Ladies and gentlemen, welcome to the fourth quarter 2008 Brigham Exploration Company earnings conference call. My name is Tanya and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator instructions) I would now like to turn the presentation over to your host for today’s call, Mr. Bud Brigham, Chairman, President and CEO. Mr. Brigham, please proceed.

Thank you, Tanya. Thanks to each of you for participating in Brigham Exploration Company’s year-end 2008 conference call. With me today, we have Gene Shepherd, our Chief Financial Officer and Executive Vice President; Lance Langford, Executive Vice President of Operations; Jeff Larson, our Executive Vice President of Exploration; and Rob Roosa, our Finance Manager. Importantly, before we get started, I would like to encourage you to be prepared such that during the course of this call you can view our conference call presentation, which can be accessed via our website at www.bexp3d.com. It includes very helpful information regarding our 2008 results as well as our plans for 2009. We will be referring to the slides in the presentation during our discussion. Now, during the call we are going to make some forward-looking statements to help you understand our company’s results. In our company’s SEC filings and the press releases that were issued yesterday there are some risk factors that should be noted that might cause our actual results to differ from what we talk about today or from our projections. I encourage you to review our filings with the SEC. In addition, in this call we will use some – the terms probable and possible reserves and locations, which are unproved reserves that we do not include in our SEC filings. Please refer to page two of our corporate presentation for a cautionary note to US investors regarding the use of the terms probable and possible reserves and locations. Finally, a copy of our company’s press releases as well as other financial and statistical information about the periods to be presented in the conference call will be available on the company’s website under the section entitled Investor Relations at www.bexp3d.com. Now let’s get started. If you go to slide number…

Thanks, Bud. Before we get into a discussion of our fourth quarter and full year 2008 results, several comments about the company’s current liquidity position and the steps we are taking to ensure that the company has sufficient financial flexibility to navigate through the current economic downturn. To set the stage, at year-end 2008, we had $40 million of cash on the balance sheet. Point number one, during the fourth quarter 2008 we began to scale back operationally given the mismatch between declining commodity prices and the elevated level of drilling and completion costs. After completing the drilling and completion operations on several fourth quarter wells in January and the first two weeks of February, we laid down our two Williston Basin rigs and have positioned the company to live within cash flow for the remainder of 2009. See slide number 40 for a brief overview of our currently planned 2009 E&D CapEx budget. Point number two, after incurring the majority of yesterday’s announced 2009 E&D CapEx budget during the first two months of 2009, as of March 10, we had $33.3 million of cash on the balance sheet. Point number three, slide number 41 lists several transactions that we have initiated in the fourth quarter 2008 and we are striving to complete in the next several months, which should further enhance the company’s near-term liquidity position. They are the pending sale of our Mountrail County mineral acreage and other Williston Basin acreage in seismic, which should close by the end of March and bring $7.2 million into the company. Secondly, the potential sale of our non-operated Mountrail County acreage in the Parshall / Austin / Sanish Fields consisting of 7,715 net acres and, based on Randall & Dewey’s estimate, 19 million BOE of net Bakken reserve potential. Given its…

That concludes our call. I’d like to thank you all for your participation. And with that, we would be very happy to answer any questions you may have.

(Operator instructions) And your first question will come from the line of Scott Hanold with RBC Markets. Please proceed. Scott Hanold – RBC Markets: Thanks. Good morning.

Good morning. Scott Hanold – RBC Markets: Bud or Gene, can you talk a little about the revolver? I know you drew it down at the end of the year, but when is the redetermination period on that and what do you all expect? Because – is there a chance that the revolver gets reduced and you got to pay some of the cash back to it – to the banks?

Well, we deliver a report to BofA on April the 1st and then they come back to us at the end of that month or early May. That calculation, we do get the benefit of any additional wells that were hooked up to production since the end of the year. So it’s a 12/31 report, but to the extent that we have moved additional wells into the PDP category we get the benefit for that. For example, at the end of the year we didn’t have either of the two of our Southern Louisiana wells up to production. One got hooked up in January. One got hooked up in March – or will get hooked up later this month. So those two will get moved to the PDP and will get the benefit for those in this April 1 report that we deliver. But –

We have another Gulf Coast that’s getting down too that also could be in that report as well.

So I mean – the steps that I think to just review, the reduced level of activity in response to really the mismatch between commodity prices and service costs that we laid our rigs, as a consequence, going forward we are generating free cash flow. And as of – as I said, as of March 10, we had roughly $33 million of cash on the balance sheet. We will close these two transactions this month. And that should add roughly an additional $7.2 million of cash. And then we’ve got the other Williston Basin transactions that are on under way. So I think we feel good about our ability to get through the downturn that we are currently experiencing, including – obviously the borrowing base would be part of that. So I think we feel very good. Scott Hanold – RBC Markets: Okay. But it seems to me the borrowing base, there is a pretty good chance that things are going to be brought down a bit when it does get redetermined. Is that a fair statement?

Yes, I mean that’s – that's up to – it would be up to BofA to determine that. And obviously commodity prices have gotten lower since the last redetermination that works against us. We will get the benefit of some of these additional wells that have come on since the end of the year and had that hopefully no question should offset some of that price impact. Scott Hanold – RBC Markets: Okay. Well, I guess what I’m trying to get at is, I mean, have you stressed test what you think could happen to the revolver that – to become –?

Yes, we’ve run lots of scenarios and have done a lot of analysis. And so I think we have looked at the issue very carefully. Scott Hanold – RBC Markets: Okay. And so based on what you see and your outlook at this point in time, you believe you can have the opportunity to ramp things up in the back half of the year given that service costs to improve and commodity prices look a little better?

Sure. That's a function of these transactions and commodity prices and services costs. So – I mean, that’s a big part of the reason why we are taking these steps on these two larger opportunities in the Williston. All the transactions that we have listed are Bakken transactions. The A&D markets are shut down, but we were getting calls in November and December about our position in the Williston. I mean, it’s a very attractive currency to have. And so –

Scott Hanold – RBC Markets: No – understand and I appreciate it. I’m just trying to get a sense of – you know, let’s say the macro doesn’t improve here until the back half of ’10 and let’s say those transactions don’t close as you expect, which obviously in this market could happen. When you look at your acreage, how much drilling do you have to do on that to hold some of it? What’s the risk here? Obviously activity you couldn't really ramp it up in that case and so we’ll see the production continue to slide off. In looking at that scenario, I mean, how much of your acreage could you lose over the next couple of years if you can’t drill, specifically obviously focused at the Bakken?

Scott, before Bud answers that question, obviously – the steps that we have taken are the significant ones. Obviously there are other steps that we’ve taken. We’ve talked about G&A, the hedge position that we continue to build out. We added some – oil prices spiked up on Tuesday – Monday or Tuesday, and we added roughly – we hedged roughly 10,000 barrels a month from April through December at a swap price of $50.75. So there are other steps that we haven’t talked about that I think mitigate risk. And the combination of those gives us sort of the sense that we are in good shape although obviously markets differ, but we feel like we feel confident.

