SandRidge Energy, Inc. (SD) Q4 2010 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Fourth Quarter and Year End 2010 SandRidge Energy Earnings Conference Call. My name is Kerris, and I will be your coordinator for today. [Operator Instructions] And I would now like to turn the call over to your host for today, Mr. James Bennett, EVP and Chief Financial Officer. Please proceed, sir.

Thank you, Kerris. Welcome, everyone, and thank you for joining us on our fourth quarter and full year 2010 earnings call. Please note 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 may make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures. A reconciliation of any non-GAAP numbers that we discuss can be found in our earnings release and on our website. Now let me turn the call over to our Chairman and Chief Executive Officer, Tom Ward.

Thank you, James, and welcome to our fourth quarter financial and operational update. Also present with me are Matt Grubb, President and Chief Operating Officer; as you know, James Bennett, EVP and Chief Financial Officer; Rodney Johnson, EVP Reservoir Engineering; and Kevin White, Senior VP, Business Development and Investor Relations. As most of you know, we have completed the transition to crude oil that started two years ago. While challenging during the process and viewed by many as a contrarian move, we can now look back and see that we not only made the right call on commodities but did so in size and scale that transformed our company. Only two years ago, our revenue consisted of over 80% natural gas and now is more than 80% oil. We remain true to our conviction on developing shallow, low-cost, proven carbonate reserves. First, we expanded our holdings in the Central Basin Platform, with the acquisition of assets from Forest and Arena, and now we have 780,000 acres in the horizontal Mississippi and carbonate play in Oklahoma and Kansas. These two areas have the important characteristics we require in all of our plays: low costs, low reservoir risk, scalability and repeatability. Key infrastructure is in place for oil and gas development. Rigs are readily available. Shallow reservoirs mean fewer drilling days and low horsepower requirements for hydraulic fracturing all contribute to low costs and very high rates of return. Furthermore, because we work in areas that have been proven by thousands of vertical wells over decades of drilling, we take on little reservoir risk in generating these high rates of return. We also have the drilling inventory in place to continue this type of drilling success for many years to come. Another advantage to our Mississippian play is our low entry cost. We have now basically shut down our leasing efforts. But once all the numbers come in, we expect to have spent less than $200 per acre and should have over 900,000 net acres leased. This is in stark contrast to the entry costs of many of the recent high-profile plays where acreage costs have been 10x to 100x higher. We could only accomplish putting together our holdings in the Central Basin Platform by being ahead of the industry and deciding to make this a core area in early 2009. Today, it would be impossible to duplicate. Also, it would be impossible to have our acreage position on the Mississippian play had we not moved aggressively during the last year. We spent two years acquiring oil production and oil drilling locations in areas that most others have overlooked. These areas are traditional carbonate reservoirs, with better permeability than most plays being developed today. It takes less horsepower to frac due to the rock's characteristics. In fact, we've seen almost no increase in overall service costs since mid-2009 because an average Central Basin Platform well is shallow, and there's an excess of shallow drilling and completion equipment. The entire industry has moved to tight deep plays that require high-pressure drilling and completions. Consequently, there is an abundance of low-pressure equipment as virtually no one drills shallow vertical wells anymore, and these shallow traditional reserves are what the industry was built on over the last several decades. Production history is the other key variable in deciding what kind of play to be involved in. We want to know our wells, how they’ll perform in future years, be aware of rate of decline and profitability. Again, this is in stark contrast to much of the industry that appears comfortable with the first year decline of 80% to 90% and little certainty of the subsequent years’ decline because there's very little vertical or horizontal well production history. We decided to build our oil asset base with much less risk in areas where there were decades of producing wells that show how the reservoir will perform. So finding shallow, predictable carbonate reserves with certainty of economic outcome and little service cost inflation has been our strategy. Even though we continue to be bullish oil for the long term, to further mitigate economic risk, we have hedged a significant portion of our production into 2013, and we are now locking in some more oil at above $100 per barrel. We continue to drill aggressively in our two core areas: the Central Basin Platform and the Mississippian. The Central Basin Platform will receive 65% of our total drilling budget this year, and the Mississippian the rest. We have also drilled 14 disposal wells and have increased our rig count to 12, as we now plan to increase our CapEx to $1.3 billion and increase our production to 23.3 million barrels equivalent. As I discussed earlier, we've been in a mode of buying land and acreage for the last two years, and we will use 2011 as the time to use our rich oil properties as a source for raising capital. We already have a clear path to more than $700 million of capital raises in the first half of 2011. Our goal will be not only to fund the shortfall in 2011 but to move EBITDA up and begin to fund our 2012 drilling program. We've been very clear that we'll search for more ways to monetize a portion of the Mississippian acreage holdings. We love the royalty trust structure, as we not only get to sell undeveloped acreage into the trust but also receive the drilling capital upfront, providing a tremendous acceleration in net present value to us. The horizontal Mississippian has performed better than we expected a year ago. If you were at our Analyst Day presentation last year, you have seen a slide that expected a 235 MMBoe EUR. We have since moved the EUR to more than 300 to 500 MMBoe, and our latest type curve from Netherland Sewell is 409 MMBoe per well with 52% crude oil, not liquids, but oil, an important distinction when NGLs are trading at less than 40% of crude. Our drilling time and costs have come down from 30 days to 21 days, and our well costs have moved down from $3 million to $2.5 million, all of this in an area that has known oil in place across 6.5 million acres with over 17,000 vertical wells drilled in the last 30 years. Therefore, we believe the play has scale, and our 780,000 acres would represent the largest land position of any operator published to date. As you have seen, our reserves are up 149% over last year. Excluding price revisions, our finding cost was $9.04 per Boe. When price revisions are included, the finding cost moves down to $3.61 per Boe. SandRidge also has a proved developed finding cost of $13 per Boe. The proved developed finding cost is important because it includes acreage costs without the benefit of booking puts. Given the different ways the companies may add undeveloped reserves, we view this as the most consistent and conservative way to think of finding cost and believe we have a best-in-class number. I'm very happy with the changes we've incorporated during the last two years, and this is an exciting time for SandRidge. Our steadfast belief in proven shallow conventional oil targets has now given us the luxury of having tremendous margins for years to come. I'll now turn the call over to Matt for the operational update.

