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Southwestern Energy Co. (NYSE:SWN)

Q4 2007 Earnings Call

February 29, 2008 10:00 am ET

Executives

Harold Korell - President, Chairman and CEO

Richard Lane - President of E&P segment

Greg Kerley - CFO

Analysts

Richard Tullis - Capital One

Jason Gammel - Macquarie Capital

David Snow - Energy Equities

Brian Singer - Goldman Sachs

Tom Gardner - Simmons and Company

Jeff Hayden - Pritchard Capital Partners

Robert Christensen - Buckingham Research

Scott Hanold - RBC Capital Markets

Gil Yang - Citi

Joe Allman - JPMorgan

David Heikkinen - Tudor Pickering

Operator

Good day and welcome to the Southwestern Energy Company fourth quarter earnings teleconference. At this time, I would like to turn the conference over to the President, Chairman and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.

Harold Korell

Good morning and thank you for joining us. With me today are Richard Lane, the President of our E&P segment, Greg Kerley, our Chief Financial Officer.

If you have not received a copy of the press release we announced yesterday regarding our fourth quarter and yearend 2007 financial results, you can call 281-618-4784 to have a copy faxed to you. Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and forward-looking statements section of our annual and quarterly filings with the Securities Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

Well 2007 was an outstanding year for Southwestern Energy. Looking at our achievements, we grew our production volumes by 57%, which is over the 2006 levels and our reserves grew by 41%, the 1.45 trillion cubic feet equivalents, which represents our reserve replacement ratio of 474%. Well, these results are important, the key accomplishments for us in 2007 was the progress we made in our Fayetteville Shale play.

During the year we made advancements in our completion techniques for the Fayetteville Shale, significantly increased our 3-D seismic database there by improving our ability to reduce risks in our drilling program, and began drilling and completing longer laterals all of which is leading to higher productivity in our horizontal wells.

Our progress in the Fayetteville Shale during '07 has set stage for another year of substantial growth in our production and reserves in 2008. We believe our production reservoir gain this year somewhere around 30% to 35%, and we are looking forward to some new things, which include the results from our development project, testing we are doing in the Fayetteville, our drilling results in the James Lime in East Texas and future opportunities we have exceeded in the Marcellus Shale in Pennsylvania.

I would like to now turn the teleconference over to Richard for more details on our E&P activities, to Greg for an update of our financial results. And then we will take questions.

Richard Lane

Good morning. In 2007 gas and oil production totaled 113.6 Bcfe. Our Fayetteville Shale production was 53.5 Bcf in 2007 up substantially from the 11.8 produced in 2006. We produced 29.9 Bcfe from East Texas in 2007, 23.8 from our traditional Arkoma Basin area, 6.4 from our Gulf Coast Permian Basin and New Ventures areas combined.

Production for the fourth quarter of 2007 was 34.9 Bcfe up 68% from the fourth quarter of 2006. Our production from the Fayetteville Shale increased to 19.9 Bcf during the fourth quarter up from 5.5 in the fourth quarter of '06. As a result of our continued strong performance, we have increased our first quarter production guidance range by 1 Bcf to 35 to 36 bcf. Our full year guidance remains at 148 to 142 Bcfe.

In 2007, we increased our year end improved reserves by 41% to 1.45 trillion cubic feet. The 1.45 approved reserves were located approximately 49% in the Fayetteville Shale, 24% in East Texas, 21% in the conventional Arkoma Basin, and 6% in other areas. In 2007, we added 507.9 Bcfe approved reserves and had net approved revision of 31 Bcf. Both the addition and revisions were primarily driven by the performance of our wells in the Fayetteville Shale play.

Including both our additions and revisions, we replaced 474% of our 2007 production. We had a finding and development cost of $2.55 per Mcfe, excluding revisions that cost us $2.71 per Mcfe. Proved developed reserves accounted for approximately 64% of our total reserves at yearend 2007.

In 2007, we invested $1.38 billion in our exploration and production business activity and participated in drilling 653 wells. Of those wells, 439 were successful, 17 were dry, and 197 were on progress at year end for an overall success rate of 96%.

Of the $1.38 billion invested in 2007, approximately 1.3 or 82% was for drilling wells, $166 million was leasehold acquisition seismic and $84 million in other cost. In our Fayettevale Shale play in 2007, we invested approximately $960 million including $789 million to spud 415 wells, $97 million on seismic, $25 million on land, and $49 million on other capitalized cost.

We added 401.6 Bcf and had 67.9 Bcf of upward reserve revisions, primarily due to improved well performance resulting in an all-in finding and development cost of $2.05 per Mcf. 3-D seismic cost longer represent approximately $0.20 per Mcfe of the total finding cost.

At the end of 2007, we held a total of approximately 907,000 net acres in the play of which 143,000 net acres are held by Fayetteville Shale production and approximately 125,000 net acres are held by conventional production in our traditional Arkoma Basin areas. Excluding areas held by production, our year end acreage position has an average lease term of six years, and average royalty interest of 15% and our cumulative all-in average acreage cost is $116 per acre.

Gross production from our operated wells in the Fayetteville Shale play increased from approximately 100 million cubic feet per day at the beginning of 2007 to approximately 325 million cubic feet per day by year end, and that could approach 450 million cubic feet per day by the end of 2008. As of mid-February, our gross production rate has increased to approximately 350 million cubic feet per day. We expect our total 2008 net production from the Fayetteville Shale to range from 90 Bcf to 95 Bcf as compared to 53.5 during 2007.

Our total proved gas reserves in the Fayetteville at year end 2007 were 716 Bcf, compared to 300 Bcf at the end of '06. Gross proved developed reserves from our horizontal wells ranged from 0.1 Bcf to 4.7 Bcf per well, and the average gross proved undeveloped reserves per well included in our year end reserves, was approximately 1.5 Bcf per well, up from 1.15 Bcf per well at the end of 2006.

