SandRidge Energy Inc (SD) 2010 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the 2010 third quarter SandRidge Energy earnings conference call. My name is Modesta and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr. Dirk Van Doren, Chief Financial Officer. Please proceed, sir.

Thank you, Modesta.

Last night, the Company issued a press release detailing SandRidge's financial and operating performance for the third quarter of 2010 and we'll file the 10-Q on Monday. If you do not have a copy of the release, you can find a copy on the Company's website, www.sandridgeenergy.com.

Now for the forward-looking statement. Please keep in mind that during today's call, the Company will be making forward-looking statements which are subject to risks and uncertainties. Actual results might differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed in the Company's filings with the SEC.

Today's presentation will include information regarding adjusted income and adjusted EBITDA and other non-GAAP financial measures. As required by the SEC rules, a reconciliation of the most directly comparable GAAP measures are available on our website under the Investor Relations tab.

Now, let me turn the call over to Chairman and CEO, Tom Ward.

Thanks, Dirk, and welcome to all of you to our third quarter conference call.

I want to start by telling Dirk that we wish him all the best as he moves on from SandRidge. I have known Dirk since 1994 and have worked with him over the last four years on a daily basis. I'll miss his wit and tireless work ethic. However, I fully understand that there are changes in all of our lives that we have to be prepared for. In this case, Dirk is leaving us with a transformed Company that is focused on a high-priced commodity with fantastic rates of return.

I am personally more enthusiastic about our Company now than any time since June of 2008. Over the last two years we have made some strategic changes that have separated us from many of our previous gas-weighted peers. We decided to significantly change our Company by enhancing our exposure to oil. We did not focus on tight shale plays with high land cost, but instead focused on low risk, high permeability, oil carbonates in proven-producing regions.

We've made our first move into the Permian Basin at a time when adding conventional oil assets was out of favor. The resulting Forest and Arena acquisitions, closed just eight months apart, have transformed our Company and positioned us to excel in the current environment. Just in the last twelve months, our oil production has grown from about 8,000 barrels a day to over 28,000 barrels of oil per day.

Keep in mind, this production is a high grade mix of 83% crude oil and only 17% natural gas liquids. The natural gas liquid space is obviously crowded and potentially faces future processing capacity issues, or worse, an oversupply of natural gas liquids. We are, therefore, not relying on a market that may remain depressed for some time.

We have a very straightforward strategy of drilling low risk, high rate of return oil wells in stable service cost environments and we lock in those returns with hedges. We currently have more than 22 million barrels of future oil production hedged at over $87 per barrel, or more than $2 billion of future revenues from plays that will generate between 50% to 100% rates of return.

Company-wide oil and liquids production has grown from less than 8,000 barrels a day in the third quarter to over -- of 2009 to over 24,000 barrels a day for the third quarter of this year. We now produce just over 28,000 barrels per day. The rapid growth in our oil production is primarily the result of acquiring great assets and then executing on them.

Production from our Forest assets is up from 7500 barrels equivalent per day at acquisition to about 11,000 barrels equivalent today. We believe that we will have similar success with the Arena assets as we move over the next few quarters. With that said, Arena produced a little over 9100 barrels equivalent per day in Q2 and we're now up over 10,000 barrels of oil equivalent per day.

Our timely move to oil is now expanding with the horizontal Mississippian play in the Mid-Continent. This oil play fits us perfectly, as it's in an area we know well, it's large, shallow, inexpensive to drill, and has a tremendous amount of vertical well control. We have been quietly and patiently building our acreage position and we have now amassed over 400,000 acres with the goal of leasing at least 500,000 acres by the end of the year.

We are moving from drilling our first well in January to having five rigs in the play today and plan to further expand to ten rigs in early 2011 as we drill over 100 wells in the coming year. To give you an understanding of the success to date that we have had in the play, we have posted all of the wells we have drilled along with our drilling costs. The 30 day peak rate, the 30 day rate, and the last 30 day rate.

Based on results to date from our wells and others, we're achieving 100% rates of return, and we have increased the per well estimated ultimate recovery range to between 300 MBOE to 500 MBOE. Considering reservoir certainty, drilling economics, infrastructure, and available services, we believe this play competes with the very best oil plays in the United States.

Given our performance in the Permian Basin and the opportunity to expand our acreage position in the horizontal Mississippi play, we have raised our 2010 capital budget from $875 million to $1.1 billion and have also set our 2011 budget at $1.1 billion. With this capital, we expect it will be able to grow overall corporate production to 21.6 million barrels of oil equivalent in 2011; more importantly, a further shift to an increasingly oil-weighted production mix.

On the oil side, we expect to grow production to 11.2 million barrels of oil in 2011. These growth productions have approximately 1 million barrels equivalent of production removed through our divestiture processes.

To fund our proposed 2011 capital program, we have raised $300 million in preferred capital including the greenshoe, and will continue to review divesting non-core assets. We will also potentially monetize a portion of our large land position in the Mississippian play. We have the data rooms open on the Wolfberry and Bone Spring packages and should sign PSAs this year with projected closings in January of 2011. We have also identified other non-core oil packages in the Permian Basin that could be sold in 2011.

We believe the preferred offering we announced last night along with the proposed asset sales and the ongoing cash flow from operations will more than bridge the projected shortfall in 2011 and greatly increase our flexibility going forward. The funding plan we laid out affords us the flexibility and time to find the proper balance between proving out the horizontal Mississippian play to further enhance its value, and finding a partner or buyer to help us fund the development of this very large play.