Thanks, Tom, and good morning. Tom has hit on many of the points I'm going to talk about. I just want to elaborate on a few important ones. First, I want to start out with 2010 production and the 2011 production guidance. For the year ending 2010, we produced 7.4 million barrels of oil and 76 billion cubic feet of natural gas for a total of 20 million barrels of oil equivalent or 120.5 cubic feet of natural gas equivalent, all of which are new highs for the company and represents a 15% increase over 2009. Since embarking on our strategy to move to oil, we have now increased oil production every quarter dating back to Q3 of 2009. We began 2010 producing about 13,000 barrels of oil per day and exited 2010 at about 30,000 barrels of oil per day. The bulk of that growth in 2010 was in the Permian Basin, where we went from about 8,500 barrels of oil per day to about 23,000 barrels of oil per day from the beginning of 2010 to the end of 2010 as a result of the Arena acquisition and drilling. Significant production growth also take place in the Mid-Continent region as a result of the Mississippian oil play. In 2010, we grew production from about 3,800 barrels of oil equivalent in the Mid-Continent, to about 7,000 barrels of oil equivalent as we exit 2010. We look for continued healthy growth in both of these oil areas in 2011 as we have ongoing active drilling programs in each. As for 2011, our production guidance is 23.3 million barrels of oil equivalent. We're projecting to produce 66.5 cubic feet of natural gas and 12.3 million barrels of oil. This is about 13% decrease in gas production for 2010 and a 67% increase in oil production. Overall, we're looking at year-over-year production increase of about 16% in 2011 over 2010. Reserves. The company total proved reserves essentially doubled from 219 million barrels of oil equivalent at year end 2009 to 546 million barrels of oil equivalent at year end 2010. We produced 20 million barrels of oil equivalent during the year, and added 347 million barrels equivalent. Extensions accounted for 105 million barrels equivalent; and acquisitions, 85 million barrels equivalent; and revisions, 157 million barrels equivalent. The present value of the reserves on a 10% discount increased nearly threefold from $1.6 billion at year end 2009 to $4.5 billion at year end of 2010. The reserves replacement ratio, excluding price revisions and acquisitions, is 521%. As for the finding costs analysis, our 2010 drilling CapEx was $947 million, so our drilled bit proved reserves finding costs, excluding revisions, was $9.04 per barrel of oil equivalent. And if we include the reserve's revisions, it was $3.61 per barrel of oil equivalent. While those metrics are very good, it is important to understand the proved developed finding costs. Our proved developed reserves increased from 137 million barrels of oil equivalent in 2009 to 222 million barrels of oil equivalent in 2010. That's a difference of 85 million barrels of oil equivalent. If we add back in 20 million barrels of oil equivalent for the production during the year and subtract out the 27 million barrels of oil equivalent for acquisitions, we get a net proved developed reserves increase of 78 million barrels of oil equivalent. That is the true organic movement in proved developed reserves year-over-year. With the drilling CapEx of $946 million, the proved developed reserves finding cost was $12.06 per barrel of oil equivalent. And with the addition of land and seismic costs of about $103 million, that number moves up to $13.37 per barrel of oil equivalent. I'm going to hit on the 2011 EEP CapEx guidance. James will hit on the corporate guidance, but I just want to start out with our drilling budget. We're looking at running 28 rigs in 2011 on average of which 16 will be in the Central Basin Platform and 12 in the Mid-Continent drilling horizontal Mississippian wells. We look to drill 138 horizontal Miss wells in 2011 for a cost of $248 million. Along with the Mississippian program, we're going to also accelerate our drilling and completion saltwater disposal wells. We will drill 24 of these SWD wells, and that will not only allow us to dispose of water through the year of 2011, it would also take us into 2012. And that will be another $45 million. We plan to drill a little bit over 800 wells in the Central Basin Platform for a cost of $582 million, and we have $27 million allocated to East Texas, Gulf Coast, Gulf of Mexico and Tertiary for miscellaneous projects. That adds up to $902 million. We have $64 million budgeted for workovers and recompletions and $6 million for non-operated drilling, and we also have budgeted $55 million of capital carryover from our 2010 program for a total of $1.027 billion for the EEP CapEx. Lastly, I want to talk about how we have improved or how we have increased our value in the Permian Basin just in a very short time. At year end 2008, our Permian Basin assets had a value of about $150 million. We bought the Forest assets in late 2009 for $800 million. We bought Arena in 2010 for $1.4 billion. And since then, we’ve spent about $500 million drilling new wells. The total investment is about $2.7 billion. We have cash flow of about $300 million and have divested -- including our announcement last night of the New Mexico assets, divested a total of $465 million. This gives us a net investment of less than $2 billion at year end 2010. Our Permian assets are now worth $3.8 billion on a trip [ph], so essentially, we have added nearly $2 billion in value in the Permian in just 18 months. And now I will pass the call over to James for finance.