Yes. And Scott, to answer the other part of your question is that we are very fortunate. Most of our acreage – we have 308,000 acreage, huge position, and most of it was acquired in the last year and a half. Most of it is either five-year leases or three years with a two-year kicker. We don’t have any more significant obligatory wells that we have to get out and drill to preserve acreage. So – I mean, we are in relatively a very, very good position with that asset in the field and we can afford to be patient. Scott Hanold – RBC Markets: Okay. And one last question and I will let somebody else get on here. But looking at Rough Rider, it seems like you are pretty excited about the potential to put some pretty large number of stages on these completions and get very nice productive oils like you saw in the Olson. I guess – give me a sense of how you think the repeatability of this could be? And really outside of the Olson, are there any other analogies we can draw from wells drilled in that area? And could that be an area you really focus on when you are able to ramp up your activity again?

Yes, a couple things and then Jeff will probably want to add to it. When you look at that area west of the Nesson, obviously we don’t have the number of horizontal Bakken completions we have in Mountrail. And Mountrail, you have probably 160 Bakken completions that we have some history on. That being said, Rough Rider where we have 105,000 net acres, we have – first, we have the four wells completed, east or west, 15 miles apart across our 105,000 net acres that were all single uncontrolled fracs. And you can see it when we show the production profile. Those wells performed almost identically. It’s pretty remarkable. They all came out about 200 barrels a day and leveled out at 50 to 90. And it shows we were successful in our effort to decline that acreage over the areas that have – as we talked about, the good Middle Bakken (inaudible) porosity. We are seeing comparable performance in the area. And then moving to the multi-stage stimulations, we have the Mrachek on the south end with seven stages and we’ve got the Olson on the north end with 20 stages again, high deliverability in the Mrachek. We probably damaged, but it’s still a good well despite that. So there is a couple of – there are operators’ wells. I mean, in addition to our single uncontrolled fracs, there were two (inaudible) uncontrolled fracs across our acreage. They are identical to those other in production performance to our wells to two of the uncontrolled fracs. And then now there are several, which were not – we don’t have specific information to provide on the call, but there are several new multi-stage completions in the area that are confirming what we are seeing with our multi-stage completions. So we don’t have the number of wells that we have in Mountrail County, but that wells we have are scattered geographically across our area and they are all providing encouragement that it is a Tier 1 area. So I would say there is a good probability that there will be – one, we’ve got our figure over there, which is one of the three wells that our operations guys did a great job of successfully running the 19 swell packers and a long lateral. And that well is just waiting to be frac-ed, and once it gets warmer, we will be up frac-ing that well. But I think there is a good probability that later in the year that scenario – Rough Rider, we will be drilling some more wells. Jeff has got something else to add.

Yes, Scott, maybe just couple words on the rocks. I mean, in the Rough Rider Area, we’ve actually got some very good control points from the historic vertical wells that have been drilled in the area for the Red River deeper objectives. And we optimized the leasing of our acreage in Rough Rider on this Middle Bakken porosity membrane. We really like the looks of it on our acreage. It’s well developed. It’s continuous. You can map it basically on both sides of the river. And then we have confirmed that. When we drilled our Olson well, we drilled a vertical post hole and we actually cored the Olson well through the Middle Bakken, Lower Bakken and upper Three Forks. We’ve got a real nice rock, you know, actual physical rock tied to our log data point. And that confirms what we are seeing in the Middle Bakken that’s real attractive. And we’ve also got excellent oil standing in the Three Forks levels [ph], which has got us excited.

Yes. Scott, I might say one more thing about the early part of your question on bringing in partners in areas. It’s an environment that none of us have seen in our last time as far as the economy (inaudible). But on the other hand, this company has been around for 18 years now, and we’ve had 18 years of we’ve been selling interest in projects and leverage in our assets in the field successfully. And really you go back to our roots, that's how we were built because we were more capital constraint then and we were very dependent – much more dependent on that at that time. I can tell you that this is an asset that we think it’s one of the top resource plays domestically, and thus we are seeing a lot of interest. We have a high degree of confidence. We are going to have some partners, good partners in various parts of this play. And we don’t know when and who that’s going to be or how big each transaction will be, but there is no question on our mind we are going to have some good partners to help us develop this acreage. Scott Hanold – RBC Markets: Okay. Appreciate that. Thanks.

Yes, thank you.

And your next question will come from the line of Joe Allman with JP Morgan. Please proceed. Joe Allman – JP Morgan: Thank you. Good morning, everybody.

Good morning. Joe Allman – JP Morgan: Hey, Gene, question for you here on the covenants for your bank debt and for your notes. Could you talk about what the covenants are and what do you think happens to some of the more restricted covenants if actually you don’t get to sell any incremental assets beyond that 7.2 million, which seems done deal?

Yes. The covenants in the senior notes are incurrence covenants. So it’s not – doesn't really create any real issues for the company. The bank covenants, we’ve got a current ratio test, which certainly we feel – our cash on the balance sheet in generating positive cash flow in the transactions we feel good about, the fixed charge coverage ratio, we’ve got to maintain a fixed charge coverage ratio. It’s essentially EBITDA to our income statement interest, which is GAAP interest. It’s not total cash interest expense. It’s the interest expense that flows through the income statement. So to the extent we are capitalizing a portion of that interest, that’s not captured in that calculation. So – and then as far as the EBITDA, the numerator, we get to recognize the gain from, say for example, this asset sale is roughly in the neighborhood of $2 million. So we’re paying leaving six on the mineral sale and our basis is four. So that flows through that calculation and we get the benefit for it. We have modeled them. We’ve looked at them. We stress test them. Obviously it’s a difficult environment, but we feel good with the steps that we are taking to get through the year. And obviously the mineral sale will help. These additional wells that we are bringing, that’s helped and will help, but that’s probably all that we are in a position to say currently. Joe Allman – JP Morgan: Okay. So I mean, if you don’t get to sell the additional assets, it could be a little touch-and-go, but if you do, it certainly helps out the situation. Is that accurate?

Yes. I mean, I think the covenants are – the covenants, we’ve done the calculations. As you have the higher price months roll off last year, it becomes – that hurts. Working to our benefit is a set of the wells that we are bringing on in the transactions that we are working on. But –

Wells we are completing in.

Yes. So it’s – obviously we’ve looked at all those issues. We are taking the whole series of steps that we’ve outlined, the hedging, the G&A reduction, in an effort to get through the year. And obviously we wouldn’t want to be in a position we have to count on some external transaction where we are not in control. Obviously to the extent we are trying to get one of those other transactions done, we can’t pull the trigger for somebody. If they want to come in and buy some of our Williston Basin acreage, that’s up to them. So we feel like we are taking steps that we feel like we have control and we can execute on to allow the company to get through this difficult period. Joe Allman – JP Morgan: Got you. And then in terms of the non-operated Bakken properties that you are marketing, what is the production from those properties? And what do you think is the timetable to get that assets sale done?