We have chosen to stand apart from the crowd. When natural gas prices moved against us, we did not keep drilling gas wells, but actively acquired oil properties. We have kept our gas assets awaiting a more advantageous gas environment when they will again be very valuable. However, we do not see an end to the difficulties in the natural gas markets until the Haynesville rig count diminishes. I do believe when that happens, natural gas prices will rebound substantially and investors will benefit from the upside of our natural gas assets.

In the meantime, we are well positioned and actively drilling high rate of return oil wells. I will now turn the call over to Dirk.

Thanks, Tom.

For the third quarter, we are continuing to see the impact of our strategic transition as oil revenues, including hedges, accounted for 68% of commodity revenues for the quarter, up from 56% in the previous quarter. EBITDA for the quarter was $149.2 million, and including the out -of-period hedge settlements, it was $197.4 million. We're in compliance with all covenants at the end of the quarter and the balance on the revolver in early November, net of the preferred transaction and greenshoe, was about $230 million.

A few of the numbers in the quarter need explanation. First, G&A was higher because of two one-time items. There was a $10.7 million cost related to the merger costs with Arena and there was a $16 million cost related to a legal settlement. Second, the 40 -- $457 million tax benefit related to Arena. The transaction was a merger for tax purposes, and Arena had approximately $250 million tax basis in the assets, and we had to write the assets up to fair value of about $1.6 billion.

That created a $460 million deferred tax liability, and SandRidge was carrying a $1.1 billion deferred tax asset with a full cost valuation allowance created by our 2009 impairment. With the enclosing of the Arena transaction, we we're able to use part of our tax -- deferred tax asset to offset the liability, hence the tax benefit. We still have over a $650 million deferred tax asset with the valuation allowance.

Since our last call we have added over $775 million to our hedge book. Over half of the amount is crude oil in 2013 and a portion is natural gas in late `10 as well as `11 and the first half of `12. We currently have $2.3 billion of revenues locked via swaps and that could easily rise to over $3 billion in the next three to six months.

Finally, I would like to thank Tom, Board of Directors, and all the SandRidge employees for a fantastic experience these last four and a half years. I look forward to facilitating a smooth transition to my successor, who will also enjoy the support of an excellent accounting and finance departments. I wish everyone in this SD family all the best, as the future of SD is brighter than ever.

That ends our prepared remarks. Modesta, we are ready to take questions.

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

Morning, guys. A quick question on realized prices, Tom, as you kind of see going forward. I guess, number one, just kind of -- as you see the mix, Tom, between the oil and liquids, how do you see that kind of playing out? Looked like maybe the realized prices were down a little bit because of that.

And then secondly, just kind of the differential as you see that, you know, as you do a little bit more horizontal Mississippian kind of what you see on diff -- I guess the overall differential of oil sort of on a go forward basis?

We -- we're at 83% crude so we, I think we model moving to 85% or so -- basically staying the same as we are now on the liquids to crude mix. As far as differentials, just as we do -- you know, with that -- 15% to 17% liquids that the differential should stay about what we have today. The Miss is crude oil, the liquids are left in, in the gas stream, the Permian drilling is 85%, 86% crude. So, I mean, on the margin, we'll move up a little bit on crude to liquids, but it should stay fairly close to what we -- what we've guided here.

It appears that he accidentally dropped out of the queue.

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

Yes, Tom, can you talk to us a little bit about the ramp-up logistics? So in terms of capital spending, we all tend to look at a number and want that all to be for well drilling. But, can you talk about what component of spending right now is for stuff like roads and infield stuff that might impact the way we look at capital versus capital being purely for well drilling?

Sure. Most of the increase is due to actual drilling wells. We added about 90 wells this year that we didn't anticipate, and then the leasehold budget is moving up with the horizontal Mississippian. The -- I mean there are expenses with infrastructure and I can let Matt hit on that in the Permian. But, most of the areas we drill in are in pretty easily-accessible oil fields, including Oklahoma and in the Permian.

So we address our salt water disposal in the Mississippian play of Oklahoma and Kansas with drilling wells that add $200,000 per well cost there. But inside of our well cost, it really does take care of building roads and taking care of the infrastructure. But maybe, Matt, you might hit on the Permian with what we're continuing to upgrade there.

Yes. Duane, in 2011 we're looking at, you know, capital dollars that are associated -- directly associated with drilling. It's going to be right about $890 million. And the way we AFE these wells, the roads and location are built into the AFE and it's -- you know, I don't have the number off the top of my head, but I'm guessing it's probably 5% of your cost.

Your percent of roads and location in the Permian may be a little bit higher than your percent of roads and location in the Oklahoma Miss just because the well costs are lower -- you know, the total well cost lower in the Permians, it's higher in the Miss. But it's just a -- probably in that 5% range.

Okay. And then in terms of the big step up in activity, you've had the capacity to execute at a high level in the past when you were drilling lots of gas wells. As you go forward here and step up the activity level even more, what kind of gaps are there that concern you the most in terms of staffing or equipment, say?

Well, you know -- I'm sorry.

(inaudible) go ahead.

Okay. Yes, just, just kind of giving you a little bit of history. In 2008, we peaked out at 46 rigs in the summer of `08, and going into 2011, we're going to keep our total rig count at 27. So from an execution standpoint, it's nothing that we haven't done before. The -- where we drill is going to be a little bit different. But, what we're looking at running is 16 rigs in the Permian Basin.

Our Fort Stockton service base is not far from there, it's just out there between Permian and the Pinon Fields. So, instead of rigs and equipment moving south, it's going to move north a little bit; so not a big difference there.

