西南能源 (SWN) 2007 Q4 法說會逐字稿

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.

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 year end 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% to 1.45 trillion cubic feet equivalents, which represents a reserve replacement ratio of 474%. While 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 3D seismic dated abase, thereby improving our ability to reduce risk 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 the stage for another year of substantial growth in our production and reserves in 2008. We believe our production of the real again this year, somewhere around 30% to 35%. We're looking forward to some new things which include the results from our development project testing we're doing in the Fayetteville, our drilling results in the James Lime in East Texas, and fewer opportunities that we've seen in the Marcellus Shale in Pennsylvania. I would like to turn the conference over to Richard for more detail on our E&P activities, and to Greg for an update off you are financial results, and then we'll take questions.

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 Bcf produced in 2006. We produced 29.9 Bcfe from East Texas in 2007, 23.8 Bcfe from our traditional Arkoma Basin, 60.4 Bcfe from the Gulf Coast basin and new venture 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 Bcf 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 Bcf to 36 Bcf. Our full year guidance remains at 148 Bcfe to 142 Bcfe.

In 2007 we increased our year end proved reserves by 41% to 1.45 trillion cubic feet. The 1.45 trillion cubic feet of proved reserves were located approximately 49% in the Fayetteville Shale, 24% in East Texas, 21% in the conventional Arkoma basin and 6% in others. In 2007 we added 507.9 Bcfe of proved reserves and had net upward revisions of 31 Bcfe. Both the additions and the 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 at a finding and development cost of $2.55 per Mcfe. Excluding revisions that cost is $2.71 per Mcfe. Proved developed reserves accounted for approximately 64% of our total reserves at year end 2007.

In 2007 we invested $1.38 billion in our exploration and production activities and participated in drilling 653 wells. Of those wells 439 were successful, 17 were dry, and 197 were in progress at year end for an overall success rate of 96%. Of the $1.38 billion invested in 2007 approximately $1.3 billion or 82% was for drilling wells, 166 million was for leasehold acquisition in seismic, and $84 million in other costs. In our Fayetteville 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 costs. 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. 3D seismic costs alone represent approximately $0.20 per Mcfe of the total finding costs. 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, an average royalty interest of 15%, and our cumulative all-in average acreage costs is $116 per acre. Gross production from our operating 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 Bcf 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 reserve from our horizontal wells range from .1 Bcf to 4.2 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 transitioned to drilling longer laterals, completing almost all our wells with slick water stimulations, and we began to see the benefit of our 3D seismic program. At year end we had acquired approximately 525 square miles of 3D data in the shale area and expect to have acquired or purchased another 370 square miles of 3D 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 the wells has been 1.2 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 3,000 foot laterals to range from 2 Bcf to 2.5 Bcf per well.

During 2007 our average completed well costs for our operated 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 reentry to reentry. 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're currently forecasting an average drilling and fleet cost of $3 million per horizontal well in 2008.

In late 2007 we began a project to demonstrate the benefits of a full scale development strategy in a four-section area of our southeast rainbow pilot area in Conway County. We plan to drill 22 wells in total there of which 21 will be developed on multi-well pad and eight will be simultaneously fracture stimulated. The results here will provide key information regarding potential cost savings, well spacing, benefits of longer laterals, simultaneous completions, and other centralized operations. While we're 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, and resulting in 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 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 at Ranger increased to 9.5 Bcf from 5.7 Bcf in '06, an increase of 67%. Since drilling our first successful well at Ranger in 1997, we've successfully drilled 156 out of 185 wells, adding 114 net Bcf of reserves at a refining costs of $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 may be significant drilling potential on our acreage going forward. In 2008 we plan 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 our proved 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 are the Travis Peak and the James Lime formations. During 2007 we invested $88 million to drill 31 wells at our Angelina Trend all but one of which were successful or in progress at year end. Our drilling results included a new discovery at the [Jebel] prospect area in Shelby County in the James Lime 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 four million cubic feet per day after 44 days of production. Earlier this month we placed our second James Lime horizontal well on production, the session airs #16 well located in Angelina County approximately 35 miles west of our first discovery well, had an initial production rate of 6.7 million cubic feet per day. We're currently completing our third operated James Lime 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 interest of 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 prospective, and we plan to spud our first vertical well on the acreage during the first quarter. We also invested approximately $10 million in 2007 to drill 25 wells in our Riverton coal bed methane project in Caldwell Parish, Louisiana of which 18 were successful and seven in progress. We have approximately 32,000 net acres in this project area that targets the Tertiary-age lower Wilcox coals at a depth of approximately 2,800 feet.

