Good day ladies and gentlemen, and welcome to the fourth quarter and year-end Brigham Exploration Company Earnings Call. My name is Angelic; I will be your coordinator for today. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Bud Brigham, Chairman, CEO and President. Please proceed sir.

Thank you, Angelic. Thanks to each of you for participating in Brigham Exploration Company's year-end 2007 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. Briefly, during this 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, a copy of our company's press releases, as well as other financial and statistical information about the period 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. We've also updated and will continue to update our corporate presentation, which can be accessed via our website. It includes both our fourth quarter 2007 results as well as our plans for 2008. Also in the event you are following the Williston Basin Bakken play, there is a map in the presentation that would be helpful to view as we describe the accelerating drilling in that very active play. So let's get started. For BEXP 2007 was a year of record production volumes, revenue and cash flow. Most importantly our substantial recent, long term investments in resource play acreage and 3D seismic began to pay dividends in 2007, highlighted by drilling successes in the North Dakota, Bakken play where we now control over 240,000 net acres. I believe that in subsequent years with the benefit…

Thanks Bud. For 2007 production volumes averaged to a record 41.6 million cubic feet of equivalents per day an increase of 13% over our 2006 volumes. In the fourth quarter of '07 our production volumes averaged 35.5 million cubic feet of equivalents per day, which exceed the mid-point of our fourth quarter 2007 production guidance that we had issued in November of last year. Our fourth quarter volumes declined 18% sequentially from our third quarter volumes and 9% from our fourth quarter 2006 volumes. The sequentially decline resulted from a combination of a pause in our Vicksburg drilling rig line in order to reprocess our Diablo 3D data and complete the structural reinterpretation of our Diablo project area. By the way we have since resumed our Vicksburg drilling and last month spud the Sullivan C-38. Number two, the natural decline experienced in our Southern Louisiana, Bayou Postillion production volumes and lastly the impact from our Granite Wash assets sale which closed on September 1st, 2007. Our fourth quarter 2007 revenue including hedging settlements increased by 12% to $29.1 million relative to that, in 2006 due primarily to higher commodity prices. Pre-hedged commodity prices increased 25%, which generated an additional $5.7 million in revenue. This increase was partially offset by $2.2 million decrease in revenue due to the afore mentioned decrease in production volume and $400,000 decrease in cash hedge settlement gains. Full year 2007 revenue including hedging settlements increased you 20% to $124.7 million. Full year revenue was positively impacted by $10.4 million due to increased production volumes and $10.4 million due to a 7% per Mcfe increase in pre-hedged commodity prices. Please note that the revenue figures I've just quoted excludes $2.8 million and $5.8 million of before tax non-cash losses associated with the mark-to-market value adjustments of our…

Thanks Gene. As I previously discussed, analysis of the Bakken shines a very positive light on our future. Drilling results in and around our acreage indicate the opportunity for very attractive proved developed drilling costs with excellent margins and strong returns on our drilling investments. The Bakken and the Vicksburg where we have a very long track record of generating strong returns, the focus of roughly two-thirds of our 2008 E&P CapEx budget. Looking back to last year, if some of you may recall, our foremost goal as we began 2007 was to generate attractive total proved finding costs. And we made progress in that respect, given that our 2007 total proved finding costs for our low operating costs and high value reserves was approximately $3.88 per Mcfe. I think it will become evident as I discuss our 2008 plan and opportunity we have, particularly in the Bakken to grow reserves that our result in 2007 are likely poor shadowing an extended period of meaningful high value reserve additions at low finding costs, providing us with the opportunity to generate accelerated growth and shareholder net assets value. So, now I'll move forward by updating you on our unconventional program beginning with the Williston Basin. We were ramping up in the Bakken with a continuous drilling program, while we continue to develop other resources plays. I encourage you to view the map attached to our corporate presentation to follow our Bakken discussion here. In recent years, we've made very substantial investments in the Bakken. One of the most exciting domestic onshore oil plays that we've seen in years. After numerous high rate discoveries in the area by other operators, our investments began to deliver tangible early results with our first three operated Mountrail County, North Dakota, horizontal Bakken completions. The Bergstrom…

(Operator Instructions). Your first question comes from the line of David Heikkinen of Tudor Pickering. Please proceed.

