SandRidge Energy Inc (SD) 2007 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2007 and Full Year 2007 SandRidge Energy Earnings Conference Call. My name is Eric, I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will facilitate the question and answer session towards the end of the conference.

(OPERATOR INSTRUCTIONS)

I would now like to turn your presentation to your host for today's call to, Mr. Dirk Van Doren, Chief Financial Officer. Please proceed sir.

Thank you, Eric. Good morning, this is Dirk Van Doren. Before I turn the call over to Tom Ward, our Chairman, President and CEO, 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 fourth quarter and full year 2007. 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 can be located under the Investor Relations tab.

Now, for the forward-looking statement, please keep in mind during today's call, the Company will be making forward-looking statements, which are subject to risks and uncertainties. Actual results may differ materially from those projected in these forward-looking statements. Additional information concerning risks, 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, Non-GAAP financial measures. As required by 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 Tom.

Thank you, Dirk, and welcome to our fourth quarter 2007 earnings conference call. You have just heard from Dirk Van Doren, our Chief Financial Officer. We also have in our office Matt Grubb, our Chief Operating Officer. We posted our fourth quarter numbers on our website and Dirk will discuss those with you momentarily.

I will now discuss the quarter's operations. Today, we have 41 rigs operating, which are distributed as follows. There are 32 in the West Texas Overthrust, of which 31 of the rigs are drilling in Pinon. There is one rig drilling on one of our several 3D exploration targets that we will talk about during the course of the next few quarters. This well is drilling to 17,000 feet within our Big Canyon area and is the first well to spud using our 3D technology.

We have added two wells to the drilling schedule in the South Sabino area that will spud in March and April, and one additional well to be drilled in the Big Canyon area during this time frame. These wells are preliminarily projected to drill to a depth in South Sabino of 9,000 feet to 12,000 feet and the additional well in Big Canyon is also approximately 12,000 feet.

We now anticipate spudding 12 wells by the year end in the exploration areas outside of Pinon. However, we will not have results from any of these exploration wells until the second half of 2008. We also have five rigs working in East Texas, two in Oklahoma, one in Ector County, Texas, and one in the Galveston Bay area. We are encouraged by our drilling activity during the fourth quarter as we added 204 Bcfe at a finding cost of $1.39 per Mcf to raise our year-end reserves to more than 1.5 Tcf of gas equivalents.

We began 2007 with total proved reserves of 1.0 Tcfe, therefore, we have added over 500 Bcf equivalent of proved reserves during 2007. Our percentage of PUDs is 55%, which is down from 59% at the end of the third quarter and 68% at the beginning of 2007. The PV-10 of our proved reserves at the end of 2007 is $3.53 billion, which is up from $2.47 billion at the end of the third quarter. The percentage of the wells that we drilled in the fourth quarter that were PUD was 63% and the percentage of the PUDs drilled in the Pinon Field was 60% during the fourth quarter.

During the fourth quarter, SandRidge drilled and completed 97 operated wells in the western division and 27 operated wells in the eastern division. We have improved refining costs during the quarter to $1.39 per Mcfe from $2.27 per Mcfe in the third quarter, primarily through increased drilling efficiencies and by adding additional deeper Devonian Caballos drilling.

We are averaging 1,750 feet per well deeper across the Pinon Field than just one year ago in the first quarter of 2007. Last year, during that quarter, we averaged 5962 feet per well in the Pinon Field and now we are averaging over 7700 per well during the first quarter of 2008. While drilling deeper, we have also achieved a per-well reduction of cost by $400,000 during the last two quarters.

As we have discussed in previous calls, the WTO is a very complex area and did real well. We have now drilled 221 wells in the last 18 months and we are seeing the impact our drilling team is making on lowering finding cost. This improvement is directly correlated to days on location and penetration rate.

Pinon Field is a difficult area to drill. Therefore, we are hesitant to increase depth unless we are encouraged to find more reserves. That is what has taken place in the last year and will be even more evident as we move away from the Pinon Field. We are exploring for another overturned Devonian chert zone on the west side of Pinon field.

Instead of wells reaching TD at 8,000 feet to 9,000 feet, we are extending the TD to 10,000 feet to 11,000 feet to encounter another overturned chert section. These lower Devonian chert zones church zones are the main pay for us in the field to produce sweet gas. We believe that this type of exploration will continue in the Pinon Field during 2008.

