SandRidge Energy Inc (SD) 2008 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q4 and year-end 2008 SandRidge Energy earnings conference call. My name is Becky, and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question and answer session towards the end of this conference.

Last night the Company issued a press release detailing SandRidge's financial and operating performance for the fourth quarter of 2008 and year-end, and it also filed the 10-K. If you do not have a copy of the release, you can find a copy on the Company's website, www.sandridgeenergy.com.

Also, you can sign up for all releases that will automatically be sent to you, and this is located under the Investor Relations tab.

Now for our 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 net income and adjusted EBITDA and other non-GAAP financial measures. As required by SEC rules, a reconciliation to the most directly comparable GAAP measures are available on our website under the Investor Relations tab.

I would now like to turn the conference over to Chairman and CEO, Tom Ward.

Thank you, Becky. Welcome to our fourth-quarter earnings conference call. We have in our office today Dirk Van Doren, CFO, and Matt Grubb, Chief Operating Officer.

Once again, SandRidge has delivered outstanding results. Our 2008 adjusted EBITDA increased 74% to $688 million. Production increased 58%. Our reserves increased by 42%, and our adjusted net income was $151 million before the non-cash asset impairment of $1.6 billion.

Operationally we cut our drilling from a high of 47 rigs at midyear 2008 to 13 at the year-end. We now have eight rigs working and plan on going to seven rigs in March. We have given our 2009 CapEx guidance of $500 million to $700 million and production in the range of 110 Bcfe to 120 Bcfe.

As we mentioned when we issued the preferred stock in January, we would only expand our budget to the $700 million level if prices improved, and we sold our Pinon midstream assets. Since January oil and natural gas prices have continued to deteriorate; therefore, we're currently running at a rig level that more closely reflects the low end of our $500 million to $700 million CapEx range for 2009. We are continuing to negotiate the sale of our Pinon midstream assets with the goal making a deal in the second quarter.

Our budget for 2009 will only expand to the high end of the CapEx range if we see a material improvement in commodity prices. Even at the low end of our budget, we will expect to fill the Century Plant Phase I in 2010. We have a proven track record of delivering consistent production and reserve growth through the drill bit, developing multiple reservoirs in the West Texas overthrust. Production performance data from nearly 150 wells shows that the Warwick thrust is one of the best natural gas reservoirs in the US. The Warwick thrust continues to expand both from a per well reserve standpoint, as well as the reservoir size. This world-class reservoir at approximately 6500 feet produces on average over 7.5 Bcf per well. This is up from 7 Bcf per well that we booked last year. In fact, the expansion area to the south shows that our last 17 wells produced over 10.5 Bcf per well. We cannot produce this zone to its full potential until we complete our Century Plant because of the high amount of carbon dioxide in the gas stream.

This reservoir would have been produced decades ago if not for the inability to treat large amounts of CO2. However, because of our joint venture with Occidental Petroleum, we are now going to be able to fully develop the Warwick thrust within the Pinon Field and produce up to 1.1 Bcf a day of total gas from this reservoir starting in 2011.

This will yield about 290 million a day of net methane to SandRidge from the Warwick thrust alone. This is a tremendous amount of gas to come from one field that no one had heard about two years ago and that only one company, SandRidge, has the right to develop more than 95% of the leasehold.

Our next challenge is to continue to explore across our nearly 700,000 net acres of land to see if there can be any other cumulations like the Pinon Field. We mentioned today that we have completed our third exploratory well outside of Pinon. The Big Canyon 121-1A is our third well we have tested in the West Texas Overthrust outside of the Pinon Field. It is located about 25 miles east of Pinon. All three of these 2008 exploration wells were drilled without the benefit of a continuous seismic data that we now have across the West Texas Overthrust. In fact, we would not have drilled the first two tests after knowing what we know today from our seismic interpretation.

The Big Canyon encountered over 500 feet of pay from the same zone as what produces in Pinon. This pay was approximately the same thickness as our good wells in the Pinon Field. However, the well did not encounter the fracturing that is associated with the prolific producers in Pinon Field. While the Big Canyon did not adjust to commercial rates, the gas was sweet with only trace amounts of CO2, and we are very encouraged to find pay in the Warwick thrust this far away from Pinon Field and also encouraged with the progress we are making with our 3-D seismic work.

