peers over the last few years. We built our foundation on shallow, conventional, low-risk oil assets.

The Central Basin Platform in the Permian Basin is a good example. In 2008, we produced 4,000 barrel of oil equivalent per day from this area, and today, we produce over 30,000 net barrel of oil equivalent per day from shallow carbonate vertical wells. The Central Basin Platform continues to provide repeatable, low-risk, high rate of return drilling opportunities. Even though the wells only average 53 barrels of oil equivalent per day during the 30-day peak period, the low cost associated with the drilling and completion of these wells makes them very attractive investments and an efficient use of capital. By buying in an area with a long history of production, we not only lowered our drilling risk, but also do not have the issues with takeaway capacity as others experienced in newer, more crowded areas of the Permian. This last quarter, we drilled 206 Central Basin Platform wells and plan to continue with this program into the future and maintain a ten-year inventory of drilling locations.

The Gulf of Mexico properties we acquired this year have gotten off to a good start. The integration of DOR has been smooth, and production has been in line with our expectations through the second quarter. We do not plan to risk capital exploring for large new fields, but exploit existing properties and generate high rates of return through re-completions and infield drilling to help us fulfill our three-year goals. We were able to capitalize on a region of cheap oil with this acquisition, and it gave us a platform with a great operating team to further exploit inexpensive oil at a time of dislocation in the marketplace. Not only did we buy inexpensive oil, we're now able to sell expensive oil. As of August 1, the LLS mark was positive $18.75 per barrel over WTI. Plus the acquisition of the Gulf of Mexico properties lowered our debt ratio a full turn and gives us more debt capacity to stay within our goal of approximately three times leverage. We continue to feel comfortable we can maintain our 25,000 barrel of oil equivalent per day production rate by spending $200 million of CapEx on drilling and re-completions.

The Mississippian continues to be our growth engine. Last quarter, we drilled 91 horizontal wells, and our production continues to meet or beat our expectations. This play also is a shallow, low-risk, carbonate reservoir where production per well on a 30-day rate has continued to improve over time. The value driver of the horizontal Mississippian play is the ability to consistently drill thousands of high rate of return oil wells over hundreds of miles. It's a story of scale. Our team has assembled 1.7 million net acres with room to drill more than 8,000 horizontal wells, and now nearly 50% of that acreage has been proven by the 872 horizontal wells that have been drilled. Each quarter, we become more convinced in the size and scope of the play.

SandRidge has now drilled 382 producing wells across the original acreage we put together from 2007 to 2011 and we are seeing consistent results from Comanche County, Kansas through Grant County, Oklahoma. This covers an area of more than 150 miles, and an area where we have nearly 850,000 net acres -- or a ten-year inventory at today's rig count at only three wells per section. We also have optimism about our extension acreage in western Kansas where we control nearly 900,000 net acres and where they have been more than 7,000 vertical Mississippian producers drilled. We are now drilling oil wells in the extension portion of the play with three rigs and will know more about the results by the end of this year.

The second quarter was very good from a production standpoint. It seems that every operator believes investors only care about the large producers in each field. We do continue to have high initial production wells, but that's not the driver behind our growth. For example, we mention in the press release that during the second quarter, we completed five Mississippian wells that produced more than 1,000 barrels of oil equivalent for 30 days. They actually averaged 2,000 barrels a day. However, it's more important to note that we completed 90 wells that drove our production increase. We do not rely on the 1,000 barrels of oil equivalent or greater wells to meet our expectations.

We drilled 21 wells during the last quarter that had greater than 1,000 barrels of oil a day equivalent of production for 24 hours. But, that really doesn't mean anything. What is important is that we can grow our oil production by more than 50% and our total production by 40% this year and continue to drill low risk type curve wells for years to come. Plus, we have the opportunity to realize lower costs going forward as our drilling efficiencies continue to improve as we've front-loaded our saltwater disposal system and electrical facilities. During the last year in the Mississippian, we drilled only 30% of our locations as PUDs. This trend continued through the second quarter. We've invested heavily into the future by building our electrical infrastructure and water disposal systems ahead of our development drilling. The Mississippian play is built on a firm foundation.

I've discussed the low-risk nature of our reservoirs, but we've also moved to a strategy of lower balance sheet risk during the last few years. In 2008, we produced 95% by volume natural gas. Today, we produce 56% by volume oil and 91% of our reserve value comes from oil. We also have mitigated balance sheet risk with our oil hedges. We've hedged 15 million barrels of oil in 2012. We're about 83% of our projected volumes at just over $100 per barrel. We've also hedged 18.5 million barrels in 2013 at $96.24 per barrel and have started adding to our 2014 hedge book with 13.4 million barrels hedged. We've even hedged five million barrels of oil in 2015. It's much more important for us to be in a position to manage any problem that may result from a global recession and continue to generate high rates of return than hold out for an additional $10 per barrel.

Our business is such that we plan ahead by at least six months. We should not have the uncertainty of short-term pricing to make our long-term decisions although some of the moves we've made over the last few years have surprised some. Strategically, they've been intentional. First, we bought producing oil assets in a geographically concentrated area, generating cash flow with significant further development potential. Next, we began leasing undeveloped oily acreage, and different than most, leasing in only one play, the Mississippian. We did buy a large acreage position but have already raised nearly $2 billion more than our cost basis from the sale of only a portion of this leasehold. Even after the sales, we have over a decade of future drilling. Our growth engine continues to be the Mississippian formation in Kansas and in Oklahoma, and we do not anticipate having another large acreage play in our near future. In our two core areas, we're the most active driller and among the largest producers and acreage holders. This concentration is deliberate. It results in SandRidge being the most cost-efficient operator in our core areas which is different than many of our peers who operate across many different plays. SandRidge is now looking forward to continue to build upon the solid foundation that we started establishing several years ago.

