Ranger Oil Corp (ROCC) 2006 Q4 法說會逐字稿

Greetings, ladies and gentlemen, and welcome to the Penn Virginia fourth quarter and full-year 2006 conference call. [OPERATOR INSTRUCTIONS] It is now my pleasure to introduce your host, Mr. Jim Dearlove, Chief Executive Officer of Penn Virginia Corporation. Thank you, Mr. Dearlove, you may begin.

Thank you, operator. And good afternoon. I'm joined here in Radnor, we've got quite a cast with you -- with us today, but by Frank Pici, who is our CFO, and Baird Whitehead, who runs our oil and gas business, Ron Page, who runs our midstream business, Nancy Snyder, who is on our General Counsel as well as being on the Board of PVA and PVG, Jim Dean, who is our Investor Relations person, Steve Hartman, who is our Treasurer, and offline in Kingsport we have Keith Horton, who runs our coal business, as well as Forrest McNair, who is our Controller. So with nine or 10 of us here, if we can't answer your questions, we have a big problem. So we'll endeavor to do that. Again, welcome to all of you and let me just get started.

My typical approach to these things is to follow the form of the press release, but not read it to you. Again, you all can read for yourselves and the level of detail that's in there that would be too consuming. I'm more interested in hearing from you and trying to answer your questions. As you can see, though, from the release, 2006 was a very good year for Penn Virginia Corporation from a financial and operating and a strategic perspective. As discussed in the release for the year, net income was at a record level of $76 million, up almost 23% over '05 for the year, operating income at $170 million up a little bit over last year, and operating cash flow at $262 million, was up about 11% over last year. So we had a pretty good year in terms of at least those financial measures.

The operating income and cash flow numbers increases were due to a strong performance by PVR both the coal and the mid-stream piece, as well as the oil and gas segment, which showed an 14% increase in production volumes, however it was hampered in its financial performance somewhat by the fact that prices were much lower. They were about 12% lower than they were in '06 than they were in '05 for the whole year. And of course because we had increased volumes from gas, coal, and midstream, we had some increase in operating expenses and some increase in DD&A. The combined, as I said with regards to oil and gas, the combined effect of the lower prices and the higher production, the prices-- prices sort of won, and actually, coal's operating income was down a little bit for the year, but cash from operations was up slightly. Net income is a little different in interpreting that because it also includes the effects of derivatives, and for 2006, Penn Virginia had a significant gain on derivatives of almost $19.5 million versus a loss in '05 of almost $15. So clearly that helped to drive the good results on the net income side. As I said operating income and cash flow aren't influenced necessarily by derivatives, and that's the year. For the fourth quarter 2006, operating income, net income, and the various cash flow measures lagged 2005 a little bit, at least with regards to oil and gas and the culprit there was gas prices which for the quarter were 41% lower in the fourth quarter of '05 -- '06 rather -- than they were in '05, so even though we were hedged and somewhat protected we couldn't quite overcome that in terms of the fourth quarter. That, in my mind, however, does together take away from the market that we did have a pretty good year and the operating results in particular, the increases in volumes, I think, were significant.

Focusing on the oil and gas segment, though, for a moment. Again, I'll follow the release, but I'm going to slip over in to the February 7 operations release in some of the statistics I give you here, but proved reserves for the year, as you can read, were up significantly, almost 30% to 287 [Bs]. 94% of that is gas. 71% of that is PDPs and although the largest percentage of our proved reserves remains in Appalachia, at about 32%, what you are seeing is an evolution in the Company because 22% of our proved reserves are now in the Cotton Valley and about 11% are in the mid-continent where we had no presence at all in 2005. So you see, not a shifting in emphasis -- well, yes, I think you are, you are seeing some shifting in emphasis. Appalachia remains extremely important to us, but we are developing other areas as well. Production was up about 14% for the year, a little over 31 days in the fourth quarter. Production was up about 19% over what it was in the fourth quarter of '05, and both of those represent for us company records. The Cotton Valley, the Mississippi Selma Chalk, the South Louisiana Exploration program were all key contributors in 2006. Obviously the second quarter mid-continent acquisition helped. It was I think about 1.3 [B]s of production.