We also drilled two vertical wells in East Texas that penetrated the Haynesville Shale section and have tested one. The vertical well that was tested produced an initial rate of 1.5 million a day and encountered 260 feet of Haynesville Shale. The second well logged 288 feet of Haynesville Shale. These two tests are in the area of very good Cotton Valley in production in the Oakhill Field in Rusk County, Texas. We know by offset log correlation that we can achieve over 300 feet of thickness by moving into our [Blocker] Field acreage where the majority of our HBP acreage is held. Our own drilling results, along with the recent discoveries by Penn Virginia, XTO and others have further substantiated that our East Texas Haynesville acreage holds tremendous value.

In Northern Louisiana we have more than 13,000 acres of Haynesville potential and currently have one well drilling at which we have a non-operated working interest. Therefore, we should know very soon how the potential of this acreage is for Haynesville development.

We are not shell experts, but we feel very fortunate to have over 36,000 net acres in this Haynesville play. Our Haynesville position combined with the Warwick thrust make us the only company to have a large exposure to two of the potentially the best natural gas plays in the US.

In response to the unprecedented volatility in 2008, we've strengthened our balance sheet by substantially reducing our CapEx budget, hedged the majority of our gas for 2009 and 2010, issued preferred stock and initiated the sale process for our WTO midstream assets. Our 2009 gas hedge book is now 85% of our low-end guidance. Our 2010 natural gas hedges are nearly identical to 2009.

Our goal during the last quarter of 2008 was to ensure that we had the ability to sell gas at a profit during a period of low energy prices. We've accomplished this by our natural gas hedges and being at $8.42 in 2009 and $7.70 in 2010.

We have chosen at this time to remain unhedged in 2011 as we expect supply to decrease as more rates continue to roll off and demand the increase.

These steps that we have taken make us feel comfortable as we move through 2009 and into 2010 when we look forward to starting a new phase in the life of this Company with the opening of the Century Plant.

I will now turn the call over to Dirk.

Thanks, Tom. I will focus on a few financial highlights, our current financial position and our projections. The key things we look at for year-end are production operating costs, EBITDA and debt position and are pleased that we have achieved our previously stated guidance.

Production was up 58% year-over-year, while costs were within our guidance. Adjusted EBITDA was $158 million for the fourth quarter and in line with our guidance and our internal model. Our quarterly capital expenditures were $568 million, and we ended the year with $2.375 billion of debt, exactly where we had previously guided. We were in compliance with all financial covenants at the end of December.

For 2009, as Tom just mentioned, the financial mission is to create financial flexibility for the next two years via hedging to protect cash flow, some capital raises -- the preferred was completed in January -- assets sales and to reduce leverage. As illustrated in our press release, our current hedge position for 2009 is 85% of our natural gas and 73% of total Company production at $8.59 per Mcfe. For 2010 we have 80 Bcf hedged at $7.70 per Mcf.

At year-end our hedges were worth $247 million, and using the strip today, the value is $392 million, and January and February are now closed out. This is important when considering the current PV-10 and our current asset value. Our current PV-10, which includes hedges and uses the commodity strip price, is $4.33 billion versus the PV-10 used in the 10-K of 2.259. Thus, in terms of financial flexibility, our initial discussions with our banks have been extremely positive, and we do not see any change in our borrowing base. In fact, we believe we will be adding a few new banks to our group in April.

Our hedges, combined with the value of the midstream business and value of our Haynesville deep rights, are worth over $900 million and provide additional financial flexibility for the Company.

Let's look at our guidance that was presented in the press release. As everybody knows, the current financial and economic environment has presented challenges for everyone, and this is reflected in commodity prices. Given the uncertainty in commodity prices, as Tom mentioned, we're presenting a range of capital expenditures for '09, and right now we're looking at the lower end of the range in CapEx.

In terms of capital, we raised $244 million net to the Company in preferred stock and looked towards a midstream transaction with a goal of closing in second quarter. We hope to reduce debt by over $200 million by the end of 2009.

Our second annual investor analyst meeting will take place in New York on Tuesday, March 3 at 8:00 AM at the Grand Hyatt, and we plan on reporting first-quarter results on May 7. As for conferences for March, it is a busy month. We will be at the Siemens Energy Conference on Thursday, March 5 in Las Vegas, Howard Weil in New Orleans on March 23rd and 24, and the Barclays Fixed Income Energy Conference on March 25 in New York.