Good morning. I wanted to step through your first quarter production guidance from the third quarter, call you expected to see growth now you are seeing a decline. Can you give us a breakdown of the regional production, Bakken Gulf Coast, Anadarko, West Texas that you had in the fourth quarter, and where you expect that to be in the first quarter now?

Yeah, David this is Bud. I'll start and these guys may want to add to what I'll tell you. I'll start with just some general comments. Part of it was the timing of our Vicksburg resumption. We thought that we spud that C-38 well earlier and obviously a 100% interest in a Floyd well. That's an impact full well in terms of production. So that's a big factor on the timing and on the gap, there's a drop in production and we've had these periods where we have gaps and wells coming online and its the nature of our conventional production in the Gulf Coast its very choppy on top and when we have eight month gap in our Vicksburg completions, obviously, we're going to see a drop in our production. But this time its compounded by South Louisiana, those terrific wells we brought online last year that despite the fact they were outperforming had some significant decline in near-term in production, but obviously drilling the Cotten Land #520 and the Cotten Land #3, that 50 feet of play relative to 30 feet that produced 27 million a day, we should have some very substantial volumes coming on there together with our continuous or our five joint venture wells that are in South Louisiana, not to mention the Bakken wells that are now beginning to contribute. So Lance or Jeff, do you guys want to add anything on that regarding David's question

I know that's kind of a general answer David, but does that help you a little bit?

Well, just trying to understand, in your last call you talked about showing growth in first quarter, now you're not. I understand you knew that you had the Vicksburg drilling timing and you knew you had these wells that were declining in South Louisiana. So just trying to reconcile between an expectation of growth and now an expectation of the sequential decline?

Well it's really timing. Obviously, if you don't have wells come on line, you just continue to see a decline and when you look we had 2 million a day of production that we sold later in the year. So you loose that then the decline in the South Louisiana and Vicksburg, if you combine those two that's 10 million a day there between those two. So, we had anticipated the C-38 coming online, well it's going to come online in the second quarter, so it didn't impact the first quarter, so it's a function of timing.

Okay, and then, on the Bakken, just wanted to go through the four wells that you've talked about from your January press release to now. The Bakke seems like it's holding in pretty well, 380 barrels per day on seven inch casing test to 310. But Hynek and Bergstrom have declined, particularly the Hynek declined considerably? Can you kind of walk us through what you'd expect for EURs for those three wells, now that you have -- some production history?

Yeah, Lance can answer that. Let me just say, we did point out or we talked about the fact that though the Hynek had a higher initial test rates, the Bakke looks like it might be the better well, that certainly is playing out that way so far, but that being said its still early. But Lance can kind of give you a feel of what our current thinking is or maybe range of reserve outcomes for those wells.

David this Lance, hi. It's obvious that we have a mix bag of the performance of the wells themselves. As far as building out decline curves, we are monitoring all the other Bakken wells in the area to build good top curves, so that we can do a better job estimating reserves. And we are updating that monthly to try and get a better handle on exactly what our reserves are. Of course, you hit it, the Bakke is holding in well and looks really great. The Bergstrom, I think is doing better than we thought initially, its really holding in while that's flattening off really flat. And Hynek started off better and is far more flattening now, so we really don't have a good strong estimate of reserves right now. We do have them based on early time data. The one thing that I would point out is Bud has a slide in his presentation out on the web, that has the drilling cost of $5.2 million and that's a pretty good idea of where our cost is averaged in our reserves. On the different ways to look at it within that matrix, we believe the average is within that matrix that he is showing on the website. So we are really excited about being able to repeat this over and over again and show good rate of returns in good multiples.

