Good day ladies and gentlemen and welcome to the third quarter 2008 Brigham Exploration earnings conference call. My name is Carol and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator instructions) As a reminder, ladies and gentlemen, this conference is being recorded for replay purposes. It is now my pleasure to turn the presentation over to the host for today’s call, Mr. Bud Brigham, Chairman, President and CEO. Sir, you may proceed.

Thank you, Carol. Thanks to each of you for participating in Brigham Exploration Company’s third quarter 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. 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 were 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 periods to be presented in the conference call will be available on the company’s Web site under the section entitled Investor Relations at www.bexp3d.com. We’ve also updated and will continue to update our corporate presentations which can be accessed via our Web site. It includes both our third quarter 2008 results as well as our plans for the remainder of the year. Also in the event you are following the Williston Basin Bakken and Three Forks Play there are some of our updated maps in the presentation that would be very helpful to view as we describe the very active drilling underway in the Play. Let’s get started, I am going to provide you with brief introductory comments and then I am going to provide you with some specific operational updates in the Williston Basin Bakken and Three Forks Play. While we have had very strong drilling results this year in the Vicksburg and Southern Louisiana those areas…

Thanks Bud. For the third quarter daily production volumes averaged 27.6 MMcfe per day. Our third quarter production volumes declined 8% sequentially from those in the second quarter and 36% from those in the prior year’s quarter. The decline in our Q3 production volumes versus those in the prior year’s quarter was attributable to several factors, hurricane Ike resulted in a number of Gulf Coast wells being shut in for between three and eight days in early September which accounted for 1 million per day in loss Q3 2008 production. Furthermore hurricanes Gustav and Ike caused oil fields service delays in Southern Louisiana which resulted in delays in getting our four new Southern Louisiana wells hooked up to production which accounted for 1.8 MMcfe per day in loss Q3 2008 production. The impact from the sale of our Granite Wash assets which closed on September 1, 2007 and produced 1.2 MMcfe per day in Q3 2007 and the natural decline in our Gulf Coast production volumes and the transition the company is going through given the recent allocation of a larger percentage of our CapEx away from our shorter reserve life Gulf Coast prospects in favor of our longer reserve life Williston Basin projects. Importantly related to this last point, in the third quarter our higher value and generally longer reserve life oil production grew roughly 32% relative to that in the prior year period. Based upon our fourth quarter projections which I will discuss in a minute, our fourth quarter oil production is anticipated to roughly double over that of the prior year period. This is important given that during the third quarter an equivalent Mcfe of our oil volumes assuming a 6:1 conversion ratio generated approximately 1.9 times the revenue of an Mcf of natural gas. So this…

Thanks Gene. I would like to thank all of you for participating and we would certainly be happy to answer any questions you might have.

(Operator instructions) Gentlemen, your first question comes to you from the line of David Snow of Energy Equities Inc. Please proceed. David Snow – Energy Equities Inc: Good morning, I am starting to see how the change in lateral length affects the resource and the resource potential, the total is still on your latest presentation 460 million barrels but it seems to me that you lost a little bit on at least some of the plays that you mentioned, you increased the amount of the expected barrels of oil per well a little less than double and yet you cut your locations in half, can you help me on how that all works?

Yes, I am going to hand it over to Lance and let me just tell you in summary I know it is a little confusing because there are a number of operational changes that have been made and that we are making going forward and one is going to more frac stages in the short lateral up from 7 to 12 and now we are going to a long lateral with 20 stages. So let me turn it over to Lance.

Thanks, this is Lance. Basically what is happening is if we made an assumption of a multiplier of a short lateral of 1.7 and we know it is somewhere below 2 multiplier, common sense kind of leads you to say that you drilled twice as much section you get twice as much reserve if you effectively stimulate the entire interval, and we believe we will be able to effectively stimulate the entire interval but there are things that – the ability for the wells to flow that 2 miles of lateral are going to reduced a little bit so we feel like the ultimate recoveries will be somewhere below 2. We don’t have any real good analogs for that right now so right now what we are assuming is a 1.7 multiplier so we are trying to put a conservative multiplier in there for any economics until we have better results, hard results to use the proper data. David Snow – Energy Equities Inc: So then I would take 85% of the 460 million barrels if I were to assume that rather blankly?