That ends our prepared remarks, Becky. We are open to take questions.

(Operator Instructions). Scott Hanold, RBC Capital Markets.

Could you remind me, and I think you have addressed it before, but given the changes in the spending plans and the flexibility, looking at the Century pipeline, when that does get up and running, are you going to have volumes that are going to be ready to flow on that to increase your net production? Are you going to start to drill into that as we get closer? How should we look at that?

Sure, Scott. We will start in 2010. Actually in the last half of 2009, we start adding to the volumes that will fill Century in 2010. But the majority of the ramp-up is in the first half of 2010.

Okay. So you will be actively drilling high CO2 wells to prepare for that coming online. Is that sort of the thought process here?

It's most of the wells that we drill. In fact, six out of the eight rigs we have working today are in the high CO2 area.

Okay, good. And on the Big Canyon well, with the fact that I guess they are not fractured but like you have seen parts of the Pinon, is that something you can identify with seismic, or when you say if you would have had the seismic, you may not have drilled certain wells. I mean what aspects do you see there that help direct where and how you drill?

Actually I can explain that in a couple of ways. Inside the Pinon Field itself, we have wells that are not fractured very well. So it is not that unusual, even though we have wells that average 7.5 Bcf per well. We have four wells, and then we have very good wells. And this well on a log characteristic looks like it would be a well in the Pinon Field; however, it did not have access to fracturing. That does not mean you could not drill another well in this same field and have fracturing within it. It gives us a lot of hope in that aspect. To answer your first question is no. You can't tell off the seismic whether you are going to have fracturing or not. You can see where you are in relationship to faults, and you can tell whether you have the zone in place or not that it is even down to trying to depict whether you have fracturing in a well bore or not, we can't do that.

Okay. So what aspect in seismic do you see that will help direct your drilling going forward?

What we see is that in large areas we feel now we know what the Warwick thrust looks like or even the Dugout Creek and the Frog Creek, and you can put yourself in areas that you can encounter the Caballos chert, the producing formation, and then you still have a risk of whether you have fracturing or not in the well bore.

But in Pinon Field, for example, we have statistically once you find gas, you find it over a large area. That is what we continue to believe here.

I appreciate it. Thank you.

Brian Singer, Goldman Sachs.

Thank you. Good morning. When you look across 2009 and 2010, what do you see as the minimum number of rigs and investment needed to meet the Occi contracts, and I guess based on where gas prices go, how do you think about the timing and ability to drill more or fewer of the lower CO2 wells?

I will let Matt hit the exact numbers. I know that we plan on being able to meet the Occi commitment just with the $500 million that we will spend in 2009. Matt?

I can't talk specifically about the Occi commit year by year, but I can say that right now we have 350 million a day of treating capacity in our legacy plants, and our plants are virtually running at capacity. That generates enough CO2 to meet the first-year Occi contract in 2010.

So it does take a lot of rigs. Basically when they drill approximately 55 wells this year -- that is based on our $500 million -- part of our $500 million budget -- would be, as Tom said, six rigs running at WTO drilling the Warwick thrust. That is about 55 wells, and about 35 of those wells are to keep the legacy, the existing plants loaded, and another 20 wells are to build toward filling the Century Phase I as it comes on-line in Q2 2010.

So, kind of the short answer to your question is we have more than enough wells planned to meet the Occi contract plus starting to fill up Century.

And I would say too that right now we're not budgeting a different budget from 2010 than we do in 2009 until we see an increase in pricing.

So would you generally think you will need the same level of commitment in terms of dollar in 2010 to be able to source the plant relative to 2009, or is there a disproportionate amount of spending in 2009?

No, I think right now as we look at and model, we will say that we will keep the same budget. We just modeled the same budget in 2010 as we do in 2009 in the $500 million to $700 million range.

Got it. Where is the CO2 going now from the wells that are producing?

The CO2 is going over to the Permian Basin for tertiary.

Got it. Last question, what are you seeing in terms of price realizations, and you are mostly hedged on the basis side, but how do you think about based on your unhedged both the Henry Hub and basis, what are you thinking about those volumes depending on where gas prices go?

As far as basis?

Both basis and Henry Hub, I guess what are you seeing in terms of overall realizations given that it seems that both Henry Hub prices have come down and basis in West Texas has widened a bit, and is there some point at which you would further restrict your unhedged production?