We had some delays in Appalachia that affected our horizontal CBM program, primarily those were due to water disposal issues which we're pretty confident are being resolved and will be resolved early in 2007. Again, referring more to this February 7 release for a minute. PVA spent $338 million on CapEx in-- for its oil and gas operations in 2006. Just in case you hadn't seen that release, $217 million on drilling, including $175 million on development drilling, where we were successful on 139 out of 141 net wells. We spent $42 million on exploration, where we were successful on 7.5, roughly out of 10.5 net wells. We spent $72 million basically on that midstream acquisition and another $28 million on leasehold. So as you can see, we-- again, we had a fairly aggressive year in terms of CapEx in 2006, and anticipate accelerating that in 2007.

In the segment information in the February 14 release, yesterday's release, 2006 oil and gas operating income was, as I said earlier, $84, almost $85 million, down a little bit from $95 million in 2005. Revenues were flat, slightly up, and the decline in natural gas prices was the culprit as far as operating results in terms of earnings went. Additional detail regarding expenses for the year and in the fourth quarter are in the release. I don't propose to read them to you with one exception. I would point out we did incur a non-cash $8.5 million impairment in 2006. It really was not an impairment, it was a series of fairly small impairments, one of them was significant at about $4 million, which was the result of a-- a missing an estimate in a one well field in South Louisiana in an operation called Bayou Carlin. As I said this call-- I didn't say, I'm saying now -- this call is really a review of 2006 as opposed to a look-forward for 2007. We did issue some information about our budget in-- earlier in-- I guess late in 2006, and we'll talk about guidance here in a minute for 2007. But I would just say we have a fairly ambitious program for PDOG in 2007, and what you see in it is an increased emphasis on the Cotton Valley and a continuation of our efforts to get the most we can out of Mississippi and the horizontal CBM while expanding in the midstream. So I'll leave it at that until we get to things like hedging and guidance, and I'm actually going to let Frank talk about those.

And let me talk for just a minute about the other contributor to the financial results at PVA, and that's of course our ownership in the various MLPs, and in particular for 2006 it was driven by PVR, as you know -- Penn Virginia Resource Partners. As you know, late in the year, December 5, 2006 we converted-- we meaning Penn Virginia Corporation, converted its ownership in PVR, which is its general partner, the incentive distribution rights, and its ownership in the MLP units which is roughly 40%, we took those things public. We sold about 18% of that to the public. We think that that will help the people on this call and others to better understand Penn Virginia, because it takes all of the guesswork out of the valuation that might be connected to our interests in the MLP because every day you all mark them to market for us, so you know what they are worth because we know what they are worth -- We know what they're worth worth and you know what they are worth and we can agree on it, I hope. Just for a moment there's two components to PVR, PVR, being again the underlying MLP, and everything that PVG owns is PVR, and all of the cash flows that come to PVG are generated at PVR. So PVR is really the key piece of this right now, and-- and for those of you who may not have been on a call a couple of hours ago where we talked about PVR, I'll give you a summary at least of how that's done.

The coal segment of PVR had a very good year. It reported record level of operating income at about $73.4 million, about 19% over 2005. Coal royalties are by far the main component of that, they came in at about $92 million, which is a record level, again, for them. That was driven by record level of production, and again, we are not the producer. We are the owner. We lease coal to others, and they produce it so it's a not our production, but it's our coal. And that came in at record levels this year, and that was largely driven -- the increase largely driven by acquisitions that we made in 2005, and also we made an acquisition or two in 2006, one of which had some effect. We also had higher royalty rates or realizations per ton if you want to say it that way. I caution people to not put a lot of emphasis on what the dollars per ton are. They are very much driven by the mix of where those tons come from. Most of our coal comes out of central Appalachia, the average price of the coal being produced off our properties there is over $50 a ton, even in this market. On the other hand we have coal in the Illinois basin and the average price of those tons are below, they are roughly $27 to $28 a ton. And there's different royalty rates. So as we ramped up production or our lessee's did in the Illinois basin, that number might change. I just caution you, because so many people seem to look at that number and think it's important. And it's important in an absolute sense in some respects, but it really isn't a measure of company performance. Sorry for that digression.