No, we may have confused you on that too, we previously for the Ross area we are using 200,000 to 400,000 barrels per well and we have given our recent well results and other operators around us including whiting we have updated the range of reserves that we think most of our wells that we are currently drilling to fall in 300,000 to 700,000. So the midpoint of that would be 500,000 barrels per well and again that is for the short lateral with the 12 stages. For now the next step we are taking is to drill the long laterals with 20 stages and that is where Lance was talking about based on doing a lot of research on Elm Coulee and the long laterals relative to the short laterals that when we look at those wells it came out 1.9 or closer to 2, it came out approaching the theoretical number of 2 to 1 but we are assuming 1.7 to 1 given that you have doubled the reservoir we are not assuming 100% improvement in the reserves and production, we are assuming 70% improvement but of course we will find out soon with our first couple of wells. David Snow – Energy Equities Inc: EOG’s presentation shows that they have got the most wells in the Mountrail County and also the only ones that are over 1000 barrels a day on average peak month production and I am wondering in play they are the best and then they use company A, B, C, D, E and F and where do you stand relative to them in the Mountrail?

EOG is an outstanding operator and they were the early leader in the technology and the play and particularly taking the swell packers out there and they also run obviously in a great area which we are in too, the Parshall Austin area and it is a little bit different animal there, it is a good quality reservoir rock and it is pressured reservoir rock, I will let Lance talk about it, it is certainly a sweet spot.

This is Lance. It is definitely where they are drilling in the Parshall Austin area that there are quite a few wells that are over 1 million barrels per well but it is a higher pressure, higher perm reservoir but you also read in their press release and in their conference all if you listen and look at their notes, basically they say that they believe in the Parshall Austin area, they only need one well per 640 and then they talk about outside the core area, the Parshall Austin area, they think that it is going to need at least two wells, two laterals per section. And they have their results are lower than the average 700,000 to 800,000 barrels per well. David Snow – Energy Equities Inc: So you feel you are doing about as good as them in balance?

I think we are doing better than them because I think we have been outside the core area because I think we have drilled more wells utilizing more frac jobs outside the quarter in Mountrail County.

I think it is evident, they are talking about the fact and we are too that there is a little different recipe in the different areas that is going to be optimal in and then there is tighter areas like the Ross area, more fracs in license and longer lateral appears to be a recipe that is going to deliver more optimal performance. So we think fortunately where we are in, as I mentioned over 50 non-operated wells and a lot of those are with EOG and we are fortunate to be participating with them because they do do an outstanding job operationally so we are benefitting from that but we are also I think on the leading edge having drilled and run the swell packers in the longest collateral out there today and using the perf-and-plug in the entire bore hole. I think we are kind of pushing, we are moving the technology and optimizing operations in the areas that we are operating in that are a little bit different geologically from the areas that they are operating in. David Snow – Energy Equities Inc: Are you going to be able to maintain two rigs out there with the $90 million to $120 million budget? Roughly how much did you spend in the Bakken this year?

On the first part of your question we are iterating on the budget as Gene mentioned. That is our goal to keep the two rigs active out there. One of the things we are going to be weighing is that we do see costs as I mentioned coming in, Lance believes and we believe that over the next six months 20% to 30% cost reductions are likely in the field and so one of the things we are considering is do we keep the two rigs busy through the entire year or do we take a little break early in the year and wait for those costs to come in on one of the rigs. So those are the kind of things that we are iterating on and we have a board meeting in December where we will present a number of different options and look at that. David Snow – Energy Equities Inc: How much are you spending up there this year?

Well it is about 63% of the announced CapEx budget. So it is obviously a very significant increase from what we had spent last year. So we are I think $180, $175ish is the E&D CapEx that we announced back in July. So it is $80 million.

Thanks a lot gentlemen. Your next question comes to you from the line of Chad Potter of RBC Capital Markets. Chad Potter – RBC Capital Markets: Good morning.

Good morning. Chad Potter – RBC Capital Markets: I guess kind of following up on the last part of the previous caller’s question, is it safe to assume the third rig probably is not going to be coming in late fourth quarter early first quarter?