Changing to an oil company wasn't easy. But by strategically acquiring EBITDA and carefully choosing our acreage play, we've accomplished what we set out to do. We have been consistent with our three-year goal of having EBITDA above $2 billion, drill within cash flow, and improve our credit metrics to below three times. When that is achieved, we will have become a mature Company that can slow down our growth targets and look opportunistically for acquisitions using debt and equity. However, in the meantime, we look forward to continued growth as we develop our core, low-risk assets. I'll now turn the call over to James.

Thank you, Tom. We had a strong second quarter with continued growth in oil production, reduction in our leverage, proven in liquidity, and beating consensus estimates across all categories. For the second quarter, adjusted net income was $37 million, or $0.07 per diluted share. Adjusted EBITDA was $269 million, and operating cash flow was $222 million, or $0.40 per diluted share. Second quarter adjusted EBITDA is up 72% over the comparable 2011 period driven by the Dynamic Offshore Resources acquisition and continued organic growth in oil production.

Production for the quarter averaged 90.2 thousand barrels of oil equivalent per day, a 36% increase over first quarter production and 45% increase over the comparable 2011 period. Recall that in the second quarter of this year, we closed the acquisition of Dynamic, so for the quarterly reporting period, the acquisition contributed a little over two months to our consolidated numbers. Excluding the impact of Dynamic, which accounted for about 1.8 million barrels of oil equivalent in the quarter, our base production grew 6% over the first quarter 2012 and 14% over the comparable 2011 period. This was driven primarily by the Mississippian which averaged production of 20,000 -- 25,200 barrels of oil equivalent in the second quarter, up from an average of 19,300 in the first quarter.

On per unit measures, LOE per BOE increase is expected due the inclusion of the Dynamic Offshore Properties. However, at just under $15 per barrel, LOE was below the low end of our 2012 guidance range due to a continued focus on field level expenses such as a reduction in produced water hauling and down hole pump repairs. Excluding the Offshore Properties, our recently divested tertiary assets, second quarter LOE decreased to $12.42 per BOE, down from $13.19 the first quarter of 2012 and $13.24 in the second quarter of '11. As a result, we're lowering the midpoint of our full-year LOE guidance by 6%, to $16 per BOE.

In terms of other per unit costs, G&A of $7.52 per BOE was above our guidance range, but includes just under $12 million of expensed, one-time transaction costs associated with the Dynamic acquisition, our royalty trust IPO, and tertiary divestiture. DD&A per BOE of $17.95, just over the high end of our previous guidance as a result of the inclusion of the Dynamic assets and the impact of non-core asset divestitures in 2012.

CapEx for the quarter was $562 million, down slightly from $570 million in the first quarter. 80% of the quarter's CapEx was on drilling and production for our E&P operations, concentrated in the Mississippian and Permian. We've slowed our land purchases since the first quarter and anticipate spending little on new leaseholds in the remainder of year. Regarding 2012 CapEx guidance, we're increasing our estimate for full-year's CapEx to $2.1 billion, up from $1.85 billion, primarily due to increased facility cost in the Mississippian and Permian and leasehold acquisition costs.

At June 30, total debt was $3.55 billion, and net debt was $3.1 billion, giving us a quarter-end leverage of 2.9 times. Long-term debt consists entirely of senior unsecured notes with maturities ranging from 2014 to 2022, and only one $350 million maturity within the next four years. Our liquidity is excellent at $1.3 billion as of July 31, consisting of a fully undrawn $1 billion revolving credit facility that matures in 2017 and $300 million in cash. In terms of funding our capital program, this $1.3 billion of liquidity, combined with cash flow from operations, is more than sufficient to fund our remaining 2012 capital budget and could take us well into 2013.

Regarding funding our 2013 capital program, we've not yet come out with formal guidance, but estimate our 2013 capital expenditure budget will be approximately $2 billion. Using a $2 billion spending level, current leverage of just under three times and growing EBITDA, we can comfortably fund our 2013 capital plan with cash flow from operations, current liquidity, and additional debt. Also, as alternatives to debt funding, other sources of capital available to us includes sales of existing royalty trust units, possible JVs or additional Mississippian acreage, and non-core asset sales. As an example, in the second quarter, we raised $155 million through the sale of a non-core tertiary asset in West Texas and the sale of some of our common units in SandRidge Mississippian Trust I. In summary, the effort to fill our funding gap for growth is starting to ease. Our Company continues to mature, and we are on our way to funding within cash flow as stated in our three-year objectives.

On page 8 of our earnings release, we have outlined updated guidance for 2012. We increased production guidance by 700,000 BOE to $33 million to reflect current year acquisitions, divestitures, and better than expected performance from the Company's core assets. This production level represents total equivalent growth of 41% over 2011 and oil growth of 54%. As I mentioned, we reduced Lifting cost guidance by 6%. Oil and gas DD&A rate increase by $0.60 at the midpoint of the range due to changes in the depletion rate as a result of the Dynamic acquisition and the sale of Company's tertiary assets. G&A projections have increased to include transaction costs I discussed earlier. EBITDA from oilfield services, midstream, and other increased to reflect improved drilling profit margins and higher third party working interest for wells drilled by our own Lariat rigs.

In the earnings release, we have updated our hedge position through 2015. The downside protection of these hedges was apparent in the second quarter where we had contractual maturities of our hedges totaling gains of $32 million and adding over $4 per barrel to our realized price. For the remainder of 2012, we have just over 80% of our guidance oil and natural gas production hedged, and from 2013 to 2015, have an additional 37 million barrels of oil hedged. We had been and continue to be aggressive users of hedges to protect ourselves from contractions in commodity prices, and we have one the most hedged positions among our peers.

One final note on royalty trust, in effort to assist the reconciliation from our financial statements back to our guidance, we added a new table in our earnings release. The table labeled net income attributable to non-controlling interest on page 12 takes the non-controlling interest, or NCI, from the income statement and adjusts for unrealized, non-cash hedging gains or losses to arrive at an adjusted NCI. This adjusted NCI is consistent with how we guide the trust's earnings. As similar to earnings per share, we don't project non-cash, unrealized, mark-to-market hedging gains or losses. This concludes Management's prepared remarks. Pamela, please open the line for questions.