During this past year, we have transition to drilling longer laterals completing almost all our wells with slickwater stimulations, and we began to see the benefit of our 3-D seismic program. At yearend, we had acquired approximately 525 square miles of 3-D data in the Shale area and expect to have required or purchased another 370 square miles of 3-D seismic data by the end of 2008.

As of February 19th, we have drilled and completed 116 wells with lateral lengths over 3,000 feet. Our average initial production rate for these wells has been 2.1 million cubic feet per day and average well cost has been $3 million. We currently expect average ultimate gross recovery from wells drilled with greater than 3000 foot laterals to range from 2 Bcf to 2.5 Bcf per well.

During 2007, our average completed well cost for our operator horizontal wells was approximately $2.9 million. During the fourth quarter, the typical horizontal well had an average lateral length of 3,120 feet and an average time to drill to total debt of 15 days from re-entry to re-entry. We are seeing meaningful improvements in early time well production, and in our drilling and completion costs per foot of well and this trend has continued into the first quarter. We are currently forecasting an average drilling and complete cost of $3 million for horizontal well in 2008.

In late 2007, we began a project to demonstrate the benefits of full-scale development strategy, in a four section area of our Southeast Rainbow pilot area in Conway County. We planned to drill 22 wells in total there, which 21 will be developed on multi-well pad and 8 will be simultaneously fractured stimulated.

Results here we provide key information regarding potential cost savings, well spacing, benefits of longer laterals, simultaneous completions and other centralized operations. While, we are still very early in the project and have only drilled a portion of the total wells, we can see the potential for cost reductions independent of service cost variations.

In our conventional Arkoma, activities in 2007, we invested approximately $148 million in our conventional play, drilling 114 wells of which 81 were successful, 23 were in progress at year end in resulting an adds of 60.6 Bcfe.

Our 2000 production from the Arkoma Basin was 23.8 Bcfe an 18% increase, when compared to 2006 production, and proved reserves there totaled 304 Bcf at year end. At our Ranger Anticline area located in the southern part of the basin, we successfully completed 52 out of 67 wells during 2007, excluding 12 wells that were still in progress at year end.

Our net production Ranger increase to 9.5 Bcf from 5.7 Bcf in '06, an increase of 67%, its drilling our first successful well at Ranger in 1997, we have successfully drilled 156 out of 185 wells, adding 140 net Bcf of reserves at a finding cost of about $2 per Mcf including reserve revisions.

During 2007, we accelerated our drilling at our Midway prospect located just 11 miles north of the Ranger project. We drilled 26 wells, all of which were productive or still in progress at year end. We operate these wells with an average working interest of 60%.

At year end '07, we held approximately 31,000 gross acres in our Midway project area and depending on the performance of the wells drilled there maybe significant drilling potential on our acreage going forward. In 2008, we planned to invest approximately $132 million in our conventional Arkoma program, and drill approximately 100 to 110 wells including 40 wells at the Ranger project and 45 wells at Midway.

In the East Texas for the year we drilled 80 wells primarily in our Overton Field and our Angelina River Trend area. Net production from East Texas was 29.9 Bcfe during 2007 compared to 32 Bcfe in 2006. Our drilling program at Overton during 2007 focused on drilling mostly approved undeveloped locations. We invested $96 million during the year to drill 45 wells all of which were completed.

Our Angelina River Trend properties are concentrated in several separate development areas located in four counties in East Texas. Our primary drilling targets start at Travis Peak in the James Line formations. During 2007, we invested $88 million to drill 31 wells that are Angelina River Trend, although one of which were successful or in progress at year end. Our drilling result included a new discovery at the Jebel prospect area in Shelby County in the James Line formation.

The Timberstar-Mills 1H horizontal discovery well was completed in December with initial production rate of 12.1 million cubic feet per day and is producing approximately 4 million cubic feet per day after 44 days of production. Earlier this month, we placed our second James Line horizontal well on production.

The Sessions Heirs #16H well located in Angelina County, approximately 35 miles west of our first discovery well at an initial production rate of 6.7 million cubic feet per day. We are currently completing our third operated James Line horizontal well and drilling our fourth and fifth wells. At December 31, 2007 Southwestern held approximately 87,000 gross acres in Angelina with an average working of just over approximately 73%.

Also in 2007, we invested approximately $42 million in our new ventures program including $17.5 million to purchase acreage in the Pennsylvania, Marcellus Shale play. We currently hold approximately 98,000 net undeveloped acres in the play, we believe to be perspective. We plan to spud our first vertical well on acreage during the first quarter.

We also invested approximately $10 million in 2007 and drilled 25 wells in our Riverton coalbed methane project in Caldwell Parish, Louisiana, of which 18 were successful and 7 in progress. We have approximately 32,000 net acres in this project area and target the Tertiary-age lower Wilcox coals at a depth of approximately 2,800 feet.

In summary, we are very pleased with our record results in 2007. We continue to be very encouraged by our success in our Fayetteville Shale project, in our programs in the Arkoma Basin and East Texas are performing well also. We are looking forward to continued strong results in 2008 including meeting or dealing our PVI target 30% to 35% production growth, very significant increases and proved reserves.

I will now turn it over to Greg, who will discuss our financial results.

Harold Korell

Before Greg start, Richard I think you misstated one thing early on that, which probably correct, but the record that listed our guidance for the year remains 148 to 152 Bcfe, I think when you said, you said 142. I know the numbers 152.

Richard Lane

That's right, yeah.

Greg Kerley

Thank you, Richard and good morning. We reported net income of $221.2 million in 2007 or $1.27 per share up 36% from the prior year. Our operating cash flow defined as cash flow from operating activities before changes in our operating assets and liabilities increased 57% to $651.2 million. These increases were largely driven by the significant growth of our production volumes from the Fayetteville Shale.