But anyway, as I said the royalties were up, and that was due to stronger coal prices and also production increases. Similar increases in production, operating income, cash flows, et cetera from PVR Coal were seen in the fourth quarter of '06 as compared to '05, and I'll refer you to this press release, as well as PVR's press release which came out yesterday to get all of that detail. Obviously when production goes up, there's some increase in expenses, particularly DD&A, that's likewise reflected in our numbers. I don't think there's anything out of line there that merits conversation. I'm happy to answer questions. With regards to the midstream component or segment of PVR, they also had a very good year. Part of the goodness of the year was we're comparing full-year results to 10-month results. Because as you may recall we bought the midstream business early last year. But a more important measure, then, might be, what are the inlet volumes on a daily basis, and those are up considerably for midstream both in the, for the year and the quarter ,and that's driven in part by a small acquisition, but an important one that we made in the second quarter of 2006, as well as a lot of success in just growing organically. Programs to stretch our footprint and expand our reach and an aggressive program to recruit new -- new people to put their gas into our system has begun to pay off, and you see it in the results of midstream. Again, I'm sparing you a lot of details of the specific numbers, but we break out for you in the [inaudible] both the quarter and the year segment information, so it's all there to see. Operating income, just to give you a few of those numbers for PVR Midstream, was $29.5 million [sic - see press release] or 80% higher than it was in 2005. That's what it was in 2006, and the gross processing margin, sort of a measure of the frac spread if you will, was at record levels for '06 so that along with the increased inlet volumes contributed to the results.

Inlet volumes in the fourth quarter were also a lot higher than they were in the corresponding quarter in '05, up almost 39%, and this again was driven by the acquisition-- by the bigger footprint, the same things that drove the yearly results. One of the things that you find this business is it is a commodity business. And while we're, although we've got some hedging in place, we are still subject to something called a frac spread, which is nothing more really than the difference in the relative prices of oil and gas. And in the fourth quarter of '06, the price of oil fell-- price of gas fell a little bit, but oil fell faster, and so if you were to compare '06 to '05's fourth quarter, you would see the frac spreads-- excuse me, the margins [inaudible], the margins if you will, the gross margins were $1.05 as opposed to $1.15. So they were down a little bit, but that was more than overcome by the increased volumes.

Turning for a minute then to PVG, which I touched on a second ago, but we launched this thing in December 5 of 2006, and as I said sold about 18% of it to the investment public in an IPO. It's performed fairly well. It came out at about $18.50-- not about-- it came out at $18.50 a unit. When I looked and it was an hour and a half ago we were at $21.92 today, we've traded as high as $23. I think if you compare us to the other GP hold cos that are out there we've performed very well.

