SandRidge Energy, Inc.
Q2 2008 Earnings Call Transcript

Published: 8 Aug 2008

[Operator:]

Good day, ladies and gentlemen, and welcome to the second quarter 2008 SandRidge Energy Earnings Conference Call. My name is Fab, and I'll be your coordinator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-session towards the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Dirk Van Doren, Chief Financial Officer. Please proceed.

[Dirk Van Doren:]

Thank you, Fabiola. Good morning. This is Dirk Van Doren. Before I turn the call over to Tom Ward, our Chairman, CEO and President, I need to make a few opening remarks. Last night, the company issued a press release detailing SandRidge's financial and operating performance for the second quarter of 2008. We also filed our 10-Q. 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 releases that will automatically be sent to you, and this is located under the Investor Relations tab. Today, we will also use a few slides and those are available on our website under Events and also under Presentations. Now for the forward-looking statement. Please keep in mind that during today's call, the company will make 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, 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. Now let me turn the call over to Tom.

[Tom Ward:]

Thank you, Dirk. Welcome to our second quarter 2008 earnings conference call. Joining Dirk and me is Matt Grubb, our Chief Operating Officer. We have now posted our second quarter numbers and a small slide presentation on our website that I will discuss and walk you through momentarily. We have added the slide presentation because of the complexity of the West Texas Overthrust and how difficult it is to describe what we are doing without some visual aid. We have been quiet for a couple of months while we continue to drill within the Pinon Field and explore both in the Pinon Field and across the West Texas Overthrust. Today, I will discuss the important test that we have drilled during the last few months and the emergence of a more concrete idea of the geological model we are developing as we access seismic and have a few exploration well bores that are drilling to tie back into our existing seismic and the Pinon Field. During the second quarter, we finished processing our 3D seismic data across the Pinon Field and our interpretation of the field data began in May. So we have only had 3D data coverage over the Pinon Field for 60 days and have already discovered a new fault block, which I will describe in more detail little later. Having the Pinon Field 3D data is critical because it allows our geoscience teams to confirm and incorporate the regional thrust fault theories and 3D mapping with controls from approximately 600 wells drilled to date in the Pinon Field. Please keep in mind that Pinon Field is fast becoming one of the better natural gas fields in the U.S. In June 2006, we produced less than 80 million cubic feet of gross gas equivalent per day from our Western Division; and today we produce over 200 million gross from the Western Division, of which the growth has been almost exclusively driven by the Pinon Field, where it is tripled in size over 600 wells. This number would be about 305 million cubic feet of gas per day if it had not been for the Grey Ranch plant fire which set us back 25 million of methane on a gross basis. We have discovered through the use of 3D that there are at least three major thrust systems that correlate across the entire West Texas Overthrust in an east-west direction. These three systems are the Dugout Creek thrust, the Warwick thrust, and the Frog Creek thrust. These thrust systems combine with the rent systems to develop classic reservoir traps. Our primary reservoir, the 1st Caballos, produces gas at 5,000 and 9,000 feet and averages 7 Bcf per well and can be drilled on 40-acre spacing with a recovery of upto 90% of gas in place. We now have 144 wells that produce from this reservoir and are very comfortable with the 7 Bcf-type curve for the 1st Caballos within the Pinon Field. This is a spectacular reservoir that until recently was not developed at a fast pace due to the high amounts of CO2 in the reservoir. Our goal is to continue to expand this prolific reservoir and develop sweet methane production in these new fault blocks through the use of our proprietary 3D data and the data from exploration wells as they are drilled. The 3D data set will not eliminate dry holes, but will help us to identify significant fault blocks to explore it. As I mentioned, we now have the ability to see some major geological events that were not known to us just a few months ago. I will now try to describe the major thrust systems across the WTO and the significance they provide to SandRidge. The first major thrust is the Dugout Creek thrust. It is the red color and northernmost thrust systems in slide 1. The majority of the existing Pinon Field sits behind this thrust as the main northern thrust that we previously called leading-edge thrust. We now believe that most of our 2nd Cab development is within this thrust. We can also correlate the Thistle Field - 15 miles to 20 miles east of Pinon, and the McKay Creek Field - 25 miles to 30 miles east of Pinon - in this same thrust, and both of these fields produce sweet gas from shallow turf reservoirs. The second thrust is the Warwick thrust. Until our 3D was interpreted across Pinon, we didn't recognize this thrust and did not carry it across the WTO. However, with 3D seismic geological control from hundreds of wells built in Pinon and supporting production data, we can now map this thrust and show it as a prime contributor to sweet gas production in the 1st Cab on the eastern side of the Pinon Field, and as the primary thrust for all of the 1st Cab production. In other words, as we move across these thrust sheets, we are in separate reservoirs. Please look at slide 1 and see the relationship between the Dugout Creek thrust and the Warwick thrust within the Pinon field. We can tie the Warwick thrust across the WTO. The Sabino Field, the Longfellow 1820-1 exploration well we are currently drilling, and the big Canyon 121-1 area are all tied together in this second major thrust system. There are also several more minor regional thrusts within this system. As we have drilled south in the Pinon area across this regional thrust and into a new fault block within the Warwick thrust, we have discovered sweet gas in the 1st Cab but at depths of 1500 feet shallower in the wells drilled to the north in the east Pinon 1st Cab sweet producers. We have tested the West Ranch 42-2 at a initial rate of 1.3 million cubic of sweet gas from the 1st Cab and are currently moving up forward to test the Cab A chert section in that well at a depth of about 3600 feet. The Cab A is significant because we are producing the shallow zone in the West Ranch 26-7 at a rate of over 3 million cubic feet of gas a day and it has a potential EUR of 4 Bcf to 7 Bcf of gas. We now are developing a theory that the shallow zone could tie from the West Ranch 44-1 which is drilling, all the way to the Longfellow 916, almost five miles across the southern part of the field. The third major thrust is the Frog Creek thrust. With the Pinon 3D data, we are able to confirm production from the Cab A which lies above the 1 Caballos together. In this thrust, the Williams 72-1, the only known commercial producer in both the Frog Creek thrust and the WTO has an EUR of just over 200 million cubic feet of gas of less than 5,000 feet with 96% methane. That well was drilled on 2D seismic and we don't believe in the best structural position. We believe that we can deeper behind this thrust and encounter the first Caballos at a projected depth of 7500 feet or less, and also believe the first cab here would produce sweet gas. We plan to add several wells to our exploration program in this thrust block in the coming months. We also believe that the Cab A in this thrust is in an ideal structural position to produce commercial gas at very shallow depth. To summarize, we now see a succession of east to west thrust that lay upon each other, by being thrusted upon each other, creating separate multiple reservoirs within each thrust. Please remember that less than a year ago, we only knew there were four producing areas in the WTO