We have not modified our model of $1.75 per Mcfe for drilling finding cost and $2 per Mcfe for our all-in finding cost that include our seismic and land expenditures, because we believe we will continue to drill for the deeper Devonian Caballos and do not yet know the cost versus the amount of gas found in these types of wells. We will also continue to add to our acre position as we have success with our 3D program. We are hopeful to have additional quarters like the fourth quarter. However, we will be pleased with meeting our top curb at $1.75 and $2.00 per Mcf on the finding cost side.

We produced 20.4 Bcfe during the fourth quarter for an average of 221 million cubic feet of gas a day. We ended the year at 235 million cubic feet equivalents and currently produce approximately 255 million cubic feet equivalent per day. We are projected to produce an average of 240 million in the first quarter and 95 Bcf for the year. Therefore, we remain optimistic that we will reach the projections that we have posted.

As we discussed in December, we are in negotiations with several potential partners to assist us in developing infrastructure for a high CO2 volumes of gas. We continue to focus on the Upper Cab reservoirs, our primary producer of the high CO2 gas. This reservoir produces between 60% to 70% CO2. However, each well that we drill has potential reserves of 7.3 Bcf at a depth of less than 6,000 feet. Therefore, it is very economical to drill for the reservoir and strip off the methane gas while delivering our potential partner the CO2 stream.

As we have discussed, in return for this stream of CO2, we are requesting the partner build infrastructure and plant capacity. We could do all of this ourselves, but we have determined that our capital is best suited to continue to explore for methane gas instead of investing in more plants and infrastructure. We believe that this reservoir will add over 1.1 Tcf of recoverable gas net to SandRidge and will be responsible for over 200 million cubic feet of gas, of additional methane gas by 2011 per day.

Due to the prolific nature of the reservoir, we anticipate only moving from one rig today to eight rigs in 2010 to produce the 700 million cubic feet a day of total volume gas. We continue to also evaluate how we will be able to explore for additional high CO2 reserves in the Fusselman and the Ellenberger formations across the West Texas Overthrust. We believe there are additional large accumulations of high CO2 gas to extract. However, we believe we will need to find additional capacity for treating an infrastructure to develop those reserves. We anticipate that we can find reserves up to 50 Bcf per well and model that we will only need to strip 20% methane to have finding costs that are less than $2.00 per Mcfe.

This project continues to interest us, but it is in all likelihood a 2009 or later event. I will say that interest in our CO2 volumes has not diminished in the last few months as West Texas Intermediate Crude remains a very attractive process for implementation of additional tertiary recovery projects in the Permian Basin. I believe that over time, we will have an ever-expanding pipeline system to carry CO2 to EOR projects across the Southwest U.S. and SandRidge will be a key component for sourcing those reservoirs.

We have now shot over 500 miles over a 1,400 square mile 3D shoot. We are impressed with the data and will have shot approximately 900 square miles by the end of this year. This year, we will tie together all of the leading edge of the West Texas Overthrust with 3D coverage. We are shooting the Pinon Field now and should have that force in process by the end of the second quarter of this year. Our [GFS assistor] is looking for major wrench faults surrounded by trapping thrust faults, overlying a deep seated structure. As you might imagine, this is a very difficult model to piece together without 3D seismic.

Once the major components are put together, we will look for individual tear faults within the wrench fault systems to develop fields. This last portion of the mixture is added through drilling wells. For example, we now can see the tear faults within the Pinon Field, but well control is needed to determine the best locations. In other words, you can be within a known producing fault block that would be updip or downdip within the block. Understanding this complexity will help us to drill the very best statistical wells within the field.

2006 was the year for SandRidge to acquire additional working interest in the Pinon Field. We were producing just over 20 million cubic feet of gas in June 2006. We acquired NEG and approximately 50 other additional working interest owners and now have over 92% working interest ownership in the Pinon Field. In 2007, we moved forward with an aggressive drilling program to expand Pinon Field and grew Company production by 73% year-over-year. We drilled 178 net wells in Pinon compared to 65 net wells in 2006. In 2008, we will explore the West Texas Overthrust. We have identified five new areas that we will explore outside of the Pinon Field this year.

As I mentioned earlier, we now project to spud 12 wells by the end of this year on those projects. We have begun that program and we are reporting how we do at the end of each quarter. We believe that there are no known geological reasons that the Pinon Field cannot be expanded. Therefore, we are naming six areas across the leading edge of the West Texas Overthrust that we will start exploring this year. These areas from west to east are Allison Ranch, Pinon, South Sabino, Thistle, Big Canyon, and McKay Creek. It is our intention to test each of these areas during this year.