No Chad, the budget we are iterating on currently is more conservative than we and I think other operators have been thinking about even 30 to 60 days ago. We are going to live a lot closer to our cash flow next year. So right now the budget we are iterating on has two rigs operating throughout the year but we won’t be in a position to – the economic environment improves, commodity prices improve and our cash flow therefore broaden or improve to accelerate beyond that but right now the main case we are working on is a two rig program through 2009. Chad Potter – RBC Capital Markets: Okay I guess typing that back to earlier comments that sort of high grading your drilling schedule, is it pretty safe to say that you probably won’t be testing the Mrachek [ph] County –

Chad we do keep pushing that out partly because it is more of an exploratory well but also because those are operated through drilling wells or have wells planned proximal to our acreage and the good thing about it, I mentioned on the call is, it seems that the vast majority of our leases are relatively new five-year leases and often times with tapers and it may be with July we can expand them so that is certainly true in Mrachek County and I think everybody knows that there in Mracheck County cost reimburses permitted and has several wells planned just to the north of our acreage block and I believe we are also going to be a participant with a slower working interest in at least one of those wells. So we think in the current environment it does not make much sense for us to allocate that significant amount of capital to a well in that area and instead we will participate with a smaller interest in our cross tent as well. Chad Potter – RBC Capital Markets: Right, can talk to you on that. I guess last question, as you are going through your‘09 iteration, are you really planning to do much drilling Gulf Coast –

Yes, Chad we are iterating on that too. We are looking at, as we always do, looking at the relative economics of the different plays in that we start from the capital to optimize our budget for 2009. So it is a work in progress but I would anticipate some drilling probably in the big ferc and potentially in the South Louisiana, we have got at least one well planned early in the year for South Louisiana. Chad Potter – RBC Capital Markets: Okay, thanks a lot.

Thank you.

Thank you sir. (Operator instructions) We have a question on the line from Michael Jacobs of Tudor, Pickering, Holt & Co. Please proceed. Michael Jacobs – Tudor, Pickering, Holt & Co: Good morning everybody.

Good morning. Michael Jacobs – Tudor, Pickering, Holt & Co: Just kind of walking through your worse days in economics and comparing your current presentation with your last presentation and looking at your current drilling cost, wondering if you could kind of talk about within your cost what is drilling and what is completion and how that has changed over the last three months?

Really the historical drilling cost and with those of today with 12 stages but also we are seeing some cost reductions and then the results are looking forward over the next six months what we anticipate both for the short laterals with the 12 stages and we are also going to the long laterals but all those lands that these guys break down for you, the proportion of the cost is drilling versus the portion that is off that is completion cost.

Yes, this is Lance. In the last three months we have seen some reduction from some of the subcontractors. We are anticipating much larger reductions and I think if you look at your track oil price and service costs, there is usually a five to six-month lag. So I think we would see a much bigger dramatic reduction in the next six months. As far as service costs, right now as far as our well cost, we are in $8 million to $9 million range for the long laterals, the reason for that large increase in those long laterals is that we are doing 20 frac jobs and each one of those frac jobs are about $200,000 per frac job. So you can see a substantial increase in the amount of the frac jobs and we are also – frac jobs are basically in our new long lateral for about 30% of our overall cost. In our overall cost they are a little over half we are in completion now because of that.

One thing that I can delineate for you is that the economics that we show in the presentation are really the short lateral economics because that is what our most recent wells have been drilled and completed on and that is the economics that we can look at. Going forward we are drilling these long laterals because as we have talked about earlier and as you model it, it looks like you can achieve – we are assuming 70% increase in the reserves and that is with that roughly 40% increase in costs. So it would enhance the economics that that is the case. Looking at Elm Coulee and other fields it might be 90%. So there is upside from there maybe 1.7 to 1.9 times that reserves and the productivity that you see and enhance their economics. So when we update in January or when we actually see the results of these first couple of long lateral wells, you may see us update the economics on a presentation going forward and incorporate the long lateral costs and associated long lateral reserves and we will be doing that if the economics do look superior. Michael Jacobs – Tudor, Pickering, Holt & Co: Sure that makes sense, looking at your older and completed well costs, I really don’t mean to major on the minor here, I am just trying to understand the discrepancy, looking at your old completed well costs somewhere between $5 million to $5.5 million and that was using a 12-stage frac and now kind of looking at the delta you are saying that it is 200,000 a stage as you go from 12 to 20 stages, that is an increase to $1.5 million. Just wondering where kind of as you are going from $5.5 million to $8.5 million things like half of the cost increase is due to more completion, what is the other half attributable to?