I think bids are due – you're talking about the non-operated –? Joe Allman – JP Morgan: Yes, the (inaudible).

Bids are due at the end of the month, and we are sort of targeting an end-of-May close. And the feedback we are getting from Randall & Dewey is there is a lot of interest and it’s – so we are optimistic about getting the transaction done when it’s going to come down to valuation. And so – but just based on the number of inquiries and the data room visits, it is a great area. That package for us isn’t just strategic. I think we learned a lot initially from the initial farm-out that we did with Northern Oil and Gas. It sort of gave us some insights that we didn’t have at that time and allowed us to put our acreage position together. We’ve learned that. We got that information. It’s non-operated. It’s not – from a size standpoint, it’s not a huge portion of our acreage. And then probably it’s been so heavily drilled up maybe not as much optionality certainly that exists on other places – other portions of our acreage where we haven’t been as active with the drill bit. So it’s just – I think it’s a good transaction for us to do. It’s not horribly strategic. We can get something done and get it done on a timely basis. And it certainly helps the company on a number of fronts.

We can forward you the flier if that would be helpful to you, too. Joe Allman – JP Morgan: Okay, that would be great. And then what’s the production from there?

Jeff is running to get that. We don’t have that out of the top of our head. We’ll have that for you here in a minute. Joe Allman – JP Morgan: Okay, great. And just another one quick – revisions, could you break out the revisions, proved developed versus PUDs on the reserves?

Sure. Lance is looking that up for you.

For the year – Joe, you asked about production. As of January, it was 477 barrels a day for that non-operated package. Joe Allman – JP Morgan: Okay.

That was barrels of oil equivalent per day. Joe Allman – JP Morgan: So, just on that, Gene, or Bud, your Williston Basin production overwhelmingly is coming from operated properties then?

Yes, you bet. We had over 2,000 barrels a day. I think it’s like – something like that 2,200 barrels a day or something. Joe Allman – JP Morgan: Got you.

Yes. I mean, if you look at our Olson that’s come on line, that’s – that's 100% in Olson – working interest? Yes, 100% in Olson. I mean, that’s a big well for us. It’s on line producing so strongly. And then the cost up in the Adix – second half of the year wells, that’s the break in our oil production. We got the additional wells that we will be completing during the course of the year, Joe, that will also provide production as we move through the year. Joe Allman – JP Morgan: I can just wait, and catch that other offline.

Okay.

The revisions, it is about 50/50, Joe. It’s a little more on the PUDs than the proved developed. Joe Allman – JP Morgan: Okay, got you. And was that mostly PUD, that was just PUDs you just couldn't book at all or was it PUD tails or –?

Yes, it was PUD tails. It was a little bit of both. But when you run year-end prices last year for this reserve report, you gain back that entire revision. Joe Allman – JP Morgan: Got you. Okay. All right, very helpful. Thank you.

You’re welcome, Joe. I’ll just mention – the three of the wells that I mentioned that we will be completing during the course of the year, we’re just waiting for costs to come down and warmer weather, or high equity wells, you know, the Figaro with the 20 frac stages, 90% working interest; the Stroebeck, which will also have 20 frac stages, is 80% working interest; and the Anderson that will also have 20 frac stages is at 62% working interest. Joe Allman – JP Morgan: Okay, very helpful. Thank you.

You’re welcome.

And your next question will come from the line of Ron Mills with Johnson Rice. Please proceed. Ron Mills – Johnson Rice: Good morning. Just as it relates to the joint venture that – or venture activities that you're thinking about, in what form or fashion do you all – are you trying – is it trying to be one big joint venture, or are you looking at several potential ventures or taking all comers as the case may be?

No, we’ve had – Ron, this is Bud. I’ll take the first shot at that. We’ve had a couple of primarily proposals from parties that have been just buying in at a price per acre, which is obviously preferred from our perspective for a number of reasons, including given that at some – once they bought in we're on a head's up aligned basis and moving forward together. So I think that that’s the most likely. We have had one party that proposed both buying in on a promoted cost per acre and then also carrying us on wells, which we are considering those proposals as well, but it’s not our preferred proposal. These cases are on the joint venturing or acreage participation, non-proven participation in our acreage in a play. Again, as we said on the call, Ron, and as you know, given how much acreage we have, if we sell down, as I said, 25,000 to even on 125,000, sell 50% working interest to somebody, we are still going to have over 225,000 net acres, just a huge position for our company our size. Ron Mills – Johnson Rice: Okay. And then from oil production standpoint, you talked about what the production was in the assets for sale. But can you break your oil production down by Williston Basin and Gulf Coast?

Ron, we do have that one slide that shows the Williston oil production. So you can look at that and – because I don’t have it out of top of my head, maybe these guys do. But you can look at that slide and then look at the – the far slide shows our net oil production. And you can take a lot off of those slides. Ron Mills – Johnson Rice: Okay. And then from – Gene, it sounded like you added some recent hedges. Can you give a quick summary of what your current hedge position is?

Yes. We have – let me just quote you some equivalent volumes. We have – we've got roughly – we've got about six – it’s like about six Bs – excuse me. We’ve got close to five Bs hedged for 2009. That would be roughly 1.4 Bs in the first quarter, 1.4 Bs in the second quarter, 1.1 Bs in the third quarter, and then 0.8 Bs in the fourth quarter. We are pretty heavily hedged on the gas. There's really not a lot of additional volumes to hedge on the gas side. Part of the trade that we did earlier this week, we did some swaps and added some pretty nominal volumes in the fourth quarter, and so that really gave us sort of maxed out on the gas side. We haven't been very heavily hedged on the oil size. As a matter of fact, before Monday or Tuesday – my days are running together. But we had hedge volumes through June and then we had no over-hedges beyond that. And so we did a very major transaction that I outlined where we added ten contracts a month from April through December, 10,000 barrels a month and swapped that at 50.75. So obviously we’d rather – we're not enamored with doing those types of trades, but we feel that certainly doing those transactions in ’09 when obviously we want to have as much protection as possible that it makes sense. We’re looking for spikes in the market, and certainly we’ve got a nice spike on Tuesday. And we look for other similar opportunities to add to that hedge position, probably more so on the oil side. As we add this other Southern Louisiana discovery in March –

And possibly the Texas Gulf Coast.