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

Good morning. Tom, first quick question. Wondering how much you can say, Tom, on the new production guidance? Obviously, most of that is related to gas. Is there anything we can insinuate as far as what that means for the new horizontal miss? Are you assuming that's going to be a bit gassier? So, maybe my question is, if you could comment on the make-up -- your expectations of the new horizontal miss versus the original?

You're saying the new horizontal miss being the extension area?

Yes, sir.

No, that has nothing to do with our guidance on -- we are not projecting extension acreage in our guidance.

Okay. And then, just wondering on that guidance -- after having, obviously, the big second quarter as far as total production. Maybe a little bit surprised, I guess, you didn't increase overall guidance. Is there -- maybe if you could talk about in that guidance assumption for the production, if you could break that down a little bit? What type of growth you're assuming between the three areas -- the horizontal miss, Perm, and the offshore?

Yes, let me take that. Hey Neal, this is Matt Grubb.

Yes, sir.

Give you a little more detail on the guidance -- how we came to that. First of all, our new guidance on paper didn't look like we increased oil production, but in truth, we did sell a couple hundred thousand barrels of oil in our Tertiary sales and didn't move that oil guidance down. There's growth in there in that's embedded that may not be obvious in the guidance.

We did have a very good second quarter. A number of positive of things happened for SandRidge in the second quarter, and if we just for a minute ignore our DOR acquisition, Hunt acquisition, and just look at organic growth, we still had 6% growth quarter-over-quarter from second quarter up to first quarter. And, if we continue to ignore DOR and ignore Hunt, and then pro forma the sale of Tertiary -- year-over-year, we would have organic growth of about 14%. So, if all those things are very strongly when you put in Hunt and DOR back in, and take out the Tertiary for the rest of the year, I think it's still about 38%, 39%, 40% growth. But, if you just look at a little bit more detail from Q1 to Q2, in Q1, we averaged about 66.5 thousand barrels of equivalent per day. Of course, we had acquisitions come in Q2. We took over Dynamic about the middle of April, and then we closed on a little Hunt acquisition, I think around June 20. Then, we sold Tertiary June 1. So, adjusting for all those numbers, we averaged about 90,000 a day in Q2. So, big move as a result of the acquisitions.

However, as Tom mentioned earlier in his spiel, we had a number of wells in the Miss that performed very well. We had five that was making a couple thousand of barrels a day for the first 30 days. We bought Hunt. When we bought Hunt, we modelled that coming in at 3,000 barrels a day. There was some pipelines and some platform that are shut down. It actually -- when we close, it actually was making probably about 2,500, 2,600 barrels a day. We got production back on since then, and it's you up -- 3,500, 3,600, 3,700. So, we think there's some flush production there that's going to come off, back down to our production.

And then, DOR is doing slightly better than we modeled even. We modeled 25,000 flat for the year. Certainly with 10% for hurricane risk for all of our Gulf of Mexico for June -- I'm sorry, in July, August, and September. The Gulf of Mexico now with Hunt, with Dynamic, and our legacy Gulf of Mexico, that represents probably 28%, 29% of our total production. When you put a 10% risk in there going forward, essentially for Q3, that does impact your guidance. And so, when you see in our public slides of [104], I say that's a pretty big move up from the [90] that we averaged in Q2. And, as a result of this, some of that flush production and some of the big wells we saw. But going forward, we don't model those big wells in. We don't know when we're going to hit them. We model our tight curve. With declines on those big wells with some of this flush production coming off, we could see August maybe even slightly down below from July. July -- I don't have the initial numbers yet, but we'll probably be in that [103, 104] range.

So, with some production coming off in August, we might be down around high [90s] to low [100s]. Then, we start ramping up again the rest of the year. As we get through August and we get through September, and we don't have any hurricanes, I think there's a chance, we might up our guidance in Q3. We'll have to wait and see. But, that's the reason for the guidance. Because of all the positive things that happened really in the last 45, 60 days, if we are going to err on our guidance -- we want to err on the conservative side.

Great color, Matt. Last question, if I could, Matt, for either you or Tom. Just wondering on the new lifting guidance if you could just maybe comment around what you're seeing as far as we well costs in the Horizontal Miss for both the original and then into the newer area? Including the water parts of it?

Yes, are you asking specifically about CapEx or LOE?

More about LOE, just if you can talk about your tight curve for the Horizontal Miss now? (Inaudible) obviously the EURs may be going up a little. Just wondering what you're thinking average cost would come out at?

Well, LOE -- we guided down our LOE to a midpoint of about $16 there from $16.80 or so. And, one of things -- one of the reasons our CapEx went up this year is because we are accelerating some projects to reduce LOE. LOE reduction doesn't come free, but long-term, it's the right thing to do. So we sell at some large disposal facilities, drilling disposal wells, and so on.

But, the LOE guys, one of our big folks in the Company -- the major components that drive LOE for this Company is water handling is number one, and then compression is probably number two. We have a lot of gas lift compressors we're running, and then of course, you have your gathering expenses and so on. But, we're moving today probably a little over 500,000 barrels of water in the Miss, and we're only trucking about 3% of that. From the high this year, we were probably -- we probably have reduced our trucking volume by about 15,000, 20,000 barrels a day. All that works into reducing the LOE to our new guidance as you see it.

So, going forward, I think LOE will continue to go down because as we -- as these wells, we have 380, 390 wells producing now in the Miss. They decline. The water production will decline with it, and so as with the acceleration of the infrastructure to move this water, we can continue to add more and more water from new wells into existing infrastructures. That would drive down both LOE and CapEx from the infrastructure standpoint.

Thanks, Matt.

And Neal, just to clarify your question to me. In the extension Miss, we would not plan on having a high gas amount in those wells because the vertical wells were nearly all oil. So, just based on vertical wells, you wouldn't expect as much as gas in the extension.