The real numbers are not actually $5.5 million. You know, $5.5 million was for the 7 to 9 type frac jobs and then it was around $6 million to $7 million for the 10 to 12 frac jobs. So the majority of that is 200,000. There is additional casing and drilling associated with that. You have got about – I think a 7 to 10 day extended drilling to drill that additional mile and then you have got the casing associated with that. Michael Jacobs – Tudor, Pickering, Holt & Co: Okay, that’s great. So just kind of taking a step back now and looking at the new economics thinking about a – you gave us kind of this $50 you had 16% rate of return at 60 or 24, assuming kind of the arm again in the scenario and let’s say we are in 50 to 60 for the foreseeable future, when do you start thinking about pulling back rigs and maybe if you could give us an idea of how many rigs you run and how many wells you drill at $50, $60 and $70 that would be helpful.

Sure. The exercise you are talking about we have already done. As Chad had asked about, previously we had talked about going to three, four and five rig next year. Now the current budget is staying much closer to our cash flow because given current commodity prices, our cash flow is not what it was even 60 days ago. We are talking about trying to keep two rigs, right now the budget is keeping two rigs busy during the year and some of these – when we model our budget we look at the current strip but we also look at a discount to the strip. So we are modeling conservatively when we look forward one key point is if we are in the $50 to $60 per barrel price environment, we are clearly right or probably understated when we say that costs are going to come down 20% to 30% over the next six months. That would have been – you would have probably seen cost come in further and of course we would be able to drill more of that wells given the level of CapEx in that environment. One other point is we do have quite a bit of non-operated wells in 2009 and if you look at our operated wells with two rigs, we would have 16 operated wells next year but the non-op activities are going to be active next year as well on top of our operating activity. Michael Jacobs – Tudor, Pickering, Holt & Co: That’s great, thank you very much for that. Just one final question to you, if you could just give us some detail on your contacts on the two regulatory – do you have any contracted rigs or you –

Yes, we currently have – we are to assume well to well contracts so we have in the entire company we have no long-term contracts. When they were trying to get us, fortunately our drilling contractors have worked with us and given us rigs without their long term contract so we are in good shape there. Michael Jacobs – Tudor, Pickering, Holt & Co: Great, thank you very much.

Gentlemen your next question comes as a follow-up from David Snow of Energy Equities Inc. Please proceed. David Snow – Energy Equities Inc: I am just looking at the return at 500,000 barrels in your previous slide I think your $50 it was 20% and $60 it was more like close to 30% and you brought that down for it to $16 and $24, what caused the change?

Yes. The upside of the numbers by the 500,000 barrel case is at the midpoint of that range with 16% at $50, 24% at $60 and $34 at 70%. David Snow – Energy Equities Inc: Those are a little lower than your previous slide?

Yes, they are. One thing I mentioned in there is we have seen our differentials expanded of late and so we factored that in this new economics and then LOE has been somewhat elevated of late as well. David Snow – Energy Equities Inc: How far the differential is expanded and what steps are underway to improve the take away?

This is Lance speaking, the differentials right now for the majority of them are still close to that range, your $6, $9 and $0.75 negative differentials we have got projected in there $10 differentials on average and then they reduced down to what we have been projecting about $6.5 negative differential in a year and a half. So we are expecting our differentials to go up over the next 18 months. David Snow – Energy Equities Inc: Is our take away capacity still underway there too still untied in the pipelines?

Say the question again pls. David Snow – Energy Equities Inc: Are you tracking it as one of the reasons and do you have takeaway capacity underway in – ?