And the Texas Gulf Coast discovery that Bud referenced earlier that will give us more gas volumes to hedge. We’ll just have to evaluate it at that time where gas prices are, and obviously it’s been a pretty weak market. So we are glad that we – other than the small volumes we did on Tuesday that our hedge position on the gas side was largely in place, as reflected in that weighted floor price that I referenced of $6.73. Ron Mills – Johnson Rice: Okay. And Bud, on the well cost, your long laterals look like they have gone from the mid-nines to the mid-sixes, and the short laterals from plus or minus six down to upper fours. Of those cost savings so far, can you try to break those down in terms of well cost versus complete drilling costs versus completion costs, and where you think the incremental 10% to 15% can continue to come from?

Ron, this is Lance. Yes, those costs – basically what we are doing on all those costs, and they are coming across the board, of course, our AFEs are heavily weighted towards the completion side. So over 50% – I think it’s in the 60% range or 60-something percent range is completion dollars. But what we’ve been doing every month to month-and-a-half, we’ll go out and rebid all of our products and services to multiple services companies, and they are routinely going down. This last time just the stimulation portion went down $0.5 million in a month and a half. But they are coming down across the board. My group is – we are meeting and talking about how to not only push down our capital, but push down our LOE in all facets of our expenses. I know that doesn’t exactly answer your question, but I think those continued costs are going to continue to come down on the rig and on the drilling side and on the completion side.

You know, 5.22, that’s all put together, we think at mid-year that short lateral goes from maybe 4.8 million today to maybe in the 4.2 million range that’s our goal for the short laterals. And then the long lateral goes from 6.5 million today, which is down from 9.5 million last year, it goes from 6.5 million maybe down to 5.8 million or so. Ron Mills – Johnson Rice: Okay. Thank you, guys.

Thank you.

And your next question will come from the line of Mike Scialla with Thomas Weisel Partners. Please proceed. Mike Scialla – Thomas Weisel Partners: Good morning, guys.

Good morning. Mike Scialla – Thomas Weisel Partners: If I’m understanding you right, it sounds like restarting your Bakken drilling is really contingent on the sale or is there a combination of oil price and cost reduction that would trigger that as well?

Gene might want to add to what I say here. All these steps that we’ve taken here are just to position ourselves given the uncertain environment. So we have maximum flexibility. And so it can be a combination of things positioning ourselves to resume drilling in a meaningful way, and prices improving to do it. But I think it’s very likely that we will be leveraging our assets. And that’s something we’ve done every year of our company’s history and with a lot of success. And of course we’ve had an environment as difficult as this, but on the other hand, outweighing that is we've never had an asset as leverageable as this one. And so I think we’ll get help in a lot of different areas in our initiatives underway that will put us in a position. We have a high degree of confidence to be able to pick up the drilling at mid-year. So the answer is, any of those above will help, but we think the likely outcome is that’s going to be a combination of those that’s going to put us in a position to aggressively ramp up during the second half of the year.

I don’t want to mislead and misrepresent. I mean, clearly there is the scenario where higher commodity prices and declining service costs put us in a position to get back to work in the Williston Basin. So I might have overstated that in my comments earlier. We’ve got so many different initiatives that we’re working at to sort of underpin the company’s liquidity position. And we are excited to get these two smaller transactions closed in March. I think what we are trying to do is create optionality on enhancing the company’s liquidity. And we’ve got all these different initiatives working sort of in parallel. Certainly we don’t have to have all of them come to fruition to create the kind of environment or we could – certainly one would be in a position to get back to work in the Williston Basin in the second half of the year. Mike Scialla – Thomas Weisel Partners: Sure. Okay. And then did you run any sensitivities on your pretax PV10 with any higher oil price cases?

Yes, we should add – and it’s pretty remarkable when you run it. I think that’s one of the things – and Lance, I don’t know if you have that in here with you. But we’ve got probably more optionality on that. I can imagine there are many companies that are trying to have optionality on that. In fact, we were putting [ph] together, potentially have it as a slide and maybe that’s something we will incorporate in there. So we have run it and it’s very meaningful. And I’m sorry we don’t have it right in front. Gene has it. I’ll let him say.

Yes. The SEC case, obviously PV10 of 288 based on a strip case that we ran on 128 produced 421.

From 288 to 421 going from SEC to the strip. Mike Scialla – Thomas Weisel Partners: And what was the strip oil price at 128?

I’m looking at the gas prices, I think it’s – oil prices – you know, there was – I can’t tell you what the strip. Unfortunately I don’t have it, but – Mike Scialla – Thomas Weisel Partners: Okay. Well, you can [ph] get that. That’s no problem.

It was a strip case on the 28th of January. It looks like it does up to $68, but that’s net of differentials. So there is a positive and negative differentials that usually flow through on a well-by-well basis.

You know, the first year average gas price was – but you’re seeing these are netting the differentials.

Right. So it goes up to $68.

You are saying that –

In the out-month – out-year.

Out-year. So it’s not on –

It starts off at 44, 54, 58, 60.

Those are years –

Those are the first years, yes.

Yes, the 44 in 2008 and – what do you say –?

If you can get that, probably the most efficient thing to do would be just to get the strip for 128. I’m sorry we don’t have that. Mike Scialla – Thomas Weisel Partners: No, that’s no problem. Thanks, that’s helpful. And then can you give your latest thoughts on the Middle Bakken and the Three Forks as to whether or not there are separate reservoirs? And have you seen any testing or done any yourself to determine that?

Well, I mean, I think companies are getting asked that less, I think, and we've heard other operators say like down there in Dunn County, I don’t think they are competing for reserves in the Bakken and the Three Forks. And they are actually drilling a well down there to confirm that where they will have a lateral in the Bakken above the lateral in the Three Forks. Clearly if they are not competing down there, we are not in Mountrail County because the separation is roughly double where a Ross Area – the separation between the laterals in the Middle Bakken and the laterals in the Three Forks. And importantly, the Bakken – and that’s about a 100 feet of separation there in Mountrail County. And importantly, also the Lower Bakken Shale is that it’s thickest there in the Ross Area in the western Mountrail County, in the Ross Area were the thickest Lower Bakken Shale. And there is a pinch point there Lance can talk about. Why don’t you go ahead and mention that.

Yes. This is Lance. There is a couple of things. One is that on the only Three Forks well that we’ve completed well within a mile-and-a-half of the Carkuff. And the way those wells stimulated, they are both of course –, one is 11 stage and one is a 12 stage frac. And the way they stimulated the pressures and rates required and the fluids required to actually stimulate and were completely different. So it’s not a definite that there is no communication, but it sure appears to be that you stimulate in completely different intervals. So – and that’s been consistent with what we’ve heard from other operators. Also there is a pinch point in the shale between the Three Forks and the Bakken that we’ve done with Schlumberger doing some rock property studies and some modeling. And I think that’s the problem why they are not communicating. And I will look at it as a problem because we have to drill two wells where if we could properly stimulate those zones, we could get double the reserves or hopefully double the reserves. So right now there is a pinch point in the Lower Bakken between the Middle Bakken and the Three Forks that’s going to pinch off any kind of conductivity of a frac wing. So I think that’s something that we are going to have to try and figure out as an industry in the future.