In summary, we're very pleased with our record results in 2007. We continue to be very encouraged by our success in our Fayetteville Shale project, and in our programs in the Arkoma basin and East Texas, are performing well also. We're looking forward to continued strong results in 2008 including meeting or exceeding our PVI target, 30% to 35% production growth, very significant increases in proved reserves. I will now turn it over to Greg who will discuss our financial results.

Before Greg starts, Richard, I think you misstated one thing early on that we should probably correct for the record, and that was that our guidance for the year remains 148 Bcfe to 152 Bcfe. I think when you said it you said 142 Bcfe. I know the number is 152 Bcfe. That's correct.

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, while 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 in our production volumes from the Fayetteville Shale. Our earnings for the fourth quarter were $71.6 million or $0.41 a share, more than double 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 $258.1 million in 2007, up from $237.3 million in 2006. We produced 113 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 price swaps and callers provides us with support for strong level of cash flow and for 2008 we have close to 80% of our projected natural gas production hedged. We 75 Bcf hedge with fixed price swaps at average price of $8.43 in Mcf, and we have 48 Bcf hedged through price callers with an average floor price of $7.92 and an average ceiling price of $11.60. Our detailed hedge position is included in our form 10K filed yesterday. Our lease operating expenses for 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 costs related to our operations in the Fayetteville Shale. We expect our per unit lease operating costs 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 for [younger] 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 for unit of production to range between $0.42 and $0.47 in Mcf in 2008. Taxes other than income taxes were $0.16 from Mcf equivalent in 2007, down from $0.30 in the prior year due to changes in severance and [addable income] tax that is primarily result from the mix of our production volumes and severance tax 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 $1.90 for 2006. Our amortization rate is primarily impacted by the timing and amount of reserve additions and the costs 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 through 509 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 utilities segment was $10 million in 2007 up from $4.5 million in 2006. The increase in operating income was due to the implementation of a rate increase which became effective August 1st 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 is expected to close approximately mid-year 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 were used 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 billion. 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 a two-for-one stock split yesterday. The split will be effective for holder it is of record on March 14th and payable on March 25th, 2008. That concludes my comments. Now we'll turn back to the operator who will explain the procedure for asking questions.

Thank you. (OPERATOR INSTRUCTIONS) And our first question will comes from Richard Tullis with Capital One.

Hey. Good morning. Nice quarter. Just two quick questions. One, what's the -- what's your current outlook on potential severance tax changes in Arkansas?

That's a good question. The playing field is running in various directions for those of who you follow it I am sure that you've 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 will be pretty much dependent upon factors that somewhat are within our control, somewhat outside our control. Our position on this is that we're continuing to work with the leadership of the state to propose a plan that would not unduly burden our operations. And so that's our effort, and as far as what might eventually come, it is a little bit difficult to say as there are continuing conversations on a daily basis.

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

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

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

This is actually his associate. I have a question on the East Texas based on preliminary reserves, there are no net reserve booking in East Texas. We would have thought that was 80 wells in the Angelina river trend, we would have seen reserve booking. Can you comment on that, please?

Well, we had a drilling and Overton field, and drilling in our Angelina River trend. What's affecting some of that is that we developed mostly preexisting locations, proven undeveloped locations at Overton and then also we had some performance revisions in the area that affect that number.

Okay. Thanks.

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

Yes, I am trying to get an idea of what the amount of acres you would tap into with these 3,000 foot lateral links. I'm just trying to get an idea as to what Bcfs per unit of acreage you are looking at recovering as you into longer laterals.

Well, the -- our materials, recent materials here provided guidance on that and also gives a look at some of the productive histories of the wells that are longer than 3,000 feet, so I would guide you to referencing that, but I can tell you that it is early in our history in the 3,000-foot or longer wells, but we think that it is reasonable for those to ultimately recover 2 Bcf to 2.5 Bcf per well.

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

It will depend on the ultimate spacing that you mentioned there. If you look at 80-acre spacing which we're not certain that's ultimately where we'll be, but kind of our nominal development plan right now. That's about eight wells per 640.