In Oklahoma, we currently have five rigs running and we're going to be ramping up to eight rigs within a year, and probably add another two rigs, I'm guessing, in February of 2011; so not a huge ramp up there. So I don't see a -- I don't see any problems going forward with our program. We're already at 23 rigs today and we're going to 20 -- you know, 27. So, it's not a big move.

As you mentioned, Duane, logistically, it's challenging in the Permian Basin, especially where we drill in the Central Basin Platform because of the -- how quick the wells are drilled. So we do have to staff up, but move staff over to take care of that with engineers, land, and geology.

We're running 16 rigs that can -- we complete two wells a day in the Permian Basin, so we -- we're going to drill 650 or 700 wells next year in the Permian. So it's just a lot of activity and that's probably why you don't see a lot of other companies trying do this because you do drill a lot of wells in a pretty small area in the Permian.

Okay. And then on the new capital raise. A more cynical person might think, gee, the auction for your Wolfberry and Bone Spring stuff might have been done sooner than the January type PSAs that you're talking about. And again, a suspicious view would be, you know, stepping up the program and raising capital ahead of those auction results might be because you're worried about the auction results. How would you respond to that?

Well, we don't have any results in. The data rooms are still open so I don't know. We could have preempted if we would have cared to but I think we'll have a better outcome by going through the whole process. We're selling oil assets in an oil market instead of trying to sell gas assets in a depressed market, so I'm -- I tend to be pretty optimistic.

What the offering does for us is give us tremendous flexibility. If you really -- I believe that the Mississippian play is a unique play today. One of a handful of plays that I have ever been in that I think can change a company. And my -- the reason I believe that is because you can control your costs.

The -- with the high pressure frac-ing really being the main culprit we're seeing in other areas that costs are tripling and -- or more, and what it takes to complete a well. And I just like being able to control our own services and then have the vertical well control to really know how large a field can be is -- that has over thirty years of production history and it's a carbonate.

So those things make me very, very bullish on the Mississippian. So what the preferred does is it gives us more time to look and drill Mississippian wells and determine how we want to sell our excess acreage. We've made it very public that we have more acreage than our Company is going to be able to take care of, and I think that in the next year you'll be able to see us not only monetize the assets that we're talking about in the Bone Springs and the Wolfberry, but now we'll have time to get the maximum amount and -- that we think we can out of the Mississippian.

And only time will tell is -- how successful we are with that, but I believe that my -- I won't say it's the best play in the United States, but it's got to rank very, very close if it has the scale that I think it does.

Okay, and then finally, to follow up on that, in the Mississippian, when you guys daydream about how good it could be, you also daydream about what might not go well. Do you think it's going to be -- two years from now, let's say, is there going to be some more aha moments about the rock variability across the play? Or it is going to be that your completion style changes? Which, which would you predict is going to be the bigger unknown?

Completion style. We already have too much control over the rock because there's thousands of vertical wells that would even -- you could even drill vertical wells in the play today and make economic wells. So all's we're doing is connecting vertical wells by drilling horizontally in a known reservoir that's been producing for decades.

Great, thank you very much.

Thank you.

Your next question comes from the line of Devin Geoghegan with Zimmer Lucas Partners. Please proceed.

Hi, I just wanted to understand -- it looks like in the press release you guys imply that the spacing on the Mississippi could be done on 160s. My understanding is the play is fairly permeable, and when I think about the Bakken and the Eagle Ford, you know, they talk about being done on four per 1280s and 160s. I'm confused why -- I'm just confused on the spacing you guys seem to be implying.

Sure. We anticipate drilling two wells per section, so 320 acres. But, if you look at the vertical well control, you see those wells are drilled on 40-acre spacing and -- I think that we've at least heard from some of our peers that they think the wells will be drilled down to 160s. We don't really know yet. We feel very comfortable. We've seen wells drilled within the 320-acre spacing, or two wells per section, and those wells are -- don't appear to be communicating.

So we're very comfortable with 320s, we're hopeful that we can drill down to 160s. We're not seeing a huge fracture component to this, so it is -- it appears to be more matrix porosity, and that would tend to make you want to feel like you could drill those a little closer together. So it is early. We're not saying we can drill on 160s, but I don't think that's out of the question.

Got you. And then my last question is could you give -- of the 62.5 BCF of gas in 2011, could you all give a breakdown by region? Just to help us reconcile?

Sure. Matt, do you have those?

Yes, I think so.

Matt's going to pull that up. If we can, maybe take one other -- Devin, do you have another question on that?

No, I just wanted to understand where the gas -- where the big decline in the gas is coming from.

Sure. You know, we're going to decline -- we're not going to be drilling gas wells, so we'll have a very steep decline next year, probably around 18% to 19%.

All right. The breakdown, the 62.5 BCF of gas is as follows. The Permian Basin, we're looking at 11.2 Bs; the WTO, 30 Bs; East Texas, about 9.5 Bs; Gulf of Mexico, about 1.5 Bs; Gulf Coast, 3.8 Bs; and the Mid-Continent, about 6.8 Bs.

Just on the Mid-Continent, given all the associated gas with the Mississippian oil -- because it's like 47% gas -- I would have thought that the amount of natural gas coming into the Company would have been substantially higher. Where is all the gas going? Because that's what I don't get. I actually had gas production much higher than you all have it, mostly because of the associated gas with the Mississippian wells. Where's it going?

