Battalion Oil Corp (BATL) 2006 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the RAM Energy Resources fourth-quarter 2006 conference call. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded for replay purposes.

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 management plans or expectations, including capital spending, derivative positions and industry conditions, are forward-looking statements within the meaning of the Securities and Exchange Act of 1934. The Company cautions that such forward-looking statements are necessarily based on certain assumptions, which are subject to risks and uncertainties, which could cause actual results to differ materially from those indicated today. Further information on these risk factors are included in the Company's filings with the Securities and Exchange Commission, and is enumerated in the conclusion of the webcast presentation slides. The management of RAM encourages you to review the disclosure in both documents.

I will now turn the presentation over to your host for today's conference, Mr. Robert Phaneuf, Vice President, Corporate Development of RAM Energy Resources, Inc.

Thank you very much, and welcome again to the call. I'd like to take just a minute to introduce the participants from RAM. We have with us today Larry Lee, our Chairman and CEO, Mr. John Longmire; Senior Vice President and Chief Financial Officer; Larry Rampey, Senior Vice President of Operations; Drake Smiley, our Senior Vice President of Land and Exploration; and John Cox, Vice President and Treasurer; and myself.

And I'd like to take care of one housekeeping item before jumping into the call agenda, per se. And that is to make you all aware that this afternoon we issued a press release that was a correction to some of our fourth-quarter results contained in the press release made earlier today, this morning's press release, rather, that dealt with the fourth quarter and year end 2006. And I'll briefly give you the highlights of that press release that we issued later today, because it will have some bearing on the numbers as we go through the conference call. If you have not seen the release yet, it's on its way out the door, so hang tight and it will be out probably before the call has ended today.

We basically announced that we made an error in one of our production numbers for the fourth quarter of 2006. The total production for the fourth quarter of 2006 was 317,000 barrels of oil equivalent, as opposed to 301,000 barrels as originally reported. And it, by virtue of translation into per-BOE amounts, effects several things that we had in the earlier press release, particularly our oil production -- our oil price, our production cost per BOE, production taxes per BOE, and general and administrative expenses per BOE. All of these are corrected by this new release, in the table.

Also, just to allay any concerns, this error in production does not affect any reported year-end 2006 financial statements or the selected quarterly financial data statement contained in the Company's 10-K and in the original press release issued earlier today.

So with that, let me just briefly describe the agenda. We'll have a brief review from Larry on the fourth-quarter results and year-end summary highlights. We will then move to discuss year-end reserves, production replacement and finding costs, then bring you up to date on our balance sheet, liquidity, our 2007 capital budget. We will then go through an operational update, and end with a couple of evaluation slides and a quick summary. So I'll turn it over to Larry to go through the highlights with you.

Thank you, Bob, and thank everyone for joining us on our 2006 year-end highlights, and our fourth quarter of '06 highlights. Our oil and gas sales did increase 3% to $68 million for the year. Operating income was up to $23.3 million, and our net income rose to $5 million versus $543,000 in '05. Cash flow from operations was at $18.1 million versus $23 million for last year, and that is impacted of course by our derivative positions and how they flow through the income statement.

Our average daily production for the year was 3533 barrels of oil equivalent and that is versus 3848 barrels of equivalent in 2005. A significant portion of that decline in '06 versus '05 is related to the reversionary interest that vested at the end of the third quarter in '05 in our Boonsville field in North Texas.

For the quarter, RAM reported $1.1 million of income or $0.03 a share. Our cash flow from operations was $3.2 million versus $5.4 million in the fourth quarter of '05, and our fourth-quarter production was 317,000 barrels of oil equivalent. That was somewhat impacted negatively by weather-related curtailment. That number is somewhere around 3000 to 5000 barrels estimated. And our first-quarter production is about 3500 barrels a day, and for a ninety-day quarter we were expecting that production to be about 315,000 BOE equivalent, and it was also slightly impacted by weather-related delays, primarily in Texas and to a lesser extent, Oklahoma.

Capital expenditures continued to move along as planned. We spent $6.6 million in the fourth quarter, and that completed the total CapEx program of $28.1 million for the entire year. And that is well over 100% increase from the $13.5 million that we had invested in 2005.