Thank you, Matt. Reviewing 2010 results, as Matt mentioned, total production was 20.1 million Boe, right on top of our guidance of 20 million. Adjusted net loss was $35.4 million for the fourth quarter, and adjusted net income was $42.4 million for the full year. Adjusted EBITDA totaled $130 million for the fourth quarter and $465 million for the full year. And for the full year, capital expenditures were $1.13 billion versus our guidance of $1.1 billion. The slight variance from guidance is primarily the result of an increase in drilling and leasing activity on our Mississippian play in the fourth quarter of 2010. Touching on a few of the numbers that warrant further explanation. On a per unit basis, LOE and production taxes continue to trend slightly higher, as oil constitutes a greater percent of our production mix. Regarding cash G&A, included in the $7.06 per Boe of actual G&A is approximately $35 million of costs associated with the Arena acquisition and legal settlements. Excluding these two items, G&A would be $5.28 per Boe. Finally, recall that the Arena acquisition and the release of the valuation allowance against our deferred tax asset resulted in a $446 million tax benefit in 2010. As an update on hedges, consistent with our history of managing our commodity price exposure, we continue to actually hedge and lock in cash flows on a high rate of return on all projects. For 2011, we have over 75% of our guidance production hedged at a price of just over $86 a barrel and $4.69 for gas. If we take our hedges out to 2013, where as Tom mentioned, we continue to add hedges at over $100 a barrel, we have approximately $40 million in Boe hedged at an average price of $67 per Boe. That represents about $2.7 billion of future revenue. One item, I think, is worth noting in terms of hedging, and I think it's important. As producers, we all assume a heightened cost risk, when we place hedge bets in the out years, as service costs can rise and compress cash flows and reduce our expected returns. It's our ability to control the costs side of our business that allows us to be comfortable hedging out two to three years of production. We know what our costs will be and are comfortable locking in the out year revenue and the returns. Turning to our liquidity and the balance sheet. At year end 2010, our credit facility balance was $340 million, and at February 22, it was $382 million. With our volume base of $850 million, our current availability under the credit facility is $433 million. This does take into account some outstanding LCs. Additionally, given our proven and PDP, PV-10 at year end 2010, we feel very comfortable with the asset coverage under the credit facility and the upcoming April borrowing base redetermination. Our total debt at year end was $2.9 billion at an average interest rate of 7 ½%. We're in compliance with all covenants under our debt agreements. We have no debt maturities until 2014, and our year end debt-to-adjusted-EBITDA for covenant calculations is 3.75x. Importantly, looking at our leverage relative to our asset base. Debt to proved reserves has improved from $5.30 per Boe to $11.80 at year end 2009. Debt to proved developed reserves is now $13 per Boe versus $18.80 here in 2009. And debt to SEC PV-10 is now 0.65x versus 1.65x in 2009. While we're currently levered on a cash flow basis, we do feel that our large and oily asset base and hedge positions provide further support for our level of debt. When we outlined our initial guidance in November 2010, our goal was to raise between $600 million and $800 million in proceeds from sales of non-core assets in order to fund the shortfall between our cash flow from operations and our capital expenditure budget. Reviewing where we are in terms of these asset sales. In December 2010 and early '11, we closed $265 million in sales of non-core assets. Yesterday, we signed an agreement for the sale of our New Mexico assets for $200 million, which we expect to close in April. The combination of these brings us to $465 million of closed or signed asset sales. If you combine that with the expected proceeds of the Mississippian royalty trust we filed in January, we have closed or pending cash proceeds of over $700 million. This is versus our original goal of between $600 million and $800 million. Given this, we're now increasing our expected proceeds to in excess of $900 million and anticipate funding the remaining with further monetization of our assets. It's our success in these asset sales and monetizations coupled with our opportunities in our two primary plays that gives us the ability to increase our development pace and raise our 2011 CapEx budget to $1.3 billion. Turning to guidance. As outlined in our earnings release, we're increasing our projected 2011 production guidance to 23.3 million Boe, which represents a 16 production growth over 2010. Of course, in the oil and gas ratios, trading at around 22:1, looking at the absolute volume growth based on a 6:1 equivalent becomes a lot less meaningful. In this commodity market environment, growth in oil production is just much more valuable. As I mentioned, we're forecasting CapEx of $1.3 billion, up from our previous guidance of $1.1 billion, and 100% of our drilling expenditures for the remainder of the year will be dedicated to oil project, as we develop our assets in the Permian and the Mississippian. As Matt mentioned, in the first quarter, we're wrapping up our leasing activities in the Mississippian, and we're also front-end loading some of our saltwater disposal drilling activities in Q1, so we do expect the first quarter CapEx to be the highest of the year. Production costs, production tax, DD&A and G&A per Boe are all in line with Q4 2010 actual results. As I discussed earlier in the call, we're making significant progress in terms of the capital raising efforts and feel confident we can fund our $1.3 billion capital program for 2011. In conclusion, 2011 has the potential to be a very transformative year for SandRidge. We have amassed two sizable oil plays in areas of the country with decades of known production history and a large inventory of high return oil drilling opportunities. We're operating in formations and plays that allow us to control our costs. We have projected a growth in production, all coming from oil, and we have a clear path to addressing our 2011 funding gap and are setting up nicely to begin to address any 2012 funding needs. We recognized that our financial leverage is high. While our commodity hedges and large asset base somewhat mitigates this, we do believe a reduction in our financial leverage over time is prudent. SandRidge will be hosting our Annual Investor and Analyst Day meeting in New York at the Grand Hyatt on Tuesday, March 1 at 8 a.m. You can see our website for details on the investor meeting and a copy of the presentation. Now I'd like to ask Kerris to open the call for questions.

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

Tom, just a question first on the Permian. We've obviously chatted on the horizontal wells there. Just wondering, again, if you could comment around prospective acres of near Permian and how soon you'd start looking at something like this.

Sure, Neal. We have, as you know, a lot of acreage, about 200,000 acres, in the Permian. And some of that acreage is now being offset by horizontal wells being drilled, and they're mainly in the San Andres. And so we’re looking at it and hopeful that there's a lot of success with the idea just like most of the reservoirs that we look at. We tend to wait and make sure that the extra cost that's incurred with drilling horizontal wells meets with the expectations we can have with drilling vertical wells. The best area for us to look at horizontal wells is where we have more San Andres only-type reservoirs or the Clear Fork in Wichita-Albany and the Fusselman aren’t as prospective, so that you're not giving up people rights to recomplete in whenever we drill a well. Keep in mind that just because we drill a well and bring on a deeper zone, we do keep very good shallow zones behind pipe, so that you can bring those on later with the recompletions. And one of the things that Matt, I'm sure, will talk about is we continue to have excellent results with recompletions in the Permian Basin. But to answer your question, yes, we do keep notice of and visit about horizontal activity near our acreage.

Yes, Neal, I just want to add that we're currently seeing nearly 90% rate of return on our vertical wells on the Central Basin Platform. So certainly, the horizontal well may be a good idea, but only time will tell. And it's not imminent, it's not anything like where you go out and do right away. But like every other program, we will watch it very carefully. We'll study it and if it’s the right thing to do, we'll certainly give it a try.