[Dirk Van Doren:]

Thanks, Tom. I will focus on a few second quarter highlights, our current financial position, and our 2008 and initial 2009 projections. The key things we look at are production operating costs, EBITDA, free cash flow, and funding needs, if any. Production was above expectations and costs were within our guidance, with the exception of production taxes because of higher prices. Adjusted EBITDA was $183 million for the second quarter, which was above our guidance and our internal model. This number based on the definition of EBITDA includes $7.7 million from a gain on asset sales during the quarter. Our quarterly capital expenditures were $523.2 million, and hence we have negative free cash flow. This was covered with borrowing under the revolver and then via $750 million high yield transaction we completed in the quarter. Looking at other financial events, we experienced an active second quarter and that continued into the third quarter. We completed a $750 million high yield offering in May, and this caused our borrowing base to decline to $1.095 billion from $1.2 billion. We hope to move that back to $1.5 billion in September. All the lock ups on our equity holders ended on May 27, and Tom completed his previously announced purchase of 100 million of common stock in open market purchases during the quarter. The exact numbers are $100.7 million spent for 1.95 million shares or $51.63 per share. And finally, we sold rig number six for $1.425 million in July, and used roughly $400,000 to repay our rig loan. The remainder went to cash, as this rig did not fit our strategy because of its size. We now own 31 rigs and have 12 rigs in the joint-venture. Our current position as of August 7 was roughly $100 million of cash, zero drawn on our revolver, and $1.81 billion of total debt. Additionally, since our last call, we have added slightly to our hedge position with 1.8 Bcf in 2008 at $12.28 per MMBtu and 8.41 Bcf at $11.73 per MMBtu for 2009. We are now roughly 78% hedged till the second half of 2008 at an equivalent price of $9.14 per MMBtu, and 17% hedged for 2009 at $10.50 per MMBtu. Let's look at our guidance that was presented in the press release. We have changed two things in our 2008 guidance

[Operator:]

Thank you. (Operator Instructions). Your first question will come from the line of Scott Hanold from RBC Capital Markets. Please proceed.