On the other hand, where we are currently carrying on this we call it development project area in the four sections and in the east-southeast rainbow area or 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 tried to describe this and maybe I would refer you if you on the last teleconference back to that subscription so maybe I don't have to do that completely again. But we would be drilling north-south wells spaced 1,000 feet apart, and that would if you layout a section, that would mean there would be six wells per section if you repeated that. Now, what we don't know yet is we don't know whether the wells being spaced 1,000 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're it at the point of drilling in that one development area wells spaced 1,000 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 1,000 feet apart possibly and it will depend upon the results and performance of what we're doing in the development area. One of the things that clearly I know some people who follow us have trouble with is the concept that we're still very sparsely spaced everywhere because we have so much acreage that we're drilling on. And we're doing this one test area so that we can try to begin to answer these questions, but we can't answer the questions about it at 80-acre or 40-acre or some other thing in between yet. Some of the other companies have been drilling wells on tighter spacing already. They may have some views on it. I don't know that their views and ours will be the same, but we'll have to test this on our own.

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

Thank you. Good morning.

Good morning, Brian.

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

Well, Brian, we're really just starting into that. We do have a nice-sized acreage block there. Our interest that where we've drilled is kind of the far east part of our block at Jebel and the other well that I referred to, the sessions well, would be the most westerly part of our acreage, so it is nice to see something 30 some miles apart still be present and productive. It certainly doesn't prove up every acre in between, but there is a lot of this story left to be told there as we go this year. We said we would drill maybe 10 to 15 wells in that program this year, and that will certainly give us a lot more look at how much of that acreage could be prospective, but early on and 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, though, so I wouldn't want to compare it to other projects yet, but it definitely has the potential to exceed our return thresholds.

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 activity if gas prices do stay strong and where would that be if at all?

Yes. Brian, that's a good question for us. Not just with gas prices moving up some because I guess when gas prices moving around, my normal answer to that is the current months we aren't a whole lot effected by how we think generally, and we're looking at the out prices, and we've done a fair amount of hedging. So that all -- that statement still is kind of is the overarching statement on gas prices. But our job as we go forward here in the -- in 2008, 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 $850 million to $900 million range, and I guess slightly -- maybe slightly above that, the the point is we're still short on cash flow to fill the capital need.

As Greg mentioned earlier, we have the utility we're selling this year. We're 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. Gas prices, 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 point when we get our organization fully fleshed out, do more drilling in the Fayetteville Shale. We would like to accelerate drilling there. If these East Texas -- if these wells hold up and additional wells we drill look good, we're going to have a desire as I put it to drill more wells in East Texas. We haven't begun drilling in the Marcellus yet, and then those projects Richard described in the conventional play and the Arkoma will are also looking quite good, so the good thing is we're flush 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 is too early for us to talk about increasing our CapEx right now.

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

Thank you. Good morning, guys.

Good morning.

Let's see, Brian asked good questions, but let me just follow up on his James Lime question. I am looking for more color with respect to how you're 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.

Well, I mean, the size of the play as an industry could be very large. I would tell you that our acreage position we've talked about is over 95,000 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 we think they'll exceed our threshold as I mentioned, but we're going to have to see some more production history.

Okay. And of the wells you plan to drill in 2008, companywide, what fraction are not booked as proved as of year end '07?

Well, the biggest factor there area obviously would be in the Fayetteville Shale. Really what you're asking there I guess is how many wells in the Fayetteville Shale program are -- in '08 would be drilling undeveloped locations. I can tell you that percentage in '08 is pretty low because we're still needing to step out and hold acreage, so might not be as high as you might think, and then that would probably go up as time goes on. So because so many of our wells are moving only a second or third well in a section and moving into new sections, and part of the strategy to hold land it's not that great of a percent in 2008.

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

Good morning, guys, a little bit of a follow-up question I believe to what David was asking. When you guys are looking at the rainbow pilot, given kind of the spacing pattern you guys are initially thinking, about what kind of recovery factor would that imply? And then second question, you guys built up a pretty good inventory of 3D seismic, you've drilled a lot of wells across your acreage, you're building up more. Can you give a sense -- you've had the sort of 50% of your acreage number out there in your presentation for a while. Can you give any sort of update on how much of your acreage position you really think is going to be economical right now?