And then, Tom, looking over at the horizontal Mississippian. We know that, obviously, the size of acreage you have there. If you could comment a little bit on kind of as that play goes from East or West, your thoughts on the prospectivity of that play. I guess not just East to West, even the seasonal kind of North to South, et cetera. I guess sort of that quin prospect area. Are all those areas, one going to be as good as the other, just kind of what are your thoughts?

On the horizontal play?

Yes.

Frankly, the San Andres produces all across the areas that they're looking at, so...

The Horizontal Mississippian, I'm sorry, Tom.

So your question, again, is in moving from East to West, are we seeing any -- I thought you were talking about the Permian, the prospectivity of East to West in the Mississippian. So I was off thinking about the wrong thing. Yes, across the play in the Mississippian, and you need to think of this, not only in SandRidge's wells, but the other operators that are drilling, we're seeing type-curve wells in and around all across our acreage, but not only across our acreage, in other areas as well. So so far, there's been not a way to choose one place or the other that might be better or worse. So we continue and we have a lot of acreage over many, many counties. So I don't know. That's the reason we keep a range of 300 to 500 MMboe, even though Netherland Sewell has us at 409 MMboe per well, is we don't know from one section to the next or one area to the next, which ones might be better or worse. But we're comfortable with the type curve currently.

I think you said in the past, frac or other completion costs, doesn't seem like you're seeing virtually any uptick like much of the rest of the market there. Does that still continue to be the case? And do you, Matt and the guys continue to think that, that’ll be the case for the remainder of the year?

Yes, we don't see any appreciable move in service costs. Again, like I mentioned, it's because there is an excess amount of frac capacity with low horsepower frac fleets. So if the industry continues to do like it appears it's going to, it fits perfectly with us, and what we like is, is that our plays have 50% increases in service costs. We don't, and so it just makes us have better rates of return in our play.

And your next question comes from the line of Pearce Hammon with Simmons & Company.

On the potential for future royalty trust, what's the current appetite for either additional trust? And what would you think is the limiting factor from SandRidge's perspective?

Unfortunately, I can say that we like royalty trust, but we are in registration in one right now. So I’m limited on how much I can talk about royalty trusts. I'll leave it that we like the idea.

And what service costs inflation is baked into your 2011 CapEx guidance? Or correspondingly, what sort of efficiency improvements might you think you'd be able to get to offset some service costs inflation?

Sure. I'll pass that to Matt.

Yes, we -- actually service costs, like Tom mentioned, the type of fracs that we pump as a big part of your drilling completion costs is a very simple system in the horizontal Miss. It's a fresh water system and really all we put in is a fresh and reduced wherein we use a fairly low strain of sand. And so there's an abundance of those type of material that's going to keep service costs in check. In the Permian, our wells, the Permian Moscow, we continue to drill those for about $500,000 in Clear Fork in the range of about $800,000. And again, those are one or two stages per well on the frac. And again, this is a low-strength crop and fairly conventional fluid. I think the thing that keeps our service costs low is the horsepower requirements that we bring on location. Today, as we step out away from the conventional reservoirs, a lot of those fracs are requiring anywhere from 25,000 to maybe 40,000 horsepower just to get the fracs pumped. In the Central Basin Platform, everything we do is a fraction of that, is between probably 3,000 and 7,000 horsepower. And then in the Mid-Continent, we're in the 10,000, 11,000, 12,000 horsepower range. So there's an abundance of those types of equipment around to do what we need to do. The rigs, we own 31 rigs in the company, and 20 or 31 rigs are running for us and some of the things we've done there. Certainly, diesel costs have gone up. Labor costs have gone up a little bit. We've went from 5 million crude to 4 million crude to offset some of those costs. But those type of costs I'm talking about, they are less than 5% of your total well costs. So from that standpoint, we just don't see any appreciable upward movement in costs this year.

And keep in mind that the two types of reservoirs that we chose for our core areas for oil are very different than the majority of companies who are drilling today. So they're shallow, and they're carbonates. And just the carbonate reservoir in itself is easier to frac than tighter, denser formations like shales because it's a better rock, a better reservoir. And so it just doesn't take as much horsepower to frac it. And as the other service costs continue to go up, we're just not seeing that because for decades, this gas industry, the natural gas industry in the United States, was built on these type of reservoirs. And so that equipment that's having to be built out to do higher and higher horsepower and deeper drilling in tighter rock is now the other type of equipment that the foundation of the industry’s been built on is available. So we have an excess capacity of equipment when other people don't.

And then my last question is, what's your current cost basis and your acreage position in the horizontal Mississippi? And where do you think current leasehold is right now there?

Well, our current leasehold is 780,000 acres. We said that we’ve stopped, pulled in our brokers, and just through the oral or written commitments that we have in place, we should end up between 900,000 and 1 million acres. Our cost basis, when we're all said and done, will be less than $200 per acre.

And where do you think acreage goes right now?

Well, there'd be different acreage costs and keep in mind there’s 6 ½ million acres. The prices per acre has tended to move up, but there's many different acreage costs in different areas of the play.

And your next question comes from the line of Brian Singer with Goldman Sachs.

Can you talk to what your thoughts are on future asset sale potential and how aggressively you're looking at that relative to additional acquisitions?

Brian, the question is the future asset sales, what we might do?

Exactly.

We've made it very clear that we have bought more of the Mississippian acreage than what this current CapEx budget will allow us to drill. We could hold basically about 500,000 acres in the next five years with this 12-year program that we have, and most of our leases have a five-year term. So what we look at then is having about half of the acreage that we’ll either choose to pick from or find a partner to move forward. And we still anticipate selling more acreage in the Mississippian past our first asset monetization that we project to have in April.

And do you expect to sell assets beyond the royalty trust market, either through a joint venture or just a straight sale?

Yes, we leave -- all those options are available, either the asset monetization we've already done or looking to do in the royalty trust. There could be joint venture, there could be just a straight sell of assets. There might be some partnership made in some other way. We’re open to other ideas, if you have any. So any type of monetization that is the best rate of return for the company is what we'll try to do.