Our earnings for the fourth quarter were $71.6 million or $0.41 per share, more than doubled the $33.8 million, we earned in the fourth quarter of 2006. Our operating cash flow also increased significantly to $204.3 million, up from $108.7 million in the prior year, again driven by the significant growth in our production volumes. Operating income for our E&P segment was $358.1 million in 2007, up from $237.3 million in 2006. We have produced 113.6 Bcf equivalent in 2007 and realized an average gas price of $6.80 per Mcf.

Our commodity hedging program increased our average gas price during the year by $0.64 in Mcf. Our current hedge position, which consists of fixed-priced swaps and collars, provides us to support for a strong level of cash flow. And for 2008, we have most 80% of our projected natural gas production hedge, we have 70 Bcf hedge with fixed-priced swaps at an average price of $8.43 in Mcf and we have 48 Bcf hedge, the price colors within average floor price of $7.92, and an average selling price of 11.60. Our detailed hedge position is included in our Form 10-K filled yesterday.

Our lease operating expenses for per unit of production were $0.73 in Mcf in 2007, up from $0.66. The increase was due primarily to increases in gathering and compression cost related to our operations in the Fayetteville Shale. We expect our per unit lease operating cost to range between $0.85 and $0.90 per Mcf in 2008 due to the increased production volumes from the Fayetteville Shale.

General and administrative expenses per unit of production were $0.48 per Mcf in 2007, compared to $0.58 in 2006. The decrease was primarily due to the effects of our increased production volumes, which more than offset increased compensation and related costs primarily associated with the expansion of our E&P operations. We added a total of 243 new employees during 2007, most of which were in our E&P segment. We expect our general and administrative expenses per unit of production to range between $0.42 and $0.47 in Mcf in 2008.

Taxes other than income taxes were $0.16 per Mcf equivalent 2007, down from $0.30 in the prior year due to changes in severance and ad valorem taxes that primarily result from the mix of our production volumes and severance tax rate refunds related to our East Texas production during the year. In 2008, we expect our rate to range between $0.20 and $0.25 per unit of production.

Our full cost pool amortization rate averaged $2.41 per Mcf in 2007, compared to a $1.90 for 2006. Our amortization rate is primarily impacted by the timing and amount of reserve additions and the cost associated with those additions.

Operating income for our Midstream Services segment was $13.2 million in 2007, up from $4.1 million in 2006. The increase was primarily due to higher gathering revenues related to our Fayetteville Shale play partially offset by increased operating costs and expenses. In 2007, we had gathering revenues of $37.7 million on volumes of 78.7 Bcf, compared to $7.9 million of gathering revenues in 2006 on volumes of 14.6 Bcf.

We are currently gathering about 400 million cubic feet of gas per day in the Fayetteville Shale play area to approximately 595 miles of gathering lines. We expect our operating income from our Midstream activities to more than double in 2008 and range between $27 million and $30 million as reserves related to the Fayetteville Shale continue to be developed and production increases.

Operating income in our utility segment was $10 million in 2007, up from $4.5 million in 2006. The increase in operating income was due to the implementation of our rate increase, which became effective August 1 of last year along with colder weather and a decrease in operating costs and expenses.

In November, we signed a stock sale and purchase agreement for the sale of our utility subsidiary for 224 million plus working capital. The transaction is subject to certain closing conditions and regulatory approvals and as expected to close approximately in midyear 2008. At December 31, 2007, we had total indebtedness of approximately $979 million, including $842 million borrowed on our revolving credit facility, resulting in a capital structure of 37% debt and 63% equity.

In January, we issued $600 million of 7.5% senior notes due 2018. The proceeds from the notes we use to pay down our revolving credit facility. At December 25th, we had about $280 million borrowed under our facility, which has a current capacity of $1 million. The combination of our growing cash flow, planned asset sales and available borrowing capacity provides a significant flexibility in executing our planned capital investment program in 2008.

Finally, we announced two-for-one stock split yesterday. The split will be effective for holders of record on March 14th and payable on March 25th, 2008.

That concludes my comments. So, now I will now turn it back to the operator, who will explain the procedure for asking questions.

Question-and-Answer Session

Operator

(Operator Instructions) And our first question will come from Richard Tullis with Capital One.

Richard Tullis - Capital One

Hey, good morning, nice quarter. Just two quick questions, one, what's your current outlook on potential severance tax changes in Arkansas?

Richard Lane

It's a good question. The playing field is running is various directions, for those of you who follow it. I'm sure that you have seen that there is a proposal to have an initiated Act up there by an individual that has put that forth.

I think that the outcome of all of this would be pretty much depended upon factors that some what are within our controls, some are outside our control. Our position on this is that we are continuing to work with the leadership of the state to propose a plan that would not unduly burden our operations.

So, that's our effort and as far as what might eventually come; it's a little bit difficult to say, as there are continuing conversations on a daily basis.

Richard Tullis - Capital One

Do you think some of the wells that you are drilling could actually be exempt similar to what's done in, say Oklahoma and Texas?

Richard Lane

The potential for that, that would certainly be inline with what the governor has stated up there, that he wants a severance tax that is fair relative to other states and those parameters are definitely included in nearby states.

Operator

And moving on, our next question will come from Jason Gammel with Macquarie Capital.

Jason Gammel - Macquarie Capital

Hi. This is actually his associate. I had a question on the East Texas based on preliminary reserve, there are no net reserve book in East Texas, we would have thought that was 80 wells in the Angelina River Trend, we would have seen some reserve booking. Can you comment on that please?