There is going to be more opportunity to the west as you get – or down in Dunn County or further to the west in our Rough Rider Area, roughly the separation between the Middle Bakken laterals and the Three Forks laterals is then or there than it is [ph] in Western Mountrail is about 65 feet over there relative to the 100 feet in Western Mountrail with less shale. So there is more opportunity there, as Lance was saying, potentially for the industry to figure out how to frac and that’s going to get both reservoirs with one lateral. Mike Scialla – Thomas Weisel Partners: Okay, great. And then just last question from me. I understand your reluctance to give full year production guidance. Just wondered if you can give us an annual decline rate on your base production right now?

This is Lance. And I was looking at that today, but basically it’s in the 30% range in there. There is variability, because you can’t really tell just looking at the base production, because we always have pump changes and fall recompletions and asset [ph] jobs that increase production that you don’t show in our particular production forecast that we put out.

Yes. But it really is a function of – you have to look back and see what wells have you brought on recently because obviously those wells are going to see higher decline rates. To the extent we are not spending capital further out in the years, we would expect to see that decline rate arrest. So –

Yes, plus you would be doing more work-overs in other things that will have arrested as well. Mike Scialla – Thomas Weisel Partners: So, maybe 30-ish percent for a quarter or so and then flatten out a little bit over the course of the year?

Certainly we would expect to see that – moderate.

One thing on the full year guidance, I mean, our expectation – we put out a budget and we're being very conservative in managing the business in that cycle, I think as we should be, but our expectations are we are going to be spending – in the second half year, we are going to be investing capital drilling wells and that’s going to impact our late year production and will be back to ramping up our production more significantly at that point in time. So I think as we move through the year and we get more visibility on that and those expectations, we will likely be updating the budget. Mike Scialla – Thomas Weisel Partners: Appreciate it. Thank you.

Yes, thank you.

And your next question will come from the line of Steve Berman with Pritchard Capital Partners. Please proceed. Steve Berman – Pritchard Capital Partners: Hi, good morning. Another non-op question as it relates to the Parshall / Austin / Sanish stuff you have for sale. EOG had shut in some wells there because I guess of the high differentials waiting on a pipeline. I assume that might be impacting you a little bit late, maybe that 477 barrel a day number you gave before might be understated. Is there any connection there?

This is Lance. The 477 was in January, and I can’t remember when exactly EOG did their shut-ins. I was thinking it was in February as a reduction in production. But the way we are modeling our EOG wells in the production forecast, we are taking a – they are shutting in 60% of their – choking their production back 60%. And so we’ve put a wait factor reducing our production on all the EOG wells 60% in our production guidance numbers that we’ve provided.

But you do raise a good point that in our first quarter guidance, that’s incorporated in our guidance. So it is – you raised a good point. It’s somewhat curtailed by EOG in that instance. And once obviously those wells are either be ramped back up at some point or at least they will have a flatter profile than they otherwise would.

This is Lance. Jeff just pulled out the press release, and Whiting announced – I'm sorry. EOG announced that on February 5 that they were reducing their production. Steve Berman – Pritchard Capital Partners: Do you have a February production number for that acreage relative to the 477 in January?

No, I don’t have it in front of me.

But do you say 60% maybe or (inaudible) are all those wells –

Well, there is more than EOG in here. EOG is just a portion of that 477. And my guess is a quarter to half of that number is EOG probably.

So maybe that’s a 20% reduction from that number because of the curtailment. Steve Berman – Pritchard Capital Partners: And that 19 million barrel equivalent number you cited before, is that kind of a 3P number?

That’s Randall & Dewey came up with potential there about 19 million barrels.

Yes, that is a 3P number. Steve Berman – Pritchard Capital Partners: Okay. And then what oil and gas price benchmarks are you assuming for ’09 to get to your statement that you feel you will be cash flow positive for the year?

We’ve looked at a number of different cases running models and looked as strip prices. And historically we’ve run different discounts to the strip. Given where the prices are today, those discounts are not as significant maybe as we used in the past. But we’ve run a whole long list of price scenarios just to make sure that we covered all our bases. Steve Berman – Pritchard Capital Partners: Okay. And the – I think I see it here on slide 41, the $6.5 million in the money hedge value, has that changed at all? Does that include –?

It does not include the transaction that we did early this week. So I mean, based on the – we did that trade in the morning, and the market sort of cracked out in the afternoon. So there should be some value there, but I wouldn’t guess it would be too significant. Steve Berman – Pritchard Capital Partners: But most of that value is in your gas hedges.

Yes, correct. I mean, there is really – until we did the trade on early this week, as I said, we didn’t have – we had June volumes hedged on the oil side, and that was really it. Steve Berman – Pritchard Capital Partners: All right. That’s it for me. Thanks, guys.

Thank you. We appreciate it.

And your next question will come from the line of Katherine Sabolski [ph] with Jefferies & Company. Katherine Sabolski – Jefferies & Company: Hi. I think most of my questions have been answered by now. Thanks for all the great disclosure in your presentations. At year-end, do you have your accounts payable balance available?

At year-end, we got about $10 million working capital deficit at year-end. So that excludes – excluding cash was the $10 million working capital deficit. Katherine Sabolski – Jefferies & Company: Okay. And accounts payable currently is sort at the same level I assume?

Yes, I have to go back and look. But it’s – yes, I don’t know out of the top of my head how that number might have changed. Ask your question again –

She said now –

Now – sorry. Yes, I just – you know, we’ve been focused on generating year-end numbers. We began to get data on January, but it’s just too early we don’t have a real clear picture yet. Katherine Sabolski – Jefferies & Company: Okay. And looking forward to the second quarter, given your reduced CapEx budget, do you think it might be possible to maintain production volumes or would it be more likely to see a slight reduction just due to natural decline?

Well, we’re not – of course, we hadn’t put out full year guidance, but we do have the South Louisiana well that’s going to come on line. It’s going to materially impact the first quarter. It will be on line for the second quarter. We have a Red River well that’s coming on line. That’s not going to impact the first quarter. It will impact the second quarter. There are some competing factors. We have the EOG shutting in their wells for part of the first quarter. That should really flatten out into the second quarter. And Lance, do you want to add something?

Yes. We could also or we will also see some declines from the divestitures as we close them because of the effective date on the non-op is in the mark.

Right. And then on the other hand, we have other wells that we will probably completing here as we get into warmer weather, the Figaro and the Stroebeck and the Anderson, which will contribute incremental additional production volumes. So it’s a roundabout way of not really answering your question, but giving you a lot of the data points that factor in one way or the other. Katherine Sabolski – Jefferies & Company: Well, that’s great. Thanks a lot for your help.