Well, over half our production currently is still gas. We're producing about 380 million cubic feet of gas equivalent a day and I think 54% or 55% of that is still gas, and we're only running one pure gas rig, and that's going to be in Pinon.

So we still have -- continue to have gas decline in Gulf Coast, Gulf of Mexico, East Texas, as well as the Pinon Field. And, yes, we're going to make some of that up in the Mid-Continent, but obviously not, you know, not all of it. And what happens is we're probably offsetting maybe 20%, 25% decline down to maybe 18% decline.

Okay. Thank you very much, guys.

Yes.

Sure. And keep in mind we're just now getting started in the Mississippian, so that production will ramp up over time. We have only moved just recently to five rigs. We'll be moved to eight by the end of the year. It will start to ramp next year, but that -- the overall production in the Miss probably the hundred wells we drilled will be weighted towards the end of the year, not the first of the year. So I think that production will be coming on more in 2012.

Okay, thanks very much.

You bet.

Your next question comes from the line of Jeff Robertson with Barclay's Capital. Please proceed.

Thanks. Tom or Matt, just a follow up to the previous question, can you say what the Mid-Continent contribution would have been, or is expected to be in 2010?

In '10 or '11? '10?

In '10. Because it would -- so, 6.8 is your 2011 number. Do you have a number, a rough number, of what you think you will get out of that area in 2010?

Let me get back with you on that. I don't have it broken out just -- well, just a minute.

In the meantime, Tom, can you talk a little bit about your thought process in terms of allocating capital and spending, or, spending -- setting spending levels where they are relative to cash flow?

And, in the context of selling oil assets in the Permian to fund other oil assets in the Mid-Continent, maybe in that what your view of the rate of return and the upside opportunity is on your assets that you're marketing for sales versus the assets in conventional Permian and in the Mississippian where you are spending your capital?

Sure. As you notice, one easy thought is that we're selling our Bone Spring and keeping the Mississippian, or keeping most of the Mississippian. We're not trying to be in every play. And we have done that in the past. We've sold out of the Piceance, and sold out of the Haynesville, and sold out of the Cana. So whenever we look at the different plays, we've made our choice. And our choice for our Company is going to be the vertical Permian and the horizontal Miss.

Now with that, that doesn't mean that those plays are bad. It just means that in the Bone Springs, it looks like it's a fabulous reservoir to drill for. I just think it has a little bit more risk. It's early in the play, and I'm -- the wells look fantastic, but for us, focusing on the shallower and lower cost wells are where we want to focus. And so whenever we're evaluating, we do look for our producing wells the -- in areas we think we have lower rates of return than where we're spending capital. So that's the oil on oil.

When I look at, you know, why we would press the balance sheet and move forward with an aggressive CapEx, is really just because we think it's a rare time here that we can have these types of rates of return, and the -- by keeping our CapEx up for a couple of years, our goal is to get to where we're cash flow neutral and still have $1 billion to $1.1 billion of spending. So that -- as we look out, that's what we're trying to achieve.

And then lastly, just in terms of the numbers on -- do the operating costs of the -- actually, the production costs, do they include any amounts that might be related to under-delivery, either to OXY in the WTO or commitment fees to the legacy plants where you're pulling the gas out to put it through the Century Plant?

No. Those are offset by credits and efficiencies. We actually have a gain.

Okay. Thank you.

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

Thank you. Good morning, everybody.

Good morning.

Hey, Tom, could you just clarify -- how much do you expect to raise in 2011 from the asset sales including the Mississippian?

Well, we've set out $400 million to $800 million. Now, that obviously would more than fill -- if our need for capital in 2011. So as you might anticipate, we're trying to look forward to 2012.

Okay, that's helpful. And then in terms of the cash flow versus CapEx question that Jeff asked, at what point based on your model do you expect to be cash flow neutral?

I mean, a lot of things change and then of course in the next couple of years. But, you know, my goal is out in 2013 that all of this comes together.

Okay, that's helpful. And then since you're really ramping down, or you've ramped down the WTO drilling, are there any lease expiration issues there?

Oh, sure. We had lease expirations either way. But thinking about the WTO is, first of all, we've selected structures that we like. We drilled three structures outside of the Pinon Field and found commercial production on one. But we -- either way, even if we would continue to keep a very active gas program, we would be letting acreage go in the WTO outside of the structures that we want to keep.

Yes. So, Tom, for example, in 2010, 2011 and 2012, could you talk about how much acreage is going to -- how much are you going to let go?

Well, I mean, today there's not -- we have proprietary seismic and I think it would be very difficult for somebody else to compete with us in the area, so we don't anticipate spending a lot of money in the WTO renewing leases. Now, with that said, we had 550,000 acres of land in the West Texas Overthrust that -- I don't have the numbers off the top of my head, but I think will be expiring sometime between '11 and '14 or so, if we didn't do any drilling.

Okay, (multiple speakers).

We had some five-year leases, so.

Okay, so what's the number again? What is your total acreage there? And what -- how much is expiring 2011 to 2014?

I don't have the exact number. I think we have 550,000 acres in WTO, and most of that would expire by 2014 unless we have -- unless we decide to move forward with drilling. Now, we do anticipate that the gas prices will be back up in, you know, the next couple of years to where we'll put rigs back into the Pinon Field, or you'll have the option, if you continue to grow as an oil company and oil continues to be at $14 an Mcf and gas is at $6, $7, or $8, you might want to sell some gas assets.

The way I look at that is, that's your period of time that you could really pay down some debt. And I don't look at paying down debt as something that we're really looking at, but we do have -- in our mind, the oil growth is going to continue and we're going to have, for the size of Company of ours, we'll have excess assets. So that's kind of where I think about it.