Well, the recovery -- Jeff, the recovery, ultimate recovery percent there is still not totally defined. We think that something in the 20% range or possibly higher is reasonable from what we've seen so far. And on the 3D 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 in the year we started to get it inhouse and be a tool for us, and starting to see some help from that. In 2008 a much greater percent of drilling will be utilizing our 3D seismic I think we are looking at that, when we put our plan together we're somewhere around 75% of our wells would be covered by that. The guidance towards the percent of the acreage that will ultimately be developed and probably your best thing to refer to there is some of the materials we've put out. We have in our public materials we have a map that shows the distribution of all the pilot areas that we have drilled, and you can see the -- how much that's been delineated there. I am not trying to avoid an exact number, but that's the best thing to look at.

All right. Thanks a lot, guys. .

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

Good morning. How is the conventional exploration going in the Fayetteville Shale leasehold if you will? Seems like it might be back-end loaded in the year. Is that because of the seismic just arriving inhouse or what's going on there, Richard, please?

Well, it is going very well from my perspective. We've encountered conventional pay zones through a pretty broad area in the play. We're seeing really nice rates from the majority of those wells, and strong economics given the relatively low costs to drill and 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 starting to kick in about now, so I think we'll have more to report on that in the second quarter, but very encouraged.

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?

You know that, Greg?

No. We don't have our guy here. It is over 100,000 somewhere. But I -- John do you have -- 105,000, 106,000 horsepower.

How does that work? When you install it, I take it it would be centralized, and does it run all out of the day installer, or do you start out with 1,200-horsepower machine and start life out with 700-horsepower and it ramps and ramps and ramps as the field -- as individual wells decline, pressures decline? Just -- some just basic layman's terms that's all unfolding?

Yes, Bob, when you look at our map and look at the area that is we're drilling across, as Richard said earlier, it is spread out. It is a very broad area that we drilled in, and in order to get production tests and establish well decline curves and all we have to produce, so that means we have to lay lines to those wells, and that means we have to have compression any place that we're reporting production curves. So the compression is in general is spread out, but it is also the other way of saying it is it is centralized because off the main gas transmission lines we'll lay laterals, we call them 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. There are not just one, there are some because of being just a broad area. So in the beginning let's say take the boundary condition case of one well, meaning one well only say drilled out there all by itself, and you'll 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're touching on, it but efficiency of compression is one of the matters here, because the compressors run and they use fuel and they're running 24 hours a day, so if they're not fully loaded you'll have higher operating costs than you would like. So one of the things over time we have to optimized on, we're by no means there, our guys are doing a great job, but when you're drilling wells in a very broad area, it doesn't afford you the complete efficiency that you would want to have which ultimately is you go into an area along with laying out the geological parameters and the well spacing, you would also think through how you drill that 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. The good thing is having De Soto gathering that's doing this for us, it gives us a lot more flexibility along those lines.

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

Yes. Thanks. Good morning.

Hi, Scott.

In the James Lime play, one other question I know that you talked quite a bit about this play, but it looks pretty exciting. And looking at your position and what others are doing there, how much acreage do you think is there left to pick up? Is there more? Are you guys actively looking at picking up some more in this play?

There is more from our perspective and our opinion where we see the play to have potential, and we're still active doing some of those things, Scott. Obviously you don't want to pinpoint that, but --

We want to call it the Chesapeake jets in on our troops.

Fair enough. And then second question, looks like you sold your assets in Culberson County, and I guess you handed towards looking at other opportunities to monetize assets potentially. Can you just talk in a general sense of what kind of efforts you're doing or what kind of assets could be up for sale in the Company yet?

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 they're a potential for other things that we're thinking about.

And next we'll go to Gill Yang with Citi.

I have pretty routine questions and 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 seems counter intuitive because I would think you would get some kind of cost leverage synergies. Could you, Harold and Richard, maybe explain that a little bit?

I think the effect there, Gill, is where the weighting of the production is. De Soto, the Fayetteville Shale play, as we -- as it becomes more and more higher percent of our total company production, and we've just discussed a lot of the reasons why those lifting costs are what they are, that's really the effect you're seeing is the not so much the throughput driving that, it is where the throughput is.

Okay. So the Fayetteville higher costs but because you're still ramping, so you're somewhat in-efficient in terms of capital usage --

There is a couple of things. The Fayetteville, for example, is higher operating costs than our old conventional Arkoma production. As a company as we have more of the Fayetteville coming on line relative to our old base, it is going to be higher. Our operating costs per unit aren't I think the way you said it in the beginning was seemed strange to you that we would say that our operating costs are going to be higher with higher volumes. It is not -- higher volumes should always generally drive down as you would think operating costs per unit, but because a greater proportion of our production will be from the Fayetteville relative to our old lower cost operating costs per unit of production, it will therefore drive our average up. Some of the reasons that the Fayetteville would be higher are the Fayetteville requires compression. Our -- just answered questions from Rob Christianson about that. We are not at the most efficient time period in the life of the Fayetteville either in regards to operating costs regarding compression. You have something else?