[Scott Hanold:]

Yes, thanks. It's Scott Hanold here.

[Dirk Van Doren:]

Good morning.

[Scott Hanold:]

Good morning. Tom, can you just sort of talk about now that you have your seismic information a little bit more on hand in the WTO, how do you think now about developing it now versus what you did before? And can you also talk a little bit about your confidence in some of the areas that you are going to step out to as far as what you think you'll see? Obviously it sounds like you've seen some gas charge reservoirs. What is the key here? Is it really fracturing at this point in time?

[Tom Ward:]

Well, we look at it differently today Scott, than we did a few months ago, because now we see, we were, if you look back at maybe in the RBC presentations, you can see we were focused on major ridge faults that were moving north and south, and now we see the major influence being more from or as much from these thrust faults that move east and west. So what we are trying to do is use the Pinon field as the analogy to get into the best place to have multiple thrusts upon each other. So in order to answer your question, I'm not sure how long it will take us to find these, how this comes together outside of Pinon. But within Pinon, what the major difference is, is that we could have multiple new fields in the north-south direction, which we didn't recognize before. So, as you think of the Frog Creek moving on top of the Warwick, moving on top of the Dugout Creek thrust system within Pinon, you have these different faults or thrusts separating each other that are completely different reservoirs that we already know have multiple Tcfe gas in place. That could actually continue on to the south. So we are incredibly pleased we'd be able to get in the Pinon 3D, and we believe that same system goes all the way across the WTO. However, it's a lot harder to go into South Sabino where you have one well instead of having 600 wells within Pinon. So the majority of our growth still is going to be within Pinon as we try to find additional Pinons in this same geological structure across the West Texas Overthrust. That's why we are expanding the exploration wells. Those exploration wells move into 10, won't be all the way out in all over the mat across the WTO. A lot of those would be drilling around Pinon trying to find and grow this tremendous reservoir. I hope that makes sense.

[Scott Hanold:]

Yeah. And just so I understand, alright, so basically what you have seen obviously is encouraging. Pinon obviously you are getting really excited here because of what you found, and sounds like you are going to concentrate efforts in and around Pinon but you are still going to do some of the stepout drilling. Is that well outside of Pinon just to sort of test the concept out there?

[Tom Ward:]

Absolutely, Every well that we drill, and we don't even have logs on the 1820-1, but just by drilling through that, once we get logs there, once we get log on the big canyon well, they'll prove to be very instrumental to determining at what depth you can produce that, and if you can get [updepth] to those types of reservoirs. What we want to do is to produce the most amount of gas from the shallowest reservoirs. So if you think of the Pinon field, the big thing is to move back along these thrusts and you continue to be up-thrusted. So it's still very early in the Cab A development. But if we can find the 267 is a very key well and we have multiple Bcf producer producing 3 million cubic feet of gas today at depths shallower than 4,000 feet. If we can find a whole thrust system like that, that would be very encouraging for us. That maybe, it's just again maybe. We don't have scientific proof of this yet, but if you could produce at 3600 feet instead of 7,000 feet and find the same type of reservoir, that's what we want to do. So we do want to and we will focus on the deep reservoirs, but we're also focusing on the shallower reservoirs too as we continue to grow.

[Scott Hanold:]

Okay. And with that last comment about focusing on some of the shallower reservoirs, when you look at your seismic information, and I guess the data points you have so far and the wells you've drilled, what can you tell us about depth as you move from west to east in the West Texas Overthrust like the big canyon area. What are your thoughts? Does it seem to get deeper there and what are the implications of that?

[Tom Ward:]

We do get deeper as we move from the Pinon field to the east. What we don't know yet is, as you go over to the east or the multiple thrust in different parts of the West Texas Overthrust that can also have you in shallow. So for example we know we can get updip to the 1820-1 in the Warwick thrust, and so we'll try to drill updip to that, and then see how many of those thrusts we can encounter as we move updip. So I think the difficulty here is there are several different thrusts, and as you move east you can be deep in one thrust and if you move into another thrust, you'd be shallow. So we don't have enough information yet today to be able to tell you what the depths of production would be across the overthrust. We think that the same thrusting goes all the way across the overthrust and it still will take us some amount of time to be able to find exactly at what depths we're going to be able to find production.