Hey, Joe. This is Matt. I just want to point out that nothing in the proven Pinon proper will expire with the one rig running. We [are able] to meet all our obligations there to keep that going. And you have to understand, we have 1300 miles of seismic.

So we have this area mapped out pretty good and we will be able to pick and choose what we want to keep and what we want to let go. And because of -- we should have a couple of years to work that process, we don't have an exact answer for you of how that's going to pan out.

Okay, that's helpful.

And, you know, the whole idea of the Company, when gas prices are more attractive, is to not only fill the Century Plant, but to fill the legacy plants. And that's still all in the Pinon Field. That doesn't require us to drill anything outside of Pinon, which is all held by production.

That's helpful. And then the same issue, lease expirations as it relates to the Central Basin Platform and the Mississippian play, what are the lease terms on some of the newer leases that you have there?

The Central Basin Platform's almost all held by production with the acquisitions of Arena and Forest. And then, in the Mississippian, most of our leases are three years with a two-year option. So we feel like with a ten rig program if -- even if we didn't increase from a ten rig program, that we'll be able to hold the 250,000 acres that we had looked at originally as being the right size for us. That could change. We might decide to own more. We have more flexibility now. But that's -- we were looking at that as the right size initially.

Okay, so I guess it's a part of the outspend of cash flow is also you've got this acreage position and you want to hold it so you need to run ten rigs to hold that, at least 250,000 of it?

No, not really. The reason that you outspend cash flow is you make 100% rates of return.

Okay, okay. All right, very helpful. Thank you.

Thank you.

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

Good morning, guys.

Good morning.

Real quickly, just looking at slide 20 from your presentation on the horizontal Mississippian well performance, I'm just trying to tick and tie to the last presentation. And the last thirty days production numbers didn't really move. Can you kind of walk me through what's happening there? And, you know, is that because things are on pump? Or just help me digest how I'm looking at this?

Yes, Dave. You know, all these wells are on gas lift right now. And that's a very efficient way to move high volume of fluids. And what is turning out is that our production may be flatter than what we're declining. We run a model to get to the 386,000 barrels equivalent type curve. We run a model that has this thing with an initial decline of about 60%, and as we look at the daily production and then start updating our curve every day, it's looking potentially like it could be more like a 38% decline.

So that's the main reason your last thirty days is not moving very much, or at all, is this, potentially this thing could be flatter. And that's kind of the range between where we're at and getting up to 500,000 barrels equivalent.

Okay. And, and, on the same kind of theme but looking towards the front end of the curve, as we look at some of these, it looks like they're -- they go through pretty healthy dewatering phases. They flow back. Can you give me any color on, I guess, wells 19 and 20, in terms of coming out at slightly lower thirty day rates? Is that representative of water flowing back? Or do you kind of look at those as steady state?

It's just basically statistical over a large area. So we'll have some wells that come on at very high rates and some that come on at less. And it's -- probably has more to do with porosity of any given area than anything else. The water cut, basically, stays fairly static so it's not necessarily a dewatering except for the wells that we feel like we over-stimulated.

Okay, that's helpful; and then just a couple cleanup questions. On your DD&A guidance going forward, you know, it goes up substantially and I'm guessing that's because the reserve base becomes more oily, less gassy. But is -- if I look at that guidance going forward, does it also include or anticipate reserve revisions for next year?

It does not, Dave. We'll be -- and I would actually think that DD&A might trend down as we get our year-end reserves done. The bookings that would come in with Arena and the drilling activity, I think next year -- once we get year-end reserves done, that DD&A rate will probably be lower.

Great. And then one just more simple one on that as well. G&A for 2010, you had an item in the notes on it about other legal settlements contributing to that going higher. Can you just walk us through what those are?

Basically one settlement in the West Texas Overthrust over a disagreement on continuous drilling in a lease.

Okay, great. Well, thank you guys very much for the clarifications.

Thank you.

Your next question comes from the line of Wei Romualdo with Stone Harbor. Please proceed.

Oh, my questions have been answered. Thank you.

Thank you.

(Operator Instructions) Your next question comes from the line of Scott Hanold with RBC. Please proceed.

Thanks. Good morning.

Good morning.

Hey, just to go back to production -- though a few guys kind of hit on this, but I just want to make sure I'm understanding this. And one of the things you said is WTO gas is expected to be about 30 Bcf next year and I think that equates to something like 82 million a day. What did that average in the third quarter? Because I think we were on the 120 in the June quarter, and if I just sort of do some simple math and, you know, say -- you know, because it's a pretty linear decline curve around what, 15%. I have a hard time getting that low in 2011.

Do you have the number, Matt?

Yes. The WTO -- eyeballing it here at average -- about 107 million, 108 million a day in the third quarter.

Okay, okay, so it was down a little bit further than I'd anticipated. But it still -- I guess as you look into next year, if you're running a rig, one rig there, why does it drop so much? I mean, even if I -- like I said, take it down 15%, and then, you know, annual decline curve -- I just don't get to there.

Yes. You know, we have a -- we have modeled some extra risk in the Pinon gas basing the first quarter of 2011 and I think that's where the bogey is. We have -- we're in the process of converting our -- all our legacy gas plants over to the Century Plant and that's about 260 million a day of high CO2 gas at 35% methane there. So it's a pretty big chunk of gas that we're messing around with right now.