Richard Lane

We had drilling in Overton Field and drilling in our Angelina River Trend. What's affecting some of that is that we developed mostly pre-existing locations, proved and undeveloped locations at Overton and then also we had some performance revisions in the area that affect that number.

Jason Gammel - Macquarie Capital

Okay thanks.

Operator

And moving on our next question will come from David Snow with Energy Equities.

David Snow - Energy Equities

Yes, I'm trying to get an idea of what the amount of acres you would tap into with these 3000 foot lateral lengths just trying to get an idea is to what Bcfs per unit of acreage you are looking at recovering, as you go into longer laterals?

Harold Korell

Well, our recent materials here provide some guidance on that also give some, look at some of the productive history of the wells that are longer than 3000 feet. So, I'd guide you to the referencing that, but I can tell you that it's early in our history in the 3000 foot or longer wells, but we think that it's reasonable for those to ultimately recover 2 to 2.5 Bcf per well.

David Snow - Energy Equities

Well, would you be able to put those - how many of those could you put into 640 acres spacing or is that something you got to determine with your down spacing and simulfrac pilot?

Richard Lane

It will depend on the ultimate spacing that you have mentioned there, if you look at 80 acre spacing, which we are not certain that ultimately, where we will be, but kind of our nominal development plan right now that eight wells per 640.

Harold Korell

On the other hand, where we are currently carrying on this -- we've call it development project area in the four sections in the Southeast Rainbow area, whatever we call that area is -- we actually are drilling, the plan there is to drill six wells per section, if you laid it out and I try to describe this and maybe I refer you if you want it, on the last teleconference back to that descriptions. So, I maybe I don't have to do that completely again as we would be drilling North, South wells space 1000 feet apart and that would if you lay out a section that would mean there would be six wells per section if you repeat that.

Well, we don't know that is, we don't know whether the wells being spaced 1000 feet apart is the appropriate spacing to develop all the economically recoverable reserves out of those sections, and the only way for us to know that in fact is to do one thing and then test another thing. So, right now we are at the point of drilling in that one development area well space to 1000 feet apart, which would result in six wells per section. Fewer wells than eight, two wells less than eight, that would repeat across, but our intention certainly is that at some point we need to also do a test drilling wells closer than 1000 feet apart possibly. And it will depend upon the results and performance of what we are doing in the development area.

One other things that clearly I know some people, who follow us have trouble with this, the concept that we are still very partially spaced and everywhere because we have so much acreage that we are drilling on and we are doing this one test area, so that we can try to begin to answer these questions, but we can answer the questions about is at 80 acre or 40 acre or some other thing in between yeah.

Some of the other companies have been doing well on tighter spacing already. They may have some views on it. I don't know that their views and ours will be the same. We'll have to test this on our own.

Operator

And moving on our next question will come from Brian Singer at Goldman Sachs.

Brian Singer -Goldman Sachs

Thank you. Good morning.

Harold Korell

Hi, Brain.

Richard Lane

Good morning.

Brian Singer -Goldman Sachs

Can you talk more about the James Lime, I guess, what do you think based on the drilling that you have done so far and how many -- how far this play tends within your acreage and when you look at the rates of return that you are seeing. How would you stack up the James Lime versus some of your other, I guess non-Fayetteville opportunities?

Richard Lane

Well, Brian. We are really just trying into that. We do have a pretty nice sized acreage block there. Our interest is that, where we drilled is kind of the far east part of our block at Jebel and then the other well I referred to the Sessions well, would be the most westerly part of our acreage.

So, it's nice to see something 30 some miles apart, still be present and productive. It certainly doesn't prove up, where we acre in between, but there is a lot of the story left to be told there, as we go this year. We said we've drilled maybe 10 to 15 wells in that program this year and that will certainly give us a lot more look at how much that acreage could be perspective.

Early on in terms of returns, early on we see good potential for nice return that exceeds our PVI threshold or we wouldn't be doing it. So, that's encouraging. We don't have that much production history yet. So, I wouldn't want to compare to other projects yet. But it definitely has the potential to exceed our return thresholds.

Brian Singer - Goldman Sachs

Thanks. My second question is just looking at natural gas prices that have moved up recently. What capacity and interests do you have in ramping up activities as gas prices do stay strong and where would that be if at all?

Harold Korell

Brian, that’s a good question for us, not just with gas prices moving up some, because I guess when gas prices are moving around, my normal answer to that is the current months we aren't a whole lot of effective buying, how we think generally, and we are looking at the out prices and we have done a fair amount of hedging,

So that statement still is kind of is the overarching statement on gas prices, but our job as we go forward here in 2007. We have a plan right at this point in time for $1.45 billion or $1.46 billion capital plan and the guidance that we have out there depending upon what gas prices are, but if you look at $7 or $8 generally, we would have cash flows of a $850 million to $900 million range and I guess slightly maybe slightly above that.

But the point is we are still short on in cash flow to fill the capital need as Greg mentioned earlier. We have the utility we are selling this year; we are considering some other sales of assets and in order to fill that gap along with our increasing cash flow, so we have to constantly keep an eye on all of the variables.

The gas price is one of the variables, but potential asset sales is another, we need to conclude the sale of the utility and monitor all of those things, there is no doubt that we have pressure internally in Southwestern energy to do more.

We have pressure to -- would like to at some time when we get our organization fully flushed out, do more drilling in the Fayetteville Shale. We would like to accelerate drilling there if this is East Texas, if these wells hold up and just allow as we drill and look good, we are going to have a desire as I credit to drill more wells in East Texas.

We haven't begun drilling in the Marcellus yet and then those projects which are described in the conventional play in the Arkoma are also looking quite good, so good thing is we are flushed with opportunities, but we want to be good managers of our balance sheet at the same time, so all of those things have to come together and it's too early for us to talk about increasing our CapEx right now.

Operator

And moving on, our next question will come from Tom Gardner with Simmons & Company.