[Scott Hanold:]

Okay. I appreciate that commentary. And one last quick one

[Tom Ward:]

There are, but in the prolific reservoirs I think we are very comfortable at 40, because that's what it's been drilled on and we have data that stretches back to 1984. So I'm not ready to say we are going to drill anything tighter than that.

[Scott Hanold:]

Okay. I appreciate it. Thank you.

[Tom Ward:]

Thank you.

[Operator:]

Your next question will come from the line of Brian Singer from Goldman Sachs.

[Brian Singer:]

Thank you. Good morning.

[Tom Ward:]

Good morning.

[Brian Singer:]

Could you talk a little more on the Longfellow, in the 916 well and the importance of that well from a faulting perspective in pushing the plate?

[Tom Ward:]

Sure, I think the first negative would be that we didn't find first cab production or a first cab section in the 916. But now once that we look at it, the positive is, is that we have this cab A at a very shallow depth and it ties together back into basically what we were hopeful it ties together from the 916 down through the 26-7 or 42-2 and we have the same section in the well that's drilling the 44-1. So the positive is that we have not tested it in the 916, but it looks very good on logs at a very shallow depth. We also have gas at 12,000 or I guess it's deeper than that. We have a gas-charged zone that we are drilling in now. We have no idea. The Woods hollow sand does produce in the field, but we don't know if that will produce in the 916. So I guess the most positive thing is we have a shallow zone that we do believe will produce.

[Brian Singer:]

Okay. And it seems like with some of the limited CO2 quantities you are getting as you move east that the rig is shifting in that direction, and just wanted to check the extent to which that's it because of the higher returns as a result of low CO2, versus any deteriorations in rate of return in that legacy Pinon area or just a greater complexity there.

[Tom Ward:]

If you've seen our slides as you have, the best rates of return we have are drilling first cab sweet wells. So until we establish a different type curve at a shallower depth, we are going to drill as many of those wells as we can.

[Brian Singer:]

Okay. And lastly, if you were to end up not selling East Texas, how do you think about how aggressively you would develop those properties?

[Tom Ward:]

East Texas?

[Brian Singer:]

Yes.

[Tom Ward:]

I think that we would stick with our four to five rig schedules. I don't see us anytime soon trying to develop anything deeper, because we have already and we have most of that land as HBP and other people could drill around it. So we'd actually see that as being one of the great sales points, is that the Cotton Valley in this area is good enough that you can drill just Cotton Valley wells and hold the other acreage and just determine if it's any good or not.

[Brian Singer:]

Great. Thank you.

[Tom Ward:]

Thank you.

[Operator:]

Your next question will come from the line of Joe Allman from JPMorgan.

[Joe Allman:]

Good morning, everybody.

[Dirk Van Doren:]

Good morning, Joe.

[Joe Allman:]

Tom, I guess you spotted these two South Sabino wells and one Big Canyon well on your new 3-D seismic, but before you had your new interpretation and I know you just commented that the first South Sabino well, the one closest to the Pinon doesn't have the first Cab, can you comment on anything what you are seeing in the other two, or you maybe mentioned it, I just missed it, but what about the other two wells? Would you say those may not be optimal locations based on new interpretation or like you haven't seen the presence of something or one of the formations rather? Can you comment on that?

[Tom Ward:]

Sure. A caveat would be that six months from now we'll probably say that we have new 3-D and that helps us know even more about the WTO. But having the Pinon 3-D shoot is incredibly important, because it has so many well bores to tie back into and it gives us the ability to understand the geology so much more across the West Texas Overthrust. So given that, and now that we know more of what a character on seismic is to give you a reflector of these Caballos cherts, I would say sure, that things would have changed on where we drill at least the wells in South Sabino. However, we need these data points and why we are drilling so deep is that these first wells drilled in each of these new areas are really key, so that then you can use that well bore to tie back into your seismic. So it is maybe not fair to say that we would have changed things. It is fair to say that once we drill this well, we'll have more knowledge than we would have before. So we should be able to hone in. The good thing is that we do have gas in each of the thrusts and we are even seeing gas at very deep depths. So that gives me a lot of comfort that we have a gas-filled reservoir and we are still in thrust. So even though we crossed the thrust on the 916 and don't have, the first Cab could be faulted out or any number of reasons. Geologically, how come we don't have first Cab there? We are still behind the thrust system, because we have wood's hollow sand in this well bore and we have that Cab A chert. So, I am actually very encouraged about the 916 and what it means. You can still explore around that and be within the thrust system.

