Battalion Oil Corp (BATL) 2007 Q4 法說會逐字稿

Welcome to the RAM Energy Resources, Incorporated, fourth-quarter and year-and 2007 earnings conference call. Our speakers for today include Larry Lee, Chairman, CEO, and President of RAM Energy Resources, and Robert Phaneuf, Vice President of Corporate Development. I will not turn the call over to Mr. Phaneuf.

Thanks, Nikea, and welcome to RAM's fourth-quarter and year-end '07 conference call. By way of introduction, today at RAM we have not only Larry Lee, our CEO, as Nikea mentioned; but Larry Rampey, our Senior Vice President of Operations; Drake Smiley, our Senior Vice President of Land and Exploration; John Longmire, our Senior VP and CFO; Sabrina Gicaletto, our VP of Finance and Controller; and me, Bob Phaneuf.

On our agenda today we are going to review the fourth-quarter and '07 results fairly quickly, and then provide you with an update on our activity that we have underway in early '08. Before proceeding let me give you a quick reading here of our disclaimer.

This is our Safe Harbor statement. As most of you know in our call today we may make statements that are other than historical facts. Information in the presentation and all such statements that refer to our plans or expectations, including capital spending that you will hear about, derivative positions, and industry conditions, are all forward-looking statements within the meaning of the Securities Exchange Act of 1934. We caution that such forward-looking statements are necessarily based on certain assumptions which are subject to certain risks and uncertainties, which could cause actual results to differ materially from those indicated today.

Further, information on these risk factors is included in the Company's filings with the SEC, as well as at the beginning of the webcast slides, which you have probably just pulled up on your screen. So the management of RAM encourages you to review the disclosure in both of these documents.

So at this point I would like to turn the call over to Larry for the prepared remarks.

Thank you, Bob, and welcome, everyone. I'll quickly go through sort of the highlights for 2007 and then talk a little bit about fourth quarter, as well as what we are doing in the first quarter of '08.

Our production was 1.4 million barrels, which was 10% above our 2006 volumes; and that counted only one month of Ascent in December of this year.

Oil and gas sales did increase 20% to almost $82 million, and our operating income inclusive of this substantial non-cash unrealized loss from derivatives was $10.7 million. Cash flow from operations, a non-GAAP measure, was $23.7 million versus $18.1 million in 2006.

We did report a net loss of $1.3 million. This was largely driven by the $10.1 million unrealized loss from derivatives, most of which occurred in the fourth quarter as a result of the unprecedented rise in the price of crude oil. That of course is versus the net income of $5 million that we had in 2006.

In addition to the $10.1 million worth of non-cash unrealized derivative loss we had, we also had a non-cash $2.4 million write-off of loan fees in 2007 that resulted from our refinancing that we did in the Ascent acquisition.

Our fourth-quarter volumes grew 37%, which was 436,000 barrels of oil equivalent that we produced for the year -- I mean for the quarter, excuse me. Our average daily production was 4,739.

Of course prices continued to rise in the fourth quarter of '07 versus the fourth quarter of '06, with oil up 53%, NGLs up 63%, and natural gas up 17%. Higher production combined with these increased product prices did drive oil and gas sales to $29.4 million or almost double our last year's fourth-quarter sales volume.

Fourth-quarter highlights, I think, we reported a loss of $6.3 million or $0.13 a share. This, once again, was largely attributable to the unrealized losses on derivatives that we booked of $8 million pretax; and also in the fourth quarter we had that $1.6 million of non-cash write-off of loan fees related to the refinancing of our debt in order to complete the Ascent acquisition.

Cash flow from operations for the fourth quarter was $7.6 million versus $2.3 million in the previous year.

Capital spending in the fourth quarter was $311 million; and that raised our full-year CapEx to $345 million. Of course the large item in that was the purchase of Ascent in late November.

We did want to provide people with sort of a highlight of what the month of December looked like, to give you some basis upon which to begin to look into 2008. Our consolidated production for the month of December -- this is the first full month of production following the acquisition of Ascent -- it totaled 203,875 BOE. Ascent contributed 90,930 barrels equivalent of that production. Our daily average was 6,577 barrels of oil equivalent for the day. Oil and gas sales for the month of December was $13,651,000.

We have had estimated EBITDA of $7.5 million. This might be a good time to point out a couple of things. During the fourth quarter we incurred $765,000 in higher professional fees than we did in the same quarter of 2006. That was primarily related to meeting SOX compliance. We actually incurred $504,000 -- of that $765,000 -- was in dealing with our SOX compliance issues for 2007. Of that $504,000, actually $250,000 of it was incurred during the month of December.