RAM's borrowing base was just reaffirmed by our lenders. At $140 million, that's the existing borrowing base as was previously approved, and that's been reaffirmed. Also in February we completed a 7.5 million share sale of common stock, which added significantly to our liquidity. And our liquidity is estimated to be approximately $68 million at the end of March 31st.

Current highlights in this quarter, the first quarter of '07, our Wolfcamp exploration play is continuing to move forward. We have begun fracture stimulating and testing both of the two wells that we drilled in the fourth quarter of '06. And while we don't have specific information to report at this juncture, we are moving forward with that plan and hope to be in a position to share with the market some of the results we're experiencing some time in the middle to the latter part of the second quarter of '07.

In February, RAM -- we proposed our third Barnett Shale well to EOG, this was a direct result of the seismic program that we undertook in '06 to put us in a position to begin to propose wells on our jointly owned [helped] by production acreage. EOG has elected to participate in the first two of those wells, and they have until mid-April to make the selection to participate, or go non-consent in the third well.

Also in the first quarter, Devon did drill, and we're just beginning completion activities on the T.L. Dickenson. It's the first well that Devon has drilled under our joint exploration agreement that we have with Devon, which is the agreement that they inherited when they acquired Chief Oil & Gas.

Our drilling success throughout 2006 continued to match our historical success rate. We drilled 92 total wells during the year. We did have four dry holes, we had 80 producers, and at the end of the year we had eight wells that were in various stages of completion. And this continues our 90% plus success ratio with the drill bit.

Our year-end reserves totaled 18.5 million barrels of oil equivalent, 59% of that is crude oil, 11% NGL, and 30% natural gas. The proved developed component of that is 71% of it, or 13.1 million barrels. The prices that we used at year end '06 were set out in the rules and regulations of the SEC. The oil price was $58.74, NGL's $36.51, natural gas $5.51.

We had a significant decline in the natural gas prices at the end of '06 compared to the end of '05. And that decline in natural gas prices contributed almost all of the decline in the PV-10 of 270 million at the end of '06 versus 345 million at the end of '05.

We did run the year-end reserves using March 31st pricing, just as a benchmark, and that PV-10 value, doing that was $330 million. I'm sure most of you are aware that both oil and natural gas prices dipped pretty significantly at the end of '06, and those are the prices that we utilized in our reporting.

As far as our production and replacement and finding costs, we produced 1.3 million barrels of oil last year, and we added net of everything 946,000 barrels. And our all-in finding cost was $27. One of the things that contributed to this high finding cost in '06 was the substantial amount of money that we spent in converting proved undeveloped locations, principally in Electra/Burk and in Boonsville into TDP reserves. So those are not adding new reserves as much as they are converting them to PDPs, and also in our exploratory activities, much of our action in '06, such as our seismic, our activity in the Wolfcamp play, both from lease acquisition and drilling, all went into setting us up to hopefully reap the benefits of that in '07 and '08.

Our reserve production replacement rate for '06 as a stand-alone is 73%, but our three-year average continues to be quite attractive at 437% of production replacement.

A quick recap, and I know many of you are familiar with this. Our principal field, the Electra/Burkburnett is still almost slightly less than 10 million barrels of oil. Boonsville, a little less than 3 million barrels, we now have at the end of '06, slightly less than 1 million barrels of oil equivalent in our Barnett Shale, and our other assets totaled some almost 5 million barrels of oil equivalent coming up with our total of 18,452,000.

I think a substantial percentage of our reserves continue to be developed, 71%, and we will be working on our exploratory projects hopefully at an even faster pace in '07 as we move forward.

Our CapEx program for this year, '07, is $30 million. We're on schedule with our development activities in both Elektra/Burkburnett and Boonsville, and in our other assets. Our West Texas Woodford and Barnett activity is scheduled to take place in midyear based on discussions with our operating partners out there. Our Wolfcamp play is on track for where we had planned for it, as we look at the '07 budget.

The one area that I think that the management and the Board of Directors will be evaluating in the next couple of months is our capital commitment to the North Texas Barnett Shale. We already have committed under the three wells with EOG and the one well with Devon, $3.1 million of capital to that program. And we had originally forecasted only $4 million. So as we move through the year, we may have to make an adjustment and look at potentially increasing the capital commitments to our North Texas Barnett Shale program.