I think an important aspect of PVG, if you own PVA or if you own PVR or if you own PVG is what we did with the proceeds. We generated roughly $120 million of proceeds. We took about $115 million of them and reinvested them in PVR, bought additional limited partnership units. PVR in turn was able to take those proceeds from selling the units to PVG and delever it's balance sheet, which makes it a more competitive MLP than it was prior to this IPO of PVG. To my knowledge, of the nine or so GP hold co's that are out there, we're the only ones that did this, most of the other ones-- and there's nothing wrong with what they did -- but they took the money into the GP and took it off of the table. We chose rather to reinvest it in the underlying MLP which we think shows a certain commitment to that MLP and I hope you'll see that commitment going forward. You know, just as an aside for those of you a little less familiar, the theory behind these public GPs is that because of the incentive distribution rights, or in English the right of the GP to share disproportionately in the cash distributed to all unit holders, anyways because of those IDRs as the underlying MLP, in our case PVR, grows its distributions the growth at the GP accelerates, because it gets that distribution, and then it also gets the IDR's on top of it. So at the end of the day what we're hoping is that PVR will go on as it has been for its five years of existence, being a grow the vehicle, and that growth will be amplified and accelerated at the PVA level due to its ownership in PVG. Maybe that's a little too much on that, but I wanted to make sure people understood it. And I might ask Frank Pici who is-- as I said our CFO and much smarter than I am, to discuss our hedging positions as well as to walk you through the guidance, so that if we doesn't work out, we know exactly who to blame.

Well, that's a stellar introduction. Thanks, Jim. Hi, everybody. This is Frank Pici. I'll run you quickly through our hedging positions and also guidance.

As far as the hedges go, on the oil and gas side we're about--based on our current production levels -- we're at right under, just under 50% hedged on our gas production. We do that in the form of cost as callers primarily. Those callers, if you take the full-year averages, are averaging about $8 floors and $12 ceilings at this point. So we think we have got a fair amount of protection out there for 2007. We're pretty much fully hedged as per our hedging policy for '07. As we go into '08, we are continuing to look at adding positions and even into perhaps into early '09 as well. When we look at our midstream hedging positions, in PVR midstream we are about, between 25% and 30% hedged on our assorted net NGL sale volumes and gas supply volumes. Those hedges are really remnants of the acquisition we made to get in to that business in early '05, and we haven't added much to them. We are in the process of evaluating that now, and are doing it on the basis of trying to hit a revenue protection target, if you will, and it's likely at this point that we will adding more positions to protect more cash flow at the PVR midstream level in '07 and probably into '08.

What we have done in the guidance with respect to the hedges that-- the natural gas hedging positions are pretty easy to evaluate. You just apply your view of gas prices and you can value those pretty easily. On the midstream hedging side we decided to give you a little bit more, little bit more help there, and we have added some wording in the back of the guidance table under those midstream hedges to give you a view on how much sensitivity there is to changing underlying gas prices when, and oil prices, when you consider our hedged positions in the PVR midstream revenue stream. So hopefully that will help you with your modeling and your evaluation of our hedging program.

Flipping back just for a second into the guidance table and yes, we provide an awful lot of detail here for you. And we feel that's helpful just because it cuts down on questions, number one, but it also with our different business segments, it gives you a way to kind of look at the main drivers for each area. Looking at oil and gas briefly, we said this in our operations release last week, we do expect production to go up significantly in '07 from '06. We have got a 16% to 23% growth indicator in our range of production volumes. That's being driven by our growth, primarily in our Cotton Valley play where we're being very aggressive on a development side. That's our biggest capital expenditures area in 2007 on a record capital budget by the way, also, so we think that's the biggest growth area we have got. We also think that our coal bed methane play in Appalachia will increase noticeably as we cure our water disposal issues there and are able to more aggressively develop those patterns up there. And we'll also have the other benefit we'll have in '07 versus '06 is a full year of contribution from the mid-continent play we got into last year, and we're aggressively growing that play especially in the Hartshorne coal CBM project as well. So that, those are the main drivers behind the production growth.