[Joe Allman:]

So what I was getting at in my question is that, like the first well, I know I'm not being critical or anything, but that well, whatever the final result of that well, it may or may not be representative of other wells you would drill in that Dugout Creek thrust, is that correct?

[Tom Ward:]

That's correct. And I would say that any of these wells that we go out 15 miles or 20 miles away from the Pinon field have a very high risk of just giving us data and not having production.

[Joe Allman:]

Okay. Got you. And then the other South Sabino well which I guess is Longfellow 1820-1, is there anything that has surprised you there, what you've seen or haven't seen there? And then same thing with the Big Canyon, can you talk about what you've seen and haven't seen?

[Tom Ward:]

We haven't seen anything in the Big Canyon, and we are not down to any potential depths. Remember we have a log in the Big Canyon that we are offsetting within a couple of miles. So we are able to correlate to that log, so there's a lot more data in the Big Canyon area just by having the one log to drill from than in the Longfellow 20-1 area. In that well the 1820-1, the only thing we have seen is a gas-charged reservoir. We have not logged it. Today we couldn't tell you that we have a section of chert that were going to go complete. We can tell you that we have seen gas shows and they appear to be sweet.

[Joe Allman:]

Okay. And then just in general, as you are looking at the 3D seismic and I know you have limited well data in some parts of the field, are there any issues outside of Pinon that might preclude you from drilling up parts of your acreage there?

[Tom Ward:]

I'll let Matt take that one.

[Matt Grubb:]

Well, I really don't see any issues, Joe. I think the biggest thing is getting in those exploration rigs to start proving some of these areas and the big thing is really understanding the data in Pinon. We've only had that for about 70 days now, but having the data in almost 600 wells of control points, that gives us a good picture of what produce is out here. And really it's our geoscience team focus now is to extrapolate this Pinon theory and to sneak data out across Overthrust. As far as terrain acreage exploration things like that, there's really nothing that really is going to prohibit us from drilling or exploring outside of Pinon.

[Joe Allman:]

Got you. And then lastly just to compare what you were thinking about the whole play a year ago today, a year ago would the acreage outside of Pinon been more important to your future than it is now, just because Pinon has gotten so much bigger and it just keeps expanding and you found these high rates low CO2 wells, can you comment on that?

[Tom Ward:]

Sure. A year ago also we knew that we had production of Pinon, and a little bit of production at Sabino, Thistle and McKay Creek over about 40 miles, and so we bought a lot of spec just acreage knowing that there was production all the way across the West Texas Overthrust, and we new we had a key well at the Big Canyon area that had chert at deep depths. What we know today is night and day different. If you would have asked me a year ago, I would rather have been concerned about drilling to the south of the Pinon field into the chert, I would say sure because I would be afraid we would get tight and wouldn't have the [frac] rate in place to be able to produce. But now what we see is that this whole layering effect of these new thrusts and there could be additional thrust that we haven't even drilled into yet. We are only talking about three of them, that not only can you move down depth, you're not down depth, you are actually up thrusted and you produce those that are even shallower. So if you would have looked at our IPO slide in November of last year, you would have seen two major thrusts, what we call the trailing thrust and the leading edge. And today that has entirely changed. So what we have defined as the Pinon field is really multiple thrusts that may be focused too much on everyone looking to the east and west and not enough on the north and south. But there could be multiple Tcfs of gas just within Pinon field yet to be found.

[Joe Allman:]

Got you. Okay, very helpful. Thank you.

[Tom Ward:]

Thank you.

[Operator:]

Your next question will come from the line David Kistler from Simmons & Company.

[David Kistler:]

Good morning guys.

[Tom Ward:]

Good morning.

[David Kistler:]

Just trying to tie some stuff together. When you are looking at these first cab wells, can you talk a little bit about where you guys see cost going as far as the drilling of them, or as you go all the way across the WTO, would that vary just based on depth, et cetera?