Also, in the month of -- for the fourth quarter, you know we ended up at the end of 2007 with 177 employees on our payroll compared to 100 employees that we had at year-end '06. So with the increase in personnel costs and the increase in the professional fees, half of which came from SOX, those were really principal drivers in our increase in G&A in the fourth quarter of 2007.

I think as we move forward in 2008 we are expecting those general and administrative expenses to normalize out in the range of about $3.75 million per quarter to around $4 million a quarter. So that is the range that we see those expenses being settled in, with the full cost of the Ascent personnel on our staff and without the kind of unusual things that fell in the fourth quarter of 2007.

I would also point out that in the fourth quarter our lease operating cost per BOE was $15.39 per barrel. That compares to $16.84 in the third quarter of '07. So sequentially it was down about 9% quarter-to-quarter. If you look at just the month of December, the LOE per BOE for the month of December was $14.19, which is actually 8% below our average for the entire fourth quarter.

So I think as we move into 2008 we believe we will continue to see some moderation in our lease operating cost on a BOE basis, as we bring additional gas volumes on in South Texas and in the Barnett Shale, and then prospectively hopefully West Virginia. We think that those volumes would continue to help us moderate our BOE LOE cost.

Jumping into 2008, I think the highlights for this year as we start out now with a full year of Ascent under the umbrella of RAM, we are going to invest $80 million in our growth for production and our reserves.

I continue to like to point out we own almost 111,000 net undeveloped conventional and unconventional acres that we feel like represent real growth opportunities for us as we move forward.

Our growth projects on page 8 in the presentation for 2008 are primarily South Texas. This is an area where we have drilled two wells and they are producing. We have one well that is drilling, and we have won well that is completing. We have six additional wells to drill in South Texas. These wells will take us anywhere from 30 to 45 days to drill and complete. So we will have a rig working for us in South Texas throughout all of 2008.

Our Barnett Shale activity is beginning to accelerate, in that we have three wells awaiting pipeline connection. We have one well that is awaiting completion. We have one well that is drilling, and we have five wells that are proposed to follow up, just sort of sequentially as we move in the 2008.

Also in our Devonian Shale play in West Virginia, we have contracted for a rig. That rig is scheduled to show up early in the second quarter of 2008. It will begin drilling. We've signed a contract to drill six wells back-to-back in West Virginia. That drilling contract has an option to add another six wells just immediately behind that. So we do have plans to drill 14 wells in West Virginia this year.

If you look at slide 9, kind of what we call our production maintenance projects for 2008. This is Electra/Burkburnett; this is where we are going to be drilling five wells per month with our Company-owned rig. We are also beginning a recompletion program that we began to do engineering work on last summer and through the second half of '07. That program is beginning to be underway, and we are looking forward to that.

In Fitts and Allen we have already drilled one well, and we are currently completing that well. We have spud the second well. That rig will continue to work in Fitts and Allen continuously throughout this year as we drill at least 10 more wells to be scheduled to follow up in this area.

Kind of on slide 10, just a recap. As we move into the second quarter we will have a rig working in the Appalachian Devonian play; Fitts and Allen; Electra/Burkburnett; the Barnett Shale in South Texas on kind of a continuous basis as we look into the balance of the year 2008.

As we've said for our capital budget this year is $80 million. 60% of that is going to be spent on development activity; this is drilling proved undeveloped locations. 33% of it will be spent on exploitation; and this is essentially in the area of our shale plays that do not yet have PUD locations booked against those. We will spend about 7% of this budget on exploratory activities that will hopefully bear fruit for '09 and 2010.

If you look at slide 12, this is South Texas. This is an area where we have 18 proved undeveloped locations. We've got another 13 probable drill sites, and another 39 possible drill sites in this area.

So far we've drilled Garza Hitchcock #12; and it initially came in flowing at just slightly less than 2 million. The Garza Hitchcock #13 was completed with initial daily rates of about 2.75 million. The Garza Hitchcock #11, which we spudded early in February, is currently completing. The Garza Hitchcock #14 is actually getting ready to spud this week. The location is built, and the rig is on location and should spud this week.

These wells are 100% owned and operated by us, and we do plan on spending about $19 million in this play this year. So far we're very pleased with the initial drilling results that we are seeing in South Texas.