And secondly, can you just talk to take-away for your oil production particularly in the Permian, and whether you see a, any backup, sort of potential for any backups as industry grows production; and b, whether there's optionality to move into some of the currently higher priced oil markets?

Yes, I'll say that currently, I'll let Matt address this, too. We don't have take away issues, but we are looking for alternative ways to move oil away from cushing.

Yes, Brian, I’d just like to add that currently out of the Permian, about 60%, 65% of our oil’s being piped out there to cushing and the remainder being trucked. The issue right now is not an issue for us getting oil out of the Permian as much as an issue that everybody's facing, and that’s the storage inventory going up in cushing. And I think there are pipeline projects in place now that we're looking at. Magellan recently announced that they may reverse their long horn line, which would take oil from Crane County down to the Gulf Coast, which would certainly help, but that's probably 18 months out at best. And then also, there are several pipeline projects in the talks that they can cushing oil down to the Gulf Coast increasing capacity there. But that's also probably 18 to 36 months out. So I think going forward, I don't see a problem getting oil to cushing. And also, there's projects at cushing right now where I think the storage capacities would go up probably another 15% this year. So from a standpoint, getting oil out, I don't see a problem. It's just more of a concern going forward whether there's going to be a spread from WTI to burn or not.

Your next question comes from the line of Dave Heikkinen with Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: I have a question, first, Tom or Matt, as you think about operational governors on your activity levels both in the Central Basin and in the Mississippian. Can you just talk through that?

Sure. The operational governor in the Central Basin Platform is just logistics. We have plenty of rigs we can get. We have plenty of ability corporately to drill more; however, logistically it's difficult to drill more than about 16 to 20 rigs at a time in the Central Basin Platform just because the number of wells that you're bringing on. So this year, we'll complete over 800 wells in the Central Basin Platform, and I think there is logistically a cap on how much we can do in the Central Basin Platform at one time. In the Mississippian, that's really a different story. It's more related to just capital, and we could double our rigs with no issue at all operationally, and that's not an issue for us as far as -- there's really no logistical issues in the Mississippian. In both areas, we have great midstream. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: James, as you think about your role as a CFO, how do you think about establishing guidelines and kind of framework for appropriate leverage, access to capital markets? And then any governors on capital access given that the Mississippian could go faster?

Sure. We mentioned in the call that on a cash flow basis, our leverage is high. We think our asset base supports it and hedges also help. But look we don’t comment specifically on capital markets transactions, but we’ll look to raise enough proceeds from monetizations to fund our cash flow gap. And we think we've got a path that we're setting up where we can start to fund that 2012 cash flow gap. As you look out longer term, I think given the capital that we're spending on the Mississippian and the Permian and the growth we're seeing, we can see a growth in production in EBITDA. We can position ourselves to really grow into our debt load and look longer term. I think we feel comfortable saying, we’d love to be below or around that 3x debt to EBITDA range. It’s going to take us a little time to get there, but we're comfortable saying that. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: So debt to EBITDA and debt to reserves are kind of the two primary thoughts, that's good.

Yes. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: On the other side, just maybe getting in the weeds a little bit on both the Mississippian and then the Permian. First, on the Mississippian, can you talk about trying to break down kind of fixed monthly operating costs per well and then where are the variable costs, to try to get into the overall aggregate of what goes into your operating expenses and taxes and the like?

Yes, in the Mississippian, the monthly average cost is about $7,300 a month. And really the fixed component of that, we have a compressor for gas lift operation, that's probably accounts for about half of that cost. And then you have water disposal, which is power costs. That's a variable cost because as time goes by and you have depletion, your water production will go down. So that cost goes down over time. But those are really two primary costs as of course you have your pumpers. That's a fixed cost, and you have some chemicals for corrosion control and things like that. But essentially, it's about $7,300 a month and about probably $4,000, $4,500 a month is for compressor rental, and that's going to stay pretty constant. Where that could go down over time is when we have enough wells out there drilled, and we can start centralizing our gas lift operations. And we'll have a significant saving if we get to do that probably in the next year or so. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then, Tom, I know in the Permian, you like to discuss average wells, including Clear Fork, San Andres, both of them in other zones. How do you split the 16 rigs running now between those areas?

They go back and forth. But most of the locations are going to be San Andres and Clear Fork. Those are the real bread and butter reservoirs. We drill a lot of Wichita-Albany locations also. But that's why we keep an average is because you might have, at some point, more San Andres drilling, less Clear Fork and then another time, more Clear Fork and less San Andres or more Wichita-Albany. And there's no way that we can give you guidance that keeps a rig constant in any one reservoir. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then just trying to get an idea, how much CO2 do you think they'll produce this year?

Well, right now, we're going into the plan from high CO2 gas is about $230 million, $240 million a day, and 65% of those are CO2.

Your next question comes from the line of Noel Parks with Ladenburg Thalmann. Noel Parks - Ladenburg Thalmann & Co. Inc.: I had a couple of things. My apologies if some of these recurred already, and I just happened to miss them. In the Permian at Permian Moscow, can you talk about the five-acre down spacing out there and whether you had any locations that were put this year for five-acre?

Sure. Matt?

Yes, in the past year, there’s probably been 200 to 250 five-acre wells that's been drilled, and there's been no, we've seen no degradation from the type curve from the standpoint of IP or a decline or otherwise, so they look very, very solid. I don't know off the top of my head how many five-acre locations we have booked. We do have an Analyst Meeting coming up next Tuesday that we’ll go into detail into all these different bookings of locations in the Permian.

I think we can -- suffice it to say, we did add some five-acre.

Yes, we did a tremendous amount of five-acre wells. I just don't have that number off the top of my head. Noel Parks - Ladenburg Thalmann & Co. Inc.: Also at Permian Moscow, where do you guys stand as far as looking towards water flood out there? I know there have been some planning in the past under the old owners, but just wondered where that stood now.

You go ahead, Matt.

Yes, I mean, right now there are no plans for water floods. We have so much primary reserves yet to recover and being able to drill down to five acres and get very good rates of return, I think that's the way to go today. And if there is a water flood potential, I think it'll be years down the road.