Your next question comes from the line of Dave Kistler with Simmons & Company. Please proceed.

Morning.

Morning.

Looking at your oil production numbers where you incorporate NGLs in that number, can you kind of break out for us what percentage of that production is NGLs?

Yes. We're running about 11% NGL in our total liquids so 89% crude oil.

And, that was down from 13% in the first quarter.

Is the driver of that being down primarily the Dynamic acquisition? Because I would imagine the Mississippian line production going up would actually be adding NGL production.

No.

I'm sorry. It's actually from the Mississippi line production going up. Because in the Mississippi line, we're not booking NGL volumes. We have a little upgrade on the gas side, but this is a crude oil. As we continue to drill Mississippi line and develop that and oil production continues to increase in the Mississippi line, it will begin to drive down NGL. Most of our -- 85%, 90% of our NGL comes from the Permian Basin, and the Mississippi is going to out grow the Permian. So, your NGLs will continue to go down slightly.

Okay. That's helpful color. I appreciate that. And then, just thinking about these five wells that you put on-line that were about 2,000 barrels of oil equivalent a day on a 30-day rate. Can you talk a little bit about what you're seeing that's leading to that variability? Has there been any more science to identify areas where you're having those kinds of impacts? Anything new since last quarter in terms of what you've learned about those wells?

No, you're just going to have a few percent of your wells are going to be extraordinary. And, what the industry does is really focus on the few percent of wells that produce very high volumes, and not the total wells that all of us drill. So, we will dry high volume wells especially when you hit a nice permeability streak, and you have good storage capacity in a location, and they'll come on a very high rate. That's nothing new to this play or any other play that I've ever been associated with. It's just that over the years, we've come more to rely on a single 24-hour IP or a 30-day IP of one particular well rather than a play.

What we're trying to do is to get you to focus on a play that's going to cover hundreds of miles in size and scale, and that you don't need to have 1,000 or 2,000 barrels a day in order to build a company. And, that's where the real focus is -- is that from Comanche County, Kansas, which hasn't had any wells that produced 1,000 barrels a day for 30-day average --, is still a fantastic county to drill oil wells in. And, even though -- and these five wells we drilled were in three separate counties. If you look at the 21 wells we drilled, we're across -- we're scattered across -- that have the 24-hour rate. Were scattered across all the counties we drill in. So, it's more of a geological work within each county and each township to understand the best places to drill. And, that's what we'll continue to do.

Okay. That's helpful. And then, you made a comment that your rig count would stay in the Mississippi line at 33 rigs. If I recall correctly, you were looking at ramping to as many as 40 rigs over the next year or so --?

That's through 2013.

Okay. As we think about that, obviously efficiencies are allowing you to drill as many wells. With 1.7 million acres, if you're running 33 rigs or ultimately going to 40, can you hold all that acreage by production? Or, does that kind of force a hand for selling a portion of that down? Or, doing a JV to accelerate activity?

We can hold that. We're projecting to have -- or have projected to have 45 rigs by the end of '13 which would let us hold all of our acreage. I don't know that we will drill every acre we have, but it is still -- and it doesn't mean that we wouldn't sell down further into the next year. But, that would be more just a decision on how we want to use capital.

Okay. One more follow-up, just on that if I can. If you're moving to 45 rigs in '13 yet you make a statement of keeping the CapEx kind of around $2 billion, how do those two tie together? Especially when you're having the kind of efficiency gains that you've witnessed year-to-date?

Yes, if we have -- continue to have efficiency gains, you obviously don't have to have as many rigs to spend the same amount of money. So, it is more around a capital requirement for us than how many rigs. There's nothing magical about having 45 rigs versus 40 rigs versus 35 rigs if we can drill the same amount of rigs.

Okay. I appreciate the color. Thank you very much.

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

Yes. Tom, in passing, you mentioned the percentage of wells that were PUDs. Can you walk us through that a little bit? Just clarify what you meant, and how we might interpret that when we think about reserves bookings later in the year?

Sure, whenever we drill -- the wells that we're drilling only about 30% of those have already been booked as PUDs. So, there will be additional wells that are being drilled that will have offsets to them that we'll be bringing on as proven undeveloped producers this year.

All right. That's helpful. And then, on the CapEx for infrastructure, can you tell us a little bit about the specifics, are we talking about tanks and roads and stuff or what exactly is it?

Yes, for CapEx infrastructure it's really primarily saltwater disposal well facilities. Because what Tom -- what you just talked about and what Tom just talked about only our wells -- 30% of those wells are PUDs. That means we're out drilling locations that aren't offsetting existing locations, right? So, as we drill these step-out wells, we're having to lay longer lines. And then also, you have electrical infrastructure that we're building to install our sub pumps. That's the infrastructure we're talking about.

So, as we go to -- as we ended 2011 last year, our producer to saltwater disposal ratio was four -- a little over four to one. As we end this year, we should be five to one. But, next year, our program should be more stepping back in to existing infrastructure. That's part of our acceleration of the infrastructure. You spend money now, you spend it next year. But, we chose to spend it now so we can step out hole acreage and then go back in and fill in some of these area. Next year, we're looking at drilling maybe 600 horizontal wells, and probably we'll drill 70 disposal wells this year and, say, 50 next year. Then, your ratio is going to bounce up to about 6.5 to seven. So, we said all along that once this play developed we should be around 10 to one. So, we're moving toward being more efficient every year as we drill out this play.

Okay. That's good. And then, in the second quarter, I don't think there was a Gulf of Mexico well drilled, and I just was wondering if you can give us any idea on how you're integrating the new properties? And, if that's changed your -- those people's drilling schedule versus when you bought it?

You know, no. The CapEx stays essentially the same. We do have a review on what we drill down there, and the timing and the projects move around a little bit. We had one guy here that we transferred down to head up that asset development part of the program. So, yes, there's some movements, but we still expect to spend $200 million this year in DOR and probably drill ten wells and participate in another three or four non-op wells.

Great. Thank you very much.

Thank you.