While we are doubtful that we will find major discoveries on our first wells, we do believe that we will find the information necessary to tie back into our seismic program that will lead to further discoveries over time. In the meantime, we will continue to grow the Company's production through aggressively drilling the Pinon Field. We have now moved our projection of ultimate gas in Pinon to over 4 Tcfe, which is up from 2.5 Tcf last year. This growth stems from the continued expansion geographically of the field at the increase of reserves associated with the high CO2 Upper Caballos reservoir -- with that reservoir.

We have such a large asset in the West Texas Overthrust that we find it hard to not have a CapEx program that continues to be above our EBITDA. We are continually asked how we plan to fund the shortfall. Our answer has been that our preference will be to have 2008 as a debt year. We did raise over $1 billion of equity last year without increasing our debt. As we look out to 2009, we will continue to look at whether equity or potential sales of assets should be considered to fund the drilling program. I continue to be motivated to grow this Company by focusing on a single area that is very unique to our industry. With that, I'll turn the call over to Dirk for his comments.

Thanks, Tom. We were pleased with the financial performance for the fourth quarter and year-end 2007. I will focus on a few 2007 highlights, our current financial position and then our 2008 projections. The key matrices we look at are production and operating costs, EBITDA, free cash flow and funding needs if any.

Production and costs were within the range of our guidance. EBITDA was $135.3 million for the fourth quarter and roughly $395 million for the year, which was within our guidance and internal model. Free cash flow, cash flow less CapEx, was negative in fourth quarter and for the full year as capital expenditures were roughly $1.4 billion. However, during 2007, we raised $1.16 billion of equity and our debt levels rose less than $1 million. We ended the year with $1.07 billion of debt and $63 million of cash.

Looking at our current position, in January, we fixed our $350 million floating rate note for three years at 6.26% between April 1, 2008 and April 1, 2011. This is a pick up of 209 basis points compared to what we paid in 2007 and 69 basis points relative to the treasury curb at that time. In other words, we should save over $7 million in interest expense versus 2007.

Our current debt position as of February 29, 2008 was $105 million drawn on our revolver and total debt of $1.22 billion. Our net cash position was roughly $5 million. Additionally, we are now 76% hedged for 2008 on an equivalent price of 883 per Mcfe.

Let's look at 2008 guidance that was presented in our press release. We are estimating that production should be 95 Bcfe. Our operating costs excluding DD&A should be $2.77 to $3.04. The G&A estimate of $0.82 to $0.90 was a gross number before any capitalized G&A. With our current EBITDA estimate of approximately $620 million using the recent NYMEX strip pricing for production is not hedged. We expect to have negative free cash flow in 2008 as Tom mentioned.

Given the large amount of equity we raised in 2008, our preference is for 2007 -- our preference in 2008 is to be a debt year. We currently have $700 million line of credit, and based on our year-end reserves in PV-10, we hope to increase that line during March. We will evaluate the fixed income markets during the year to see if we can term out some of the revolver, but we are well aware that this market is currently struggling.

Looking to the remainder of the first quarter and to the second quarter, we will be at quite a few conferences, so please check our website for times and dates of these presentations. Of course, we are hosting our first investor analyst meeting in New York on Thursday at the Grand Hyatt and currently, we are planning to release our first quarter results on May 8th after the market closes with a conference call at 9 a.m. Eastern on May 9th. That ends our prepared remarks. Eric, we are ready to open up the call for questions.

(OPERATOR INSTRUCTIONS). Your first question comes from the line of Joe Allman with JP Morgan. Please proceed.

Good morning everybody.

Good morning Joe.

Hey, Tom, could you give us some more information on that increase in your estimate of the Pinon Field from 2.5 Tcfe to 4.1 Tcfe, or you have just over 4 Tcfe? Because if we are looking at the math, can you help us sort of visualize like where you are extending the Pinon Field and also if you would talk about recent wells, how do they compare in terms of production and costs versus wells you were drilling say six months ago or so?