You mentioned we're looking at the Gulf Coast Permian, if that ultimately happens, it is one of our highest areas in terms of LOE, so that would be a positive effect on the total company.

Does that help you, Gill? Hello?

I am sorry, his line is closed. Okay. Moving on we will go to Joe Allman with JPMorgan.

Hey. Good morning, everybody. Richard, can you tell us what the fourth quarter average cost was for the wells in the Fayetteville 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're probably looking to drive that down. And what would be the big drivers of getting the costs below the $3 million a day?

Yes. Well, our full year '07 number I think was $2.9 million. Our fourth quarter number was $3.0 million. We've generally guided -- 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 costs. We got help in the 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 will in fact be drilling more wells even outside of that [demo] project, multi-well pad locations, so we'll get some effect -- some positive effects of that independent of service costs. A lot of things that we have to work at, some that we're starting to identify and see how that all comes together.

That's helpful. And then outside of the Fayetteville Shale, what are the trends these days in terms of drilling and completion costs?

In our active areas, I would say that we've basically set a plan that is not too different from what we saw in 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 would think. Another factor in the Fayetteville Shale is we are 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 we're doing some things that we're seeing some good results from in terms of how we're perforating and how wer're spacing all of that that may give us some better well results if that's the case, and we keep doing more of that, those actually would cost a little more. So a lot of moving parts there we're looking for the best economics.

And, gentlemen, we'll return to Gill Yang.

Hi. Yes. Thanks. Can you comment on your hedging activity for -- into '09? Are you starting to think about layering on more hedges more aggressively for '09 yet?

We have laid on -- Gill, this is Greg. We have laid on some hedges in '09 over the last few months. We've got a little over 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 the swaps, and we've got collars from 8 to over 1,050 kind of floor and ceiling, and we've done some swaps in 2010, starting to look at that, so we are looking at that. We've been watching it obviously the market is run up here recently, too, and I expect that we will continue to be pretty active hedging as we have done in the past, kind of little layers at a time.

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

Percent -- I don't -- we are volume metric wise, yes.

Percent wise? If you look at that.

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

Right. Okay. Thanks.

You're welcome.

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

Good morning. Wanted to dig into the southeast rainbow project area there, wanted to get a look at what the Fayetteville will look like in the future. What are your AFEs for wells in that area running now?

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

Okay.

In that range.

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

Well, we've attacked that part of it in this demo project, and Harold described the challenges with compression, and what he pointed to there is that the more certain you can 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 can -- we're modeling the rates of those wells. Obviously that's --

Our intention on that is not to put out a model for it, but rather to do it, and then we'll know what the numbers are, David.

Okay. I just see that as the -- a case study for your long-term development and as you go through the year.

That's pretty much right.

Just one additional quick question, and just wanted to get an update as far as gathering and compression or kind of base and wide pipeline capacity expansions, timing, as you look through out and '09, can you just give us an update on that?

Sure, David. This is Greg. We've 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 1st for both phases, Phase I and Phase II would be in servicing, but actually Phase I, the first phase is 65-mile lateral that will cross the lower portion of the play and tie in to interstate pipelines on the east of Arkansas with actually being serviced this fall. So 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.

Okay.

And that schedule is we've reaffirmed recently with boardwalk management that our project is on schedule, but its construction has not started. It is scheduled to start sometime middle of this year, so -- but the I think 98% of the right of way for production laterals has been acquired, quite a bit of the pipe has already been produced, and quite a bit of it has already been coated, so we're on schedule.

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

Yes. Hi. I was wondering I think the thickness goes thicker going to the east and southeast rainbow is in the west. And I think you've just done a lot of work there is the reason for starting your pilot work in that area, but could you -- is it still -- is it essentially true you get better results going east on average? I was looking for the latest slide and what's the average thickness there in the southeast rainbow area?

Well, the -- a lot of questions there. I would say generally the thicker areas you would think if everything else was held constant would provide better wells, but in fact we've seen we've seen across the play and and we have not seen systematically better we wells associated with the thicker parts of the play. The demo area, the south rainbow area, is more of an average thickness type area for us.