Right now we have about 85 million to 90 million a day running at Century, and we're experiencing vibrations with compressors and I'm hoping to get those items resolved and then move the rest of the gas over. But, you know, we're going into winter, we're starting up a new plant, so we have a bogey of about 10 million a day of methane risk in the first quarter of `11, which makes it probably maybe -- hopefully a conservative estimate, but what it does is it kind of contributes to, you know, 0.9 or BCF of gas in '11.

So, you know, I think instead of producing -- Company-wide, instead of producing on average of 180 million a day in the first quarter, we may be in this 185 million to 190 million a day and I think that would probably make more sense to you if we took that risk out on a straight decline. But we do have some -- you know, we are -- you know, we could experience some problems just converting everything over.

Okay. Is it reasonable to you sort of, you know, still that, sort of 15% more of a linear decline rate in the WTO with one -- I mean, with one rig? I mean that -- to me that should be a pretty conservative expectation going forward. Is that a fair statement?

Yes. Yes. I mean we have 18% decline model in the Pinon Field right now. So that's probably close to what you're thinking. Did you say 15%?

Yes, 15%. Yes, that's the number I was -- you know, for --

I think it's in that range. And I think it's going to be this 15% to 18% range with one rig running.

Okay. Fair enough. And looking at the Permian -- one question I have is -- you all provided that third quarter earnings supplement, which is -- which provides a lot of nice detail. And one of the thing I -- I'm just trying to cross reference. If I look at your Investor Update that you put out in sort of mid-October, in the Permian oil, there's a Permian oil slide where you identify 7200 Permian oil drilling locations and in your update today, you indicated there is 8073. Where did that extra thousand rig locations come in? I think this one includes 700 that are going to be divested. So it's, effectively, up almost 1500, 2,000 locations.

Yes, it's really up in the Fuhrman-Mascho Field. Initially, we were hesitant on booking five acre spacing but we look at our drilling in a year-to-date about a third, or maybe closer to half the wells been drilled on five acres and there has been no degradation at all on the type cure at the five acres versus forty acres. And so we've booked more five acre spacing wells. And that's (technical difficulty) big difference.

Okay, okay, and, you know, one last question. You know, looking at the Mississippian oil play, when you're out there identifying well locations, is there -- is something specific you all are doing about, you know, how you're going about this drilling? Or is it, you know, using what you know on, on some of the vertical well control that, you know, a lot of --

It's mainly, it's mainly statistical.

It's mainly statistical? Okay. Fair enough. Thanks, guys.

Thank you.

Your next question comes from the line of Philip Dodge with Tuohy Brothers Investment. Please proceed.

Yes, morning, everybody. If you said this, I missed it. So, at worst, could you remind me how much of the 22 million BOE guidance for 2011 is from the horizontal Mississippi?

Can you split that out?

Just the drilling. (inaudible)

Yes. We have not split that out, Philip.

Okay, fair enough. Maybe this one will be even harder, though. Okay, I mean, can you give me a tentative estimate on the increment that you would see by the end of 2012, say, if you could go that far out?

No. We're basically, you know, the play is so new that we're a little bit tentative here to start making projections out that far. But -- and we will have 100 wells drilled in '11, 100 more wells.

I think on that first question, of the 62.5 BCF in `11 of gas, we have about 6.9 BCF of that from the Mid-Continent. And I would probably estimate that just from -- I guess where you're talking about just from the drilling wedge of the horizontal Miss, that would probably be about 1 BCF of gas in there.

Okay, so let me just try one more on that. Would you expect the production mix, whatever the production is, to move out of this ratio of sort of 53% oil to 47% gas?

Continue to be at that ratio?

Yes.

We're hopeful that we --

Would that be consistent, Tom, as you move ahead?

We're comfortable with that. We think that in some areas of the play will be more oil, but we haven't yet proven that. So we're comfortable with the 53% today. We might be changing that during the next year.

Okay, thanks very much.

Thank you.

Your next question comes from the line of Richard Tullis with Capital One Southcoast. Please proceed.

Thank you, good morning.

Good morning.

Just looking at 2011 guidance at this point, I guess you're estimating about 59,000 barrels day after what you plan to sell. And I guess that's about what you averaged in the third quarter as well. I was just trying to reconcile the growth expectations for next year, given the amount of capital that you're dedicating. I guess, you know, why not a more robust growth rate?

Well we're growing in oil and not -- and letting gas decline. So I think we're maybe unique in this; that we look at the two commodities as totally separate. And, while everybody combines them, and MMBOE, obviously the revenue from one is much greater than the other. So whenever you combine everything together and project growth, you can say you're not growing, but obviously your revenue is much better by growing oil and letting gas decline.

Okay.

It's really that simple.

How much of next year's 21.6 million barrels is related to the Arena assets?

I don't think we even isolate out Arena by itself in our modeling as it's all part of the overall Permian Basin. We continue to have about 70% of our budget moving -- looking at the Permian. So we believe that the Arena asset will do like the Forest asset has done and really start to grow as we put rigs to it.

Okay. I know you put the -- your kind of blended Permian type curve out recently. When you look at your total portfolio there, what's your typical first-year production decline?

It's about 60%, just over 60%.

And what about the second year?

It blends in together. You end up with a -- at the end of the second year, with 6%. The final --

The second year is probably 30% to 40%.

Yes, and then you end up with a 6% final. Is that where you are?

Okay, thank you. And the Mississippian oil play, I know you have about 20 wells online so far. What are you seeing on LOEs in differentials?

Do you want to hit that, Matt?