Barnett Shale. This is an area that we are continuing to see good activity on. We have 11 wells producing; four wells completing or waiting on pipeline connection; one well drilling; and five wells proposed that we'll just follow up these wells as soon as we can get them drilled. Then we've already identified an additional 31 future locations.

While we originally budgeted $10 million of CapEx for this play, we are seeing a lot more activity, as is shown on slide 14, out of our Devon Area. This is an area that we essentially did some lease work on last year so we could accelerate drilling across the lease lines. We now have drilled the Etta Burress 2-H and 4-H as horizontal wells that were simul-fracked and they are awaiting a pipeline connection.

One thing I would point out here is that this is our first time to do a simul-frac. These wells, you end up only spending about $2 million to drill and complete these wells, as opposed to the $3 million for a single longer-length horizontal well like the Etta Burress 3-H. But our expected EURs out of these horizontal wells is 3 to 3-plus Bcf.

So if you are spending $2 million apiece, you are spending $4 million for roughly an estimate of 3 Bcf, which gets you $1.33 finding cost; as opposed to where we are spending $3 million on a single lateral horizontal well, where we are trying to get 2 Bcf for about $3 million of investment or roughly $1.50. So we are anxious to see how this works.

As I said, the Etta Burress 3-H has been drilled and is awaiting completion. The Molloy 1-H is currently drilling.

Devon has proposed four more wells; it is the T.L. Dickenson 4, 5, and 3 and -- well, actually the T.L. Dickenson 2, 3, 4, and 5. Those wells will be drilled sequentially just as soon as the rig moves off of the Molloy well and moves up on those Dickinson wells. So we should start seeing some production growth out of the Devon drilling wells as we move into the early part of the second quarter this year.

On 15, this is our EOG acreage. EOG has drilled and completed the Dethlof well and is awaiting pipeline connection. We have one well pending; it is the Brown 2H. We have contracted for a rig on this well and expect to move a rig on and spud this well within the next week or two. It currently is on a well, and as soon as it completes the well it is currently drilling it is scheduled to move to the Brown, and we will spud that well.

We will continue to work on the wells that we have proposed to EOG, getting those drilled in '08, as well as identifying additional drill sites from our seismic activity work in this play.

One of our exciting plays going into '08 is our West Virginia Devonian Shale play. This is once again a play we own 100% of. We've got 45,000 net acres. We are going to spend about $19 million out here this year drilling these 14 wells. We are very excited to get this project kicked off and underway.

If you look at page 17, it shows you where our acreage is in relationship to Cabot's Hurricane project. Interestingly enough I looked at the Cabot website a day or so ago. In their 2007 program they indicated they were going to drill 11 wells. They've put the potential of 1,100 drill sites on their acreage, which was about 134,000 acres in the western part of West Virginia. They are using a completed well cost of slightly over $1 million and EUR range of 1 to 2-point Bcfe of recovery. The initial IP rates are between 1 million and 2-plus-million a day.

So as I have said before, our modeling, we used about 8/10 of a Bcf of EURs. We used $1.1 million to $1.2 million to drill and complete these wells; and another $100,000 that well's contribution to the gathering system that we will be developing here.

So we are anxious to get the drilling program kicked off in West Virginia and move ahead with this program. We will keep everybody posted on that.

Look at 18, this was our liquidity at the end of the year. We had about $47 million in liquidity. We still stand at about that same amount today. We were able to increase our credit line to $375 million versus our previous $150 million to effect the acquisition of Ascent.

We have of course given our reserve to our lenders, and we will be talking to them about the borrowing base. We are thinking we may see a modest increase in our borrowing base as a result of our year-end numbers. Once that is completed, we will let everyone know; but that looks pretty good.

I think our valuation issue still is a mystery to me personally, in that we are trading for about half of our reserve value. Getting no value for our 110,000 acres, no value for our service equipment, our rigs, our drilling rigs and service equipment, as well as our gathering systems that we own.

So we continue to look forward to pointing this out and showing the growth that we are anticipating in 2008. We feel confident that as time goes on the market will begin to recognize the value that exists in this asset base that RAM Energy owns.

Now to do a quick summary, we do have a large inventory of growth opportunities as we move into '08 and '09. We've got an awful nice cash flow base coming out of these long-life assets that we own. We are still 60% crude oil and natural gas liquids on a production basis, which is helping us in this pricing environment. We do operate 92-plus-% of our asset value.

I think we've shown that we can create value both through acquisitions and the drillbit. Our valuation continues to be compelling versus our peer group on almost any industry standard that you would apply to oil and gas assets.