[Matt Grubb:]

Sure. Yeah David this is Matt. As far as cost for the first cab is, we go from west to east within the Pinon field it does get a little deeper, I guess from maybe 5,000 feet down to 8500 feet. So your cost do increase from maybe $2.5 million to $3 million in that range. The good thing about that is, as you go from west to east the gas also gets sweeter. You go from may be a 61% CO2 into a transitioning of 33% CO2 to another transition of zero CO2. Again as you go west your cost goes up a little bit, but the value of your methane or the value of wells go way up because you lose on the CO2 and you increase the methane. Now what happens is as you go from north to south, what Tom just alluded to and a few minutes ago is, in any given thrust, as you go from north to south, you do go down dip. But as soon as you are crossing to a new thrust, you pop up again to an updip position. So you can be in the Warwick thrust at a higher position of the Dugout Creek, or you can be in the Frog creek thrust at a higher position in the Warwick thrust. So you do gain structure and you get shallower again. Outside of Pinon and going to the east towards South Sabino and in Big Canyon, we still don't have enough data yet on first Cab to really talk about costs at this point.

[David Kistler:]

Okay, that's helpful. When you guys outlined at least your total estimates for 3P reserves and then also the new estimates you gave us for proved reserves, can you break those down between Pinon sweet and CO2?

[Matt Grubb:]

Yeah. Our total proved reserves in the Pinon field is 1.1 Tcf. Okay? Of that, the total proved from the first cab is 559 Bcf. So that's roughly half of your total proved reserves in Pinon. From a 3P standpoint, your total 3P reserves for Pinon is 5.09 Tcf, call it 5.1 Tcf, and your total 3P reserves for the Cab one in Pinon is 3.3 Tcf.

[David Kistler:]

Right. Thank you. Thanks for that. And then jumping over just a little bit to the rig side of things. With you guys looking to ramp up to 40 rigs within the WTO, can you talk a little bit about the new rigs you are securing? I can't recall if you are buying them or if you are just going out on contract. Can you give me a little bit of color on that?

[Tom Ward:]

We have been going out on contract, and we've had access to several outside rigs and have made a year to 18 month contract on those.

[David Kistler:]

Okay. And then lastly building off of Joe's question, maybe being a little bit more specific to what you've seen on the 3D data that you've gotten and then as you comp it against the 3D that overlays on the Pinon. Is there anything that you are seeing in there that discourages you as you start to move outside of the Pinon?

[Tom Ward:]

No. We don't see, I think the 3D data has only encouraged us because we see these thrusts going all the way across the Pinon field, and as we drilled our exploration wells we are seeing gas. So to me that's very encouraging and we don't see anything yet that makes us believe that we can't drill in a specific area.

[David Kistler:]

I certainly appreciate the update guys and also for how thoroughly you guys laid out the press release. It made our job a lot easier.

[Tom Ward:]

Thank you.

[Operator:]

Your next question will come from the line of David Heikkinen from Tudor, Pickering, Holt.

[David Heikkinen:]

Good morning guys. Just thinking about the geologic complexity, as you move east-west and north-south, can you rank, is it well depth, natural fracturing, do we find gas, CO2 content, finding the Cab 1? What are the top priorities, anything else that I should have included in that list, just as we think about exploration drilling to the south and to the east?

[Tom Ward:]

I'll hit it and then turn it over to Matt and his opinion too. For me, the most important thing is to find the greatest amount of gas at the shallowest depth. Obviously finding costs are important. So as we now focus on South Pinon or Southeast, South Pinon is becoming more and more encouraging to me. So the greatest encouragement to me is to understand that we have multiple thrust systems that move to the south near other well bores to where we can expand very rapidly. Also the next thing that encourages me is you have the same thrusts that go all the way across our acreage, and so we will have an aggressive drilling schedule. And one thing that we do is we go out and drill very quickly. In fact, maybe too quickly on the first couple of wells before we had the full 3D shoot. But we won't finish our 3D shoot until the end of 2009. With each day that goes by we have more data, and as we drill these thrust sheets we now have a geological model that's different than it was six months ago. And so I feel like we have even a better chance with each well that we drill to be successful outside of the Pinon field. The Pinon will continue to be the work horse. Matt?