Tom Gardner - Simmons and Company

Thank you. Good morning, guys. If I can ask some good questions, let me add a just a follow-up on his James Lime question. I'm looking for more color with respect to how you are going about identifying prospects and how big could this play be, and perhaps any idea of a relationship between initial rates and ultimate recoveries you might have, would be helpful as well.

Harold Korell

Well I mean the size of the play as an industry, could be very large, so I would tell you that our acreage position we've talked about is over 9,000 gross acres, so that gives you a sense of the magnitude internally here for Southwestern Energy.

I probably wouldn't speculate a lot more about what these wells ultimately will do as in other plays like this the initial rate tends to give you some indication of the ultimate recovery, but not always. So that we think we will exceed our threshold as I mentioned, but we are going to have to see more production history.

Tom Gardner - Simmons and Company

Okay. And of the wells did you planned to drill in 2008 companywide, what fraction are not booked as proved as of yearend '07?

Harold Korell

Well, the biggest factor there area, obviously would be in the Fayetteville Shale, really what you are asking there I guess is how many wells in the Fayetteville Shale program in '08 will be drilling undeveloped locations.

I can tell you that percentage in '08 is pretty low, because we are still meeting to step out in whole acreage, so might not be as high as you might think and that that would probably go up as time goes on.

So, because so many of our wells are moving only a second or third well on a section and moving into new sections and part of strategy the whole land, it's not that greater percent in 2008.

Operator

And next from Pritchard Capital Partners, we'll go to Jeff Hayden.

Jeff Hayden - Pritchard Capital Partners

Good morning, guys. Remember a of follow-up question, I believe it was to what David was asking, we guys are looking at the Rainbow pilot given kind of speaking pattern, you guys are initially thinking about what kind of recovery factor would that imply.

And then second question you guys have built up a pretty good inventory of 3-D seismic, you have drilled a lot of wells across your acreage, you are building up more, can you give us a sense. You have had that sort of 50% of your acreage number out there in your presentation for a while. Can you give any sort of an update on how much of your acreage position you are really think is going to be economical right now?

Greg Kerley

Well, that the recovery Jeff, the recovery ultimate recovery percent there is still not only defined. We think that something in the 20% range or possibly higher is reasonable from what we have seen so far and on the 3-D seismic we didn't get a lot of utilization of that in 2007 because the data was being acquired and being processed as we're going through the year and then late year we start to get it in-house and be a tool for us and starting to see some help from that in 2008 to a much greater percent of drilling.

We will be utilizing on 3-D seismic, I think we've, our look at that when we put our plan together were some around 75% of our wells would be covered by that. The guidance towards the percentage of the acreage that will ultimately be developed, probably your best thing to refer to there is some of the materials we've put out. In our public materials we have a map that shows the distribution of all the pilot areas that we've drilled and you can see how much that's been delineated there. I'm not trying to avoid and exact number, but that's the best thing to look at.

Jeff Hayden - Pritchard Capital Partners

Alright, thanks for that guys.

Operator

And moving on our next question will come from Robert Christensen with Buckingham Research.

Robert Christensen - Buckingham Research

Good morning. How was the conventional exploration going in the Fayetteville Shale leasehold if you will, it seems like it might be backend loaded in the years that because of the seismic just driving in-house or what's going on there, Richard please?

Richard Lane

Well, its going very well from my perspective. We've encountered conventional pay zones through a pretty broad area in the play. We are seeing really nice rate from the majority of those wells and strong economics given the relatively low cost to drilling complete those wells. I think your assessment is right in terms of the timing for '08. We saw the activity really by virtue of our plan and when we would dedicate a rig to that program really start to kick in about now. So, I think we will have more to report on that in the second quarter, but I'm very encouraged.

Robert Christensen - Buckingham Research

And a follow-up, how much horsepower in the way of compression would you estimate has been put into the Fayetteville Shale as of this moment.

Greg Kerley

This is Greg. We don't have our guy here. It is over 100,000 somewhere 105,000 - 106,000

Richard Lane

106,000 horsepower.

Robert Christensen - Buckingham Research

How does that work I mean when you install it, I take it would be centralized and does it run all out of the day installed or do you start out for the 1200 horsepower machine and do you start life out with 700 horsepower than ramps and ramps and ramps, as the field is individual wells decline pressures decline, just some basic layman's terms that's all unfolding.

Harold Korell

Bob when you look at our map and look at the areas that we are drilling across, as Richard said earlier. It's spread out. It's very broad area, that we have drilled in and in order to get production task and establish well, decline curves and all we have produced. So, that means we have the way lines to those wells and that means we have that compression in anyplace where we are reporting production curves.

So, the compression is, in general is spread out, but its also, in the other way of saying, it is a centralized because of the main gas transmission lines, we laid laterals, we called laterals out into the field area to a central gathering point location and then multiple wells eventually will come to that central gathering point. We have many central gathering points all there its not just one, there are many, because being such a broad area.

So in the beginning, let's say take the boundary condition case of one well, meaning one well, I want to say drilled out there all by itself when you have one compressor depending upon the volume that would come out of that one well. It may only partially load that compressor or over time you have to change that compressor, as you drill more wells in order to effectively load it.

So, one of the things that actually, I don't know if you are touching on it, but efficiency of compression is one of the matters here because the compressors run and then they use fuel and they are running 24-hours a day. So, if they are not fully loaded, you have higher operating cost than you'd like. So, one of things that over time we have to try to optimize on and we are by no means there.

Our guys are doing a great job, but when we are drilling wells over such a broad area it doesn't afford you the complete the efficiency that you'd want to have, which ultimately is, you going to an area along with laying out the geological parameters and the well spacing. You'd also think through how you drilled that relative to the compressor that you size for it.