Well, LOE, you know, the -- really, all the LOE has to do with compression principal for gas lift. Of course you have, you know, you have a pumper that's going out there. But the -- all our water disposal -- we drill water disposal wells. And we drill them to the Arbuckle, and it pretty much takes water on vacuum, so there's very little LOE related with moving the water around. I think we'll run right now is about, on average, about $75, $100 a month LOE per well.

Okay. What about price differential?

Well, price differential is -- for the bulk of this play, we believe, is going to be a couple of dollars off NYMEX. And the greatest gravity is about 35 API gravity. There is a small area to the west that you could dip below 30 gravity, and that differential would be probably $6 to $7 off NYMEX. But that's probably less than 10%, 15% of our drilling.

Okay. And then just finally, do you have any well cost increases factored in to the 2011 CapEx number?

As far as drilling and completion?

Yes.

No. We're using $2.5 million to drill and complete, and then another $200,000 for our per well allocation on the salt water disposal facilities.

And what about across the Permian and elsewhere? Do you have any cost increases?

No, we're not factoring any cost increases in the Permian. The -- we can drill probably 800 wells in the Permian next year. And so the, you know, half of that, or maybe more than half of that, is going to be in the Arena where we stuck with the same pressure pumping company that Arena used and we're in good shape there, and we also move in another frac crew in the Permian.

Now we have four different service providers pumping for us and the costs are pretty stable now. We have various agreements locked in from the end of this year to the end of next year, so I just don't -- I don't see any increases there. Plus we use a lot of our own rigs and services as well.

Okay. Well, thanks, very much.

We're just drilling different types of wells than the rest of the industry. We're not competing with the same types of services so we're not seeing any real increases in service costs and we're not seeing any backlog of getting wells completed. We'll complete two wells a day in the Permian Basin. We have no backlog in Oklahoma, either.

Okay, thank you.

Thank you.

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

Just as a follow-up on the capital. I think your 11 million BOE of oil production excludes the volumes that you plan to sell. Can you talk about what a potential sale of some of your Mississippian acreage would do to your -- to the capital program next year? I mean, I guess my question is you talk about $400 million to $800 million of proceeds. Does the capital that you also talk about reflect anything from a potential sale in terms of bringing in a partner? Or would a sale have an impact on your capital number?

No. the sale would not have an impact on the capital and we have taken the most conservative approach, assuming that we sell everything that we put in the slide. So if we were to raise $800 million that would just go towards the next year in 2012. And what our goal is is to bridge the gap across to '13. We'll see if we can do that or not.

And can you say anything about what kind of terms, or what you would be looking for in the form of a Mississippian partner?

No. We'll just look for the best deal we can get, obviously, but it could be -- it could range from any number of different types of transactions. So we're -- what I really like is that we're going to continue and you guys can just look as we bring on wells if they continue to get -- be as good as they currently are, which we think they will, we believe we will be able to have a very valuable asset.

Okay, thank you.

Thank you.

Your next question comes from the line of Mike Breard with Hodges Capital. Please proceed.

Good morning. First I would like to say thank you for having your conference call on Friday instead of Thursday. But second could you give us an update on your exploration program in the West Texas Overthrust and what the current drilling is and what you plan to do in 2011?

Oh, with the drilling plans in the West Texas Overthrust -- we only have one gas rig.

No, I mean the exploration plans. Do you have the prospects you'd identified?

We still have the opportunity to drill some wells if we choose to. We haven't made a decision to try to drill other structures yet. The gas in those structures, if there's commercial gas there, isn't going anywhere. And we really are just trying to minimize the amount of money we're spending on gas and so it's really just a wait-and-see attitude here of -- that's not to say we won't go drill an exploration well or two next year, but we don't have anything planned.

Okay, thank you.

Thank you.

Your next question comes from the line of Gary Stromberg with Barclays Capital. Please proceed.

Good morning.

Good morning.

Most of my questions were answered. Dirk, probably one for you. It looks like you reaffirmed your borrowing base at $850 million, relaxing covenants. There's also something that says it permits the sale of non-core assets without an automatic reduction in the borrowing base. What are those non-core assets? Does that include the Bone Spring and Wolfberry?

Yes. It's the assets that Tom and Matt have spoken about. And the way we went about it was we took those out of the borrowing base before it was approved. So with those asset sales, nothing would happen with the borrowing base. Just a little -- a little forward thinking on our part and hope that you won't see any change in the 850.

I guess as a follow up, you know, as I look at my model without asset sales, liquidity gets a little bit tight in 2011. Would you look to the high-yield market to term out some of your revolver to help free up some liquidity?

No. We really have very high confidence that we can get some assets sold there. They're oil assets and, you have to wait a month to see, but there's -- we could have already sold them if we would have chosen to, so I'm just not thinking about having no asset sales.

Okay. That's all I had. Thanks.

Thank you.

Your next question comes from the line of Ken Carroll with Johnson Rice. Please proceed.

Hey, guys, good morning.

Morning.

Quick question -- you had Apache yesterday talking about some of their Permian assets, in particular, some horizontal --

Ken, we can't hear you.

I'm sorry, can you hear me now?

Yes.

Okay. I'm sorry. Had Apache yesterday talking about some horizontal successes they had drilling in the Permian, and they seemed pretty excited about it. Have you all looked at horizontal drilling, or do you plan to test that at all?

We have not yet. We do know about the wells that are being drilled. So far we are very comfortable with drilling either -- you know, let's assume we drill a well in Fullerton or Tex-Mex and we drill down through some deeper horizons. You have basically four to eight different horizons that you can test with a very shallow vertical well.