Thank you.

And your next question will come from the line of Joel Musante with C. K. Cooper & Company. Please proceed. Joel Musante – C. K. Cooper & Company: How are you doing, everybody? I just had one quick question. What’s your – for your proved developed PV10 reserves, what’s that number?

Proved developed PV10? Joel Musante – C. K. Cooper & Company: Yes.

You want the SEC pricing? Joel Musante – C. K. Cooper & Company: Yes.

At year-end, PV10 is 170 million – 171 million. Joel Musante – C. K. Cooper & Company: Okay.

172 million. Joel Musante – C. K. Cooper & Company: All right. All my other questions have been answered.

All right. Well, thank you. Joel Musante – C. K. Cooper & Company: Thanks a lot.

And your next question will come from the line of Mike Canon [ph] with Orex [ph]. Please proceed. Mike Canon – Orex: Hey, guys. Just a question on the borrowing base redetermination. Is there a formula attached to that or is it fairly subjective in terms of the prices that Bank of America uses as well as the service cost that they factor in?

They will use their price deck, I mean, whatever that price deck is at the time we are doing the redetermination. So it is a very subjective exercise. Generally the non-producing reserve as a percentage of the total borrowing base, they are capped out at roughly 25%. Mike Canon – Orex: And that’s for what part?

Non-producing, essentially the PUDs and the what’s not hooked up to production. So that’s why when I mentioned earlier bringing these two, we have these two discoveries in Southern Louisiana that aren’t hooked up. We tested them. We generally know what rates, but the fact that they are not producing gas to sales, at year-end you leave them in the non-producing category. But we will get credit for those in April. So it’s – there is a big subjective – it's not just a formula. I mean, they do sort of a calculation based on the company’s assets and then they also do a cash flow calculation and sort of look at the combination of the two and make an assessment. Mike Canon – Orex: Do you get any credit for your acreage in the Bakken that’s not producing?

No, not in the borrowing base, no. Mike Canon – Orex: Okay. Was it reserve reports due April 1 and they have 20 days to calculate whatever they think the borrowing base is going to be?

Right. Mike Canon – Orex: And then they go to lenders, so –?

Then they put word out to the other banks and make it – what they will do is make the recommendation to the other banks. Mike Canon – Orex: You basically have between now and sort of mid-May. If you needed to get something done to pay down the revolver and be within on size, if you will?

Yes, but I mean, I think we’ve outlined. We’ve got cash. We will be building cash. Mike Canon – Orex: Has there been any other private land sales or any other evidence since January? I mean I see the slide that you provided, but it has evaluations remained the same per acre in the Williston, the Bakken generally?

Yes, what was the question, I’m sorry?

Sorry, Mike. Mike Canon – Orex: No, if there is any more recent data on acreage sales, private or leased?

No, that was the most recent one that we put up on that slide. That was January BLM and –

Jeffrey has put out our report back in December.

That was on that leasehold.

Okay, okay.

And the next sale will be late March, early April.

Yes, you can get what Jeff has reported. It adds a little color on that. What’s the date on that, do you have it, Jeff?

January 29.

January 29, that’s regarding that lease sale. It adds some color. It’s obviously a real strong sale. So, just to give indication of the industry’s interest, which was (inaudible).

When is the next one, Jeff?

It’s scheduled for late March, early April. Yes, the BLM sale. Mike Canon – Orex: Okay. That’s helpful. And then the strip case that you ran at the end of January, I think you said it was 4.21. How much of a decline in service cost was factored into that case versus any cases you ran at the end of the year?

It wasn’t factored in at all. You raise a good point. I mean, it’s – the service costs and to develop those PUDs have come in quite a bit. So, no, that’s not even inclusive of that.

The development costs in that particular report were roughly $167 million.

But we assume it’s down 30% from that. That makes it 120, so net 40 million. Mike Canon – Orex: Does that make a material difference in terms of probables being converted in the PUDs in terms of your engineer reports? I mean, have you run estimates on what the current decline in service costs would add potentially versus your year-end reserve estimates?

No, but I mean that is something we probably should look at. Mike Canon – Orex: Okay.

The numbers keep changing so quickly right now. And we have run our economics on every kind of – as it’s going down.

Yes, (inaudible) economics. We don’t run the reserve report, but –

Well, but we update the reserve report. And as we add well, as we hook up the Southern Louisiana well, we will update the report. And we don’t go back and retrack the (inaudible). We look at all the – we typically – in the past when we do these redeterminations, we don’t typically redo the capital expenditures, the AFEs. But it might be something that in this environment to discuss with the banks.

In the past you haven’t seen the kind of movement. This is unprecedented in a six-month period to kind of moving on the cost side. But you raised a really good point. Mike Canon – Orex: I was just curious on what cost today versus cost at year-end versus I mean even since the end of January when you ran your own strip case had to have come down 10%, 20%.

It’s more than that, I think.

I mean, we did do it –

Since year-end.

Since year-end. But since we did our year-end report, we’re probably down –?

Because we did in February.

Yes. As you’re finalizing in February, so we’re putting those numbers together at year-end. So we’re getting some of that benefit. Mike Canon – Orex: Okay.

We have a good improvement on current prices.

Yes, yes. Mike Canon – Orex: Okay. And there would be some PUD conversion there and probables that were not economical?

That’s right. And more than anything, it just would make the overall PV10 go up.

And we it will look much better at mid-year, just the trend lines on this. I think the costs are going to be down further at mid-year as per our slides. Mike Canon – Orex: Okay. And what was the PV10 associated with the 75 acres – or 7,700 net acres and 3P reserves in Mountrail?

Is that the marketing with the PV?

I don’t know if we want to release that right now. Mike Canon – Orex: That will be – that’s obviously a component to it.

Right, right. Mike Canon – Orex: Whatever price you get.

That’s right. That’s right. Mike Canon – Orex: What’s happened over the last six months? I guess, really last four months in terms of commodity prices, I mean, you had a really – let’s say, you were, relatively speaking, under hedged. I mean, has that changed your mindset going forward in terms of hedging strategy and your target ratios?

Well, it did change our minds. You’re right. Over the course of that period, we have put in hedges just kind of to cover ourselves in this uncertain environment, and thus 70% of our gas is hedged.

Yes, we were pretty lightly hedged in November. And coming into October we were very minimal. We have added substantially to our hedge portfolios since October of last year.

And we like – everybody saw the concern about the gas prices with all the supply. And so we got more aggressive with our hedging, and we’re opportunistic. And Gene and the guys did a great job, when you’d see a little spike in the gas prices working with the consultant to put on some more hedges. And I think that’s part of the reason you’d look at our – our hedges are pretty attractive, particularly relative to when we put them on. Mike Canon – Orex: Have you all engaged anyone more broadly in terms of strategic alternatives to enhance shareholder value?

