SandRidge Energy, Inc. (SD) Q2 2012 Earnings Report, Transcript and Summary

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. [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's intent is to discuss SandRidge Energy and not our Royalty Trust. The trust 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 cost; 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've 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 we -- 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 a 30-day peak period, the low cost associated with the drilling and completion of these wells make 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 10-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 recompletions and infill drilling to help us fulfill our 3-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 are now able to sell expensive oil. As of August 1, the LLS mark was poised at $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 3x 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 recompletions. 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 our 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 10-year inventory at today's rig count at only 3 wells per section. We also have optimism about our extension acreage in Western Kansas, where we control nearly 900,000 net acres and where there have been more than 7,000 vertical Mississippian producers drilled. We are now drilling oil wells in the extension portion of the play with 3 rigs. And we'll 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 mentioned in the press release that during the second quarter, we completed 5 Mississippian wells that produce more than 1,000 barrels of oil equivalent for 30 days. They actually average 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 barrel 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 have 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 or 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 5 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 higher rates of return than hold out for an additional $10 per barrel. Our business is such that we plan ahead by at least 6 months. And we should not have the uncertainty of short-term pricing to make our long-term decisions. Although some of the moves we have made over the last few years have surprised some, strategically, they've been intentional. First, we bought producing oil assets in a geographic-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 a 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 2 core areas, we are 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 continuing to build upon this 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 have accomplished what we set out to do. We have been consistent with our 3-year goal of having EBITDA above $2 billion, drill within cash flow and improve our credit metrics to below 3x. 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, $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 90,200 barrels of oil equivalent per day, a 36% increase over the 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 2 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 increased as expected due to 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 downhole pump repairs. Excluding the offshore properties, our recently divested Tertiary assets, second quarter LOE decreased to $12.42 per Boe, down from $13.19 in the first quarter of '12 and $13.24 in the second quarter of '11. As a result, we are 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 is just over the high end of our previous guidance as a result of the inclusion of the Dynamic assets and the impact of noncore 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 leasehold in the remainder of the year. Regarding 2012 CapEx guidance, we are increasing our estimate for full year's CapEx to $2.1 billion, up from $1.85 billion, primarily due to increased facility costs 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 2.9x. Long-term debt consists entirely of senior unsecured notes with maturities ranging from 2014 to 2022 and only 1 $350 million maturity within the next 4 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 can 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 3x and growing EBITDA, we can comfortably fund our 2013 capital plan with cash flow from operations, current liquidity and additional debt. Also as alternative to debt funding, other sources of capital available to us include sales of existing Royalty Trust units, possible JVs or additional Mississippian acreage and noncore asset sales. As an example, in the second quarter, we raised $155 million through the sale of noncore 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 3-year objectives. On Page 8 of our earnings release, we have outlined updated guidance for 2012. We increased production guidance by 700,000 Boe at $33 million to reflect current year acquisitions, divestitures and better-than-expected performance from the company's core asset. This production level represents total equivalent growth at 41% over 2011 and oil growth at 54%. As I mentioned, we reduced lifting cost guidance by 6%. Oil and gas DD&A rate increased 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 the 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 have been and continue to be aggressive users of our hedges to protect ourselves from contractions in commodity prices. And we have one of the most hedged positions among our peers. One final note on Royalty Trust. In an 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 Noncontrolling Interest on Page 12 takes the noncontrolling interest or NCI from the income statement and adjusts for unrealized noncash hedging gains or losses to arrive at an adjusted NCI. This adjusted NCI is consistent with how we guide the trust earnings as, similar to earnings per share, we don't project noncash unrealized mark-to-market hedging gains or losses. This concludes management's prepared remarks. Pamela, please open the line for questions.

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

Tom, just a 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, I guess, my question is just if you could comment on the makeup, your expectations of the new Horizontal Miss versus the original.

So 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, kind of if you could break that down a little bit, kind of what type of growth you're assuming between the 3 areas, the Horizontal Miss, Perm and the offshore?