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

Good morning. Just a follow-up question on the CapEx increase. The accelerated infrastructure for saltwater disposal [and electrical], is that different from what you were thinking at the start of the year? Or, is it simply costing more? Or, are you just building up more for '13?

Yes, it's different. It's not costing more. When you're running this many rigs, you come up with a plan of how many wells you drill. But then, once you get down to actually drilling the wells, it depends on permits, selling damages, where do you get right away for pipe, for electrical, certain things. So, those things tend to move the schedule around a little bit. But also, we probably drill -- with the success of this Miss, we do have a lot of acreage, and as we gain more and more success through the drilling -- gain more and more confidence, we start drilling more step-out wells in the [mid]. So, that part of it probably changed a little bit, and you add all those things together, it did add up to more infrastructure cost for us this year.

Sure. We could, if we chose to, drill more infield wells and not spend as much as on facilities. But, if the play's going to work, you are going to have to build out facilities at some point. The way we look at this is that if new areas are working just the same as the original area, you might as well be building out facilities to get to those wells now.

Okay. I noticed your IPs are getting better. I think last year, it was 275 barrels, now you're averaging 325 barrels. Do you have an updated EUR number that you would assign to the wells on average?

No, we'll do that at the end of year.

So, you're still -- I think it's 450 barrels still the number you've got out there, is that right?

Yes, it's 456 barrels.

That's based off the 275 barrels though, isn't it?

275 barrels on a 30-day IP.

Okay. I know, previously, you were thinking about potentially selling another 250,000 acres in the play, is that still a thought? Or, has that changed?

Well, we don't want to sell any more original acreage at least today, and we have about 855,000 acres in the original play. We feel we have ample capacity to move forward into '13, and maybe even through '13 with other ways of financing. So, we don't have to sell any acreage. In the extension area, until we get through the end of the year and see how the wells are and how they compare to the original, I think there's probably two big of a bid-and-ask right now. So, I think it would be into next year before we really review selling down additional acreage in the extension area. And, it might prove out to be that we want to keep it all. It's just -- we have many options that we can look at right now.

In 2013 (inaudible). Just one final question. I know Tom, you answered that you wanted to view this play more as a large play, repeatable. But, just focusing on those 1,000-plus barrels a day wells -- three counties. Can you tell us what counties they are? Are they contiguous, or are they spread around.

Sure. Alfalfa County, Oklahoma, Grant County, Oklahoma, and Harper County, Kansas.

Okay. Thanks, Tom.

The next question comes from the line of Craig Shere with Tuohy Brothers. Please proceed.

Hi. Congratulations on a good quarter.

Thanks.

A couple quickies and then a little more fundamental question. The three rigs drilling now in the extension Miss, can you comment on where they're drilling?

We have given presentations in the past that show where the areas are, but I've said we've drilled so far in Ford, Gray, Finney, Hodgeman, Ness.

And, picking up on Neal's LOE question, Matt? Is the CO2 fee payment delay, in fact, a delay or a cessation due to qualification for offsetting CO2 tax credits?

No, it's just delayed. There's a -- we have certain terms in our agreement with Oxy, and we have to get the plant tested, get everything, basically all the components run to their satisfaction. But, we're real close on that. We expect to turn that over to them here soon. We probably will have a shortfall penalty, probably kicking in starting into Q4 this year.

Okay. James, I don't know if you have any feedback on the prospect for offsetting that with tax credits?

Yes, we're going to. We'll recognize the expense in the fourth quarter this year. We think there's a chance we ultimately offset it with tax credits, but we're not baking that into the numbers now, and that won't be determined for some time from now.

So, that would be a 2013 event?

2013 or even '14. It's not something that we're baking into our guidance right now.

I got you. Tom, the market is up. Oil is up. You had a good quarter that beat consensus. Mississippian was terrific. SandRidge's shares are down, and there's a couple of things I'd note. One is just optical. That despite the fact that you effectively raised oil guidance, optically, it appeared ignoring the Tertiary divestiture to be flat. You are front-loading your infrastructure expense. That wasn't immediately apparent, but even apart from that -- I think there's a -- that's just a comment, but there's a question in here.

In your February slide deck, and I think there's some concerns about the logic behind some of the more recent moves. In your February slide deck, you had a sum of the parts value of about $690 million for the PV-10 on the Tertiary oil recovery play. That was later sold for about [$130 million]. And then, you had a $50 million bolt-on in the Gulf of Mexico, and now you're raising 2012 CapEx by another $250 million. Can you discuss the thinking behind these more recent moves and the relative value of divestitures versus your development activities?

Sure. I think first thing on your comment that we have to make long-term decisions to run a Company that can't really focus on one day's price movement in our stock. And, if we continue to build the Company on the core areas that we have in the Permian and the Mississippian, that all will take care of itself. Especially if we hedge in the volumes like we're doing.

With regard to the Tertiary, we feel like we made a good sale on a cash flow basis. Yes, there's a tremendous amount of reserves there, but they come in over a very long period of time. You have to have access to CO2 which is fairly tight in the Permian Basin. Then, the other area was -- oh, the bolt-on acquisition. You're buying assets for under two times cash flow and putting that assets -- and then putting that to work on drilling long-term producing assets in the Mississippian. I just think it was a good trade.

Understood. So, ultimately, probably the market's greatest concern is when do we finally get our arms around CapEx to the degree that we don't keep seeing inflation in CapEx and acquisitions on a net basis? And, we feel like we're really comfortably getting our arms around that on a go-forward basis? I guess the question is, are you confident that $2 billion in CapEx roughly is about as high as we're going to have to be going on a go-forward basis?

That's always been our goal. We have said $1.85 billion to $2.1 billion when we came out with our three-year plan in 2011. The goal of the Company is to be able to fund an aggressive drilling program and have that all within cash flow at the end of 2014. And, I don't think there's any change to that. Well, there isn't any change to that. That as long as we can fund a $2 billion CapEx program and grow like we're growing, then I don't see that there's any issue. Now, it seems to me that you're concerned that we won't be able to fund it, and I just, I don't think that's -- I think that you'll be able to see even by the end of this year that we'll have 2013 funded.