We do have some indicators for expenses as well. We-- the way we have provided guidance on direct expenses in the oil and gas segment, we have not-- we're not expecting a big reduction in operating expense. Hopefully, you know, once-- once the water disposal issues in the East are taken care of we'll get to a more steady run rate on that, but we didn't want to project anything going down at this point so we're being conservative there. Exploration is really just a function of the capital program and our risking of that capital program. Our DD&A rate we've got a range there of $1.85 to $2, I would expect that to be closer to the higher end of that range based on where we ended our fourth quarter rate at and where our capital costs have been. You can see the range on CapEx which we have given you previously in a previous release, but you can see that we have got a very heavy weighting towards development spending as has been our norm with a much larger overall budget here in '07 because of the opportunities we have got to drill, and we'll aggressively go after that. When you get into the coal segment, you can see in general, I guess I'd characterize the coal as somewhat flat guidance with 2006. You can see the coal royalty turns are pretty much on line with what they were in '06, the royalty rates are pretty similar. The expense segments haven't changed a whole lot. On the midstream side we do expect to have some growth, you can see some capital in there, which is the capital in that area, is primarily for expansion. In particular we are looking at building a new plant in our Beaver complex, in the panhandle of Texas, and also we're looking at the possibility of building a plant in East Texas as well to help service our corporate production there and under PVOG. So that's why the capital expenditures numbers are up a bit on the midstream side.

If you look at our G&A, our corporate G&A it is higher than it has been running. Our fourth quarter-- fourth quarter actuals were high. The biggest components of that were the, some compensation expenses we incurred as a result of bonus accruals, and also the PVG transaction, and also we are in the middle of a system conversion, a computer system conversion and we have had some expenses on that that we believe are well spent in order to improve our systems going forward to service all of our business segments, so, and they are-- they are expected to be one-time expenses. However, when you look at our guidance going forward, you can see that the run rates we have got in here are pretty similar to '06, plus we have got some additional expense in there for the fact of having a third public entity being PVG. So that's the additional G&A expense line you see there.

From a debt standpoint, we are predicting higher debt to fund the, to help fund the capital program that we've-- that we have budgeted. We have got plenty of debt capacity to do that if we choose to. We can also look at some other things if we choose to monetize some non-core assets and things like that if we want to do that. On the PVR side we have reduced our debt levels in this guidance and that's because of the proceeds PVR received in the sale of units back to PVG in that transaction. Remember that we don't, we don't forecast or guide acquisitions, so this could change as we go through the year, and if we actually make ac -- when we actually make acquisitions, we would probably fund them with debt to the extent possible out of PVR. We do have some debt capacity there as well. So, Jim, I think that's primarily what the guidance is all about.

Okay, thank you, Frank. I guess I just might elaborate on one thing Frank said. And that is, you know, you look at coal's guidance in particular, and it does appear-- and in fact it is-- it's flat. And what is going on here? And the key is 2006 was such a good year that we had a lot of people running flat out. Again our lessees in 2007 they, we're expecting some cutbacks due to prices in the higher price, higher cost operations may cut back a little bit. So what are you going to do about it? And while we can't be specific to that for the obvious reasons that, you know, the ink isn't dry on the paper yet, in the last two years, 2005 and 2006, we have made eight acquisitions in the coal business, not all of them huge, but many of them significant. We have made an acquisition of an entire midstream business, and an acquisition in it in 2006. So one, the business up 2005 another acquired another one in 2006 and have identified there a little more specifically capital projects that are more organically oriented. So, again, not to apologize or anything else, but just to underscore what Frank said, we do not budget acquisitions, but in PVR we surely make them. So I think these flatter numbers will reflect those acquisitions as the year unfolds. So with that, operator, I'm happy to try to answer any questions.

Thank you. Ladies and gentlemen, at this time, we'll be conducting a question and answer session. [OPERATOR INSTRUCTIONS] Our first question comes from the line of Scott Hanold with RBC Capital Markets.

Thanks, good afternoon.

Hey, Scott.

In the Cotton Valley, could you kind of talk about your guys' plan on your 100% owned acreage versus AMI. You have obviously talked about drilling, you know, one horizontal well and maybe half dozen other wells this year. You know, what can we expect there in the back half of the year in if things go well?

Baird, why don't you elaborate?

