Bud Brigham – Chairman, President and CEO Gene Shepherd – EVP and CFO Lance Langford – EVP of Operations Jeff Larson – EVP of Exploration

David Snow – Energy Equities Inc Chad Potter – RBC Capital Markets Michael Jacobs – Tudor, Pickering, Holt & Co

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 have been covered fairly thoroughly in our press releases. After our Williston Basin operational summary Gene will give you a review of our financial results for the quarter following which we will be happy to answer any of your questions. First some general comments regarding the Williston Basin. In our view the Williston Basin Bakken and Three Forks reservoirs will likely become the largest oil field discovered in North America in the last 40 years. It is already clear that it is the largest economically viable oil resource play in North America and its standing production may surpass that of the largest North American oil field Prudhoe Bay within the next five to seven years. As a result the Williston Basin Bakken and Three Forks development is critically important for our nation’s energy needs. This giant field can positively mitigate our negative trade balance and improve our energy security by proportionally reducing our countries oil imports. Further while some are concerned that the burgeoning natural gas supply as a result of the numerous natural gas resource plays being developed around the US negatively pressuring domestic natural gas prices over the next several years the Williston Basin Bakken and Three Forks Play is the only large scale high quality oil base shale play in North America. Given that and the associated stronger margins we therefore expect to continue to be provided by oil over the next several years, we anticipate a very positive differentiation in favor of quality Williston Basin Bakken and Three Forks operators. Brigham Exploration with almost 300,000 net acres in the Williston Basin given our small size is the public company most leveraged to the Williston Basin Bakken and Three Forks Play. Importantly primarily as a result of our growing Bakken and Three Forks production, our company’s net oil production is expected to double to about 2000 barrels of oil per day in the fourth quarter of 2008 relative to the year-ago period. Given our inventory this growth in our oil volumes is just getting started. It is also important to note, as we pointed out in our operations press release that our cash flows are benefitting from this transition. During the third quarter an equivalent Mcfe of our oil volumes assuming a 6:1 conversion generated roughly 1.9 times of that revenue of an Mcf equivalent of natural gas. In other words, our estimated 2000 barrels of oil per day for Q4 on a 6:1 conversion is roughly 12 million cubic feet of equivalent production but it is generating revenue roughly equivalent to 22 million cubic feet of natural gas production. This is a very, very beneficial transition for us and we believe we will be increasingly positively differentiated by this over time. Gene will discuss our current thoughts on 2009 CapEx. We are currently iterating on our 2009 budget and it is safe to say that the majority of our capital expenditures will go to drilling in the Bakken and the Three Forks where we believe we can generate good returns at oil prices as low as $50 to $60 per barrel. I will discuss that further in a minute. Gene will also discuss the fact that given the current state of the capital markets we will be living much closer to our cash flow than we have in prior years. We are going to be conservative as we move forward and when things improve we will be in a position to accelerate. Given that most of our acreage in the Williston was recently acquired with five-year lease terms and that we believe we can extend those terms if we need to, we think we can afford to be conservative without losing our valuable acreage inventory. Now I will briefly get more specific regarding our operations in the Williston Basin starting west of the Nesson Anticline where we have two very important wells completing or near total depth. As those of you who follow the Bakken and the Three Forks Play know, Brigham and other operators have seen significant improvements in our well performance as we have optimized our operations in the play. These improvements are facilitated by the substantial activity in the region and the sharing of information that takes place in the basin in both an informal basis as well as through our participation in a large number thus far 52 non-operated Bakken and Three Forks wells at low working interest. We expect those operational enhancements to continue into the future. Importantly we believe we are the first company in North America and the Williston Basin to successfully run 19 swell packers in a long lateral in an attempt to stimulate 20 intervals. We have also run a swell packer further out in a long lateral than anyone in the Williston Basin to a total measured depth of 20,095 feet. Like other leading operators in the Basin we spent time conditioning the well bore prior to running the swell packers at the bottom so now they are steady and we have our frac scheduled for the Olson in early December. During the frac, we will be using the perf-and-plug method throughout the entire length of the long lateral and that is as opposed to sliding frac sleeves. We believe the perf-and-plug method is likely more optimal for initiating the fractures in the reservoir, just another example of one of the recent development that appear to be improving performance. It is our belief that these procedures that we are incorporating could represent the next step in operational progression in the play outside of the Parshall Austin (inaudible) area with the potential to provide another step change improvement in the