The management team, we own 22% of this Company, so we are very focused on growing it and beginning to achieve the value that we think the Company represents.

One thing I would point out just briefly before I turn it over to Q&A is that we have put into slide 23 in the show presentation a schedule of our derivative positions. If you flip to that you can see that we have about 1,500 barrels a day that has ceiling prices on it on crude oil in the low to mid $80 range for this year. Then the rest of our position is either hedged with floors only and no ceilings; or is unhedged.

So we will continue to be dealing with this unrealized marked to market issue for a while if oil prices stay in this $100-plus range as these 1,500 barrels a day roll off during 2008 and early 2009.

Looking at our gas hedges, for the first quarter of this year we are in pretty good shape with our ceilings at $16.70. Our ceilings drop to $10 for the second quarter and $11.04 for the third quarter. Then they drop down to $12.86 for the fourth quarter.

Of course what we have is we've got nice floors at $7 and $8 on these gas hedges going into the summer. We feel like we've got pretty good protection there.

Then our floor prices for our oil continue to be pretty attractive, as well. Our bare floors are all in the $70 range. So just want to point out that derivative position to everyone, as they try to look at the mark to market issues that we talked about earlier in the presentation.

I think with that, Bob, I will turn it back over to you and we will take some Q&A.

Sure, thanks. Moderator, if you would go ahead and introduce the Q&A.

(OPERATOR INSTRUCTIONS) Leo Mariani, RBC.

Just a quick question here on the Barnett. It clearly looks like Devon has kind of been accelerating the pace of drilling there on their acreage. I'm curious to know if you guys have a sense of how many sort of total Devon wells can be out there left in inventory going forward.

Leo, just in this Rawle/Burress lease we are only at a density of about 110 acres per well, with everything that has currently been proposed. So there is certainly some additional well sites or drill sites on the Rawle/Burress lease.

Then we will move to the other acreage we have with Devon, I feel quite certain. In total we have about 3,500 acres that we jointly own with Devon, and this Rawle/Burress lease is only 1,500 of those.

So this is just where we've had the early, very successful drilling. But we're working the seismic on the other acreage we have, and we will be looking forward to moving there and drilling after, I think, we get the Rawle/Burress lease drilled out.

Okay. Just jumping over to another comment you folks made in the Barnett. You basically are sort of targeting getting all the well locations drilled that you proposed to EOG at this point. Just curious as to how many of that locations you will -- have been put to those guys at this point in time.

We've put five locations to them at this point in time as, Leo, I think I have said before. The Brown was one that we proposed; EOG agreed to participate and operate it. The proposal lapsed, and they did not spud it. Then we reproposed it. They once again elected to participate and operate it. The election or the proposal lapsed again without them drilling it.

That is when we decided that we've built location, and we've contracted a rig. We notified EOG that we are going to move a rig on and drill this well. And just waiting for them to tell us whether they are going to participate or whether they are going to go nonconsent.

So I think we will continue to move forward with the wells we've proposed. Then we are also -- we will be looking at additional proposals as we work our seismic.

Okay. So I guess even if these folks do go nonconsent on the rest of these wells, it would be your intention to go off and get these drilled on your own, these other four, besides the Brown this year?

That is certainly what would be our intention. But I am kind of anxious to see what EOG elects to do as far as the Brown. I think that will help give us kind of a course of action as we move forward on this acreage.

But we need to get this acreage drilled. We think it's got value to us, and so we will be pushing ahead to get that acreage developed.

Okay, great. I guess quickly to Appalachia, how is your situation with pipeline takeaway and ability to sell gas if you guys have success in your drilling program there?

Leo, we did put it in the 10-K that we just filed. We have a gathering system there. We hooked those wells up, turned them on, and were able to sell some gas to that polymer plant that our little gathering system is connected to. They are able to take gas with up to 20% nitrogen in it. So that is going to allow us to begin some gas sales, which will help us from a testing standpoint determine kind of how quickly these wells will clean up on their own.

We also have on order a nitrogen rejection unit, which we will set at our gathering system, which will help us take the nitrogen out of the gas stream.

So that's one of the reasons, remember, we didn't really want to kick off the drilling program until sometime in the second quarter. Because we wanted to get the gathering system kind of up and running; make sure we could sell gas to that polymer plant; get the nitrogen rejection unit on order, with an eye to getting it delivered in the second quarter, so that as we drill these wells we can begin to get them into sales. Now that will give us a market immediately.