Scott we, we have six wells planned, six exploratory wells planned up in the 100% acreages this year. I would say if I had to guess now that's only going to increase. Because we actually recently gotten in to a development program onto the 100% acreage because of some encouragement we have seen. Now within the AMI with GMX, we have two horizontal wells planned. We're going to test this lower Bossier again. The first time because of some operational problems we had, the thing has just not performed, but we think it warrants another test, and we're going to do it differently this time and do it with a gentler rig versus with a five track operation.

We also have-- a horizontal well planned in the Taylor Sand, the lower part of the Cotton Valley. We'll probably get that kicked off, probably sometime early to mid-second quarter. Depending upon the results of the horizontal program, you know, things are going to shift probably over time, but we're going to want to get some production information under our belt before we make that commitment. We're very satisfied with the vertical well results. The only reason, of course to do the horizontal well is because of improved economics and improved flow rates, which causes those improved economics. But, you know, worst case the vertical wells are working just fine.

Just another bit of information, we are probably going to try to drill some 20-acre space wells this year. We have solicited railroad commission to down space from 40 acres down to 20 acres. We think we will obtain that approval. So we will do some of that testing also to see what kind of interference if any that we see between wells we we really think the kind of geographical complex that the Cotton Valley is, there's probably little chance to see any serious communication between wells, and it should result in primarily incremental reserves, but in a nutshell, that's a fairly high level summary of our program in the Cotton Valley this year.

Okay. And you indicated that, I'm sorry if there's some of that you have seen recent encouragement that makes you feel a little bit better. Can you give more specifics about that? And then sort of -- you know, if things go well in your 100%-owned acreage would you potentially be less active in the AMI and more active in the 100%-interest acreage towards the end of the year?

What we have seen in the 100% acreage so far is the lower part of the Cotton Valley does not appear to be as productive as the upper part of the Cotton Valley. We have made quite a bit of water in the lower part. The upper parts we're seeing high quality reservoir characteristics. It does make more water but also would cost less money to drill those wells. We have seen recently, we have to find an area of the 100% acreage whereas the lower part of the Cotton Valley worked, and we're offsetting that as we speak, so simultaneously we're going to continue to drill wells onto the upper part of the Cotton Valley, we initiated the program in the lower Cotton Valley. As far as trying to answer the question whether we would shift money from the AMI up to the 100% acreage, it's probably a little bit early to address that. I guess it would depend upon economics. We are very happy with what we are doing down in the AMI with GMX. We would see no reason to cut back there. And I would say subject to incremental dollars to do this, we would probably be more apt to expand our program than to keep it the same.

Thank you, guys.

Thank you.

Our next question comes from the line of Steve [Bremen] with Pritchard Capital Partners.

Good afternoon. I was wondering if you could-- and I'm mainly interested in the Cotton Valley discussion in terms of the proved reserve increase, the amount of PUDs you booked relative to the developed wells. Again, mainly for Cotton Valley but any of the other projects you want to talk about.

Well, as you would expect, with the resource play, and its early in its development, you know, as you continue to expand your sheer density of wells it gives you the opportunity to add PUDs, and, you know, that, we think that's the best way to do it. You might as well give the best information to the public as far as how you view your acreage. So we have roughly just north of 100 [Bs] in the East Texas Cotton Valley. We've got a lot of probables and possibles left in that acreage also that we have not booked, of course. And we'll continue to book those as we drill additional wells.

All right. But in terms of saying you-- you know, just two PUDs for every one PDP, you can't get into those kind of details right now?

Well, it depends on how we drill these. Typically you are just not just drilling PUDs throughout the year, you are sometimes drilling probables and possibles. And, you know, you may have, you may have four PUDs, if you have successful with a step-back probable or possible location. So it's sort of a mixed bag, really. It's not a standard rule as far as how many PUDs per PDP well you add, but it can be anywhere from one to four to be honest with you.

Okay. Thanks.

Our next question comes from the line of Dan Morrison with Aperion Group.