From a financial liquidity standpoint, at the end of the year we were setting on $43.7 million worth of immediately available liquidity.

Pro forma, with the offering now, the estimate at March 31st increases that to about $68 million. So we certainly have the financial flexibility to accelerate our drilling programs if they warrant, and also we continue to look at the possibility of additional acquisitions in and around our operating areas.

In Electra/Burkburnett, we drilled 79 wells in this field last year. When we started 2006, we had about 200 PUDs identified in this field. Of the 79 wells we drilled last year, 70 were PUDs and nine wells were non-PUD wells. But the geoscience team, after evaluating the success that we did experience in '06 in Electra/Burkburnett, we have identified and our engineers have confirmed that we have 200 locations to drill, so we're still looking here at an almost three-year drilling program ahead of us in Electra/Burkburnett.

Our finding costs continue to be very attractive, as we're able to drill these wells at $128,000 a well, with a recovery rate of about 22,000 barrels of oil equivalent, to be recovered over the life of these wells.

I always like to point out -- I know you've heard me say it many times -- but I think one of the things that helps us here is the fact that we have our own drilling rig, our own workover rig, our own gas plant, and our own supply company, and we are in control of our drilling costs to a much greater extent than we are anywhere else in our portfolio. And also that puts us in control of the timing. We do still plan to drill six wells a month in this field throughout '07, and we have in fact drilled 18 wells in this field in the first quarter of '07.

So we're on schedule with and Electra/Burk. And I would point out that as a result of the additional PUDs, we were able to add some additional oil volumes to our reserve report.

One thing that did happen to us in Electra/Burk, because of the long life of this field, crude prices being exactly what they were at the end of '05 as they were at the end of '06, but our operating costs did increase between '05 and '06. So the margin compacted a little bit when you look at the economics on that particular date. And so that resulted in us reaching an economic cutoff earlier on some of the existing production, but we were more than able to make all of that up by both some performance as well as the identification of the additional drill sites within the field. We do plan on spending about $9.7 million in this field in '07.

In Boonsville, this is our -- [been] conglomerate gasfield in Jack and Wise Counties. It did produce about 44,000 barrels of oil equivalent in the fourth quarter. We do have 20 identified PUD locations and have plans to spend $1.6 million drilling in this field during '07. And once again, this field -- we do own our own gathering system here, as well as this field gives us our ownership rights in our deeper Fort Worth Basin, Barnett Shale.

Turning to the Barnett Shale, this is a project that we spent a lot of time and effort on in '06. We've got almost 28,000 acres, 6800 net acres, this is all helped by production. 90% of it is in the core area. Wise County is the largest -- is the county that has produced the most gas out of the Barnett Shale of all the counties that are in the play. And 90% of our acreage is in Wise County. We have 325 potential horizontal drilling sites in this acreage position, assuming eighty-acre spacing. We had only nine gross producing wells currently. We have one that's awaiting completion. We had acquired 35 square miles of 3-D seismic in '06. And we budgeted to add up to another 60 square miles during '07. Our operating partners here are EOG resources and Devon Energy.

I will turn you to the next page, which is the Barnett Shale EOG area. This is our largest acreage position in the play, it's almost 23,500 acres, 5600 net to us, 290 of the potential drill sites are on this, and at the moment we only have one well that's actually producing, and we have not booked any proved undeveloped locations today on this acreage.

Twenty-seven square miles of our seismic -- of our 35 is covering this area. And our ongoing seismic review at the end of the year supported 11 additional drilling locations that we could specifically identify with our seismic and geological interpretation.

We began to propose wells to our partners in the well, primarily EOG. In January, we proposed our first well. In February, early February, our second well, and about the middle of March we proposed our third well. EOG has responded that they're going to participate and operate the first two wells. Under the joint operating agreement, they have until sometime in early May to spud that well. Correspondents going back and forth between the land staff here at RAM and the land staff at EOG, indicates that they are acquiring additional rigs and doing the land work necessary to begin that program.

Our plans would be to continue to propose the wells that we've identified from our seismic interpretation, with an eye towards having several of the well proposals pending, so that once we are hopeful that the rig shows up and begins to drill the two wells that we already have consented to by EOG, that that rig will just stay on our joint acreage through the balance of '06. That's certainly our hope.