Understood. I appreciate it, and it was a good quarter. Congratulations.

Thank you.

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

Thanks, good morning.

Good morning.

I know you are probably not prepared to talk about any of the results up in Kansas quite yet until you've got a statistically comfortable sample to talk about. But, can you say just in general from the wells that you have drilled. You said they're encouraging, can you provide a little bit more context around that relative to your core asset? Or, some of the verticals historically there? Or, just some kind of color on that?

Well, we drilled 50 wells in Kansas that have basically exactly the same production as in Oklahoma. Now, as you get up into the extension portion, which is one set of counties north of the southern counties, which are -- in the original would be that we've drilled in are Harper, Barber, and Comanche. As you go further north, we have just now started drilling in those counties. First wells were 80 miles north of existing horizontal wells, and we're comfortable with the extension play because there's so many vertical wells that have been drilled, and they produce oil and we're in an oil system. So, the same types of rocks -- the same type of geology. That's what make us comfortable, and you know we're seeing oil. So that's all the color we're going to give because we will drill good wells, and we'll drill poor wells. In the next few months, we'll have enough of a dataset to be able to say if these counties, early on, are as good as the counties to the south.

Is there any -- when you sit back and look at the geology and the depth pressures, differences between what you have in more of the core [inner salt seeing] areas versus more the north area? Would you suspect it's going to have more oil, less pressure? Is it [shallower]? Is there some general context you can set an expectation on?

What we said is that the wells have a higher oil content than the wells in the original area.

Okay. Fair enough. When you step back and you look at the infrastructure, the permitting process in Kansas versus Oklahoma. Is there going to be a little bit of a higher need there? Is the infrastructure going to be -- need to come up to speed quite a bit if you start to get more aggressive in some of your newer acreage?

Should be the same. Kansas is a very easy place to operate in.

Okay. And finally, just on the CapEx summary. Just so I'm clear, and maybe you've talked around it. I just can't figure it out here. To be more direct, it looks like you pulled forward some CapEx into 2012 from potentially 2013 and maybe even beyond that because of higher -- better results and your high activity. If I were just looking at it, you talked about potentially $2 billion-ish in 2013. Wouldn't that number have been higher if not spending that CapEx this year, is it really pulling it forward say from '13 into '12?

Yes. When we talk about CapEx and funding gap, I think we need to talk a little bit longer than just a snapshot of this year. Things we're doing right now is going to reduce what we have to do next year and the year after and so on to develop this Mississippian play. So, yes, I think we're going to be -- we're at $2.1 billion this year, and we're going to be around -- it's too early for me to say exactly what the guidance is going to be for next year. But, we're looking at probably $2 billion. It's going to be a little bit less than this year.

One thing though is we're done with our land spending. Land and seismic this year, we're probably looking at $200 million, and part of that is seismic. A big chunk of that was just licensing coming over from the Gulf of Mexico acquisitions. And then, the land we're done with our land acquisition. So, that alone there is enough to reduce CapEx. So, yes, that and the infrastructure build-out we're doing -- I think all those things work to reduce CapEx going forward.

Okay, thanks.

Your next question comes from the line of Joe Allman with JPMorgan. Please proceed.

Thank you. Hi, everybody.

Hi.

Hey, Tom, I know James gave the list of events that could help reduce the funding gap. So, what are the next events, say between now and year-end? Monetizations or raising external funds that could help reduce the funding gap

Joe, we've got $1 billion -- at quarter-end, we had $1.421 billion liquidity. Right now, we've got a $1.3 billion. That comfortably takes us through the end of the year and into next year. I don't think we can comment on specific transactions. You've seen us be very active year-to-date and selling on core assets. Selling royalty trust units. We'll continue to look at those, but I don't think we can comment on specifically what those other sources will be between now and the end of the year.

Okay. Got you. Okay. I've got a question on oil acquisition. I'm wondering how that fits into the Gulf of Mexico budget. Your budget on an annual basis is $200 million for the Gulf of Mexico. This is a [$50] million acquisition. This is just simply additive to that budget? Or, does it replace some of the drilling that you would have done to get production?

Well, we don't have anything planned from a CapEx standpoint for Hunt. That was basically a PDP acquisition that we bought at very low multiple. Some of the other properties already had interests in. So, it was truly a bolt-on, but there's no CapEx expansion plan at this time for that acquisition.

I guess what I meant, Matt, is that my understanding was that you're planning to spend $200 million a year in the Gulf of Mexico. If you were to make small bolt-on acquisitions, that would be part of the $200 million budget?

Yes. That's correct. We -- that's our goal. Gulf of Mexico -- we look at it as 10% of our CapEx budget, and I think we can stay comfortable within that and keep our production pretty flat.

So, this $50 million acquisition, is this -- this is above and beyond the $200 million you plan to spend over a 12-month period? Is that right?

Yes. The $50 million acquisition cost itself?

Yes.

Yes, that's correct.

But going forward, when you look at bolt-on acquisitions, do you expect them to be above and beyond the $200 million of CapEx?

I'll try to hit it, Joe. So, the Hunt acquisition -- well, let's go back. DOR already had a program in place that would have us spending close to $200 million. The Hunt acquisition is a bolt-on on top of that for this year. Going forward, where we wouldn't already have the rig contracts in place, the acquisitions would be included in our $200 million. That's what we projected.

Okay. Got you. And, in this acquisition -- what do you think you spend in terms of multiple of cash flow?

Just a little over one times. A little over one times, yes.

Okay. Got you. And then, I think Matt, is it pretty much 100% PDP, is that --?

It was, yes. It was -- if it's not 100%, it's very close to it.

In your 8-K, you didn't give the reserves. What kind of reserves did you have at this point?

We'll do all of that at the end of the year, Joe. I don't have those numbers right in front of me for the particular assets.