Yes, there was a successful water flood in the unit, not just operated by Arena or us. So there has been, you're exactly right, there has been water flooding in the Permian Moscow unit in the past. Water flooding and tertiary is really not something we'll focus on as much as drilling from primary production. Noel Parks - Ladenburg Thalmann & Co. Inc.: And actually, also looking out to the future a bit, in the Permian, of course the possibility of other zones, a deeper zone, I guess also some shallow behind pipes might not be as prolific as your main target. What sort of oil price environment sort of determines red light or a green light in terms of putting energy into evaluating those? Is there, if we say head us into a less volatile oil price environment where say we could count on $70 for the long term, are there things that come onto the plate that, say, $60 or $50 wouldn't enable?

I think you're asking is what price gets down to where the red light comes on? Was that... Noel Parks - Ladenburg Thalmann & Co. Inc.: Yes, especially as far as pursuing some of the more elusive deeper targets in the Permian.

Well, you bring up a good point. We don't know what's going to happen out in the future with oil price, and we continue to be very bullish. But the only thing that no one is taking into consideration is a dramatic drop in oil, so we hedge. And so whenever we look out in the next three years, we have a tremendous amount of oil that's hedged going forward. And yes, we might be giving up some of the upside, but we have years’ and years’ worth of upside that if we lose $30 or $40 a barrel, you'll probably see us continuing to hedge out into out years and locking in the rate of return. So what we look at, and to answer your question, we have almost 100% rates of return in the wells that we drill, so even down to $50 a barrel, we're going to be where it would be competitive with gas prices today. But what the key is, is that we want to lock in these current rates of return that we have, and so you'll just see us continuing to hedge as oil prices go up.

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

Guys, could you address your booking philosophy year-over-year? When I look at your reserves this year, you do have significant revisions on the gas side. And last year, you guys were pretty vocal about pointing out that low-value gas assets at other companies didn't really make a lot of sense. So could you comment about the philosophy a bit?

Sure, we still believe that. We still believe that a PUD is a PUD when it has PV-10, not PV zero plus $1. So we were very vocal last year. And we're the only company to write off all of our PUDs that didn't have PV-10. And then this year, also last year, we were very vocal to say that at $4.25 gas, we start to bring back on our reserves. And a reserve is a reserve is a reserve, that once it has PV-10 and so that's whenever we have gas that has PV-10 we’ll bring it back on the books.

So basically, that's just how the numbers fill up. Now the situation with your land position in the Mississippian, you've extended into Kansas and you've got a very large tranche and you're indicating maybe you’re done. Is it more that you've got as much as you want to get or is it that the play doesn't seem to extend beyond what's already been locked up?

The first. We have really as much as we think that -- we have said that in our capital, the capital we have in keeping 12 rigs working we can hold about 500,000 acres, and we're going to quit at about 900,000 to 1 million acres and use some of that for monetization.

And the last thing, in the Central Basin Platform, in passing, you've mentioned good midstream and you've already told us there's not a take-away problem. Can you specifically talk about both electricity and gas handling since that was a problem for Arena and maybe that would be something investors would like to hear specifically?

Matt?

Yes, one of the things that we did that we were very cognizant of when we bought Arena is the issues that they were having with both gas processing and also electricity. And prior to buying Arena after we bought -- even prior to buying the Forest assets, we had decided electricity was a huge problem out here. And we built our own 20-megawatt substation back in, I believe it was in 2009. Late 2009, we started one up. And so we had experience to do that and know that we need to do the same thing when we purchased the Arena assets. And so just last year, we started up another 20-megawatt system for the Permian Moscow field, and what that allows us to do is drill a couple of thousand wells that we’re going to add to that system. The other advantage of operating our own substation is we have very short downtime. If there is a problem, we have our own guys come out there and fix it and it’s often a 12- to 24-hour turnaround as opposed to maybe 10 days to several weeks. And so as a result, we’ve had very little downtime even with the freezing problems here recently, we didn't lose electricity as much as we just had wells freezing up. But that has helped out a lot. On the processing side, I think that what really helps us is that we do have a lot of leverage for the processes out there that Arena didn't have because of our size and the quantity of volumes that we produce. So we were able to negotiate very attractive contracts for San Andres that we just currently closed our negotiations, and it was very successful in not only upgrading our netbacks on both the residue gas and the liquids, but also, as part of negotiations, we had a processor commit to spending a lot of money to upgrade compressors and plant components. And so we continue -- we have a very active midstream crew. We continue to not rest on our laurels there, but also continue to look at other ways to minimize downtime such as building spillover-type facilities to other processors and pipelines as well. So it's an ongoing project, but we have made significant strides in the last year.

And the next question comes from the line of James Spicer [ph] with Wells Fargo Securities.

Just a couple of questions. To begin with, I just wanted to follow up on the natural gas reserve revision number. Am I correct in assuming that these are primarily PUDs that were added here and that the primary variable that enabled PV-10 to move beyond zero was the gas prices basically just moving from $3.40 at year end 2009 to $3.80 at year end 2010?

I heard that it was a question about the gas prices, but can you get maybe a little closer to your phone?

Yes, I was just wondering, first of all, just confirming that those are primarily PUD reserves that you’re adding through those revisions, and secondly, that the primary variable there was just gas prices moving from $3.40 at year end 2009 to $3.80 at year end 2010.

Yes, the answer is yes. And that's exactly a pricing that brings -- the reserves were never gone. They just didn't have PV-10 last year, and they have PV-10 this year. And they’re held by production in the Permian field, most of the gas reserves we had.

And then secondly, you mentioned that given all your asset monetization announcements to date, you are increasing your expectations for proceeds from $700 million to $900 million. Do you think that, that additional $200 million fully fills your cash flow shortfall for 2011? And then on a kind of related note, can you give us any idea on potential timing of further horizontal Mississippian monetizations beyond your royalty trust structure?

I'll hit the second part, and then pass to James for the first. The timing on Mississippian is that we just have now just finished buying the acreage, so have potentially the first asset monetization in late March, early April. We'll continue to look for ways to monetize, but we're in really no hurry because we do have long term on our leases. So I think throughout the year, we'll continue to do several things. We'll look at other asset monetizations like we've already done. We will talk to other people about either joint venturing with us or partnering with us selling acreage or we'll decide that we want to develop areas ourselves and maybe look at other ways to bring in capital. So I think that we're wide open to other ideas. I have said that our goal this year would be to not only get to $900 million but to really start pre-funding 2012.