[Matt Grubb:]

I think Tom hit the nail on that. Our number one goal is to find sweet gas in the shallow chert reservoirs. And what's really encouraging is to understand these multiple thrust sheets because the more thrust sheets you have, as we know it now, the more opportunities you have to explore and to build the shallow chert. Every thrust that we just mentioned a few minutes ago you can find updip or you can find the chert up high. So you always have opportunities to go shallow. As far as reserves, and we used 7 Bcf for the first Cab, and what that really depends on is fractured intensity, that's something we can't predict. We don't know what the fracture intensity is from one place to the other. So really it's really statistical, and I think the more wells we drill, the more we'll converge around our 7 Bcf of reserves for the first cab. The other risk, if you will, is the CO2. We know that we have high CO2 over to the west side of the field in the first Cab, and it goes to sweet on the east side of the first cab. And what we don't know is, for instance, if we go down the Frog Creek thrust with that same CO2, you breakdown will continue or not. So there is a risk there. However, the only well we have in Frog Creek thrust that we know of today is sweet gas. So that is also good news.

[David Heikkinen:]

Okay. And Matt, maybe thinking about the surface topography as you move to the south with the ridges on the surface, how easy or hard and how long does it take to get gathering systems to these new exploratory areas?

[Matt Grubb:]

I think it is challenging as we move south and in some areas as we move to the east. That's really well-by-well and that's something that we take into consideration when we go through our technical reviews every week to pick locations. We certainly would try to explore and drill wells where we can, build locations cheaply where we think we can, lay pipe and lay rows to get in and out. There will be some instances where we find up how we may have drilled two, three, four wells off the same path because of the surface restrictions. But today we are not there yet.

[David Heikkinen:]

And Dirk just to remind me, in your exploratory program, the expectation is that you don't add any production for any of that anyway, so timing of those wells is it really going to impact your guidance?

[Dirk Van Doren:]

It's true. Of all those wells, we assume that they'll produce nothing in 2008 or 2009.

[David Heikkinen:]

Okay. Thanks.

[Operator:]

Your next question will come from the line of Jeff Davis from Waterstone Capital.

[Jeff Davis -Waterstone Capital:]

Thanks, guys. Good morning.

[Dirk Van Doren:]

Good morning.

[Jeff Davis -Waterstone Capital:]

I am curious if may be you can help me understand something in the guidance, showing the all F&D $1.80 for the first six months of the year and despite that you are taking your DD&A for oil and gas up for the full year '08, and then when I look at the midpoint of the '09 DD&A rate of $2.85, it's the same context of where you've been the last few quarters. Just seems like a mix shift of bringing in those lower costs producing properties. DD&A should go down over time?

[Dirk Van Doren:]

That's correct. It should go down over time. Unfortunately, when you look and you get inside the numbers, what you realize is we are with the NEG acquisition there's a huge amount of reserves booked at a higher cost. So when you move forward, it takes a while to bring those numbers down. The other thing to keep in mind is we are going to try to give you numbers that are in our mind pretty conservative. So we are hopeful that we can beat those numbers. But as we move forward, and I think you'll see it more in 10, 11 and 12 you are 100% right. You should start to see those numbers go down. But the NEG acquisition is still going to be around for a while. We scrubbed those numbers pretty hard. I worked with the folks in accounting on those numbers and the folks that do our modeling hopefully we beat those numbers, but I don't want to give you a number that will just get crushed by a don't do. But I think you'll start to see that, but I think it is going to take a couple of years before it really gets into the numbers.

[Tom Ward:]

One thing I must add NEG acquisition is pretty interesting to me anyway, is that we gave $1.5 billion for NEG in November of '06 and at least some analysts have thought that our East Texas assets might be worth that today.

[Jeff Davis -Waterstone Capital:]

Okay. And then just quickly on the income statement. The reported loss on derivative contracts, that's realized and unrealized in that number right?

[Dirk Van Doren:]

That's correct. That number today or at the end of July was negative 10.2. So it has declined dramatically from the end of the third quarter. Obviously, with prices coming down and where our hedges are, it's good and bad. It doesn't look as bad on the income statement, but the flip side is we are getting close to being in the money.

[Jeff Davis -Waterstone Capital:]

But the realized portion is about $58 million or so, does that sound right?

[Dirk Van Doren:]

Correct. It is not my favorite thing in accounting. We'll just leave it at that. It's very difficult. I think it's very confusing, but it's what we have to live with.

[Jeff Davis -Waterstone Capital:]

Thank you.

[Dirk Van Doren:]

Thank you.

[Operator:]

Your next question will come from the line of Jeff Robertson from Lehman Brothers.

[Jeff Robertson:]

Thanks. Matt, you talked a little bit about fracturing in these thrusts. Can you all tell from the seismic anything about the reservoir quality yet?