I think right now we are comfortable with 110 B's and being 85% hedged. Overall, we model $0.70 on basis for the Company, and I think that has been a fair amount because of our hedges. We have even hedged basis now out into 2011. That is an area that we watch very closely and want to make sure that we hit on model. We tried very hard whenever we have swaps on to match those at basis.

So I think in looking at our production, maybe you could stick with that $0.70 to $0.75 basis number overall for the Company.

Great. Thank you.

Eric Johnson, Silver Lake.

I first want to congratulate you guys on getting the convert done and really making steps to shore up the balance sheet in what has been arguably -- we deemed this one of the worst markets we've certainly ever experienced. I know it has been a tough road.

Just talking more about the balance sheet, though, given plan of, call it, $600 million spend this year, where do you anticipate the total debt number to be year-end?

In my discussion I said it will be down $200 million. I think when you will post the slides to the investor analyst day on Tuesday morning at the bright hour of, I guess it is going to be 4:00 AM your time on the West Coast there, so you can get up early and check it out, but we will have the full model up, and it shows it down north of $2 million by the end of the year.

You mean okay, so it will be -- where do you stand right now given the preferred?

Where do we stand right now as far as what?

At total debt.

Total debt, I don't really think of it as that way. I think of it as bank debt and arrested debt. Total debt right now is standing at -- hold on, let me get my calculator -- basically 2350. A little bit less than where we ended at year-end.

I mean right now we are really tracking exactly where we thought we would be. I mean really taking a closer look at the balance sheet and what most E&P companies have been faced with in this slowdown is that working capital is coming out of the business. If you look at the balance sheet on page F4 of the 10-K, you will see that our accounts payable at the end of '08 was up $150 million relative to '07, and essentially that money has come out of the business in the first two months of the year. So we are basically a little bit less than where we were at year-end, but we expect to be down probably another $200 million from here.

Okay. And you anticipate the borrowing base to go up -- you just have no clue of what you are looking at?

I think the borrowing base stayed the same. I think in this environment asking for a borrowing base increase, I mean I guess it is one company I'm aware of that did it in December, but I don't think a lot of companies are asking for that.

I think internally what we have modeled and what we have assumed is that the borrowing base stays flat. Rodney and his guys have done a lot of work on that and have worked a lot with our lead bank to make sure we understand exactly how they look at things, and we've been pretty comfortable with the PV-10 value of being north of $4 million, and our initials discussions with them looks like it is going to be flat. Plus, we're adding some banks to. So we should not have a problem with that.

Is that a semi-annual redetermination or annual? It will be April and September this year.

And one last question just regarding the pick, the 8 5/8. Remind me, can you only pick that for two years?

You can pick it for four years. There's only two years left. So we did not pick it for the first two. So we could pick it the October payment of 9, the two payments in 2010, and the April payment in 2011. Just so we are clear, we have to tell the trustee five business days before the beginning of the pay period what we plan to do, so that would be sometime in late March, and you can go back and forth. So you can pick one time and not pick another time.

As we've say, that is a board decision, and we will be making that here in the next couple of weeks.

Thanks, Dirk.

David Kistler, Simmons & Co.

Real quickly thinking about the ceiling test impairment, can you guys give us some color on different gas prices and what that would have done to the impairment given kind of a onetime static issue?

As far as the ceiling test impairment, at the year end, we ran reserves on the gas prices of 571, and we had a write-down. We ran another case with a year in reserves in February here at the strip, which started out at about $4.00, and with our given credit to our hedges and letting the strip run out, we would not have had a ceiling test impairment. So really that tells you how close it is between having an impairment and not having an impairment.

That's helpful. I appreciate that. Then with your $5 million CapEx, when we look at that, it is the low end of guidance. Does that incorporate any service cost decline since you last updated CapEx or even since you --

Service cost has declined. Just to give you an example, the $500 million in CapEx this year, primarily we will be drilling the Warwick, Caballos wells in Pinon. Right now we have six to eight rigs running in that reservoir, and just to give you a perspective on drilling costs, that is just drilling completion costs. In Q3 of 2008 these wells were costing $3.3 million to drill and complete, and today we are running a case of $2.8 million. So they will drop off quite a bit.

Okay. And was that factored in, though, into your $500 million?

Yes, that is factored into our budget.