In other words you don't want to drill so much in an area where you have to install way more horsepower than you eventually need over the life of that, so there is a lot of optimization that will come along.

Good thing is having the sort of gathering that you are doing this for us, it gives us lot more flexibility along those lines.

Operator

And next from RBC Capital Markets, we'll go Scott Hanold.

Scott Hanold - RBC Capital Markets

Yeah, thanks. Good morning.

Harold Korell

Hi, Scott. How are you?

Scott Hanold - RBC Capital Markets

On the James Lime play, just one another question. I know that you have talked a quite a bit about this play, but it looks pretty exciting and looking at your position and where other are doing that, how much acreage do you think is there left to pick up is there more, are you guys sort of actively looking at picking up some more in this play?

Harold Korell

There is more from our perspective and our opinion, but where we see the play to have potential and we are still active doing some of those things, Scott. Obviously you don’t want to pinpoint that but, we want to call the Chesapeake jets on our troops.

Scott Hanold - RBC Capital Markets

Fair enough. And then second question, it looks like you sold your assets in Culberson, and I guess you hinted towards other outlook and at other opportunities to monetize some assets potentially.

Can you just talk in general sense of what kind of efforts you are doing, or what kind of assets could be up for sale in the company yet?

Harold Korell

We generally don't talk a whole lot about that, but we have mentioned Permian and Gulf Coast areas that we would consider selling this year, and there are potential for other things that we are thinking about.

Operator

And next, we’ll go to Gil Yang with Citi.

Gil Yang - Citi

Hi, and I've got some pretty routine questions maybe partially answered before. You made a comment in the press release that LOE would go up in '08 because of higher volumes, and that's seems counter intuitive because I would think that you will get some kind of cost leverage synergies, could you Harold and Richard may explain that a little bit.

Harold Korell

I think the effect there Gil is, where the waiting of the production is, this total where the Fayetteville Shale play as we as it becomes more and more a higher percent of our total company production, and we have just discussed a lot of that reasons why those working costs of what they are, that's really the effect that you are seeing is the not so much the throughput driving that is where the throughput is.

Gil Yang - Citi

Okay, so the Fayetteville's higher cost that is just still ramping and so you are somewhat inefficient in terms of capital of --

Richard Lane

Well, there was a coupe things that the Fayetteville for example is higher operating cost than our old conventional Arkoma Basin production, so as a company as we have more of the Fayetteville coming online relative to our old base, its going to be higher.

Our operating cost per unit -- I think the way you said it in the beginning was seems strange to you that we would say that our operating costs are going to be higher and with higher volumes.

It's not higher volumes should always generally drive down as you would think operating cost per unit, but because a greater proportion of our production will be from the Fayetteville relative to our old lower cost operating cost per unit of production, it will therefore drive our average up.

And some of the reasons that the Fayetteville would be higher are the Fayetteville requires compression -- just answered the questions from Robert Christiansen about that, we are not at the most efficient time period in the Fayetteville either in regard to operating cost regarding compression some time.

Like you had mentioned, we are looking at the Gulf Coast, Permian if that ultimately happened, it's one of our highest areas in terms of LOE, so would be a positive effect on the total company.

Harold Korell

Does that help you, Gil? Hello?

Operator

I'm sorry his line is closed.

Harold Korell

Okay.

Operator

Moving on, we will go to Joe Allman with JPMorgan.

Joe Allman - JPMorgan

Hi good morning everybody.

Harold Korell

Good morning, Joe.

Joe Allman - JPMorgan

Richard, could you tell us what the fourth quarter average cost was for the wells in the Fayettevale Shale, the longer lateral wells, and I know your expectation for 2008 is an average of $3 million a day, but it seems that you are probably looking to drive that down, and what would be the big drivers in getting the cost below to $3 million a day?

Richard Lane

Yeah. Well, our full year '07 number I think was $2.9 million, our fourth quarter number was $3.0 million. We've generally guided, or we have guided the 2008 program to be about $3 million.

And worth noting is that absolute dollar amount is kind of holding while the size of the well we are engineering and producing is bigger, so we've talked about in the past we're watching cost per foot as well, and that's going the right way.

So what kinds of things can affect it in 2008 are just more efficiencies as we get better and drill a higher percentage of development wells, we could get some help from service cost, we got help in second half of '07 there and there is still some pressure on that and then the things that we've been talking about related to our demo project.

We'll in fact be drilling more wells even outside of that demo project multi-well pad locations. So, we'll get some positive effects of that independent of service cost. So, a lot of things that we've to work at some that we're starting to identify and see how that all comes together.

Joe Allman - JPMorgan

It's helpful. And then just outside of the Fayetteville Shale. What are the trends these days in terms of drilling and completion cost?

Richard Lane

In our active areas, I'd say that we've basically set a plan that is not too different from what we saw on average well be in '07 and to the extent we do better than that on service costs we'll have a lower average well I'd think. Another factor in the Fayetteville Shale is we're still trying some new things on the completions.

And as you know the completion part of the well costs is the bigger of the drilling and completing the bigger piece and that we're doing something's that we're seeing some good results from in terms of how we're perforating and how we're spacing all that may give us some better well results if that the case and we keep doing more of that and those actually would cost a little more. So, lot of moving parts there. We're looking for the best economics.

Operator

Gentlemen we'll return to Gil Yang.

Gil Yang - Citi

Hi, thanks. Could you comment on your hedging activity for into '09? Are you starting to think about learning on more hedges more aggressively for '09 yet?

Greg Kerley

We've laid on -- Gil this is Greg and we've laid on some hedges at '09 over the last few month. We've got a little over a 100 Bcf hedged in '09 about a third of that or 30% or so in collars and some about bulk of it more in swaps probably averaging 830 or so on that swaps and we've got collars from 8 over 1050 kind of floor and ceiling. And we've done some swaps in 2010 starting to look at that. So, we're looking at that. We've been watching it obviously the market is run up here recently too and I expect that we'll continue to be pretty active at hedging as we've done in the past kind of little layers at a time.