In the Devon area, we've got 3500 gross acres, 1200 net to RAM. We own 36% interest in these wells. And we have seven producing wells at the end of the year, four PUD locations, an additional eight locations identified seismically. Devon did inherit a continuous drilling clause that requires drilling of a subsequent well every 120 days after the completion of the previous well.

Devon did drill the T.L. Dickenson 1-H in a timely fashion under that agreement. And if you will turn to page 19 in the presentation, you'll see where the T.L. Dickenson is located. Once that well is completed, which we believe it will be successfully completed, we will be in a position to book some proved undeveloped locations that are direct offsets to that, and that's what we envision happening, both as Devon drills their wells and as EOG begins to drill on our joint acreage. As we prove up locations, we will then be also adding proved undeveloped locations along the way.

So, once again, Devon, under their agreement, we should get roughly three wells a year out of Devon. There is really know limitation on the number of wells that either we or EOG could propose on our joint acreage in the Fort Worth Basin play.

Our Wolfcamp fairway play in Southwest Texas, we have 15,000 gross and net acres. We are in this play by ourselves. We have drilled these two wells vertically, which we did in the fourth quarter. And we have begun the stimulation process. We have multiple stages in each of these two wells that we're going to test. And obviously we're starting at the bottom and working our way up the wellbore and we are hopeful that we will have some results to share with the market, as I said, sometime in the middle to the latter part of the second quarter. This continues to be -- could be a significant play for us if we can commercially confirm it. We're still actively trying to pick up additional acreage in this play as well.

With that, I think I will turn it over to Bob to let him take everyone through the valuation analysis before we open it up for Q&A.

Slides 21, 22 and 23 really look at our valuation compared to our peers. And as an overall statement, I would just say as we go through these, and as we proceed to develop our upside, the mean values of the peer group that are out there in existence today should provide some measure of potential of our upside as we show that we can execute on our game plan and end up in some of the same places as our peers.

So on page 21, you look at sort of reserve base metrics, and on the left-hand side of the slide there's enterprise value to proved reserves, on a BOE basis. And on the right-hand side, you can see that RAM is being valued at $15.23 per BOE versus the peers that are valued at -- when you take the mean or the median $26, $27 a BOE. So again, peers are being valued at considerably higher levels on a per BOE basis than RAM at the current time.

Same thing is true if we look at enterprise value on the right-hand side of the slide, as a percent of PV-10 value. Again, RAM being valued at 104% of its PV-10, which as you heard earlier has got a very high component of proved developed in it, of the total proved, versus our peers that are basically selling at 200% plus of their PV-10.

As we flip to page 22 and look at more cash flow-based measures, here again, enterprise value to last 12 months EBITDA. RAM is valued at 8.4 times versus the peer mean of 13.6 times. And on the right-hand side of that page, enterprise value to last 12 months daily production. And this is interesting from two standpoints.

One, again, RAM is at a considerable discount to the mean of the peer group. RAM at 79,000 per daily BOE of production with the peer group at 161 per BOE of daily production. But in that graph you'll see the Herald Mean, and basically this is a statistic that was gathered looking at transactions from the John S. Herold database of between $25 million and $250 million, basically done in the areas where RAM operates, Gulf Coast, onshore, midcontinent, Permian Basin. And essentially the transaction value on a per daily basis -- per daily BOE basis, for the last 12 months has been about $85,000. So RAM is actually selling for less on a daily BOE basis than many of the transactions that have taken place over the last year, which as most of you know, are primarily on proved reserves. So the market is really not giving RAM any upside on its daily BOE production compared to peers.

Lastly, on page 23, I would point you to price to NAV. Here again, we looked at the current price on a per-share basis compared to NAV, and RAM is selling for less than half of basically the mean of the peer group. And when we did these values, we basically didn't put any value in for acreage. And so this means that none of our Barnett Shale acreage or Wolfcamp shale acreage is really being valued in this metric here. So if that does indeed turn out to be as valuable as we think it might be, we have a long way to go to catch up with some of our peers there with respect to potential price appreciation.