economics. Again we expect more developments as we move forward. To understand how rapidly things have evolved in the basin, you simply have to look back at where we have come from since late 2006 when the service companies were recommending to us completing our well with one large uncontrolled fracture stimulation. Since that time, we have experienced substantial improvements in well performance as we have moved from the single uncontrolled frac in a long lateral, the swell packers with 6 or 7 intervals in short laterals during 2007 and early 2008. Beginning mid-year this year, our best wells today have been completed with 10 to 12 oscillated and stimulated intervals in short laterals. Given this progression in performance we have high expectations for our Olson and Figaro wells to the west of the Nesson Anticline where we have drilled a long lateral roughly 9600 feet in length through the middle Bakken and where we plan to frac 20 intervals pro well along each lateral. In this area west of the Nesson Anticline we fraced 7 intervals in our Mrachek short lateral wells which came on for about 727 barrels of oil per day. Given the improvement we have seen in our Bakken wells with 10 to 12 intervals, we are eager to see the results of fracing 20 intervals in a longer lateral with more reservoir exposed. Now shales are not definitive in this play but you would rather have them than not and the Olson and Figaro have provided some of the strongest shelves we have seen today including excellent oil shelves over the shakers and intermittent three to four foot natural gas players with 10 players [ph] of up to 20 to 25 feet in length. Again these wells are long laterals utilizing swell packers and we are planning to attempt a fracture stimuli 20 intervals in each of the wells. Both wells are currently scheduled to be fraced in early to mid December, so we should have results by late December or early January. We have roughly 95,000 net acres in this area of North Dakota, west of the Nesson Anticline which we call our Rough Rider project. With success a semi two long laterals per 1280 acres, we could drill up to 148 net long lateral Bakken wells to fully develop our acreage here. So this is a very important area for us. One last point about our Rough Rider area west of the Nesson Anticline, if you view our updated map of the area in our corporate presentation, I believe it is slide number 19, you will see that other operators are also accelerating their drilling near our acreage. These operators include Whiting, Continental, Encore, Conoco Phillips and Petro Hunt and Petro Hunt by the way are drilling a well directly offsetting some of our lease hold in McKenzie County. Some of this flurry of activity includes Three Forks wells which we believe has excellent potential under our 95,000 net acres in our Rough Rider area. Now I will move each of the Nesson to the Mountrail County area. Last week we announced four Parshall Austin area Bakken completions. As expected our two 25% working interest EOG operated wells, the Austin 25-35H and the Wayzetta 13-01H are both strong wells. Both came on at about 1700 barrels per day. We also had a 18% working interest in the successful Slawson operated Payara 1-21H. Due to mechanical difficulties they were only able to do a large single stage fracture stimulation. Despite the less than optimal stimulation, it is a strong well producing at an early rate of about 574 barrels of oil and 287 Mcf of natural gas per day. The only well we were disappointed in was the Kvamme 2 1H which came on averaging about 150 barrels of oil per day. However it is an area where we don’t have much acreage and it helps us to define the eastern edge as the more prolific area. We have another EOG operated well currently completing. We have a 12.4% working interest in the EOG Austin 19-30H which is located in the same township as the other prolific Austin producers just north of the Parshall Field. This well is currently being fraced so we should have some news on it later in November and it should be another very strong well. In total we control about 8700 net acres in the Parshall Austin area assuming 320 acres pricing with short laterals the company could drill about 27 net wells in the area so we have significant reserves here that we will be developing over time. Assuming 700,000 barrels of oil per well and assuming 80% net revenue the Parshall Austin area by itself could provide us with net reserves of over 15 million barrels of oil. These are probably reserves moving into the proved category over time with additional potential provided by the Three Forks. Now moving to our Ross and North Stanley areas we began production tubing in our previously announced Carkuff Bakken producer which after 12 stimulations came on at 1110 barrels of oil per day. This well continues to perform well; we recently put it on pump and have been producing about 332 barrels of oil and 324 Mcf natural gas per day after having already produced about 25,000 barrels of oil. Also in the Ross area we have a 30% working interest in the (inaudible) which came on at an early rate of about 656 barrels of oil and 505 Mcf of natural gas per day. Importantly we are currently preparing to spud our first long 24 hour stage Bakken test in the Ross area the Anderson 28-33 1H. This well is less than 2 miles to the west of our Carkuff well. Given how well the Carkuff has performed with 12 fracs, we are looking forward to seeing how a longer lateral produces after 20 stimulations. Fundamentally more reservoir rock exposed and fractured should generate power rates and recoveries. We are also developing the Three Forks in the Ross and North Stanley areas. Our recent Three Forks discovery the Adix 25 1H was a short 5559 foot lateral with 12 fracture stimulation intervals and it also