[Matt Grubb:]

No. We really can't tell from seismic on the quality of the reservoir. All we can really see is the depth of the reservoirs and (inaudible) structure. We've been doing a pretty good job up in Pinon, that is, everywhere we drill we get an open hole logs, but we also get imaging logs and what that does is it helps us to identify, it's not quantitative but it's qualitatively the degree of fracture intensity in the well. And I think once we do enough of those we can maybe get some kind of fracture mapping across the Pinon. And really that's what makes this place somewhat statistical is that once you know that you have chert and you know that you have a gas field thrust, it's just a matter of drilling enough wells to get to that tight curve. That's really about it.

[Tom Ward:]

And Jeff, that's what's so important about knowing where these thrusts are on a north to south basis of Pinon, because the very best fracture enhancement is along the leading edge of a thrust. So as you look at the top part of the Dugout Creek thrust or the top part of the Warwick thrust or what we believe will be the Frog Creek and each of these minor thrusts in-between that, as you get towards the most structurally up dip area along the leading edge of each thrust, you'll have the best production.

[Jeff Robertson:]

So, Tom you think that the reservoir quality as long as you are in the right part of the thrust there is not a lot of difference between the three different thrusts. Is that right?

[Tom Ward:]

I would say it's still too early to say that, but what we are hopeful of is Cab A, even though it's at a structurally higher level, can have that same fraction intensity. There is no reason that can't be filled. It's thick. So you should be able to have the same amount of height. The question is, does it have sweet gas, which we are hopeful of and we see sweet gas in it; and can you have the same type of reservoir as the first Cab and the Cab A? We don't know yet. But it looks very encouraging at shallow depth.

[Jeff Robertson:]

And then two other questions on the Frog Creek thrust. What are your plans to drill some of the exploratory prospects in that? And secondly, Tom, have you been able to define any prospects for the Allenburger from the seismic yet?

[Tom Ward:]

We have lots of prospects on the Allenburger. It's just that we can fill up our CO2 plans with first Cab well. So there's really no reason today to be drilling a lot of Allenburger test because you make better economics on drilling first Cab test, and we are waiting to get the plant full and build the [centric] plant built. On the Frog Creek answer, if you look at slide 1 you'll just notice more blue stars in the Frog Creek than the other thrust. So we are pretty excited about it.

[Jeff Davis -Waterstone Capital:]

Thank you.

[Tom Ward:]

Thank you.

[Operator:]

(Operator Instructions). And your next question will come from the line of Salil Sharma from Highbridge Capital Management.

[Salil Sharma:]

Hi, good morning.

[Tom Ward:]

Good morning.

[Salil Sharma:]

I just had a quick one. If I add up your Q1 and Q2 production I get about 48.3 B, and if you analyze what you are doing today, these two add up north of 100 and that's your guidance. So could you please clarify what you are assuming for production growth in the second half?

[Dirk Van Doren:]

Sure, a couple of things. We had a very good. I'll answer it in a couple of different ways. We had a great May. We started to have a couple of wells in the Gulf of Mexico or Gulf Coast (inaudible) we had a great June and then we got the fire in Grey Ranch. And while we ended the month and we showed an actual rate of 295, I would not say that we averaged 295 in July. And so, can you get to a number that is possibly a little higher than 100? Yes. But I guess the way I think about it from a non-technical standpoint, we had the Pinon field optimized with Grey Ranch operating. And when that went down, our mid-stream guys had to really work their tails off to reoptimize the field, that's taken sometime, and we may see, we are not sure if we wouldn't see a down dip in August. So I wouldn't be going out and saying we are going to do 105 or 110 and we are sand bagging you. Could we do a little better, right now? yes. But we are pretty comfortable with 100, given what's happened with the Grey Ranch plant, and what we saw in July.

[Tom Ward:]

And we also anticipate that that production, that 5 Bcf of production won't come back until January 1.

[Salil Sharma:]

Right. Thanks.

[Tom Ward:]

We may get Grey Ranch on earlier, but we are not sure right now.

[Salil Sharma:]

Okay, great. Thanks.

[Tom Ward:]

Okay. Great. Thanks.

[Operator:]

There are no further questions at this time. I would now like to turn the call back to management for closing comments.

[Tom Ward:]

Well as always we just thank you for being on the call. Thank you.

[Operator:]

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