Yes. Let me take that. Hey, Neal, this is Matt Grubb. I'll give you a little bit more detail on the guidance, how we came to that. First of all, we -- 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. So there's growth in there that's embedded that may not be obvious in the guidance. We did have a very good second quarter, a number of positive things happened for SandRidge in the second quarter. And if we just for a minute, just ignore our DOR acquisition and Hunt acquisition and just look at organic growth, we still have 6% growth quarter-over-quarter from second quarter to first quarter. And if we continue to ignore DOR and ignore Hunt and then pro forma to sell Tertiary year-over-year, we would have organic growth of about 14%. So all those things went strongly [ph]. And when you put in Hunt and DOR back in and take out the Tertiary for the rest of year, I think it's still about 38%, 39%, 40% growth. But if you just look at a little more detail from Q1 to Q2, in Q1, we averaged about 66,500 barrels equivalent per day. And of course, we had acquisitions coming 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. And 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 5 wells that was making a couple thousand barrels a day for the first 30 days. We bought Hunt. When we bought Hunt, we modeled that coming in at 3,000 barrels a day. There are some pipelines or some platforms that are shut down. And actually, when we closed it, actually it was making probably about 2,500, 2,600 barrels a day. And we got production back on since then, and it's up 3,500, 3,600, 3,700. So we think there's some plus production there that's going to come off back down to our projection. 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 in June -- I'm sorry, in July, August and September. And so the Gulf of Mexico now with Hunt, with Dynamic and our legacy Gulf of Mexico, that represents probably 28%, 29% of our total production. So 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 104,000 so that's a pretty big move up from the 90,000 that we averaged in Q2. And as a result of this, some of that plus production in 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, but we model our type curve. And so with declines on those big wells with some of this plus production coming off, we could see August maybe even slightly down below from July. July, I don't have the official numbers yet, but we'll probably be in that 103,000, 104,000 range. And so with some production coming off in August, we might be down around high 90s to the low 100s, and then we start ramping up again the rest of the year. And so 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, but we will have to wait and see. But that's the reason for the guidance. And because of all the positive things that happened really in the last 45, 60 days, if we're 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 maybe just comment around what you're seeing as far as well cost and the Horizontal Miss both for the original and then into the newer area, if you -- including the water parts of it.

Yes. Are you asking specifically about CapEx or LOE?

More about LOE, just kind of, I guess, if you talk about kind of your type curve for the Horizontal Miss now, besides obviously the EUR is maybe going up a little. Just wondering what you're seeing at -- 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 the 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. And so we sold some water disposal facilities, drilling out some disposal wells and so on. But the LOE guidance, one of our big focus in the company. I mean, the things -- 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 bit over 500,000 barrels of water in the Miss, and we're only trucking about 3% of that. And so from the high this year, we will probably -- we have probably reduced our trucking volume by about 15,000, 20,000 barrels a day. And so 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 these wells we have 383 and 90 [ph] wells producing now in the Miss. As 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 an infrastructure standpoint.

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 gas in the extension.

Your next question comes from the line of Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: 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. David W. Kistler - Simmons & Company International, Research Division: And that was down from 13% in the first quarter. And is the driver of that being down, primarily the Dynamic acquisition, because I'd imagine the Mississippi Lime production going up would actually be adding NGL production.

No. I'm sorry. It's actually from the Mississippi Lime production going up because in the Mississippi Lime, we're not booking NGL volumes. We get a little upgrade on the gas side, but it's all crude oil. So as we continue to drill Mississippi Lime and develop that into oil production, you'll see the increase in Mississippi Lime will continue to drive down the NGL. Most of our -- 85%, 90% of our NGL comes from the Permian Basin and the Mississippi is going to outgrow the Permian. So your NGLs could continue to go down slightly. David W. Kistler - Simmons & Company International, Research Division: Okay. That's helpful color. I appreciate that. And then just thinking about these 5 wells that you guys 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 kind of new since last quarter in terms of what you've learned about those wells?

No. I mean, 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 the -- we will drill 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. It'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 the 1 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 the real focus is, is that from Comanche County, Kansas, which hasn't had any wells that produced 1,000 barrels a day for a 30-day average, is still a fantastic county to drill oil wells at. And even though -- and these 5 wells we drilled were in 3 separate counties. If you look at the 21 wells we drilled were across -- were scattered across -- that had 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. David W. Kistler - Simmons & Company International, Research Division: Okay. That's helpful. And then you guys made a comment that your rig count would stay in the Mississippi Lime at 33 rigs. And if I recall correctly, you guys were looking at ramping to as many as 40 rigs over the next year or so.

No. That's through 2014. David W. Kistler - Simmons & Company International, Research Division: 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 the activity?