For the most part the majority of the oil is trucked and then put in a pipeline and parked out. There is a lot of confusion in that. So everything we have right now has been truck and then put in the pipeline and carried out in the markets or trucked over to the refinery and then piped out. But what we are doing for our incremental capacity that we can’t get on the pipeline we will be putting in rail cars and railing out of the area and that is where you are hearing the larger differentials of patrolling of crude out of the basin and that can be as high as $17 or $18 a barrel of differential. So it will be a blend and that is why we have the tin, we are going to have the lower pipeline differentials in combination we suspect in the future with some significant reserves going out of the basin via rail. David Snow – Energy Equities Inc: Are there any plans to put pipes in to take it out?

There is a consortium of people talking about getting pipes in the ground to carry all out. If you can go back and listen to EOG, of course they have probably the largest volume in the area trying to get it out, you can probably get the most detail off of their conference all. XTO is another one. Yes and also Bridge is expanding their pipeline, they are not putting a new pipeline in but they are expanding their system and in the first quarter of 2010 we should go from 110 to 160. David Snow – Energy Equities Inc: And you will have access to the increment or will it be particularly much used by the EOG and others?

I think that is when everybody thinks that you are going to have a listen. If you listen to the other conference calls they show that in mid 2010 is when they take away problems are going to lessen but I think the industry is still pushing to get additional pipes in the ground out there because this is going to be such a large oil produced basin.

All of us operators will benefit from that, you would expect as we move into 2010 the differentials again contract. David Snow – Energy Equities Inc: Is there pressure from the tar sands also on the differentials?

The tar sands from Canada are actually creating some of the capacity problems that used to not be here for the basin as a whole but I know that there is a large pipeline coming out of Canada that still has over 100,000 barrels of capacity on it for that sour crude and the heavy crude. David Snow – Energy Equities Inc: Is that increasing or decreasing as a pressure?

It has increased over time. Right now, all the pressure is being created by the local markets, all the incremental.

And the tar sands seem to be seasonal. During the summer months they are using tar sands to a greater degree to make asphalt in Canada and they can’t do that during the winter months. So we tended to see at least historically that there is differentials expand during the winter months when that excess Canadian crew has been put in the pipeline since out to the US markets. David Snow – Energy Equities Inc: Okay, thank you very much.

Okay gentlemen, we do have an additional follow-up question from Chad Potter of RBC Capital Markets. Please proceed. Chad Potter – RBC Capital Markets: Hello again. I guess following up on that last question, I believe you guys have your gathering line late and you are just waiting on (inaudible) kind of timeframe that we expect to see gas fills there?

Well the gathering line is the gas gathering line and we have got the main trunk lines to our Ross area also with a water disposal line in there. So we are working with five different countries right now to build a small processing plant so that we can get our gas treated in the MDU pipeline. So we hope to have that in early next year. There are also a bunch of other alternatives like wetland EOG, if you listen to their conference call, their EOG and Hess are both permitting wet gas lines which will probably create a lot of opportunity to get the gas out of the market. Chad Potter – RBC Capital Markets: I guess separately actually you mentioned MDU, both MDU and St. Mary is kind of relatively condemned acreage at current pricing and services cost along the Burke Mountrail County line, any sort of commentary on that one?

I believe you are asking about MDUs and St. Mary’s wells, both are up in Burke County north of where we are. If you look at our Ross and our North Stanley area we are in Mountrail County and so it does look like based on the wells that we have been watching up there that the performance of those wells is quite a bit more marginal than the wells we are drilling in the Ross and North Stanley area. Jeff, do you want to add anything to that?

Yes we have been moderating that activity. There has been Three Forks and Bakken tests up in the Burke County area with some disappointing results we are clearly watching that but as Bud pointed out the vast majority of our acreage is as a result of that.

Yes, we have very little almost no acreage up there. Chad Potter – RBC Capital Markets: Right. I know you have like 9000 acres in that county.

Yes and that is part of the (inaudible) looking more perspective for the Three Forks but it is certainly a high risk at this point. Chad Potter – RBC Capital Markets: Yes same area definitely acres the Three Forks, thanks a lot guys.

Yes, that’s right. You are welcome.

Ladies and gentlemen, this concludes the question-and-answer portion for your conference today. It is my pleasure to turn your presentation back to Bud Brigham for his closing remarks. Sir?

Thank you Carol and thank you everybody for participating in our call. We look forward to reporting on what should be an exciting finish to the year.

Ladies and gentlemen thank you for your participation today. You may now disconnect and have yourself a great day.