Okay. And I'm wondering if you could tell me just what is the more important consideration in constraint onramping up capital constraints or labor personnel in the Fayetteville?

Well, I think that we have to consider all of those things, and for the past couple of quarters I have been saying and would say that the people side of things and having the capacity there to manage, not just to carry on the operations, but understand when you're drilling so many wells, you need to be looking at how they're performing in order to know you're 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 dependent upon how you want to fund the program and we want to be efficient with our capital, so I would say it is a combination of both things at this point in time. Clearly we have a deficit in cash flow relative to our capital, but we have the ability to borrow, and we're selling some things, 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 them efficiently. In other words, that means the people side of things, and the organization to carry it on effectively, and then layered on with the capital side. So it is a continuously moving target. I don't think it is really possible to say one or the other, if I had to I guess I would say people right now, and the organization and drilling rigs and that side of it.

And next we'll return to Jeff Hayden with Pritchard Capital.

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

Yes, Jeff, I think we're looking at four or 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 early wells, which we'll be doing a lot of extensive testing there, coring, sending that rock to the appropriate places to get things measured. So that partly dictates how fast you really want to go the first year. We to want get our hands on some of the rock and see that the resource can be measured. And then possibly maybe then in an area we already drilled a vertical we would try a horizontal.

Okay. Appreciated it.

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

Hi, again. For the -- for 2008 and the Fayetteville Shale is the focus of the drilling going to be on just developing the known areas or would you still have a lot of delineation in the play to do?

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 at there will be a lot of areas that we're depending onto where we already drilled, and those may only have a well or two in them. But as a percent, we're more in the development phase in 2008 than '07 certainly.

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

Yes. I would say that's probably pretty close, maybe 75/25.

Got you. Okay. And just a follow-up to my previous question. So I didn't understand your answer. So in your other active areas outside of the Fayetteville or even including the Fayetteville, are you seeing costs decline, are you seeing rig rates decline, are you seeing like stimulation costs decline?

Right now we're actually bidding some of those big packages in certain areas, and I 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 would say there is not a lot of movement on the rig rates, at least where we're active.

Okay. Got you. Okay. Thank you very much. Very helpful.

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

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

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

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.

Thank you very much, guys.

And we will return to Gill Yang with Citi.

Hi. It looks like you bought I guess about 6,000 acres for -- or 4,000 acres for $25 million in the Fayetteville. Is that right?

Can you repeat that?

Sounds like you bought about I think 4,000 acres for about $25 million in the Fayetteville. Is that about right?

Maybe you're referring to the integrations where we're consolidating acreage when we get ready to drill a well? Our all-in costs there in the play I think what we said is about $116 per acre. There are small amounts of acreage when we are doing the final rollup 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 costs because there is a pretty intensive brokerage cost piece to that.

Greg, do you have something to add to that?

No.

Is that what the $25 million land spend was in the Fayetteville in '07? Is that '07 or '06?

We're sitting here frowning at the moment because we're not sure, maybe --

Do we need to do some checking to make sure what number you're specifically talking about.

I think Richard's -- my understanding is the integrations, the other pieces we're doing to get land and to say get land ready to be drilled on is being captured that way -- at that.

But his number, $25 million for 4,000 acres would say we bought some land for $6,250 an acre.

And we did not.

That doesn't sound -- there is something else in that number.

Brokerage costs and things like that is what really are that related to.

Maybe we could get a chance to research whatever it is you're talking about.

Okay. All right. I had a follow-up, but I think I may have done the calculation wrong. But you did say you spent $25 million in the year.

That's correct.

I am not sure how many acres you added in the year. But that's what I was getting at.

That's correct. The part there is that a big piece of those costs are ongoing getting land ready to drill wells, so you can't think of it as purely as bonus.

All right. All right. Thanks.

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

When might a midstream MLP make sense? Is it too early in the growth of the midstream? Yes. A couple of years out maybe?

I really couldn't tell right now, David. It wouldn't be something we would be prepared to answer.

Okay. Great. Thanks.

And returning to David Heikkinen with Tudor, Pickering.

I hate to have the last question. What's your pre-tax [SEC PV10]?

I will have to pull out --

In the K we filed the other day it is -- hold on a second. We have one here we can give you the number.

Thanks. I could get it from the K or we could get it off line.

$2.6 billion.

Okay. Thanks, guys.

You're welcome.

Okay, gentlemen, it appears there are no further questions. And, Mr. Korell, I would like to turn the call back to you for additional or closing remarks.

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

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