So with that, just to quickly go back to a summary. We talked about Electra/Burkburnett and Boonsville, and the stability and cash flow base that we think we have over the next couple of years, particularly with the PUDs that we have to drill in those areas. We think we have a compelling valuation compared to our peers. We have significant management and technical expertise. We have very much of a balanced exposure with respect to our oil and natural gas hydrocarbon mix, large inventory of growth opportunities in the Barnett and potentially the Wolfcamp. A high degree of operating control on the properties we operate, and we have a proven value creation through both acquisitions and the drill bit. And lastly, but certainly not least, management owns a substantial amount of RAM stock and surely is aligned with shareholders on that basis. So with that, we will stop and open it up for questions. Moderator?

(OPERATOR INSTRUCTIONS). Leo Mariani, RBC.

Good afternoon. I was hoping to just get maybe a little bit more color on sort of your '07 CapEx budget. You told us you had about 30 million slated, you had about 3 million or so you think spent in the Barnett, 4 million budgeted. Give us kind of a sense of maybe where you think that number could go to, EOG elects to put a rig in the field come May and keep it there, for the balance of the year. Would that potentially cause you to spend some less money on other areas?

Leo, I think that once the rig shows -- the 3.1 million we have committed is ASE. In other words, we have not spend it, we have just committed to spend it under our well proposal. I think that once they get that rig on place and we can get a sense of can we keep that rig, we believe we can continue to drive well proposals out and pretty much to keep that rig busy throughout the balance of '07. We're already kind of looking tentatively of almost increasing that budget by at least 50% and maybe larger. I just think that -- the way that that program is shaping up, we were trying to be fairly conservative about what we thought we could accomplish in the Barnett, not knowing how quickly we would work our way through the seismic analysis and have these proposals to EOG. That started a little earlier than we thought, and we're at a faster pace than we thought. So we're seeing that that number probably is going to go up at least to 6 million, maybe larger than that depending on how we keep that rig. I don't think it would impact us cutting back on our CapEx in any other areas. We have the financial flexibility, with the liquidity we have, and with the cash flow from operations we're anticipating in '07, that we ought to be able to do this full 30 million plus any additional increase in the Barnett that sort of we recommend and the board approves here probably. We'll probably really take a hard look at this, I think, in the second quarter and be able to be pretty more definite about that as we move into the middle to the latter part of the second quarter.

Okay. Switching over to the Wolfcamp real quick, it sounds as though you guys are potentially a little bit encouraged about some of the results there, and are going to kind of keep moving forward. I guess you said to stay tuned for some results, mid to late second quarter here. I guess you anticipate at that point in time, basically having some sustained production [cap] from sort of all the zones on these two vertical wells that you thought looked attractive.

Yes, Leo, That's our plan. We've got three zones in one well, we've got two zones in the other well that we want to test. And unlike if we were -- if this was in a development mode, which it's not at this point, you'd just drill them; you would frac all of those zones and you would start flowing them back all at the same time.

Given that these are initial test wells in this exploratory play, we really need to get a good test for each of these zones as we move up the hole. Remember, one of the things that is still an unresolved question and will be unresolved, I think even after we get sustained rates out of these wells, and that is whether we would ultimately be drilling this play on a horizontal basis or a vertical basis. So that's why we're probably spending more time doing the testing as we work our way up the hole than we would routinely.

But right now, as I said all along, this is an exploratory play, and we continue to move forward with it and we continue -- we're a long ways from telling everyone this is a successful play. But clearly we continue to move forward with it, and we continue to be encouraged with the results that we've seen today.

Okay. What's the thickness of the shale there that you guys have encountered with those two vertical wells?

What, 3500 feet, something like that? The whole section is about -- almost 4000 feet. Not all of that is going to be prospective, and that's why we're looking at these zones that we think are more prospective, but the sections that we're working with are 500, 600, 700 feet thick per zone. So they're pretty thick zones that we're targeting.

Okay. Can you remind us what you had in the budget here for 2007 in terms of dollar spend and activity planned?

We have $7.4 million, and it breaks down this way. We drilled both of those wells in the fourth quarter, we spent a little less than $1 million each drilling and casing and doing all the science, which we did most of that -- not all of it, we did most of it in the fourth quarter. Then we have budgeted these frac jobs -- Larry help me out -- they're about 300? $250,000 to $300,000 a zone; we've got five of those in the two wells, so that's another $1.5 million plus additional cost. Probably looking at $2 million that we're going to be spending sometime between the first of the year and, say, mid-May in these two wells.