So you think you are in that 300,000 to 400,000 barrels of oil for each of these wells?

I think on an average we are in that range between the 200,000 and 700,000 barrels which I know is still a pretty broad range, but we are really not comfortable giving a good strong estimate, but in the range of that matrix that table that Bud has…

Obviously the Bergstrom or the Hynek might be kind of the lower side of that range in the Bakke and certainly the Hallingstad would be at the upper end of that range. So it's early, but at this point the way the wells are performing it looks like there is a good probability that all of them will generate reasonable returns but there is variability among them.

Right. I think if I was forced to give you an answer, right. I would say it would be in the range of 200,000 to 450,000 barrels on an average if you took all the four wells that we drilled today including the Hallingstad.

Okay. Thanks guys

Thank you

Your next question comes from the line of Ron Mills of Johnson Rice. (Operator Instructions). Please proceed, Mr. Mill.

Good morning. Just a couple of follow-ups early on, on a couple of things to follow what David had asked. As you look at the second quarter profile Bud, or Gene, because you are not going to complete the C-38 well in the Vicksburg until, April results, so you probably won't be able to get that well online until May. And then your Cotten Land well is definitely not a second quarter impact well. What do you have coming online, or what do you see coming online in the second quarter they can provide that first quarter sequential growth as opposed to what it looks like would be more like a third quarter startup of sequential growth?

Sure, Ron. It is going to be driven by timing and the timing on the C-38 which could be a latter part of that, but wells they have a good probability of contributing to the second quarter, the Cary Estate that PetroQuest is currently completing its own 26 feet of play. In the Bakken the continuing sequence of wells the Manitou State that's currently drilling and of course the Krejci that we're currently fraced here in the next couple of weeks. But the timing of those I mean we have been in the trough here with absent significant completions and the timing of these wells coming online will affect how much of the growth that you see in the second quarter and obviously what the C-38 should fully impact the third quarter as well as more of the Southern Louisiana wells. And one other well that I didn't mention is the Mracheck we are doing that [the] completion also in the Bakken as well that one should contribute also.

Okay. And then in terms of just to gas oil split you have been running 80% to 85% gas. I would assume as you drill more and add wells in the Bakken, the oil component is going to go up. How quickly and to what extent, do you think you can increase the oil component of your production?

Ron, its Gene. I would expect, just based on a conservative modeling that we are doing as far as contribution form the Bakken well, that may be in the 65% gas range in the neighborhood.

And is that by year-end or is that--?

That would be at year-end, yeah.

Okay. And Gene, one easy one for you; LOE for the fourth quarter of $0.70 per annum was well below where you had expected it to come in at $0.89 or $0.90 per annum. Was there just lack of workovers that you were expecting, and is that why the first quarter guidance is back up in that $0.85 to $0.90 range?

Yeah, I mean, obviously you know, yes. We had some workover activity, but it was below our actual, as far as the two prior quarters. And a big part of fourth quarter, obviously we sold the Granite Wash assets and we had a lot of expenses or high operating cost, assets given the amount of water those wells are producing. So, we saw a little bit of benefit given that we closed that transaction on September 1st. So we sort of missed out on the Granite Wash LOE contribution for the month of September, but obviously saw a full quarter's impact in the fourth quarter.

But in terms of expectations, what's driving the increase back up to the mid $0.80 range.

Well, I think we're just being may be a little bit conservative. Another issue is that we're expecting higher ad valorem taxes. So, it's really a combination of the new wells that we'll bringing on in the first quarter higher ad valorem taxes and so the Bakken wells that we completed in the first quarter and really primarily the higher ad valorem taxes.

Okay. On the Bakken, Lance, this might be a question for you because as soon as they find it than it's in your hands. If you look at the economic profile of a well and you look at the matrix that you will have in your presentation of 200,000 barrels to 700,000 barrels. What do those production profiles look to get to those eventual recoverabilities in terms of where do wells have to come on, and what's your engineered decline curves in each of the first four or five years before you start to get to a more stable decline period to get to those economic runs?