And then with respect to the exploratory well, as you think about other wells that you are going to drill now that you have the 3D, will you step away from that well, or given what you have found and what you saw in the log and trying to understand if there is -- if there are pockets that are fractured around there, will you drill in closer proximity to kind of get a better handle on it? I'm just trying to understand your thinking?

We feel like we are very close to a reservoir there that could be productive and be economic. However, we have also multiple areas across a 700,000 acres of contiguous acreage block that we can test.

So one of the challenges for the Company obviously is the $500 million CapEx. We don't have anything budgeted for exploratory wells. I mean the good thing is that we have long-term leases and a large acreage plot put together, and we will have to wait until we have a more robust budget to move out and drill a lot of exploratory wells.

So, yes, we feel like we are very close to having production here. Keep in mind there are other fields that produce sweet gas to the east of the Pinon Field. They just have not been explored with as many wells as Pinon has.

So we are confident that we can find gas out across the West Texas Overthrust; however, we do need a larger budget to have that exploration activity.

Great. That is helpful, guys. Thanks so much.

Eli Kantor, Pritchard Capital Partners.

In terms of drilling activity in Pinon for this year, what is sort of the rough percentage breakdown between drilling the Warwick, Dugout and Frog Creek? Is it pretty much 100% Warwick?

Yes. Basically in the budget model we have moving forward until we move into the Century Plant, we are focused on the Warwick. And that is the area of best finding costs.

Now at the beginning of the call, I think I heard you guys mention that you plan to potentially monetize the midstream West Texas Overthrust assets and the Haynesville deep price for about $900 million. Is that right, and if it is, does that essentially mean you are putting a $400 million value on the Haynesville deep rights?

No. I think my comment was our hedges plus the midstream, plus the Haynesville, if the hedges are worth $3.92 and what we said in the press release is that the midstream could be worth 500 between what the proceeds we get in and the CapEx that this person what cover, that would leave $8 million left and I said 900 plus. So we have left that sort of vague.

I think what we are trying to say is that we have some flexibility in moving forward throughout the year with different options to look at as we move forward, that we do have some financial flexibility and especially with this lower CapEx budget.

Gotcha, thanks. One other question. You guys have mentioned in the past that you need to drill a minimum of 46 high CO2 wells this year, 64 next year to meet the Century commitment. Does that sort of stay flat in 2011 and thereafter, or does that minimum well count continue to increase?

Yes, 2011 is kind of way out there, but if you are thinking of a -- we are thinking of having a total high CO2 treating capacity of 1.15 billion cubic feet of gas a day, to keep that flat you are probably going to need to run seven or eight rigs and complete these wells, basically call it a one well per rig per month, something like that.

Got you. Thank you very much.

Jeff Robertson, Barclays Capital.

Thanks. Just to follow up on your comments around the Big Canyon, Tom, did you all have 3D seismic before you drilled that well when you picked the location?

We did have, Jeff. What we didn't have was the connection to the Pinon Field. Keep in mind that just in July we had the 3D that came over the Pinon Field, and after that, we have now connected across to the Big Canyon.

So the different phases that we have had are stages from stage one to stage -- I think we have four or five different stages of seismic that go across to the Big Canyon. Just now, in fact, aren't even through looking at those as they connect together. So you can see the Warwick thrust moving from one area to the next.

While we knew that we could get up-dip to the original well that was drilled to the south of us, we did not know how that would connect across to the main field of Pinon and how you can see different areas, including this, where we believe we can get into the Warwick thrust or the Dugout Creek for that matter and Frog Creek and have potential areas to explore.

Tom, can you take the data that you have at Warwick and Dugout Creek and what you think you are seeing in terms of fracturing and use that as you look at these other fault blocks to help pick structural locations where you have a higher chance of getting into fractures that you need to make reservoir?

Yes. Well, obviously drilling test wells is imperative. So as you move across, what we plan to do is to drill a number of wells across a number of areas, but we can see structure, and we are seeing sweet gas.

So, yes, I think that we will be able to high-grade, and the more wells that we drill will give us the keys to tying back into the Pinon Field. We have some very good data today that we didn't have six months ago and that we hadn't interpreted three months ago. We continue to have a 50 [GSI] that work only on the areas outside of the Pinon Field.

A second question on East Texas. Are the two vertical wells that you all drilled in East Texas, are those the only wells that you plan right now?

Yes. Our acreage is held by production, and we don't have anything in our current budget for horizontal.