No. Mike Canon – Orex: No? And does your – suppose you raised a significant amount of capital from one of these sales, I guess it all depends on the acreage value that I assume in the acres sold, how much you could actually raise, but it could be material. Does your revolver agreement allow you to buy back your bonds, which are trading at the stress levels today? And is that something you’d consider?

That is certainly – I mean, it just doesn’t make sense in the environment today. We’ve looked at it. There’s an opportunity for somebody to take advantage of that discount, but it just doesn’t make sense for the company to do it. Mike Canon – Orex: Okay. Well, thank you. That’s it for me.

Okay, thank you.

Your next question will come from the line of Houston Netherland with Natixis. Please proceed. Houston Netherland – Natixis: Good morning, gentlemen. I don’t have the presentation in front of me here, so I apologize if this stuff is covered in the presentation. But I think I heard you say the majority of your $37 million will be spent in the first several months of ’09. Could you give me a little bit better idea of, specifically in 1Q, what that number might look like?

Yes, Houston. It’s – I mean, I think, as I said, majority is probably the right – if you look at our total E&D spending, our total drilling expenditures for the year of roughly $27 million, all but maybe $3 million or $4 million will be spent in the first quarter. Houston Netherland – Natixis: Okay.

Yes, but that’s based on the current budget, obviously. And hopefully, we’ll be in a position to put out some kind of updated budget later in the year. Houston Netherland – Natixis: Okay. And then, I think I heard you say the market value of your hedges is around $7 million. Is that right?

Yes, $6.5 million. And that was as of ’09 [ph]. Houston Netherland – Natixis: Okay. Now, are there any covenants in place that would prevent you guys from selling your hedges to give your liquidity a little boost?

Not that I know of. Houston Netherland – Natixis: Okay. And then just a quick one here. Can I get a capitalized interest number for the fourth quarter?

Fourth quarter, it’s 2,000 – it was probably – I will have to get that for you. Out of the top of my head, I don’t have the right hedge here in front of me. Houston Netherland – Natixis: Okay then. Thanks very much.

Thank you.

Thank you.

And your next question will come from the line of Kenneth Pounds with Nutmeg Securities. Please proceed. Kenneth Pounds – Nutmeg Securities: Hi, gentlemen. Finally someone touched on a little bit what I think is one of the real key issues here and it’s, I think, aptly demonstrated on slide 49, which is oil pipelines and refineries. Someone else mentioned that there were some people shutting in because of the high differentials. I think it’s very critical that for everyone on this play and the valuations that you all would like to receive now and in the future and the recognition you deserve for your work here to receive good prices. How close are we to some of these proposed pipelines or alternative solutions that would help you all close the differentials?

Yes, this is Bud. I’ll just give a quick little comment, and Lance, he knows a lot – so much more about that than I do and he can answer your question a lot better than me. But just generally, my understanding of EOG, and Lance may add onto this, is that they were shutting, as you said, because of the differentials but also just recognizing that the oil prices were very low relative to probably their outlook over the longer haul. And given the significant amount of reserves and production capacity that they had there, they thought it would make sense to curtail their production and bring it back up and produce that out at a later date. But so, Lance may have more data on that.

I believe they announced that they were going to bring it back on in first quarter of 2010 and –

Which is when –? Kenneth Pounds – Nutmeg Securities: Well, the call is not about EOG. The call is about the differentials, and Canadians are having the same problem for a different reason. But how close are we to one of these pipelines that you’re looking for here on your chart?

Well, basically, most of these pipelines that are on the chart are already constructed. Enbridge is going to have an increase in their capacity that they will have the capital investment completed somewhere in first quarter 2010 and that will be an additional 50,000 barrels a day. There are also all these rail stations. And what I was getting ready to say about EOG, they are building their own loading station, buying their own frames, and basically the cars so that they could transport their own crude. And so I think what they’re doing is trying to lower that portion of the oil that has to be railed out, lowering that differential to as low as you possibly can. I think they’re doing a great job, and I think there is probably a dozen other companies doing the same thing, trying to get rail costs as low as possible. So, what portion that doesn’t make it via pipeline will go via rail. As far as the largest pipeline expansion as Enbridge, should be done first quarter 2010, there’s a whole bunch of other things in the works, both on the gas side and the oil side in this area. So there is really not a good timetable on those other expansions. Kenneth Pounds – Nutmeg Securities: That really seems to be the key for you guys. I mean, there’s a lot of interest right now that you got differentials what they got down to 14 or something and now you said 8 or 8.50. And so, that really seems – it seems to be a real classic bottleneck situation here that’s really hurting you all. Second question, since you said you were 70% hedged in natural gas and you’ve gone higher since, but there are some people thinking that natural gas might go into the trees and stay there. There’s potential for more L&G coming to our shores. Have you considered shutting in some of your unhedged natural gas production or your higher-cost natural gas production?

Well, this is Bud. Maybe I’ll start with that. I mean, we share the concern near-term on natural gas. On the other hand, we did take – we’re seeing a rig response and we’ll see a supply response. In my view, you might see more volatility in natural gas if we have – clearly going to be a soft year this year, but as we get into next winter, it could be really soft as I know some are concerned it could. But as we get in to next winter, we’re going to begin to see the supply response. And if we have some cold weather, you could see strong gas prices in the winter. But clearly, there’s a lot of supply out there that can be turned on with the rig activity. And so you could see a balancing out of the supply and demand, but with probably more volatility over time. As far as us shutting in gas production, I think it’s probably unlikely. 70% of our gas is hedged or maybe north of that. Our LOEs are relatively low relative to peers. I guess it would just depend – because we really hadn’t thought about it much, but it would depend on how low gas prices got because our gas production would still be profitable at probably lower levels than many operators. Gene, do you want to add anything to that? Okay. Kenneth Pounds – Nutmeg Securities:

No, we don’t. It’s really – a lot of factors is found in the right partner in the right area. There are a lot of companies interested. And some are more interested in one area and some are more interested in another. I think the probability is it’s less likely that we’ll have one partner coming in for a big chunk of participation. It’s more likely that we’ll have one, two or three partners in different areas, maybe for 20,000 acres here, maybe 50,000 acres there, or something like that. And so it’s not that we’re going into this with a set target number or goal. It’s trying to optimize our value on the assets with the right partner, which means, of course, it will help us to optimize the value over the long haul if this one has a good partner in there. Kenneth Pounds – Nutmeg Securities: Great. Thank you.

You’re welcome. Go ahead, Gene.

Yes. Houston has asked a question about capitalized interest for the fourth quarter. And for the full year, capitalized interest was $4.8 million. For the fourth quarter, it was $1.4 million.

Any other questions?

Your next question will come from the line of Nick Van Bavel [ph], private investor. Please proceed.