Yeah, Joe this is Lance. I'm sorry, Ron. Basically how we model them is we take in all the data that we have from the Bakken wells in the area and of course we don't have 10 years of production on those wells. So what we do is we try and put those together and pull tight curves. And then we do a curve fit using our [area] software program. There are hyperbolic fit curves we use in exponents that are in excess of one, so they're flattening off. And if I just look at the curves, it looks like that the final decline rate probably is not reached until about 6 years out is when you had final decline rate.

And based on the data that you have, how does that decline rate, I mean obviously the first three wells, the variability that has been already talked about by you'll on the call, but is it typical first five-year profile down 50% then down 30% and then down 20, 15, 10. I'm just trying to get a sense as to what that typical well profile looks like? Hello

I'm looking at it. I'm trying to figure out how to answer this so I don't mislead you so.

And is this $5.2 million well cost, that's I'm assuming that's a single-lateral what's the lateral link you'll are drilling?

That's a 640 section, so about 4,500 feet. Our frac jobs we've done 7 or 8 frac jobs in each of our 4 wells so the cost is variable on the number of frac jobs of course and the number of -- and we're using the Swellpacker technology right now. So that's average of the four wells that we have, that we've drilled today.

And then the operating costs of roughly $8,400 per month. Is that a fairly fixed component?

I think it is right now, and that number Greg and I have been talking about that number is also that's our best estimate. We haven't had enough months. We've basically, our oldest well is 2 months old, so we haven't had enough history to get a good firm cost on our operating expense, but we feel like that that's a very conservative number. So we feel like we'll be able to stay within that. The other thing what you would expect to see overtime, and I've told you this probably 10 times. You'll expect the cost to go down overtime, and if they don't go down overtime it's because you're spending more money on the completion, and you'll expect the reserves. So really what you are expecting is the cost per barrel to go down overtime, and that's going to happen. We're going to do a whole lot of things in the area we're gearing up for full scale development, we're going to be creative in trying to buy some of the, what I call dumb iron and stuff to try and lower those costs, frac tanks, metal strings those kind of things were out there right now, there its very competitive. We can bring it in a lower cost plus we're going to be figuring out ways to do things faster and better as well as everyone else. And that's part of the reason we're in the consortium to try and have open conversations with six other companies that are active in the play, so that we can learn from one another.

Okay. Well, I may try to follow-up on the production profile just to get a sense, and then lastly the 200,000 to 450,000 barrels that you've based on what you've seen so far that you feel comfortable that those that you always would average in that level and when you talked about the metrics of 200,000 to 700,000 barrels. Is that mainly focused on that 88,000 acres east of the Nesson Anticline or would you also include the acreage you have to the west?

We've included the larger area, I mean, as far as -- what we've -- I am sorry -- answer the question.

Well, Ron, I think that now we just have a lot of data east of the Nesson and Mountrail, so that 200,000 to 700,000 the data supports that east of the Nesson, west of the Nesson now it's just too early. We think there is a tremendous amount of option value there. We've got the Mracheck, which we are attempting to run the Swellpackers on and complete. We have 51,000 acres there and 100,000 acres to the Northwest and far eastern Montana, where there has been an activity to the south. So, that's provided some encouragement for the Bakken. A Sinclair well was recently drilled horizontal to the south of our Montana acreage, it came on at 300 barrels per day. So we are really excited about that acreage, but we don't have the data to say what range of potential outcomes that we would expect on reserve recoveries over there.

Alright, thank you. Let me jump off now, thanks

Okay. Thanks, Ron

There are no further questions in the queue at this time. I'd like to turn the call back over to management for closing remarks.

Well, this is Bud. Again, I want to thank everybody for participating in the call, and as I have said before we look forward to reporting on what should be a very exciting year for the company, thank you.

Ladies and gentlemen, we appreciate your participation in today's conference. This does conclude the presentation. You may now disconnect. Have a wonderful day.