We also have been approved by Columbia for a tap into their mainline that runs through here. That is obviously going to take a little longer to get that tap built and deal with the compression that we would need, to be able to get that into the interstate system. So I'm expecting that to take place sometime probably later in the second half of this year.

But we are going to go ahead and start our drilling program. We do think we can sell enough gas into the polymer plant to begin to get some -- enough meaningful information that we can see what kind of a play exists here.

I do continue to watch and monitor what Cabot says publicly about what they are doing. They are dealing kind of with the same thing as getting the nitrogen issue under control and getting their gas stream into the sales mode. So that is the same thing we will be doing.

Okay. What kind of pricing are those guys going to give you relative to NYMEX there at the polymer plant?

We're going to probably get about $0.50 below index out in this area. Once we can get it into the interstate system, then we should be able to get pricing similar to what everybody else is going to get out there.

So we will take a little bit of a haircut on it initially, but we are willing to live with that until we can get the test results and get some gas moving in this play.

Okay, thanks a lot, guys.

(OPERATOR INSTRUCTIONS) Ron Mills, Johnson Rice.

A couple questions were just asked, but can you talk a little bit about what -- you gave us a December snapshot of production. Would you be willing to provide current production and kind of how you expect your production profile to look throughout the year? Given you have some of the wells drilling in South Texas that have pretty nice rates, and given some of the recent hookups in the Barnett.

Ron, what we're looking at I think is production around 600,000 barrels in Q1. What we had was we had -- Ascent really wasn't spending any money on their assets towards the end of last year. Production continued to fall a little bit as we moved into January, plus we did have some weather issues in Texas and Oklahoma with some ice and snowstorms we had this winter.

So production was down a little bit in January from December. We were able to get it back up -- actually slightly above our December rate by February; and we've got the rate climbing.

I think what we're going to try to do is, as we get at the end of the quarter, try to give a little better guidance on what we think the first-quarter production will be and what our exit rate is at the end of the first quarter.

Then probably sometime fairly early in the second quarter we're going to try to give the market our viewpoint of what we think production might look like by quarter. We are not quite ready to do that yet for the balance of the year. But we are going to do that here fairly quickly.

Because I think we need to let you guys have some idea of what we see from the time we spud these wells till we complete them and get them hooked up and get them producing.

Okay. But I'm assuming directionally, as you had mentioned in the past, you would expect kind of the line to move kind of up and to the right as we go, as we move through the year.

Absolutely. What we are seeing, from what we are seeing out of the Barnett, what we are seeing out of South Texas, and our first initial results even in Fitts and Allen are encouraging.

So what we see is that our two big maintenance projects, Electra/Burk and Fitts/Allen, should pretty much maintain or slightly grow what we are getting there. The South Texas should be a driver of growth for us. Barnett Shale should clearly be a driver of growth as we start getting these wells hooked up.

Then West Virginia, quite frankly we are not at this point forecasting much in the way of growth out of West Virginia, because we don't know exactly what to use for that.

To fund your Barnett activity, which it sounds like you may have an increase, would you potentially take some of that money that had been originally budgeted for South Louisiana and maybe redistribute it?

That is certainly a possibility. You know, we don't have that money budgeted for South Louisiana until the fourth quarter anyway. Given where prices currently are and if they kind of stay anywhere in this range, we should be generating extra internal cash from what our own internal forecasts were that would allow us to deal with an increase in CapEx in the Barnett, should we be lucky enough to need to do that sometime, probably midyear.

Okay. Then this is just something -- I missed it; I got cut off for a couple minutes. The LOE you were talking about in the low $16 range for the fourth quarter and it was running roughly $15 in December, what did you say about the outlook for that?

Ron, it was $16.84 in the third quarter. It dropped to $15.39 for the fourth quarter. It dropped to $14.19 for the month of December.

Okay.

I would anticipate that we would continue to see a little bit improvement in that as we add South Texas gas, as we add Barnett Shale gas, as we add West Virginia gas. Because as all of us know, it is not as expensive to produce gas on a BOE basis as it is oil.

So I think we will continue to see some moderation. We are experiencing increase in cost on an absolute basis. But I think with a better mix or a little higher mix of gas coming onstream that our overall BOE cost should moderate. So we should not be seeing a lot of cost increases, and we might continue to see our BOE cost moderate slightly.

Okay. Thanks, I'll jump off and jump back in. Thanks.

Neal Dingmann, Dahlman Rose.