We can hold that with -- 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. David W. Kistler - Simmons & Company International, Research Division: Okay. And 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 2 tie together especially when you're having the kind of efficiency gains that you've witnessed year-to-date?

Yes. If we 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 wells.

And your next question comes from the line of Duane Grubert with Susquehanna Financial.

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 guys tell us a little bit about the specifics? Are we talking about tanks and roads and stuff? Or what exactly is it?

For CapEx infrastructure, it's really primarily saltwater disposal well facilities. Because what Tom -- what you just talked about and what Tom has just talked about only are wells that -- 30% of those wells are PUDs. That means we're out drilling locations, they aren't offsetting existing locations, right? And so as we drill these step-out wells, we're having to lay longer lines. And then also you have electrical infrastructure we're building to install our subpumps. So that's the infrastructure we're talking about. So as we go to -- so as we end 2011 last year, our producer-to-saltwater disposal ratio was kind of 4, a little bit over 4:1. As we end this year, we should be 5:1. But next year, our program should be more stepping back in to existing infrastructure. And that's part of our acceleration of the infrastructure, you can spend the money now or spend it next year but we try to spend it now so we can go -- so we can step out a whole acreage, and then go back in and fill in some of these areas. And so next year, if 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 kind of balances up to about 6.5 to 7. So we said all along that once this play developed, we should be around 10:1, so we're moving towards 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 changed your -- those people's drilling schedule versus when you bought it.

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 have 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 10 wells and participate another 3 or 4 nonop wells.

And your next question comes from the line of Amir Arif with Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just a follow-up question on the CapEx increase, the [indiscernible] infrastructure for saltwater disposal, electrical. Is that different from what you guys were thinking at the start of the year? Or does it simply cost you more? Or are you just building up more [indiscernible]?

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, settling damages, where you get right-of-way 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 to the drilling, gain more confidence, we start drilling more step-out wells in the Miss. So that part of it probably changed a little bit. And you add all those things together, it did add up to more infrastructure costs for us this year.

We could if we chose to drill more infill wells and not spend as much on facilities. But if the play is going to work, you're going to have to build out facilities at some point. And 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. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: I mean, I noticed your IPs are getting better. I mean, I think last year, it was 275, now you're averaging 325. Do you have an updated EUR number that you would assign for the wells on average?

No. We'll do that at the end of the year. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: But there's still, I think is -- 450,000 is still the number that you have out there, is that right?

Yes. It's 456,000. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: That's based off the 275.

275 on a 30-day IP. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then I know previously you were thinking about potentially selling another 250,000 acreage 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 850,000 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're -- 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 2 bids of a bid and ask right now. And so I think it would be end of 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. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So it's 2013, if there's any [ph]. And then just one final question. I know, Tom, you mentioned that you wanted to view this play more as a large play repeatable. But just focusing on those 1,000 barrel a day-plus wells, 3 counties, can you tell us what counties they are? Are they contiguous? Are they spread around?

Sure. It's Alfalfa County, Oklahoma; Grant County, Oklahoma and Harper County, Kansas.

And the next question comes from the line of Craig Shere with Tuohy Brothers.

A couple of quickies, and then a little more fundamental question. The 3 rigs drilling now in the Extension Miss, can you comment on where they're drilling?

We have given presentations in the past that showed where the areas are. But I'll say we've drilled so far in Ford, Gray, Finney, Hodgeman, Ness.

Okay. 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 delay. There's -- we have certain terms in our agreement with Oxy. And we have to get the plant tested, get everything, basically all the components running to their satisfaction. But we're real close on that. And we expect to turn it over to them here soon. And so 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 now.

I guess, so that would be a 2013 event?

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

I got you. Tom, the markets of oils, 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. And you guys are front-loading your infrastructure expense and that wasn't immediately apparent. But even apart from that, I think there's -- 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 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 of that we have to make long-term decisions to run a company that can't really focus on 1 day's price movement in our stock, and that as if we continue to build the company on the queries 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 the bolt-on acquisition. You're just -- you're buying assets for under 2x cash flow and putting that asset -- then putting it to work on drilling long-term producing assets in the Mississippian. I just think it was a good trade.

Understood. So I guess that 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. And we said $1.85 billion to $2.1 billion when we came out with our 3-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 or there isn't any change to that, and 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 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.