Got you. Matt, earlier on in the call, I just want it clarify -- did you say that quarter-over-quarter from the first quarter to the second quarter -- if you ignore Dynamic and Hunt and the Tertiary sale, the sequential organic production growth is 6%?

Yes.

Okay. Total Company right?

That's correct.

Okay. Got you. And then, year-over-year, so second quarter '11 to second quarter '12, ignoring those same things -- I'm not sure if you have to factor in other acquisitions and divestitures, but organic growth is 14%?

Yes, that's the year-over-year from the end of '11 to the end of '12.

Okay. End of '11, okay. Got you. Does that factor in all divestitures? I don't have my scorecard in front of me with all the --.

Yes. That's ignoring Dynamic, Hunt, and adding back in your Tertiary.

Okay. Got you. Are there any other transactions we need to keep in mind to really figure out organic growth?

Well, East Texas -- we sold that. That was about $25 million cubic feet of gas equivalent a day. That was last November, I think it was.

Got you. Okay. And then lastly, that Tertiary sale? Was that mostly proved developed? Or, was that mostly proved undeveloped?

Most of that --.

[Roll volume].

What's on the books for that was mostly PUDs. Proved undeveloped.

Okay. Got you. All right. Thank you. Very helpful.

Thank you.

Your next question comes from the line of Charles Meade with Johnson Rice. Please proceed.

Morning, gentlemen. Tom, I was wondering if you could give a little narrative on where you are on your rig count ramp in the Mississippian versus where you thought you were going to be heading into 2012? And then, maybe follow that up with a discussion of maybe any efficiencies that you're seeing there that -- beyond or maybe below what you thought at the beginning of the year?

We're exactly where we thought we would be going into 2012. We are being a little bit more efficient than we anticipated. So, we might not end the year exactly at [32 or 33], but we do plan to drill 380 wells.

Got it. In that efficiency, is that just a straight-up cost efficiency because of rig rates? Or, is it actually maybe better actual maybe days to drill performance that's reflective of the kind of rigs that are available now?

Days on location.

Got it.

Are coming in quicker than we anticipated.

Got it. And then, any comments about cost in the play?

Well, costs are loosening, and maybe everywhere, as rigs have -- smaller rigs have left other gas plays, they tend to want to come to the Mississippian. And so, there's actually a loosening of rigs today and stimulation costs as you know have continued to move down. We'll be bidding our 2013 work here soon.

Got it. And then, one other question for me going back to a comment you made earlier in your prepared remarks. I believe you said that, you said 50% of your Mississippian acreage is now proven. I guess, two questions to that is, is that -- I'm assuming that's the 850,000 in your original play?

Yes. 872 wells have all been drilled down into the original.

Got it. And so, when you say that that's proven, is that -- a little more detail on that definition? Is that proven as far as SandRidge is concerned? Or, is that proven counting for an SEC definition -- you've got a PDP or a PUD on it?

No, it's not an SEC definition. That shows that there have been wells drilled across the areas. We have acreage that are horizontal that are -- have proven that there's an oil system in place and that we can drill wells there.

Got it. Got it. Probably from an SEC definition that percentage is going to be a little bit lower?

Oh, of course. You only book one well off of each side.

Got it. All right. That covers my questions. Thanks.

Thank you.

The next question comes from the line of Richard Tullis with Capital One South Coast. Please proceed.

Thank you. Good morning, everyone.

Good morning.

A couple questions on the Permian. Looking at your acreage positions throughout the play, are you seeing any potential horizontal drilling opportunities there?

We -- our Permian acreage is mainly the vast majority is vertical wells at 4,000 to 5,000 feet deep. So, yes, there could be some events where you'd drill horizontally, but it's mainly just a vertical play.

So, no plans to test any horizontal targets this year or even into next year?

Not on anything of scale.

Okay. I think that's all I have. Thank you.

Thank you.

The next question comes from the line of James Spicer with Wells Fargo. Please proceed.

Hi, good morning.

Good morning.

A couple questions on the financing side. With all of the growth that you've had here, do you have any -- I know it's early, but do you have any sense or expectation as to how your borrowing capacity might change as a result of your fall re-determination? And then, how much cushion if any, do you like to maintain on your revolver to feel comfortable?

Yes, this is James. We set the borrowing base at $1 billion. I think we could have comfortably gone higher than that. We didn't. You have got to pay for that unused capacity so we didn't feel the need to make it higher than $1 billion. $1 billion gives us plenty of cushion, I think, in the fall and then even into the spring, we'll look at resizing that. We've got plenty of capacity with the banks in our group. So, we can comfortably go higher than that, but again, just don't see the need to now.

How comfortable into the revolver do we feel? Depends on where we are in our growth. If we're at a stage where we're cash flow neutral, then I think we'd be more comfortable. If the stage were still burning cash, I think, once you get halfway into it or something, you want to make sure you're looking at alternatives or terming it out.

Okay. And then, just a question on your view on the royalty trust structure. Are royalty trusts simply a financing alternative in your view? If you were fully funded within cash flow, there would be no reason to do any more royalty trusts? Or, are there other strategic reasons why that could continue be a preferred alternative even over the long-term?

Sure, I think it's primarily to fund our business. I think if we were mature and cash flow positive, you'd see a lot -- you'd probably see us not doing or doing a lot less in terms of the trust. It is an attractive cost to capital. We are able to monetize PUDs at the public's cost of capital which is not easy to do. It's attractive form of financing, but I think it's one that gets us through this period until we're a more mature Company. So, I think down the road you'd see a lot less of us doing trusts.

Great. Thanks a lot.

You're welcome.

Thank you.

(Operator Instructions) Your next question comes from the line of Omar [Jama] with RBO Capital. Please proceed.

Good morning.

Good morning.

By the way, James, I like the disclosure on the trust. It's very clear and easy to understand and highlights the value and the financing that way. So, I compliment you on that.

Thanks, Omar.