And, you know, we have been asked questions about some of the high rate wells that we have brought on, and those are all because we have taken them down a little bit deeper. And so I'm -- I think that they're -- and we're very hopeful that there is an application that can be made horizontally. You just always have to weigh the cost of those wells versus how much oil and gas we're going to get out of them. We just don't know yet.

Got you. And is your acreage near the Apache acreage at all?

I'm sorry, I couldn't hear you.

I'm sorry. Is your acreage near the Apache acreage? Do you know?

How close are we?

We're not too far. They're a little bit north of us on the Central Basin Platform, drilling some horizontal in the San Andres. We're watching the program and, you know, if we think it makes sense, we're certainly not afraid to try it. But it's just still too early.

Drilling vertical San Andres wells are -- is pretty efficient process. We drill those in four days.

Got you. All right, guys, thank you.

Thank you.

Your next question today comes from the line of Brian Singer with Goldman Sachs. Please proceed.

Thanks, good morning.

Good morning.

Just a quick question on the land and size and budget for next year of $100 million. How much of that is land acquisition? And maybe you can give a little bit of color on where you're looking to acquire and whether there is potential for you to look to be more aggressive to the extent that you're successful in the drilling program?

Yes, I think first of all that land and seismic budget for next year for '11 is $50 million, not $100 million.

I'm sorry, that's right. Yes.

Yes. And the bulk of that is land. I think a small -- we hope to get to 500,000 acres by the end of this year in the Miss play, which I think we'll do or be real close. But we did budget about $10 million next year for that. And the $40 million just based on historical spending, we'll get lease sales that come up in the Permian. That makes sense to us and other areas that we'll bid on.

Thanks. I think if I'm reading it right, it does say it was -- it is $100 million versus $50 million previously. But we can follow up?

(inaudible).

I'm sorry, what? I'm sorry, Brian, what was that?

If I'm reading it right, I think it does say it was raised to $100 million from $50 million, but we could follow up after. Thank you.

$100 million this year.

For this year is $100 million, for next year is $50 million.

I see. Okay, thanks.

Okay.

Your next question comes from the line of Mitch Wurschmidt with KeyBanc. Please proceed.

Hi, guys. Just a couple of follow ups; most of my questions have been answered. But, just -- I'm sorry if I missed this, but what's the timing looking like on a horizontal Miss JV?

We don't have it planned. Actually it's -- and we haven't said we'll have a JV. So we just said that we'll market some leasehold and what we have now is optionality and as the play continues to get better, what we didn't want to have happen was to be forced to do something too early. So there's no time limit that we have now. We have brand new leases. We have a lot of acreage and we have wells that are coming on and meeting or exceeding our expectations.

Okay, appreciate the clarification on that. And then just a follow-up on an earlier question on this sort of gas production out of the horizontal Miss, is it just being a little conservative, I guess, or just -- you mentioned the wells being hooked on later in the year. I just feel like I -- when I model, I get a little more gas production out of that area. Are the wells -- is the gas production being hooked up right away on that part of it?

Yes. Once we drill a well, we can usually complete within three weeks.

But is it just -- what's the decline, I guess, for the gas side of those wells in the first year?

I think we're anticipating a basic [carbonate] decline.

Yes, what happens on the gas a little bit that makes it hard to model is while our water and our oil, we assume, you know, we assume is a kind of a constant water-to-oil ratio that declined proportionally with each other.

The gas, what happens over time, is the GOR increase as we draw the pressure down the reservoir. So you start out with a smaller gas/oil ratio and it increases to a certain point and then it becomes pretty flat, and then it rolls over with the oil and gas. So early on, you don't get peak gas as much you do -- might three months down the road on these wells.

Okay. That's really helpful. Thank you. And then just on the Pinon -- just what does LOE sort of look like for that field? Just compression and different things going on just for our modeling purposes?

Yes. For the Pinon Field in calendar '11, Mitch, I think we've got our LOE going from about $1 -- $1.85 or so average for '10 up to -- it may actually go up to about $2.15 area. That really just relates to volumes falling and a pretty sizable component of the cost out there being a fixed cost.

That includes workovers and production taxes.

Okay, that's great. That's really helpful, guys. Appreciate that. Thank you.

Thank you.

(Operator Instructions) Your next question comes from the line of Rhett Bruno with Bank of America. Please proceed. Hello, your line is open.

Hello? Can you hear me?

Barely.

All right. Hang on one second. Is that better?

Yes.

Okay, in the Mississippian/Oklahoma play, can you give any color on how much of the acreage you have now is outside of, say, the Woods, Alfalfa County areas? And have you drilled any wells outside of those counties?

Yes. We're not going to break down exactly how much we have in each area, but the majority of our acreage is in Woods, Alfalfa, and Grant. And we have drilled wells outside of Woods and Alfalfa.

Okay. Would you say they're more to the north than the south?

No, I wouldn't say.

Okay. All right, thanks.

Thank you.

I would now like to turn the call back over to Tom Ward for closing remarks.

Well, thank you and thanks, everybody, for joining us. As we have embarked over this last year to make change in the Company, I think looking back on it, we have made dramatic change and it's not always the easiest thing to do. So whenever -- we had questions last year when we started moving to oil, looking back on it now, we believe it was for sure the right thing to do.

And as we move forward, we're -- we've raised capital now to be able to fund going forward. So this is a critical time for us today, and we feel like, looking forward, that all of the work that we've done over the last year will pay huge dividends for us.

So that's a -- with that, I want to say thank you and just feel free to give us a call if you have any questions. Thanks.

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