I will try to adhere to this rule, unlike my follower guys. You outlined pretty well on what you all are going to do out East. How much -- I guess a couple questions on that.

One, how long have you locked that rig in? Do you project that going up? As you said, some of your service costs it sounds like might be going up a little bit.

Then around that out East is once you start seeing some of the results there, do you still have some variability where you could change some of the plans based on how good some of that is coming out?

Yes, Neal, we basically have that rig tied up for 12 wells. We got six wells that we contracted for. It is our option for a follow-up six. The drilling contractor knows that our plan is that, if that play develops the way we think it is, it will be a multiwell program for us in 2009.

So I think we will be able to get the rigs we want, because we do want good quality rigs for that play. The thing that has been encouraging to us is that most of -- in fact maybe all of the major service companies have now set up shop in West Virginia in the last what, Larry, couple of years.

So we've really got people that we can depend on and that we know from the work we've done in Oklahoma and Texas, New Mexico, and other places all these years that are out there working. So I think the quality of the service work we're going to get as well as the cost of it is going to be pretty much in line with what we are forecasting.

Okay. Than just last question. I know you're not really in the acquisition market, Larry, given that large one you did last year. But what are you seeing out there in the market today?

Now that prices have done what they've done, has sort of activity cooled off, as you see it, down the road; and you're kind of glad you have what you have; or what are you seeing?

Well, first of all, I am very happy with what we have. I think having closed that acquisition on November 29 and basically get it contracted in October like we did, we are benefiting from this run-up in prices, well above what we had forecast. The initial drilling results are coming in as planned. So I would have to say right now we're very pleased with the acquisition we made.

There is still activity in the marketplace. I think the market is -- when you see big price -- this is my experience. When you see large price movements like this, the bid and ask on M&A transactions kind of move away from each other for a little while, and then they begin to come back together.

So I am expecting that you will start seeing M&A activity began to pick up again as you go into the second quarter. Because I think the back end of the curve is beginning to give you some ability to take the price risk out of a transaction if you want to do that.

There are still some companies that need to sell. There are still some individual asset packages where people want to sell. As we've talked about many times, this is an industry that has got a lot of gray hair in it, and a lot of people are wanting to go do something other than work as hard as you have to work in this business to make any money.

Right, okay. I look forward to all the activity.

Richard Rossi, FBW.

Afternoon, everybody. Covered most things, but you had that headcount increase this year for obvious reasons. What is the headcount expectations as we go forward for the year?

Rich, we are still looking for some additional people here in the Tulsa office, as well as the Plano office. While we are going to start in West Virginia with consultants in West Virginia being overseen by people in our two Texas and Oklahoma offices, we fully expect that maybe by the end of the year we will have an office out in West Virginia, and we will need to actually do some hiring of people out there.

So a specific headcount I can't give you, but I know that right now we're probably looking for at least a half a dozen professionals. We've hired some and we are still looking for some more.

Then of course if we open up that West Virginia office, that could certainly take another six to eight people in that place. So we will continue just to kind of be on the lookout for good talent and continue to try to fill in where we think we need additional people on a staff basis.

If I recall, Ascent didn't have anybody in West Virginia. They were using consultants, right?

They were using consultants, and we are using the same consultants because we actually think those guys did a good job as far as the wells they got drilled and the gathering system they got built, given the financial constraints that were on them as a result of Ascent's financial position.

You know, that is one thing. Ascent, they were not in a position to sign a multiwell contract. So they couldn't really get the good quality rigs to drill those wells. They were having a difficult time really getting I think the good service companies to work for them.

So I think that we will see better results, but we've been out, our guys have been out, spent time on the ground with those consultants, and at this point we are happy with the quality that those guys bring to the table.

Then just from a G&A standpoint, ex-ing out the SOX -- I presume pretty much onetime costs, first time around. The absolute dollars, do you expect that to hang in where it was in the fourth quarter?

Rich, as I look into next year, I think that the G&A will be between about $3.75 million to $4 million a quarter. That is about where we are forecasting it internally as we look at it.

We will have some SOX work to do in 2008 because Ascent didn't have to be SOX compliant at the end of 2007. So get basically a year to get it SOX compliant.

RAM was SOX compliant, and I am proud to say we met all of our requirements to do that at the end of December 2007. But we are not expecting that the Ascent effort will be anywhere close to the $0.5 million we spent on getting RAM compliant this year. Probably be half that.

Okay. All right. Thanks very much.

Ron Mills, Johnson Rice.