Hello, Bud and Gene. It was a great presentation. I just had a question, I guess it’s really for Gene, about booking reserves. My understanding is SEC is amending their reserve recognition standards for the end of the year. And my question is, what impact is that going to have on your reserves and what impact would it have had on your 2008 reserves had those new rules been in place?

This is Lance. And basically, those rules if they get passed, what they will do is, for one thing, our PV10 would have dramatically been higher because you’ll take the average price through ’08 and use that as your year-end instead of using the December 31 price, which was obviously low. So when you have that, you’ll have a higher PV10, which will give you more production on the tail-end of your producing reserves and also you’ll have more of your PUDs come in to play which will – are improbable, which you can’t report today. They will become PUDs next year, more of them will. And then you’ll also be able to document and report probable reserves also. So I think it’s going to be a better tool for the investors and it will be better for us to quantify the assets that the company has.

And the other factor related to that, which isn’t as much to do with the changing of our guidelines, but there will be more statistics, more wells out there with the 10 to 12 and even long laterals with 20 frac stages. So if they get enough statistics, then they will be more comfortable booking PUD to the level of a newer technology wells.

Yes. I guess my understanding was that they were specifically targeting, amongst the other changes they were making with regard to pricing, they are also specifically targeting, helping a resource play such as the Bakken to where you weren’t forced to book just neighboring locations. But Gene, if you can show that that was statistically accurate across entire region, you would be able to book much more of those probables into PUDs.

That’s correct. This is Lance. So, instead of just doing the two offset PUDs, if you can show continuity to the reservoir and productivity of the reservoir, you can book more PUDs. And that’s exactly we’re at. I think that’s what it should be. I mean you should be able to try – our goal should be to try and actively reflect the value that we’ve proven up. And so hopefully next year, if everything gets passed, it will be a transition year, but it will be interesting to see the impacts on proved reserves and PV10.

And it could be a real inflationary factor on the reserves.

Yes, it seems like it would have an enormous impact on your reserves.

I think you’re right.

Okay. Thank you.

Thank you.

And your next question will come from the line of Kenneth J. Elliott [ph], private investor. Please proceed.

Good morning, gentlemen. How are you?

Fine. How are you?

Very good, sir. Well, Bud, first let me say, this is my first opportunity to call in. I’ve been a long-term shareholder and I want in all these era of negativity pay a professional compliment to your shareholder department. They have been very responsive in both written material and phone call. They have done a great job.

Well, good. Thank you.

Bud, let me direct this to you because I come from a little more of an energy experience with the practical level you might say. Your Q&A has been phenomenal. I want to reference, for everybody’s review and listening, two great articles. One, the Oil & Gas Financial Journal December 2008 with an excellent article on yourself and the company. And then recently, the part publication, $100 a copy, the play book, the Bakken Shale. Page 37, and I’m taking – I’m back up (inaudible). Going on the basis with the current Q&A has probably solved everybody’s mind, the fundamental question is simply this. Are we going to survive without the threat – or wait a minute I'll say it backwards. Can you navigate the company through this critical environment without worrying about qualified opinion from our auditors and some statement that were in near violation of our lenders’ covenants? I think that’s pretty well been answered adequately in my mind. I want to go a little long term and very positive. In the Bakken book, page 37, there is a Williston Basin resource inventory. You just take those figures if you’re still comfortable with them, discount 50%, and given the attention that the Bakken play is being given like in my area of California, which was similar to the – equal to the midway sunset – and correct me if I’m wrong, Bud, if these figures are still correct – are we not in an incredible strategic position long-term assuming we get through the short term?

Yes. And I don’t have that figure in front of me, but we do have slides that we’ve had in our Corporate Presentation head. When you look at the USGS assessment, this Bakken play will be the largest oilfield in North America in the last 40 years. I think you’re right. And you’d look at even at production and we’re so early in the drilling in the Bakken Three Forks play that already the production is north of a 100, and I think it’s 135,000 barrels a day. And you look at the North America’s largest oilfield at Prudhoe Bay is 315,000 barrels a day and on a significant decline. So it’s not inconceivable that in the next five to seven years that the production from the Bakken and Three Forks could exceed that of North America’s largest oilfield. So I think it’s going to be – and I think you make a good fundamental point over that time period, over the next five years. It’s going to be very important for our country, for our trade balance, for our energy security, and for the domestic industry. So I think you’re exactly right, and you’re hitting on what we’re striving to do through this – once in a lifetime as far as my last time economic storm that we’re in, to manage our way through that such that we can be optimally positioned coming out the other side to capitalize on it. And Jeff was just reminding me another key point that’s relative to your larger point is that there is going to be so much option value because if those articles talk about there’s so much oil in place, and the option values over time whether it’s refracs, whether it’s increased density drilling. Of course, the Three Forks right below it; it’s just starting to be scratched, and then secondary recovery, CO2 (inaudible) pilot projects. So this is going to be a 20, 30-year play, and it is going to be of real importance domestically.

Two observation – well, one observation and one question. Recently, in the Oil &Gas Journal was a very small but specific comment saying that the Bakken play or Bakken Field is getting special attention by the current administration. Is that referencing a previous question that came up or statement about the pipeline bottlenecks, et cetera? Or is there further incentives planned for the Bakken?

I have not heard that, but I would be interested to see that. Some may think there is a real need. It certainly would be very beneficial for the country and for the industry, but I have not heard that. So if you find anything on that, I would love to see it.

I think I’ve sent that to Rob Roosa in the Oil & Gas Journal.

Yes. And unfortunately, Rob is not in here, but I’ll ask him about that. But we do know that the governors there of those states are very focused. The states of the political – politicians there are very focused and were involve through the alliance and other associations out there in supporting their efforts.

Well, of course, my State of California, Bud, has not been very complimentary to oil and gas. So you can understand why we’re in trouble out here.

Sure, sure.

One last thing is this. The current Q&A I think or hopefully has solved the issue of our survivability or violation of loan covenants. Having said that, given the potential reevaluation by the SEC in speculating on the common stock, isn’t this stock ridiculously discounted or having been shred as to the true potential value, or is there something out there that we’re not seeing?

No, I would agree with you 100%. I think management here believes that, and we’ve recognized our stock is undervalued. I think we’re buyers at this level.

Would management and the Board be of themselves considered buying the stock themselves or maybe you just answered it?

I’m speaking of myself. I would. I’ve been locked up, but I won’t be. So it’s something I’ll definitely be looking real hard at.

Sure. Well, once again, thank you very much. And just wishing you a good drilling and continue to be a long-term shareholder. Thank you.

Great. Thank you very much. I appreciate the call

You bet. Thank you.

Operator There are no further questions at this time. This concludes the question-and-answer session. I would now like to turn the call back over to Mr. Bud Brigham for closing remarks.

Well, thank you. That concludes our call. I really would like to thank everybody for their participation in our call, and we look forward to reporting on our first quarter results. Thanks.

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. And have a great day.