Was your gold there just to help define the thickness of the sale and things like that to help the people understand what you may have?

Help us understand, yes.

All right. Thank you.

[Matthew Lemy], Highland Capital Management.

On the 2009 forecast here, the guidance, can you give me a little bit more detailed breakdown on your LOE, the 180 to 193?

Give me just a second. Our LOE -- just strictly LOE runs about $1.00 an Mcf, and that includes offshore operations and tertiary. That drives it up a little bit. Without those, you will probably be in the $0.70 range.

So you take that $1.00 in Mcf and then you have about $0.11 or so for transportation and miscellaneous related fees, processing gathering in the mid-30s or low 30s, $0.30 to $0.35, another $0.10 or so on ad valorem taxes, and then I would say $0.30 on production taxes, and that gets you up to $1.87 per Mcfe.

Okay, great, and I think most of my other questions were answered. If you could just elaborate, I know someone had asked earlier about basis. But if you could just elaborate a little bit more on where you think West Texas basis is going over the next, say, 12 to 18 months outside of your hedged position, just I am talking in general given how much gas is coming on in points east.

Matt, the only thing I know is that you can hedge basis today for under $0.80. So I suppose the market is a lot smarter than I am. We tend to try to take those hedges at [Waha] whenever they are $0.75 or so to meet our model, and that is what we have done in the past. Today I think the [Cal-10] is right at $0.75 and Cal-11 is just under $0.80.

Great. Thanks a lot, guys.

David Heikkinen, Tudor, Pickering, Holt.

Just thinking about your credit facility, do you anticipate any amendments to the covenants under the new facility?

The covenants? No.

And you mean they are 4.5 to 1 on EBITDA, funded debt to EBITDA ratio at 2.5 to 1?

I guess I need to ask you a question. Do you mean that the banks would be asking for or that we would be asking for?

Either way.

Either.

Okay. And then on the lending 80% of the discounted present value, you talked about the 4.4 or 3 billion at the strip. That gets you pretty considerable upside to where your current facility is. Are they lending less than 80% of current value?

I think there is a variety of calculations, and while that 80% might be your rule of thumb, there is a variety of different things they are looking at.

So, do we have cushion? Yes, we have cushion right now. Would I say they are lending less than that? I really don't look at it that way. I just think that pretty much anybody wherever you are right now is where you are given the environment we are in. If they get more cushion, they get more cushion.

But I mean I think if you sit down and talk to them, they look at about seven or eight or nine different calculations. Not only your way they look at it relative to the line being fully drawn and all the other debt. They've got a lot of different ways to look at it. Does the PDP if it is produced out cover just the bank debt if it is fully drawn, there is a variety of different calculations they run, just not your one number?

I was just looking through the K and just kind of ticking through and see if you were going -- other companies have amended. So I didn't know if you guys would be requesting an amendment is the reason I was hitting those things.

We have no plans. We had discussions yesterday. We have no plans on asking for any (inaudible).

Okay, good to know. As you think about the operations side of the business, you've hit basis, you've kind of hit your growth rates, set up for 2010, 2011, how do you think about allocating capital at $500 million? Does that mean you don't do anything in Oklahoma, don't do the West Texas, and basically honor your Pinon commitment? Is that the way I should model it where other areas would decline and Pinon would just chug forward?

If you look at a low CapEx case, yes.

And then given the well results in the Haynesville on the vertical test, that is very analogous to what vertical tests have done when you have had pretty successful horizontals. Anything that you see in your field, additional faulting, any thinning? I mean I am just trying to think about things that would cause that not to have a similar potential as you look at where your acreage is.

We have a slide that shows what we believe will be over 300 feet thick across the Blocker area, and so no, we don't see any difference.

Okay.

I will say too and I will address a little bit more on basis that we have, starting in Q4 of this year, the ability to take about 40% of our gas from Pinon to [KD]. We can do a substantial amount now, but it increases to about 40% in Q4 '09.

All right. That was it. Thanks, guys.

Joe Allman, JPMorgan.

Tom, I think you said you have six out of the eight rigs in Pinon, six of them running in the Warwick thrust. Correct me if I'm wrong there. And then, where are the other two? It sounds like you have one outside of Pinon.

We have one still running in Cotton Valley in the Minden Field in East Texas, and we have one in Ector County, Texas (inaudible).