Richard just asked the question on the G&A. Just to go back to the Barnett a little bit. The Devon acceleration from one well every 120 days drilling requirement to their current pace, is that just a function of the results that you all have seen on the previously-drilled well? Or do you have any idea what is driving that increased activity?

Ron, my take on it is two things. Devon was very definite about their plans to accelerate drilling on the Chief acreage when they bought it. Then with what we did with dealing with the lease situation last year, allowed that accelerated drilling to happen.

So I think it is the combination of their commitment to the Barnett, their enthusiasm with what they are seeing throughout the play, and what they see as additional opportunities on this acreage and the results of the wells we've seen out here.

All these wells that we have drilled and the Rawle/Burress well have an estimated EUR of about 2.3 when you average all of them that we've done so far. But that Dickenson well was by far the best well we've drilled out here. I think that Devon believes, and I believe too, they are one of the premiere Barnett operators in play. They've got good acreage, and they want to get it drilled and get it produced. So we are real excited about seeing all this activity come out of Devon.

Then is the thought process so you can move forward on the EOG by contracting your own rig, just apply some of the same techniques that Devon is using on that acreage? Or is it not that transferable?

We think it is very transferable. We've had the pleasure of having worked with Chief when they were, I thought, was the premiere small player in the field. I think Devon has got to be considered probably the premiere player in the play today. They certainly are the biggest player in the play.

We've had the good fortune of being partners with both Chief and now with Devon and EOG. I think EOG does a good job, too. Just they don't want to drill.

Okay. Then final--

They want to drill the Bakken and other stuff; I understand that.

Right. Then finally, just the West Virginia shale, you talked about cost in EURs. Can you walk through kind of what the expected spacing is for horizontal development up there?

And if you have 1 million, 2 million a day IP rates, kind of how that production profile you would expect to be realized?

We have modeled it internally to look just like what we are seeing in the Barnett play, where you're going to probably see a 60% decline rate within the first year; and then it is going to kind of stabilize and produce at that lower rate for an awful long time. That sort of seems to be what we've been able to determine looking at West Virginia.

We are modeling it at 8/10 of a B. I think we have modeled it at about 800 Mcf a day of initial flowing rates. Clearly Cabot has done better than that. I think all of their wells in their Hurricane project have been 1 million a day or better. They had one well that came in 1 million a day natural, without treatment. They are telling the market that they think the EURs are anywhere from 1 to 2-plus Bcf; and we are figuring on about 8/10 of a Bcf.

From a spacing standpoint, we are modeling 80-acre spacing. Once we get into the play we may find that the spacing will be maybe less than that. But right now we are going in assuming 80-acre spacing; and 8/10 or 800 Mcf a day of initial start rate; and about 8/10 of a Bcf of recoveries; and a typical shale decline curve.

Okay, great. Thank you, guys.

Robert Setrakian, Helios.

The $80 million in CapEx that you have, with internally generated funds with oil prices here, gas prices here, and I think you had mentioned that you were going to save money on the interest rates because of what has happened to LIBOR on your debt facilities. The $80 million in CapEx, can that be funded with internally generated funds for the year?

Robert, if prices stay anywhere close to where they are today we're going to come very close to, if not generating that $80 million internally. Now you know we haven't given formal guidance, but I think if you look at most of the analysts' forecasts they are showing probably $60 million to $65 million worth of internally generated cash available for drilling.

But interest costs are down significantly. I know the Fed gave us another three-quarters of a point today, so that is going to help us again. We are certainly at the moment, we are generating positive cash flow at the moment.

Robert, just another benchmark for you; it is not quite the same. But if you look at that one table that we had in the press release that deals with December results, which showed about $7.5 million of EBITDA; certainly on kind of an annualized basis that would more than get you there. So there is some good cushion there.

Yes. A follow-up question. You mentioned since the acquisition what oil and gas prices have done, the benefit from the interest rate. But in terms of from the acquisition's perspective, in terms of opportunities, and in terms of how integration has gone, has there been any -- have you been positively surprised? Is it as expected? Any challenges that you weren't expecting?

I think from an integration standpoint, I think it went extremely well, particularly as it relates to getting out the financial information. I think the fact that we -- this is our first time to be an accelerated filer for our annual reports. To keep on top of being a first-time accelerated filer; and also make an acquisition on November 29 that doubled the size of the Company; and having met all of our SOX compliance; and getting our statements filed timely; and getting all of that done, I couldn't have asked for a better integration as it related to the financial side of the house. It just went as smooth as we could have helped for.