I will take the last portion of the question and then let Matt discuss some of the reserve, how we look at Pinon today. Our costs during the fourth quarter did move dramatically down and we continue to move those costs down. However, I don't think we will move them at quite the same pace that we did during the last half of the year. So, as we discussed this before, but as we started drilling in the field in 2006 really were the ramp ups in 2007, our costs actually increased, and so now as we have basically the same amount of rigs working for a number of months, we've been able to focus on those costs.

And as I mentioned, our costs as we have even drilled 1,700 feet deeper, our costs have actually moved down by about an average of $400,000 per well over -- where our high point was in the middle of 2007. So, we do continue to do a better job of getting wells down and the costs are strictly associated with penetration rate and days on location. So, our guys are doing a very good job of drilling in a very complex reservoir. With regard to the growth in the Pinon Field, it's really just an expansion of the Pinon Field and also looking at the reserves in that Upper Cab zone that we talked about also has been increasing over time. Matt, do you want to hit that?

Yes. Actually, Joe, part of the increase is due to additional working interest and net revenue interest that we increased in the field through some acquisitions over the year. We also had an increase in our sweet Caballos -- sweet gas drilling this year and also the biggest increase is our tight curve on our Upper Caballos.

Last year, we worked on a tight curve of 5 Bcf with total gas with Upper Caballos, and that was raised by about 30%. The tight curve (inaudible) wells is replaced by 7 Bcf per well instead 5 Bcf, so that increase is about 600 million of methane per well on the Upper Caballos. So, you have about six-tenths of a Tcf increase there, about 0.13 Tcf increase due to the sweet gas and about 0.3 Tcf increase due to acquisitions. So, that brings you up from the 2.59 Tcf to 3.65 Tcf, and our PDP reserves is about 0.5 Tcf, that gives you the 4.1 Tcf.

And we will be at the investor conference, we'll go through this in a lot of detail.

Okay that's helpful. And then -- okay, but just to follow up with Matt there, so I got the 0.60 Tcf by increasing your tight curve 0.13 with the sweet Cab, 0.3 by increasing your working interest, your net revenue interest, can you tell me what was the rest of that again please?

That was (inaudible) 0.3 due to acquisitions, 0.13 for sweet gas increase, and 0.63 is the big one for the Upper Cab development.

Got you, okay. And then lastly and I'll get back in the queue, you guys are doing some activity in the Thistle Field. Could you talk about what you might still be doing there and if you are not doing anything there, what's your kind of takeaway from what you have done in the Thistle Field?

Yes, we have drilled in around Thistle Field and the old Sabino field. My takeaway is that those fields are still just in their infancy like Pinon was in 1987. However, there was no reason to keep spending money out there -- drilling wells as we were having our 3D programs over the area now.

So, we have moved back away from drilling outside of Pinon until we have the 3D and that's -- currently the 12 projected wells we are going to drill outside of Pinon are all on 3D. So, that's how come you don't hear of really moving back into Thistle or Sabino and probably will be a 2009 event that we expand those two areas as we shoot them later in 2008. So, there's really no change in thought of that, but this on Sabino are just small fields that should and could be expanded.

Okay, very helpful, thank you.

Your next question comes from the line of Ellen Hannan with Bear Stearns. Please proceed.

Hey, good morning.

Hi, Ellen.

Tom, just a follow up on your introductory comments, I think, about the expansion of CO2 and the processing capacity, gathering, et cetera, you say that you are more inclined to leave that now in the hands of your partner to spend money on, can you elaborate a little bit on that and does that have any implications for the CapEx in either '08 or '09?

No implications for CapEx for us other than we currently are spending money on a project to move forward. If for some reason, we don't find a partner in the project, we would move forward ourselves to be able to build a plant, we call it the Century Plant, and with that plant, it will allow us then to proceed with moving forward with drilling, moving from one rig in the Upper Caballos zone to as I've discussed eight rigs by 2010.

The idea is that there are potential partners in the Permian Basin that we could work with that would be able to use CO2, and for us, we'll make our money stripping off methane gas and producing methane gas. So, we believe the higher rates of return on capital would be by drilling rather than building plants and pipelines.

Okay. And then, just one follow up. I think Joe you kind of went through these numbers, but the 4 Tcfe that you are now looking at in Pinon, is that net recoverable to SandRidge?

Yes it is.

Okay. Thank you, that's it.

Next question comes from the line of [Vinod Chagwani] with Catapult. Please proceed.

Hi good morning guys.

Hi, how are you?

Good. Just a question on the strategy, should we expect SandRidge to continue to focus on growth in and around Pinon in the areas that you have already mentioned or would you be looking to expand outside that area, outside the West Texas Overthrust?