So am I correct you have got six in Warwick, and where would the other one be running in Pinon?

None, six in Warwick.

So you have got six in Pinon and that's it?

Yes.

Okay, so eight rigs running now?

Eight rigs now going to seven in March.

And then the increase in EURs with the Caballos wells, I guess that is an internal estimate. Could you talk about what you saw with your year-end reserve report in terms of what the independent reservoir engineers gave you for Caballos wells?

Caballos is, just to be clear, the Warwick thrust is where we're talking about and that is an outside reserve well.

This is Matt. That 7.5 Bcf has increased from 7.75, and that is a third-party consulting increase. It is not an internal increase.

Okay, that's helpful. And then with the reduced rig count here, will that enable you to fill the Century Plant, or will that enable you to meet the obligation with Occi? Because I think in your previous budget, it sounded like you were trying to give yourselves more of a cushion so that you're just not meeting the obligation but you surpass that. Could you address that?

The way we talk about it now is that the $500 million this year, if you kept the same budget moving toward the $500 million to $700 million in 2010, you would need to be at the higher end of 2010 to fill. In either case, we will meet our obligations.

Okay. So, the new budget, basically the high CO2 production with the new budget, the production is roughly going to be the same as it was with the prior budget?

Yes. (multiple speakers)

Then the midstream sale, maybe you said this earlier, but what is the status with the midstream sale?

The same. We continue to have interested parties, and it is a very big midstream project. So we will just continue to work through it.

And then how about with East Texas, I know you updated East Texas last time. But what is the status of selling any East Texas assets?

We have interest if we want to sell. Things just continue to get better as people drill wells closer to our area, and then we actually now have tested just to the south of our main area.

So I think that if we use that, it is still financial flexibility. In our opinion the Warwick thrust is a superior producing zone than any zone that we know of. So if push came to shove, we would prefer to have Warwick thrust wells than any other well. Right now we don't have a deal to sell the deep rights; however, there is always a chance we could if we need to do that.

Okay, that's helpful. Just last question, just going back to the question on the Warwick reserves raising the estimate to 7.5. So in your year-end reserve report, I know it is an average, did you see some reserves get greater than 7.5 Bcf?

That is the average across the field. Keep in mind, that is not in just a couple of wells; that is 150.

All right. Very helpful. Thank you.

Ellen Hannan, Weeden.

Just a quick question on the Frog Creek thrust that you discuss in your press release here. Is there anything booked in either your proved, probable or possible categories for Frog Creek?

Just very little. We tested it in just a few wells. But if you look at our slide presentation and we will talk more about it on next Tuesday, but the Frog Creek thrust, the main portion of the thrust is south of where we're currently developing the Warwick in the Pinon Field. So we think the largest upside is yet to be encountered. It is just encouraging that the wells we've tested are good wells.

And do you think you can bring that at your lowest finding cost really of anything that you are doing?

We don't know what an average well would be, and we don't know that it would have the same exponential type curve as the Warwick. So I can't really answer that. But I would say it is shallower, and so theoretically you could. Again, the Frog Creek thrust isn't even in our 3D reserves.

Now if you do anything --

And Matt just mentioned too, it is sweet gas. So, yes.

Would that be considered exploration, and then you really have nothing budgeted for exploration in your CapEx for '09?

That is correct. And as you look at the slides, I think it is on our website now but it will be updated on Tuesday, you will see that the main area of Frog Creek exploration is to the south of Pinon Field, so it is outside of the field.

Great. Thank you very much.

David Heikkinen, Tudor, Pickering, Holt.

Just one comment and question around the Century Plant and just trying to understand one thing. Occi gets all of the CO2 that is produced; you get all of the methane. You pay royalties on the methane to your royalty holders. Occi doesn't -- just reading through it -- doesn't look like they pay anything other than getting all of it. How is that royalty or value of CO2 thought about?

It is thought about as a waste product that as you produce the methane, the royalty is all embedded in the methane sales. So in other words, you can't produce the sellable gas without having CO2 being extracted from it.

So the capital Occi is investing is basically allowing you to produce the methane, so you're in the preposition where --

It is not producible if you don't have that plant.

And that is why you're constrained today. Okay. Thanks.

I'm showing you have no further questions of this time.

Thank you very much. We look forward to seeing anyone who can make it on Tuesday to our analyst and investor meeting. Thanks, again.

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