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

I know you guys are probably not prepared to talk about any of the results up in Kansas quite yet, until you've got, I guess, a statistically comfortable sample to kind of 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 drilled in are Harper, Barber and Comanche. As you go further north, we have just now started drilling in those counties. Our 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. And so the same types of rocks, the same type of geology, that's what makes us comfortable. And 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. And in the next few months, we'll have enough of a data set to be able to see if these counties early on are as good as the counties to the south.

Is there any sort of -- when you step back and look at the geology and the depth pressures, difference between what you have in some more of the core developing areas versus the more the north area? I mean, would you suspect it's going to have more oil, less pressure? Is there some general context you can sort of set an expectation on?

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

Okay. That's fair enough. And when you step back and look at the infrastructure, the Permian process in Kansas versus Oklahoma, is there going to be a little bit of a higher need? Is the infrastructure going to be sort of -- need to come up weak [ph] quite a bit [indiscernible] you start getting more aggressive in some of your newer acreage?

It 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 on it and I just can't figure it out here. But to be more direct, it looks like you pulled forward some CapEx into 2012 from your potentially 2013 and maybe beyond that because of higher -- better results and your high activity. If I were just sort of looking at it, you talked about potentially kind of $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. I mean, when we talk about CapEx and funding gap, I think we need to talk a 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. And so yes, I think we're going to be -- we're $2.1 billion this year. I think we're going to be around maybe -- it's too early for me to tell exactly what the guidance is going to be for next year, but we're looking at probably $2 billion. So it's going to be a little bit less than this year. One thing though is we're done with our land spending. We're land and seismic this year, we're probably looking at about $200 million. And part of that's 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 are going to work to reduce CapEx going forward.

And your next question comes from the line of Joe Allman with JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So Tom, I know James gave a list of events that could help reduce the funding gap. So what are the next events, say between now and year end, your monetizations or raising external funds that can 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 $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 in selling noncore assets, selling Royalty Trust units. So 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. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. I've got a question on oil acquisition. I'm wondering how that fits into the Gulf of Mexico budget. So 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 properties we already had interest in, so it was truly a bolt-on. But there's no CapEx expansion plans at this time for that acquisition. Joseph D. Allman - JP Morgan Chase & Co, Research Division: I guess, what I meant in that 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 not our goal. Gulf of Mexico, we look at it as kind of 10% of our CapEx budget. And I think we can stay comfortable within that and keep our production pretty flat. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. 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, that's correct. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. But going forward, when you look at bolt-on acquisitions, do you expect them to be above and beyond the $200 million of CapEx or do you ...

I'll try to hit it, Joe. So the Hunt acquisition -- well, I'll first go back and say 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. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. Got you. And then in this acquisition, what do you think you spend in terms of a multiple of cash flow?

Just a little over 1x. A little over 1x. Yes. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Perfect. 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. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And then in your 8-K, you didn't give the reserves. Well, what kind of reserves did you have at this point?

We'll do all that at the end of the year, Joe. I don't have those numbers right in front of me for the particular assets. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. Okay. And then, Matt, earlier on in the call, I just want to 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. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And that's total company, right?

That is correct. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. Got you. And then year-over-year, so second quarter '11 to second quarter '12, ignoring those same things, and again, I'm not sure if you have to factor in other acquisitions and divestitures, but organic growth is 14%?

Yes. That's year-over-year from the end of '11 to the end of '12. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. End of '11 to -- okay. Got you. Does that factor in all divestitures? And I don't have my scorecard in front of me with all the ...

Yes. That's ignoring Dynamic, and added back in your Tertiary. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. Got you. Are there any other transactions we need to keep in mind to really figure out our organic growth?

Well, I mean, East Texas, we sold that. That's about 25 million cubic feet of gas equivalent a day. But that was last November, I think it was. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. Okay. And then lastly, that Tertiary sale, I mean, was that mostly proved developed? Or was that mostly proved undeveloped? Or what's the...

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

And your next question comes from the line of Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C.: So I was wondering if you could give the -- 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 kind of follow that up with a discussion of maybe any efficiencies that you're seeing in there 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. Charles A. Meade - Johnson Rice & Company, L.L.C.: Got it. And that efficiency, is that just a straight-up kind of 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?

Based on location or coming in quicker than we anticipated. Charles A. Meade - Johnson Rice & Company, L.L.C.: Got it. And any comments about cost in the play?