I had a question about the -- I remember -- I believe it was last year. Maybe you can help me with the history there on, there was a lot of concern about the water disposal wells and having to front-end load the costs. Can you remind me what the history was? Whether it was last year or the year before? And, can you help us understand, looking ahead, like how many years will this -- or months even -- will this increase in infrastructure spending carry us for?

Well, Omar, I think that the look back historically is that one of the reasons that the Mississippian was slow to have competition and how we were able to put together 2.2 million acres of land that ultimately we keep 1.7 million acres was because of the question around disposal. And so, we had to make an early commitment to upfront put in a disposal system. Now, so the other companies might choose to not put in disposal systems, but it would show up in LOE on exceptionally high costs due to hauling water. So, it's really not an option to not put in a disposal system if you want to have an ongoing program in the Mississippian. We've just been much more aggressive, and it has been an effective barrier to entry for us on competition in our areas. So, the way we look at it is, it's a blessing in disguise to have to deal with water to make oil, and the oil -- the shallowness of the zone, the amount of oil we can make -- offsets, more than offsets, the amount of infrastructure costs to put in saltwater disposal systems. And, that's through the savings on the drilling of the wells, and then just how much we're finding.

Then, as far as, excuse me, now moving out into the future, we will continue to have infrastructure costs. We should just be able to maybe maintain those going forward, or have them come down slightly. We haven't proposed our 2013 budget yet.

Okay. And then, just a couple of other quick follow-ups on the same topic. Can you give any other understanding just to help people have some comfort of what exactly the spending is? That it's not cost inflation. That it really is infrastructure? Can you give any, any other information, like for instance, in the extension Miss, are you putting in more water disposal wells there just because that's a new area? Or, is this really just true step-out drilling in the primary --?

It's more in the original. The extension Mississippian is just getting started. So, the extra costs go into across this 150 miles from Grant County to Comanche County -- it's a big area where we have a lot of acreage. And, every time we drill in a new township, we have to go put in a disposal system -- and not only a disposal system, we have to run electricity to it. It's the prudent thing to do, rather than, we could save CapEx in the short run and haul water and rent compression, but it's not the right thing to do. What I think is being missed here is, it's good that we're spending on infrastructure because we're finding production. And, the production so far in Kansas out of the 50 wells we've drilled is exactly like the production we found in Oklahoma. So, I want to keep on spending on infrastructure.

Yes. Okay. Yes, it does seem like a good thing, but there's so many earnings reports and people see higher CapEx --.

I mean, you guys get so bogged down on the month to month --.

Yes.

Equation of what happens. It's just -- it's really -- it's difficult for a management team to have conversations like this whenever it's so obvious that what we're doing is correct, but yet we have to maybe sit and defend ourselves putting in infrastructure.

Yes. No, I think you've explained it pretty clearly now. What is the payback on something like this? Like when do you get to use this infrastructure? Is it two years from now?

No, we use infrastructure right away. Just understand, the play is -- it's a low cost play. From a drilling standpoint, it's a low risk play because on our 1.7 million acres there's 17,000, 18,000 vertical wells that's been drilled at Miss, but you just have to handle the water. So, what we're looking at is 275 barrels of oil equivalent IP, but you may have 2,500, 3,000 barrels of water that comes along with it. What make the play work is having cheap water disposal.

So, if you have 3,000 barrels of water, you're looking at 100,000 barrels of water or so a month at $2 bucks a barrel, right? You could have $200,000 a month just in water trucking if you're not careful with this thing. When you drill a disposal wall and spend $2 million, you can see it's a pretty quick payback by a year or less.

All right. Last quick one, when do we get to see some leg on the extension Miss? Are you going to wait until next year?

Yes.

I believe you also want to monetize some of that at some point. Is it -- is that a 2013 event?

Yes, we don't -- we might choose to monetize some. We might not. But, that's a next year event, and we won't have enough wells drilled to delineate the play until the end of the year.

All right. Thanks. I think you're doing a good job.

Thank you. Your next question comes from the line of David Snow with Energy Equities Inc. Please proceed.

Yes. Hi. You were modeling an eventual three wells per 640. Have you done anything in just the science area that would confirm that? Or, indicate whether maybe you ought to be doing more? Or, how do you get that number?

Well, we've drilled over 40 wells that are closer -- that are actually on four wells per section. Or, at least they're not actually in the same section, but are close enough to be called four wells per section and haven't seen interference. So, we feel comfortable with three wells.

But, it sounds like you may at the end of the day do four?

Oh, I feel comfortable with three.

How much of the original oil in place do you feel you're getting with the three?

Well, simply primary recovery is probably in the 5% to 10% for this. It's just on a bigger spacing. A vertical well, you get similar recovery, it's just draining a lot smaller area.

Primary being your horizontal is that what [you're saying]?

Primary being, there's no water flow. There's no enhanced recovery with it.

Okay. That's with horizontal drilling.

We don't anticipate water flooding.

Okay. And, to what extent do you think your -- from the vertical wells your percent of oil in the extension area is going to differ from the 45%, 55% in your acreage today?

What, I'm sorry? What difference do we anticipate in the extension between what?

Oil and gas -- do you think you'll be over 50%, for example, based on vertical in oil?

Yes.

55%?

The vertical wells are nearly all oil. Now, what you don't know is how much oil you're going to find. We could find just the same amount of oil as in the original and not have any gas.

So, how much of the verticals in the 850,000?

Well, the vertical wells in the 850,000 -- in the original area -- do produce gas. So, that's part of the -- I think you're trying get to the extension. We will know a lot more at the end of the year.

The vertical wells -- are they mirroring the overall 45%, 55% ratio that you're looking at now?

No, not necessarily.

Oh, okay. All right. Thank you.

Thank you.

And, with no further questions in queue, I'd like to turn the call back over to Mr. Tom Ward for closing remarks.

Thank you for joining us on the call this morning. We do look forward to seeing many of you at conferences this fall, and as always, we welcome any questions in the interim. Thank you for your continued interest in SandRidge.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect and have a great day.