Then we will be -- we are trying to buy some more leases in the play, and we have planned to drill well No. 3 and well No. 4 sometime probably in the third quarter. That was our original plan, and we wanted to test these first two wells sufficiently to determine whether wells 3 and 4 should be vertical wells or whether one of those wells or both of those wells should be a horizontal test. That's the reason we planned those in the third quarter.

So we had $7.4 million for the entire budget, and I would say at this point we still feel like that's adequate to do the job that we're intending to do on that play this year.

Okay. A quick financial question here for you. I guess lease operating costs in the fourth quarter, were a little higher than I thought they might be. I was hoping you could just give us a little color around that, and give any indication of what we should expect going forward in '07.

Leo, we had two items that affected the fourth quarter that were unusual. We had about a $275,000 workover expense on one of our wells in South Louisiana that was -- obviously it was expensed, which was all in the fourth quarter. And also, we got our ad valorem tax bill from the various Texas authorities in October, and our ad valorem taxes were $350,000 higher than they were in the previous year in what we had been accruing for. So you have two items in the fourth quarter that accounted for that. Ad valorem taxes have been going up pretty dramatically throughout Texas and a lot of it has to do with the value of the oil and gas assets. That's how they are valued. You have a lower severance tax in Texas, but you have this ad valorem tax. And you really don't know what that is going to be until you get your assessment from the taxing agencies. So obviously what we will do is we will take the new '06 ad valorem tax number and accrue that throughout '07, and after our experience in '06 we will probably add a little bit to that accrual so that we hopefully won't have that accrual from the ad valorem tax surprise in the same quarter at the end of '07.

I think if you take those two and normalize those out, we weren't as far off -- we clearly are having price pressures, like everyone in our business. Our non-operated costs seem to be going up at a pretty dramatic rate, and we're trying to analyze that and see what is happening. But what we're hoping is maybe some of those cost pressures will begin to mitigate as had been talked about a lot in public commentary, with both drilling costs and then hopefully that might also flop over into some service costs.

It sounds as though fourth quarter was a little unusually high and we should expect that to be a little bit lower in '07, relative to fourth quarter of '06..

I think, as I said, we had those two big items, that accounted for about $700,000 of the LOE in Q4.

Okay. Well, thank you very much.

(OPERATOR INSTRUCTIONS). Clay Cummings, Johnson Rice.

Good afternoon. Bob, do you think you could break out -- I know you're talking about the correction to production in the fourth quarter. Could you break that out by gas, oil and NGLs? I did not see that in the press release that you'd sent out this afternoon.

It was primarily in the oil area. I think it was exclusively in the oil area.

It was? okay.

Yes.

That takes care of that. And just curious, as far as whether you guys can quantify the impact of the weather and the gas plant that was down in the fourth quarter, and how much of that impacted fourth quarter and what is the expectation for the first quarter of '07?

Best guess that we can, is that we can, is that somewhere between 3,000 and 5,000 barrels of lost production in the fourth quarter, and it looks like it's going to be between 2,000 and 3,000 barrels in the first quarter, is our best estimate at this point.

Okay. And then you see yourself turning back towards kind of a 4,000 barrel range going into the second quarter?

I think that -- we really see -- we're about 3,500 barrels a day. If you take that volume, that's going to add another maybe anywhere from 30 to 50 barrels a day, so that will get us back up to 3550, 3560 roughly. And the pace at which the Barnett wells come on would be the incremental on that, because we're certainly not forecasting any gas sales at this point out of our Wolfcamp play. We're really looking at the additional gas growth volumes coming out of the Barnett Shale and the Fortworth basin once we get that drilling program [to stop].

And then, last question, with the well that Devon has recently drilled and is completing, do you have a timeline for when you think that's going to be online?

No, we just know that they've started -- they're getting everything at the site all geared up to begin the completion. Probably is 30 days, because that's probably going to be at least a five-stage completion job. And then by the time they flow it back and -- well they do have a pipeline. Drake is reminding me, the pipeline is there, so we're not going to have anything delayed as far as a cook-up. It's just going to be the time necessary to do the multistage frac job and then flow it back and begin to flow it into sales.