No. Our goal is to totally focus on the West Texas Overthrust.

Okay. And secondly, just if you can perhaps update the number of unbooked locations now that the PDP and type count has changed?

Sure. Matt, do you have that?

Yes. We have for the West Texas Overthrust and really just in the Pinon Field itself, we have 2,594 total locations, 397 locations are PUDs, 583 are probable, and 1,614 are possible locations, and that's all within the Pinon Field itself.

Okay, thank you.

Thank you.

Question comes from the line of David Heikkinen with Tudor Pickering. Please proceed.

Hey Matt, just a question, the split between your sweet gas and sour gas on those locations?

Okay. The sweet gas we are looking at 1,782 locations and then the high CO2 is 812 locations.

Okay. And similar ratios for PUDs, probables, possibles, I guess you probably have more probables than possibles on the high CO2?

Yes, on the probables, you have 382 sweet, 201 high CO2. On the possibles, 1117 sweet and 497 high Co2.

Okay, thanks. And then, the west side, talking about trying to drill to another overturned chert at 10,000 feet to 11,000 feet, can you talk about how big of an acreage area you consider the west side and how many wells that is and what you think that does for reserves per well?

We really don't know on a reserves per well basis. However, our best producing zone is the Upper Cab, but it produces high CO2. The best producing sweet zone is the Lower Cab over the Pennsylvania, which would be the Tesnus. And by adding another series of sweet gas down below, you could theoretically be adding 2 Bcf or 3 Bcf per well.

So, we can't say that yet and that's why we don't model it yet, but we -- the first, we are just now starting to produce those wells and we are seeing the same types of rates in the Overthrust that we see in the zone up above it. So, the way you think of us basically was sitting in there on the west side that you could cover, oh, maybe a third of our Pinon Field that would have this additional potential.

And whenever you hit that zone, you TD -- where we have TDed at 8000 feet, you drill another 1000 feet of shale or so and then encounter another 500 feet to 1000 feet of chert. So, these are massive amounts of rock that have been turned over. It is not in ten foot sections, there are in hundreds of feet. So, it's a big discovery whenever we decide to drill deeper and can find another well. I'd also expound that we really believe that the same thing happens on the east side of the field. We just haven't tested it yet.

Just keeps getting bigger. The final question is, as you head to the east, CO2 content in the Upper Cab, can you give your thoughts around what you think the overall CO2 content is going to be as far as a percentage across the field? Any updates there?

There are geological theories that would say that as we move east we run into less CO2. Those are just theories. We do know that we have very prolific wells on the east side of our fields that are sweet. We're not sure at all. We're not at all sure today that those are associated with the first Cab or maybe just in close proximity to a wrench fault that might make them so productive.

So, we're too early to say exactly what we believe other than there's a possibility that as you move east, you can run into the first Cab and have sweet gas and that theory is just now beginning to be looked at. So, it's too early to start putting anything to it other than it's something I think about.

Okay, thank you.

(OPERATOR INSTRUCTIONS). Your next question is a follow-up question from the line of Joe Allman with JP Morgan. Please proceed.

Good morning again guys. In terms of the revisions in your reserve data, could you break it up for us, what volume was price related, what volume was performance related and if you guys are in the performance related revision, if you're booking future locations, could you kind of break that up for us too?

I will pass that to Matt.

Price related revision is 20.1 Bcf. Performance related revision, these are revisions to previously booked reserves, 52.5 Bcf and all other revision related to drilling is approximately 279 Bcf.

Does that answer your question?

Yes, that's very helpful. And then back to a previous question. Tom or Matt, could you talk about like just recent production, could you kind of give a comparison between some of the productivity of the wells just recently versus what you were seeing maybe six months ago or a year ago? And then you talked about decreasing cost by $400,000, so what is the current cost right now roughly?

I'll take the first part of that. Really we're not prepared to say that statistically our tight curve has changed. In the past we drilled very good wells, isolated wells that are very good and we've had some of those recently. What we really see is that as we bring on more sweet gas that we have to continually make sure that our compression and pipeline system is keeping up with our drilling and we're just in time company, and every time we add on a new compressor station which is approximately every 60 to 90 days, we get a bump in production. And so, that's where we continue to see as compression comes on and new gathering systems come on that we have good increases in production.