As far as the operational side, we knew we had good people in the field, and we do have good people in the field. They have taken the challenge that we've given them and the financial support we have given them. They are charging ahead just like we hoped they would.

In the office we've lost a couple of people, and we've hired three or four new people. So I'm talking about on the technical side. And that is to be expected. The technical market for talent is extremely competitive and fierce right now for engineers and geologists and land staff.

So while we've not had any problems there, we expected to have a little transition, and we have had that. But the people that we've got, the people that have stayed with us, are very talented and are doing a great job.

So I think we feel like the reserves that we've based our deal on are definitely there, and we are very pleased with the early drilling results, particularly what we are seeing in South Texas. I think that is -- I think we are very pleased with what we are seeing down there; and we felt like we had a lot of probable and possible reserve opportunities down there.

West Virginia, you know when we really started looking at West Virginia we didn't have as good a handle on that as we do I think today. We've been extremely encouraged by what our neighbor across the lease line is doing and what Cabot is doing. So I would say overall we are excited about the opportunity that this acquisition is presenting us.

Thank you very much.

Mark Lear, Sidoti & Company.

These South Texas projects look pretty awesome. I was just wondering if you could kind of give me an idea of how you think or how these wells look after a little bit of production history; and how much they are costing you; what the economics of these things look like here.

Mark, these are costing us about anywhere from $2.4 million to $2.6 million to drill and complete. We've modeled all these at about 1.5 Bcf.

So far I think it is too early to declare a major league victory; but so far the initial rates and the pressures and the initial production profiles that we've seen have matched up very close to what we had hoped we would see. We thought these wells would come in somewhere around 2 million a day, and we would get 1.5 Bcf out of these wells.

One thing that they are doing is they are coming in with more condensate than we had originally forecast, which is good for us with where condensate values are today.

I think the last one came in at about -- what was it -- 78 barrels or something like that, Larry? The one that we are currently in the process of completing certainly looks good on the log. So we are pretty excited about South Texas right now.

What is the net revenue interest you're seeing from these wells?

We own 100% working interest. We've got 75% nets in these wells.

All right. Can you just give me an idea of how do you think these DD&A rates are going to shake out through '08?

Mark, I can't give you an answer on that. One of the things we're going to try to do is we're going to try to give all you guys a little bit of production guidance and some cost on a unit basis guidance very early here, in either late this month or very early in Q2. Because we need to try to give you a little bit of that. We're trying to model some of that right now.

Right, but do you think -- is there a bit of true-up in the fourth quarter? You'll see a bit of a drop-off? Just to get an idea whether fourth quarter was a good representation.

(inaudible)

Yes, okay, no problem.

Mark, I don't want to mislead you, because I just don't know right now. I will get that and I will certainly get back with everybody so that everybody has the same information on that.

You bet. Thanks.

Leo Mariani, RBC.

I was going to ask the same question on DD&A here. But just real quick with respect to costs, you talked about on the G&A side having some onetime costs for Sarbanes-Oxley in the fourth quarter. Just curious to know if there was anything else, other than the interest cost you took, that was sort of onetime in nature, anything related to employee severance or anything like that.

No, the employee severance cost that did occur as a result of the Ascent merger was flushed out and was paid for by the seller. So we didn't have any of that.

We did have some additional year-end bonus cost that did flow through in December as well. Leo, as I said, probably $0.5 billion between the SOX costs and sort of onetime.

I think we are going to -- we are rationally -- we may start trying to make that on a more even basis, try to accrue it by quarter rather than having it all flop into the fourth quarter.

That is where I think as we look forward to balance of the year, we are thinking that that $3.75 million to $4 million a quarter is about what the runrate is going to be. Because we only had the Ascent piece in there for one month, which was the month of December. Then we had some onetime costs with SOX and some kind of onetime bonus numbers into December, as well.

Okay. Now does that G&A forecast you are giving here include stock-based compensation or no?

No, it does not. Because we stack that out as a separate item since that is non-cash.

Okay, thanks a lot, guys.

It appears there are no further questions at this time. I will now turn the call over to Mr. Larry Lee to end the call.

Well, I just want to thank everyone for taking the time late in the day to join us. We look forward to hopefully seeing many of you, as we will be in New York I guess later this month at the Sidoti conference. Then we will also be in New York in April for the IPAA conference.

We will continue to provide updates on our operational activities as we go throughout the year. So with that, thanks, everyone.