Gil Yang - Citi

Are you ahead of -- for '09 are you are head of where you were for '08 at this time last year.

Greg Kerley

Percent I don't we're volumetric wise yes.

Gil Yang - Citi

Percent wise.

Harold Korell

And that's how we look at that.

Greg Kerley

Percent wise we haven't provided guidance for 2009 so I really can't talk percentages of what we've got hedged.

Gil Yang - Citi

Okay, thanks.

Greg Kerley

You're welcome.

Operator

And moving on next we'll go to David Heikkinen with Tudor Pickering.

David Heikkinen - Tudor Pickering

Good morning, I just wanted to dig in to the Southeast Rainbow project area and try to get a look at what the Fayetteville development can look like in the future. What are your AFPs for wells on that area running now?

Richard Lane

Let's see there, we've some longer laterals there that we're trying, David so I think they are ranging to $3 to $3.5 million.

David Heikkinen - Tudor Pickering

Okay.

Richard Lane

In that range.

David Heikkinen - Tudor Pickering

And then thinking about operating expenses, whenever you have centralized compression and basically a full development, where would that be for the concentrated development like this?

Greg Kerley

Well we've attacked that part of it in this demo project and Harold described the challenges with compression and what he point to there is that the more ascertain you cam be about volumes and ultimate needs, the better you can size those resources and load them more optimally. And so that's what we're doing there. We're modeling the rates of those wells, obviously that's….

Richard Lane

Our intention on that it's not to put out a model for it. But rather to do it and then we'll know what those numbers are David.

David Heikkinen - Tudor Pickering

Okay. Yeah, I just see that is the case study for your long-term development and has it go through the year?

Richard Lane

That's pretty much right.

David Heikkinen - Tudor Pickering

Just one additional quick question and I just wanted to get an update as far as gathering and compression or kind of basin like pipeline capacity expansions, timing as you look through '08 and '09. Can you just give us an update on that?

Greg Kerley

Sure David, this is Greg. We think we're in real good shape for moving our gas in 2008 and 2009. But 2009 is dependent clearly on the Boardwalk pipeline and its in-service date is scheduled for January 1 for both phases. Phase I and Phase II would be in servicing but actually Phase I -- the first Phase I is 65 mile of lateral that will cross the lower portion of the play and tie-in to the interstate pipelines on the east of Arkansas with actually being serviced this fall. So…

David Heikkinen - Tudor Pickering

Okay.

Greg Kerley

That would provide us effectively the entire 1.1 Bcf or 1.2 Bcf a day capacity on that pipeline will be available in that first section but it won't reach the other markets until both laterals are completed.

David Heikkinen - Tudor Pickering

Okay.

Harold Korell

And that schedule as we've reaffirmed recently with the Boardwalk management that our project is on schedule, but it's construction has not started it's scheduled to start sometime middle of this year.

But I think 98% of the write away for the production lateral has been acquired quite a bit of the pipe has already been produced and a quite bit of it has already been coated, so we're on schedule.

Operator

And we do have a follow-up and that will come from David Snow with Energy Equities.

David Snow - Energy Equities

Yeah. Hi. I was wondering, I think the thickness goes -- thicker going to the East and Southeast, Rainbow is the West, and I think and again there is done a lot of work there is that recent starting year pilot work in that area, but could you -- is it essentially true that you get better results going East on the average, I was looking for the latest slide and what's the average thickness here in the Southeast Rainbow area?

Harold Korell

Well the lot of questions there, I would say generally the, the thicker areas you would think if everything else was held constant, wouldn't provide better wells, and but back we have seen variability across the play.

And we have not seen systematically better wells associated to the thicker parts of the play. The demo area, the South Rainbow area is more of an average thickness type area for us.

David Snow - Energy Equities

Okay. And I am wondering if you could let me just what is more important consideration in constraint on ramping up capital constraint or labor personnel in the Fayetteville?

Richard Lane

Well, I think that we have to consider all of those things, and over the past couple of quarters I have been saying, and would say that the people side of things and having the capacity there who managed not just to carry on the operations that you don't understand that when you drilling so many wells, you need to be looking at how they are performing in order to know you are doing the right things.

So I would say, over the last couple of quarters that would be it, I think the question about capital is depended upon how you want to fund the program and we want to efficient with our capital.

So I would say its the combination of both things at this point in time, and clearly we have a deficit in cash flow relative to our capital, but we have ability to borrow and we're selling something.

But there will be some point in time that I would imagine, we would want to put more drilling rigs out here, and that will be driven by having the capacity to operate and efficiently, in other words that means the people side of things and new organization carried on effectively, and then layered on with the capital side.

And so it is continuously moving target. I don't think it's really possible to save one or other perhaps two I guess I would say people right now, and the organization and then drilling rig and that side of it.

Operator

And next we will return to Jeff Hayden with Pritchard Capital.

Jeff Hayden - Pritchard Capital

Hey, guys, real quick question jumping over to the Marcellus. You mentioned in the release one vertical well, at least the vertical well in Q1 what are kind of the drilling plans beyond that, and are you looking at potentially any horizontal wells this year?

Harold Korell

Yeah, Jeff. I think we are looking at four, five wells something in the nature of that size program for '08. That's partially dictated by how fast we can get the important data back from the early wells, which we're doing a lot of extensive testing there, coring and sending that rock to the appropriate places to get things measure.

So that partly dictates how fast you really want go to the firs year. We want to get our hands on some of the rock and see that the resource can be measured and then possibly we would maybe in that area, we've already drilled the vertical, we will try horizontal.