Thanks. Question on your mid-continent assets to Cow Creek. How does your acreage look for wood, for potential as far as some of the recent development that's going on up in that area?

Dan, in most cases, when we bought Crow Creek, the Woodford had already been severed. Having said that, you know, we -- we are leasing Woodford acreage as we speak. I prefer not to disclose where that is at that point in time. We have got quite a bit of money earmarked for that effort this year, we've got a couple of different geological areas in which we're focusing on and to date we have acquired roughly 2,000 acres in that play type. Most of the stuff we do in our Crow Creek is either horizontal [inaudible] wells in the Hartshorne, which by the way we have been very successful at and we're very pleased with the results of those wells. Or the Granite Wash over in Washita, Oklahoma.

You all had been leasing some over on the Fayetteville Shale side of that trend. Could you give an update on how much you've accumulated there?

We've got almost 14,000 acres as we speak. We've drilled -- we have drilled two wells. We are laying pipelines to those two wells we have deferred to completion until the lines are laid-- the lines are almost laid. In fact we just initiated completion on one of those two wells here in the last few days. Our plan is to have a development rig come in to the area probably early second quarter time frame. We have got some money earmarked for development wells. We're pleased with what we have seen so far. We think we're seeing the right things to -- at least based on the industry and their success, we think we have the right -- the right characteristics as far as thickness and organic content and some of those other things that make this tick. So at this point in time we're encouraged, but until we get some of these wells on line and see how they do, you just never know. But we are encouraged at this time.

Thanks.

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

Hey, guys. You know, another question, would you guys be willing to talk about what your year-end '06 SEC pre-tax PV 10 number was?

It will be in our 10-K filing.

The pre-tax number?

Yes, I mean-- we do-- we generally give after-tax that's true, but--

It's about $800 million.

$800 million. Okay. And one other question. Frank, you kind of mentioned monetized -- mone -- potentially monetizing non-core assets and sort of looking at your guy's footprint it is fairly diverse. You know, can you kind of give us your thought process on assets you may potentially think about monetizing?

Well, if anything I doubt that there's much in the way of operated assets that we would consider. I shouldn't speak for Baird, I don't mean to, but when I said that I think it, a more likely candidate might be we own some royalty gas in Appalachia that we would not consider to be really a core asset. It does provide a nice-- nice reserve bump for us. It obviously has no LOE on it, so it's a nice piece of business to have in your oil and gas portfolio, but it's not something we generally add a lot of valuable from. So we would consider maybe, if we were going to consider something, we would probably consider something like that.

Okay. But nothing like on, like acreage sort of if we look up in the Williston Basin it looks like activities projected in '07 tended to be a little less. What are your thoughts up there?

Yes. We have -- we have said that the play we were in there, and Baird can help me with Barrett, I think, Baird?

Yes, the red water red bank we drilled three wells between late '05 and '06, which were all plugged. Since Bill Barrett is divesting in those, there sort of will us in position. One of the reasons we got in there is because of Bill Barrett's expertise, maybe it makes sense for us to go ahead and try to, to dove tail their divesture in those acreages and ours at the same time. We still have roughly 40,000 gross acres 20,000 net down in Dunn County with a private company that we plan on drilling a couple of wells in this year. I didn't really talk about it. We would be drilling horizontally in the [Black and Double Night]. We have not given up on that play. We still think it's a viable play. We're just going to go ahead and refocus it down this one area, and we will be the operator on that stuff.

Okay. Thanks again.

Thank you.

[OPERATOR INSTRUCTIONS] Gentlemen I'm showing no questions in the queue at this time. Do you have any additional remarks?

Nothing, operator, other than, again, to all of you on the call, we appreciate your interest, and we hope we have given you an informative look at what went on in 2006, and a little bit of a-- the best we can tell you, what is coming in 2007. So we look forward to talking to you again next quarter and hopefully we'll see some of you on the road as we get around. Thank you very much.

This concludes today's teleconference. Thank you for your participation.