Well, costs are loosening and may be everywhere. But as 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. Charles A. Meade - Johnson Rice & Company, L.L.C.: 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 50% of your Mississippian acreage is now proven. I guess, 2 questions to that. I'm assuming that's the 850,000 in your original play.

Yes. 872 wells have all been drilled down into the original. Charles A. Meade - Johnson Rice & Company, L.L.C.: Got it. And so when you say 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 kind of counting for an SEC definition, you've got a PDP or a PUD on it?

No. 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. Charles A. Meade - Johnson Rice & Company, L.L.C.: Got it. So probably from an SEC sort of definition, that percentage is going to be a little bit lower.

Of course, yes. You only book one well off of each site.

And your next question comes from the line of Richard Tullis with Capital One Southcoast.

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

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.

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

A couple of question on the financing side. With all the growth you've had here, do you have any -- I know it's early. But do you have any sense or expectations as to how your borrowing capacity might change as a result of your fall redetermination? 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've 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 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 far comfortable into the revolver do we feel? It depends on -- it kind of 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 it's a stage we're 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 Trust simply a financing alternative in your view? And if you were fully funded within cash flow, there would be no reason to do any more royalty trust? Or are there other strategic reasons why it continues to be a preferred alternative even over the long-term?

Sure. I think it's primarily to fund our business. I think if we were maturing 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 of capital. And we are able to monetize PUDs at the public's cost of capital, which is not easy to do. So 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 trust.

[Operator Instructions] And your next question comes from the line of Omar Jama [ph] with RBL Capital [ph].

By the way, James, I like the disclosure on the trust. It's very clear and easy to understand and kind of highlights the value in the financing that way, so complimentary on that. I had a question about the -- I remember, I believe it was last year -- maybe you can help me with the history there. There was a lot of concern about the water disposal wells and having to front end-load the costs. So can you remind me what the history was, whether it was last year or the year before? And can you kind of help us understand looking ahead, like how many years will this -- or months even, will this increase in infrastructure spending kind of carry us for?

Well, Omar [ph], I think that the thing to 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 some of the other companies might choose to not put in disposal systems. But there, it would show up in LOE on exceptionally high cost 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 that the oil -- the shallowness of the zone, the amount of oil we can make more than offsets the amount of infrastructure cost 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 now moving out in 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 -- 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 other information? Like for instance, in the Extension Miss, I mean, are you putting in more water disposal wells there just because that's a new area? Or this is really just true step-out drilling in the kind of the primary...

It's more in the original. I mean, 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. And 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. And so what I think is being missed here is that 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.

Okay. Yes. It does seem like a good thing. But there's so many earnings reports and people see...

I mean, you guys just get so bogged down on the month-to-month equation of what happens. It's difficult for a management team to have conversations like this when 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. I mean, what is the payback on something like this? Like when do you get to use this infrastructure? Is it 2 years from now?

No. We use the infrastructure right away. Just understanding the play, 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 on Miss, but you just have to handle the water. And 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. And what make the play work is having cheap water disposal. So you have 3,000 barrels of water, you're looking at 100,000 barrels of water or so a month at a couple of bucks a barrel, right? So you could have a couple of hundred thousand dollars a month just in water trucking if you're not careful with this thing. And so when you drill disposal well and spend a couple million dollars, you can see it's a pretty quick payback, about a year or less.

All right. And then last quick one. When do we get to see some lag on the Extension Miss? Are you going to wait until next year? I believe, you also want to monetize some of that at some point? Is that a 2013 event?

Yes. So 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.

And your next question comes from the line of David Snow with the Energy Equities, Inc.

You were modeling on an eventual 3 wells for 640. Have you done anything in this 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 4 wells per section or at least they're not actually in the same section but are close enough to be called 4 wells per section and haven't seen interference. So we feel comfortable with 3 wells.

It sounds like you may, at the end of the day, do 4?

I feel comfortable with 3.

How much of the original oil in place do you feel you're getting with the 3?

Well, typically, 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 drilling us a lot smaller area.

Primary being your horizontal, is that what you're talking about?

Well, primary being there's no water flow, there's no enhanced recovery with it.

Okay. That's for horizontal drilling.

Yes. We don't anticipate water flooding.

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

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%?

I mean, the vertical wells are nearly all oil. What you don't know is how much oil you're going to find. And so 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 to 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.

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 the 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.