We do believe that over time if our theories are borne out that we'll be able to change our production curve higher, and that's really a new thought to me. I was fairly confident that we were drilling a tight curve that had been there for a number of years and was very confident in the sweet tight curve that we have. However, as we move away from drilling less Tesnus, which is a Pennsylvanian sand, to drill in these Devonian Cherts that have higher deliverability that were actually I believe in time we'll move that curve up. So I'm not prepared to say that the curve is moving and we are very comfortable with where we have it, I think that maybe next quarter we can talk more about that. And, Matt, on the reserve?

Yes. Just to elaborate a little more, as Tom said, we increased our drilling depth from about 1,700 feet over the course of the year and maybe recently increased this drilling less Tesnus wells and more Lower Cab wells. And the reason being as you're finding cost is better for your Lower Cab, the Tesnus is about 0.75 of a Bcf of well and a Lower Cab tight curve is about 2.6 Bcf per well. So, as we move to Lower Cab, we were able to reduce our finding cost as well as develop more reserves for the dollar.

As far as cost improvements to $400,000 per well -- at the beginning of the year we were running about 12 rigs in Pinon and we rapidly ramped up to 30 rigs by May. And during the ramp up, that really ramped our cost, we lost a lot of efficiencies during that time. And our finding cost at Q2 was about $1.48 Mcfe and Q3 it ballooned up to over $2.00 about $2.27 and in Q4 we brought it back down to $1.39 Mcfe, resulted in drilling finding cost for the year of $1.61. But as far as the Lower Cab, it's been a year of those -- several drilling, about half of our rigs is drilling in Tesnus and half Lower Cab.

By the end of the year when we are around 30 rigs, we will probably have 24 rigs, 25 rigs in the Lower Cab and four or five in the Tesnus. And our Lower Cab costs went from about $3.3 million at the beginning of year, it ballooned up to a little over $4 million in Q3 and we brought it back down to $3.2 million range. So, as we got our rigs ramped up to a 30 rigs and were able to maintain that rig count for several months, we regained our efficiency and brought our cost back down.

Okay, it's very helpful. And then, just to clarify an earlier point about the CO2 agreement that you're working on. Tom, are you indicating that you probably won't have an agreement until 2009 or that that project won't really get underway until 2009?

The project is actually underway. We've already started the project and we believe that sometime this year we'll have an agreement.

Okay. So sooner rather than later?

Yes.

And then, can you talk about East Texas, anything that highlighted over there in East Texas? And then what are the kind of plans long-term for East Texas and some of these other assets?

East Texas continues to be a very good area to drill for us. There is really nothing that stands out about our acreage position versus a lot of other companies. We have 30,000 acres of land that -- what does stand out is that we have a block of acreage that's never been drilled on. So, instead of saying we're going to move from 160s to 80s or 80s to 40s or 40s to 20s, we have a block of raw acreage that we're starting to develop.

And our belief is that over time we'll be able to move that in the proved basis and then we can look at that asset and decide if we should keep it or if we should monetize it to help fund the West Texas Overthrust. We don't have any preference today. One way or the other we know it's too early to try to monetize the asset because we haven't proven we've given up too much raw acreage.

Just any update on Pinon's assets?

We're in a process that continued to look to sell that asset and we think that that could happen during this quarter, actually in the second quarter, sorry.

Got you. Okay, very helpful. Thanks guys.

Your next question comes from the line of [Michael Land] with [Fairmont Capital]. Please proceed.

Hey, good morning guys.

Good morning.

Real quick Tom. I wonder if you could share any views on gas prices and how that might influence hedging in '08, additional hedging in '08 and beyond? Thanks.

Sure. We've not hedged any gas since January 29th, but we did hedge obviously, a lot of gas through 2008 and what our goal is as Dirk and I sit around and talk, is that we want to make sure that if we are going to be out spending -- if our cash back is going to be more than EBITDA that we want to guarantee that we have an EBITDA stream.

So, we did fairly aggressively hedge our '08 gas, then looking forward still continue to be pretty bullish at long-term natural gas prices. So, we've not chosen to hedge very much past '08. We have about 22% of our gas hedged in the first quarter of '09 and really nothing after that. So, even though we're fairly well hedged in 2008, we have a very open book after that and obviously long-term continue to be bullish energy.

We currently have no more questions in queue at this time.

Well, we thank you so much for joining us and we hope to see you in New York on Thursday morning. Good bye.

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