Jeff Hayden - Pritchard Capital

Okay. Appreciate it.

Operator

And we also have a follow-up from Joe Allman with JPMorgan.

Joe Allman - JPMorgan

Hi again. For 2008 in the Fayetteville Shale, is the focus of the drilling going to beyond just developing in known areas, or do you still have a lot of initiation donation in the play to do?

Harold Korell

The development depends, how you define that, Joe, but generally the development in '08 as a percent of our wells is quite a bit higher than in 2007. There will be less of reaching out and single-section wells.

Although there will be a lot of areas that we are pending on to where we've already drilled and those may only have a well or two in them, but as a percent we are more in development phase in 2008 than '07 certainly.

Joe Allman - JPMorgan

And just what would be a rough percentage like 80%, 20% development versus kind of reaching out?

Greg Kerley

Yeah I would say that's probably pretty close might be 75, 25.

Joe Allman - JPMorgan

Got you, okay. And then just follow-up to my previous question, so I didn't understand your answer, so in your other active areas outside the Fayetteville or even including the Fayetteville, are you seeing cost decline, are you seeing rig rates, are you seeing stimulation cost decline?

Richard Lane

We are right now we're actually bidding some of those big packages in certain areas and don't want to divulge those numbers obviously, but we're seeing some more pressure on the pumping and cementing and completion side. That could give us a little more relief this year. Broad based I'd say there's not a lot of movement on rig rates at least, where we are active.

Joe Allman - JPMorgan

Okay, got it. Okay, thank you very much, very helpful.

Operator

And moving on for a follow up we'll go to Robert Christiansen with Buckingham Research.

Robert Christiansen - Buckingham Research

Yes how do you view the rent or purchase decision for compression?

Greg Kerley

Bob, this is Greg. Right now our compressions are really leasing the bulk of that because there's, as Harold indicated I mean where we added the project a lot of these projects are changing things out quite a bit, as we drill some packed levels of wells and then and then we'll increase the size of either compressors or compressor stations and add-on. So, where we're out right now we think that is what makes the most sense to us.

Richard Lane

Yes, I think another big factor there is our arrangements in terms of that have allowed us to have some flexibility in what we're providing.

Robert Christiansen - Buckingham Research

Well, thank you very much guys.

Operator

And we will return to Gil Yang with Citi.

Gil Yang - Citi

Hi, it looks like you bought at about 6,000 -- 4,000 acres for $25 million in the Fayetteville, that right.

Greg Kerley

Can you repeat that?

Gil Yang - Citi

Sounds like you bought about I think 4000 acres for about $25 million in the Fayetteville? Is that about right?

Richard Lane

Maybe you are referring to the integrations, what we were consolidating acreage, when we get ready to drill a well. Our all in cost there in the play I think what we said is about $116 per acre there will be -- there are small amounts of acreage when we are doing the final roll up of the section to get the final pieces of leases put together to drill a well and those right now, those are going to run at higher cost because there is pretty intensive brokerage cost fees to that.

Harold Korell

Greg, do you have something to add to that.

Greg Kerley

No.

Gil Yang - Citi

That what the $25 million land spend was in the Fayetteville in '07 or …

Richard Lane

We're sitting here frowning at the moment because we're not sure, maybe -- we do some checking to make sure what number you're specifically talking about.

Greg Kerley

I think Richard's, my understanding is integration the other pieces that we are doing to get land and notification to get land ready to be drilled on, has been captured that was at that--

Harold Korell

But his number $25 million per 4,000 acres let's say we bought some land for $6250 an acre.

Greg Kerley

And we did not--

Harold Korell

That doesn't sound, that something other in that number--

Richard Lane

Bob, brokerage cost and things like that, is what we really that related to.

Harold Korell

Maybe we get a chance to research whatever you are, is you are talking about it.

Richard Lane

Okay.

Gil Yang - Citi

Okay. Right, Well I follow-up, but I think that maybe -- I may have done the calculation wrong, but you did say, you said you spent $25 million in the year.

Harold Korell

That's correct

Gil Yang - Citi

I'm not sure how many acres you added in the year, but that's what I was getting at.

Greg Kerley

Now that's correct, and the part unsaid there is that, a big piece of those cost are ongoing; getting land ready.

Gil Yang – Citi

Okay.

Greg Kerley

To drill well, so you can't think of it is purely as bonus.

Gil Yang – Citi

Alright, alright. Thanks.

Operator

And we do have a follow-up from David Snow with Energy Equities.

David Snow - Energy Equities

When might a midstream MLP make sense? Is it too early in the growth of the midstream?

Greg Kerley

Yes.

David Snow - Energy Equities

A couple of years out, maybe?

Greg Kerley

I really couldn't tell right now, David that we would be certainly be prepared to answer.

David Snow - Energy Equities

Okay. Great, thanks.

Operator

And returning to David Heikkinen with Tudor Pickering.

David Heikkinen - Tudor Pickering

I hate to ask the last question. What's your pre-tax of the PV-10?

Greg Kerley

I'll have to pull that --

Harold Korell

In the K out here today --

Greg Kerley

Hold on a second. We've got one here that we can give you the number.

David Heikkinen - Tudor Pickering

Yeah, thanks. I can get it from the K, or we can get offline.

Greg Kerley

Yeah, $2.6 billion.

David Heikkinen - Tudor Pickering

Okay. Thanks, guys.

Greg Kerley

You are welcome.

Operator

Okay, gentlemen. It appears there are no further questions and Mr. Korell, I'd like to turn the call back to you for any additional or closing remarks.

Harold Korell

Okay. Well, not much more to say. Just thank you for joining us today and we look forward to really good year again in '08. Have a good weekend.

Operator

And that concludes toady's conference. We would like to thank you all for your participation.

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