James. So just wrapping up on '11, yes. With $700 million of pending and closed sales kind of at the end of April, that puts us well on the way to this $900 million goal. So yes, with another very roughly $200 million, that would fully fund us for 2011.

And your next question comes from the line of Philip Dodge with Tuohy Brothers Investments.

The positive reserve revisions have been pretty well covered, but just interested whether there was any performance in that or whether it was oil price.

Yes, on the revision, it's primarily oil price.

And on the royalty trust, if demand were supporting it, would you consider raising the size?

I don't think we can comment about the royalty trust, sorry.

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

How do you see the 2011 production growth generally progressing throughout the year? Did you have significant weather impacts in 1Q and taking all that into account?

Sure, I'll pass to Matt.

Well, our guidance, I think, is about 16% over 2010. As far as weather-related problems, we did have a pretty brutal cold weather storm that blew in really across the Southwest here, but it hit our Central Basin Platform production pretty hard in February. And we were basically down from February 1 through 14 for two weeks there. And not down 100%, but down quite a bit. And even though our field guys did an excellent job at getting everything back on, we probably lost 100,000 barrels of oil equivalent during that process. But overall, that is built into our guidance model, unless there is something else that hits us hard, I feel very comfortable about our guidance.

And do you see it kind of evenly growing throughout the year? Or is it kind of front-end loaded?

Yes, really, I think it's going to be a little bit back-end loaded because right now, we're getting -- for example, in the Mississippian horizontal play, we have 12 rigs out there, but four of them are drilling saltwater disposal wells today just to get caught up on the need for water capacity but also to set us up for future development. And then in the next two months, we'll roll those rigs over into drilling the producer. So we'll go from eight rigs to 12 rigs drilling producers in the next two to three months. So as we do that, we'll get a more of an accelerated ramp up in probably Q2, Q3. In the Permian, I do see a pretty steady ramp up there. We have 16 rigs running, and we've been running that for a little bit now and with no change in rig count. I think that will be more of a linear growth pattern.

And in the Mississippian, it is important to note that we keep rigs working in a rather tight area and most of our rigs because of the saltwater disposal systems put in place. And that disposal system, while it costs money up front, it saves about $2.50 a barrel to haul water with trucks. And so we have moved much more aggressively than anyone in the play to make sure we drill disposal wells and cut that cost out.

And in the Mississippian with the acreage that you currently have, how much of that do you think has been de-risked at this point drilling horizontally?

The whole key to the play was it was de-risked because of all the vertical wells. So, I think, about this is that in that play, in particular, there has been 17,000 wells drilled that are all vertically producing from the same zone. And all’s you're doing is drilling a horizontal well connecting up the same rock that we already have the type curve on and know that there's oil in place. So whether it's drilled horizontally or vertically, it's the same rock with just an eight to 10 fracs bringing on eight to 10 wells instead of one vertical well. But if you look at our presentation, I think on Slide 12, you can see that between us and others, there has been horizontal wells now drilled in Payne, Pawnee, Noble, Kay, Grant, Woods and Alfalfa and Barbara County, Kansas. So there's a lot of horizontal activity also. It's just something to think about is that this play in the Permian Basin and the Central Basin Platform have decades of production. And so as the industry goes into new or newer plays without any vertical controls, it's not to say they won’t be good places to drill, they might be fantastic, but there's no way to know until you get two or three years of production of where that decline curve's going to go. One thing about the Haynesville is that it now looks like it has a much steeper decline than what was projected in June of 2008. That's really only because there's a couple of years of production history to look at.

So the newer areas that you've been adding in the Mississippian, they have as much vertical activity as, say, some of your earlier areas?

Yes. If you look across the early areas that we looked at in Woods, Alfalfa and Grant, there were about 1,200 wells across that play that were drilled vertically, and that's where we started, but there's tremendous control. In fact, if you look at the map that we provide again on that same slide, you can see that where the vertical well control is to the south and to the north.

And just finally, with the credit facility, any potential there that you see for increases based on the year end reserves or PV-10 numbers?

We do have a determination coming up in April. And given the increase in our PDP PV-10, we've got plenty of coverage there. So we'll work with the banks coming up in April to determine that, but have plenty of room. The facility is $850 million. We have $382 million drawn as of now.

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

First, on the Mississippian play, you feel pretty good about the delineation from vertical well control and whatnot. But have you seen any variability in the horizontal wells that tell you what may be better ears than others, what is that specifically? Because I know, for example, like in the Granite Wash, we're now finding that sometimes the vertical wells don't -- I mean, it’ll tell you what a horizontal well may necessarily do. And then secondarily, your production target that you have for this year, just to confirm, with this royalty trust structure, you'll still report that the total production combined for both entities, and that's what your guidance is set at?

Yes, you're correct, the royalty trust structure does have all the production coming through the company. With regard to the Mississippian, that's one of the reasons we put down all the wells we drilled. And if you noticed, there's a wide variability of production location to location. So we don't anticipate every well coming on at 800 barrels a day, and we don't anticipate every well coming on at 100 barrels per day equivalent. But what we do anticipate, that is over the course of a play, that you can have this 240-barrel a day type curve through first 30 days’ production, and then you should be able to feel more comfortable in the ultimate decline of the wells because you have all the vertical wells that show basically a 2.5 B factor. And were coming in with a 1.5 B factor in our type curve. So again, it's just how many years’ worth of production, knowing the decline. And then the variability, you really can't tell because it has to do with the permeability across a 4,000 foot lateral in between well to well. And so what I always try to say is that we're going to have very good wells mixed with poorer wells or even just good wells across the play, and we don't see yet that there is any certain one spot that is better than others. And that includes us or our peers drilling. So we're not claiming our acreage is better or worse than anyone else.

And you say you're using like a 1 ½ B factor, and so when, I think you said Netherland, Sewell gave you 409 MMBoe for the total EURs. What is baked into your guidance, what does that B factor imply in terms of a 30-day rate?