So we could probably look for some data points I guess in mid-second quarter.

Yes, I would say that's -- like I said, they're getting geared up for it right now.

Thanks.

Neil Dingmann, Dahlman Rose.

Just two quick things. One, on the seismic-wise, are you guys going to have to shoot much more this year? Obviously it looks like you did a great job last year, [on mote] the costs out for that now?

We have forecast and we've budgeted for 60 square miles, both acquisition and shoot. Drake, do you remember how that breaks down approximately as far as shooting versus acquisition?

Well, not on a mileage basis. Last year we did 35. So we're almost doubling what we did last year. And some of that we think we can maybe acquire that's already been shot; some of it will [be around] the JV. And --

We did -- most of what we acquired in late '05 and '06 was stuff that we were able to buy off the shelf. We had to do the interpretation; we didn't actually have to shoot it. But one of the things we're going to do in this year, '07, is actually organize and do a shoot ourselves. In fact, we're talking to some of the offset operators about joining us in that shoot. And that will probably be something we will do over the summer.

Okay, okay. And then, [just in] your projected CapEx for this year, do you have baked in - any thoughts on what you have for service costs etc. on that, or is that just purely on what you're going to be spending outside of that?

You mean what we've got in the budget for seismic?

Yes sir. Do you expect seismic as well as some of your expected completions, some of these other costs, any expectations built in for that?

Well the drilling and completion is in the $4 million that we talked about, that probably is not going to be sufficient. We are going to probably have to improve -- have to increase that dollar commitment. But the seismic is in our 2.9 of G and G in the budget. And all of that is budgeted and we feel like that we will be able to accomplish that work program within the money we have budgeted for it.

That's it, exactly. Lastly, obviously looking down the road a little while, what's your thoughts, Larry, about once cash flow starts coming in, would you think about hedging some of this? How actively is it more just opportunity --?

Yes, no, we will continue to -- our policy has been -- we try to keep hedges out about 24 months in front of us, and we want somewhere between 40% and 60%, 65% of our productions hedged, and we will continue to try to take advantage of what -- for somebody that's been in the business as long as I have, looks like a very attractive commodity price deck.

I agree. All right. Thanks, guys.

(OPERATOR INSTRUCTIONS). Bill Powers, Powers Asset Management.

Good afternoon. Two quick questions. Firstly, as far as -- I noticed out on your presentation you have a type curve for your Barnett Shale wells. Could you just give a little color as far as how closely you're finding the nine wells that you have on -- about how they're performing as far as vis-a-vis expectations?

The wells that we're -- that type curve is the wells we've experienced in the Rawle, Burress area, which is the area that we have the most data points in. We've got seven producers and one well that's currently being completed. So far they're all tracking -- that curve is what they're tracking. It's what they're doing.

So you're seeing a very mild decline in --

We're seeing a pretty reasonable decline in what we're seeing in this area. Now, will this translate to the other areas? Bill, I can't tell you. But that's what we're actually seeing out of this Rawle, Burress area.

And what is your current production from -- I may have missed it as far as from the Barnett Shale wells currently, and vis-a-vis -- and also where it kind of ended the year at in '04 -- excuse me, in '06?

I just don't have that at my fingertips. If we can -- we'll go on with the other questions and we will try to get it. The production rates at the end of '06 are going to be pretty much what they are today because the Dickenson well is -- would be the new data point that we would have since the end of '06.

Okay, thank you.

(OPERATOR INSTRUCTIONS). There appears to be no further questions at this time. I will now turn the call over to Robert Phaneuf for any closing remarks.

Thanks very much for all of you taking the time to join us this afternoon, and just one last housekeeping item. I am informed that the press release I referred to earlier with the correction did clear at 4:26 Eastern time, so it should all be out there if you haven't seen it. If you have any other questions or thoughts that you would like to share with us, please give us a call, we will be around. Our telephone number is 918-632-0674. Give us a call anytime you have a question. Thanks very much, bye bye.

Thanks, everyone.

Ladies and gentlemen, this concludes the presentation. You may now disconnect, and have a great day.