Yes, it’s a 1.5 B factor on the hyperbolic.

Yes, so what will be the EUR on that well that you used in those?

Did you ask EUR?

Yes, you’re using a 1.5 B factor?

Yes, the EUR is the 409,000 barrels of oil equivalent.

At a 1 ½ B factor?

Yes, that's correct.

Now what we've done is to say this is a very large area, and we say 300 MMBoe to 500 MMBoe. Now if you were to use a 2.5 B factor in that same type curve, you'll be above 500,000 barrels of oil.

So what would be the 30-day rate on a well that has an EUR of 409?

I think it's 244 Boe.

Yes, 244, 245 barrels equivalent.

So what are you using in your guidance? You’re using that 244, 245 Boe?

Yes, that's how we model it.

Now currently, we're above that on the wells drilled to date.

And your next question comes from the line of Jeff Robertson with Barclays Capital.

I can't remember if you talked about this in your comments, but the guidance increased on oil up about 10%, can you talk about how much of that is due to the increase in capital versus how much of that you all are attributing to the performance uplift in the Miss?

Well, I think I can't break those two apart. I think they're all interrelated. Just oil guidance itself is going to be up 67% from 11% to 10%. Overall guidance is up 16%, and we'll have a decrease in gas this year still. But it's all driven by number of wells we drill and our model of how quick we put them online. What I don't want to do is start breaking out oil gas by plays and by field area. But obviously, the bulk of our production growth is going to be where we drill, and that's in the Permian and in the horizontal Miss and everywhere else, Piñon, East Texas, Gulf Coast of Mexico will decline.

And then you said on your saltwater disposal you were building in the capacity into 2012, so once you start moving those rigs over to drilling oil wells they’ll pretty much stay drilling oil wells until at some point next year when you need more?

Yes, that's generally correct. Like I said, we have four disposal wells going right now. We're going to three next week, and we’ll really back that out to one rig is the way we budget it right now. But I can see that one rig going away probably midyear and going over to drilling producers. And so yes, the plan is to get plain disposal wells out there, so we can spread out our drilling and then just plan accordingly when we need to pick up additional rigs to drill disposal wells or convert a rig from a producer to a disposal well.

And, Jeff, just keep in mind that can change if we move out and start drilling additional areas inside the Miss. We'd need to have more disposal capacity as we bring in new areas.

And just in terms of the play with the water handling, I guess the saltwater disposal systems you all are putting in do translate into a cost savings versus the well. So I guess as you look at newer parts of the play you have a little bit of variability in the costs until you get those systems in place, is that correct?

Sure. It's front-end loaded to what's putting in disposal.

And your next question comes from the line of Mike Breard with Hodges Capital.

One problem you had from a stock market point of view in the West Texas [indiscernible] is that you were the only ones there whereas people drilling in the Haynesville or Bakken, you had press releases coming out constantly from other operators. How many people are actively drilling now in the Mississippian? And has that number increased? And have you had calls from others looking to joint venture with you in the Mississippian because you were in there early?

Well, let we think about. There are a number of private operators that are drilling and do we know how many rigs are working in the whole play? 19 rigs in the whole play, of which we have eight. And four of ours are drilling disposal wells, so there are other operators drilling in the play. I think interest is -- six other operators, thank you -- getting all the numbers given to me, so very nice people here. So we do have other operators working in the play, there is interest in the play. And really for us, it's more a question of what brings in the highest rate of return. We made a decision that for us, a royalty trust idea, if that were to come through, is a better option initially than doing something else. It doesn't mean that our ideas won't change as the year goes on or do a number of things.

But have people started to have more interest now? Has anybody contacted you yet, talking about a joint venture knowing that you have excess acreage?

I had a lot of discussions throughout the week with a lot of different people, so the play has more interest today than it did a year ago.

[Operator Instructions] And your next question comes from the line of Devin Geoghegan with Zimmer Lucas Partners.

I went to an acreage expo recently, and a lot of the geologists that I talked to seemed to think that the drainage is more in 160s. Even though the rock is permeable, it appears to be compartmentalized, so to speak. So a lot of people that I've talked to think that it might actually work on 160s. I know you guys have been kind of taking the average of 320/160, but are you seeing any evidence that would make you more bullish on the density?

Well, we have moved from 320s in the last year down to about 215. So three wells per section, and we're not seeing interference as we’ve drilled wells that close together. We've done that several times. So there's no argument that I think -- we've seen other people drilling 160s, and I can't argue that it won't go to that. We're prepared to go to 160s, if that drainage is the appropriate drainage. Keep in mind, vertical wells were drilled on 40s and even 20s, so it's possible that we can move down.

And your next question comes from the line of Robert Carlson.

I wonder if you could comment on some volume guidance for 2011, '12 and ’13 and also update it on your current hedges. I know last night, I saw you on Kramer, you mentioned that those hedges had been modified.

Sure, we gave an update on our current hedging, and we've also said that we're willing to add 2013 at kind of the $100 range on crude oil, not making a bare case for crude oil by any means, but just wanting to make sure we can lock in 100% type rates of return if we're correct in our service costs don't move up in the next couple of years. And I think the preponderance of evidence is that we're not seeing service cost inflation as others do. And I don't see the industry changing because it is very difficult to move in and buy shallow carbonate reservoirs because they're not as abundant to buy big acreage positions as zones that have never been drilled before in places that have never produced. And so like in the Simpson Basin platform it would be impossible for us to have ever gone and bought the acreage and to drill the wells like we are today. So we had to make the acquisitions and that, and we had to be there early to do that. As far as guidance out into future years, we're only giving guidance out through 2011.

And that is what now?

On production?

Yes.

They are on production, right?

It's 23.3 million barrels of oil equivalent.

Yes.

Did you say we do have some $100 hedges in place presently?

We do have what, excuse me?

$100 hedges.

We put on some $100 hedges, over $100 hedges, in 2013.

At this time, there are no further questions in queue.

Well, thank you, as always, for joining us for this call. And if there are any additional questions, be sure to give us a call then. Thank you.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect. Have a wonderful day.