continues to perform well. It came on initially at about 765 barrels of oil and 760 Mcf of natural gas per day in very early October. We had also to put it on pump and it is currently flowing about 350 barrels of oil and 320 Mcf of natural gas per day. About two miles west of the Adix, we have just commenced another important Three Forks test the Strobeck 27-34 1H. The Strobeck like the Anderson Bakken test in the same area will be a long lateral test with 20 fracture stimulation intervals. To our knowledge this will be the first long lateral Three Forks test with 20 fracture stimulation intervals using the perf-and-plug method. Again more reservoir exposed and fractured should mean more rate and reserves. About 18 miles to the north of the Adix and Strobeck wells in the North Stanley area, we have a 25% working interest and are currently drilling short lateral Three Fork tests the Fidelity Grove 11-36H. We should have results for this well by early December. So in summary we are achieving strong well performance in the Ross and North Stanley areas. We are in development mode here. We are moving reserves from probable to proved and we expect that a good portion of our 2009 capital budget will likely be spent in this area. Our results have improved substantially as we have increased the number of frac stages from 6 or 7 stimulations to 10 to 12. For example, it appears our Carkuff and Adix wells reserves likely average in the range of 500,000 barrels of oil or possibly better. In addition just five to six miles to the South east of our Ross area, Whiting has delivered some even more recent wells with rates as high as 4500 barrels of oil per day. I encourage you to view slide no 27 attached to our corporate presentation so that you can view the well performance on and around our acreage. These recent results have given us the confidence to move our expected reserve range for most of the wells we will be drilling in the Ross and North Stanley areas up to 300,000 to 700,000 barrels of oil per well. That is up from our prior range of 200,000 to 400,000 barrels per well. We are currently seeing higher differentials and higher LOEs of late. Incorporating these higher differentials and the recent higher lifting in operating expenses while it is in the early pull back in drilling and completion costs we are seeing, we estimate the rate of return on a mid-point well in this area, a 500,000 barrel well at 16% for the $50 per barrel oil case, at 24% in the $60 per barrel oil case, and 34% in the $70 per barrel oil case. We are in the process of updating our economic slides attached to our corporate presentation and encourage you to view them. We do expect drilling and completion cost to come down further as we move forward. Our expectation is for cost to come down 20% to 30% over the next six months which should further support our economics. We also believe that our utilization of longer laterals with 20 stimulations could provide a significant step change improvement in the economics here. If that does occur, we will once again be updating our economic expectations in January. We believe the economics of this play will only get better. We will benefit from lowering costs over the next 12 months and our continued operational improvements. Given that we control approximately 36,876 net acres in the Ross and the North Stanley area, assuming two long laterals drilled per 1280 acres in the Bakken and two more long laterals drilled per 1280 acres for the Three Forks we could ultimately drill 115 long lateral wells to fully develop this area alone. If you assume 500,000 barrels per well, we could have over 47 million barrels net to develop in this area alone. As we discussed in our operations press release, our Bakken drilling is now providing the consistent quarterly growth in longer reserve lot higher value oil production in reserves. We expect this very positive trend to continue in years to come. Briefly before I wrap up and hand the call over to Gene, I will say a quick word about the Anadarko Basin with (inaudible) Woodford shale play. We currently control about 12,700 net acres in this emerging horizontal drilling resource play. We have been active in the trend since the early 1990s and we have had a great deal of success over the years drilling primarily Springer and Morrow wells. We are participating in our first horizontal Woodford well the Cimarex operated Base Farms 1-23H. As noted in our press release, this well is in the same area where most of Cimarex and Devon’s recent Woodford completions produced a peak rate of between 5.8 Mcf and 8.4 Mcf of natural gas per day (inaudible) stated that the reserves could be 4 Bcf to 5 Bcf per well. If the Base Farms 1-23H is successful, we could drill up to three offsets to develop the section and assuming full development of our 12,700 net acres, we could potentially participate in 79 net wells. Assuming 4 Bcf per well, we could potentially develop about 250 Bcf year net to our interest. So this could play could end up being significant for us over time and it is an example of how our legacy areas expose it to some of these new emerging resource plays. That completes my comments, now I will turn the call over to Gene to review our financial progress after which we will be happy to answer your questions. Gene?

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 is a very beneficial transition that is underway for us. As reflected in the updated guidance that we issued last week, we expect our production volumes to resume their upward trend in the fourth quarter with the anticipated hook up of two new Southern Louisiana producers to sales during the fourth quarter. Our improving and accelerating Bakken operated drilling results in the ramp up of our Bakken non-operated activity particularly in the prolific Parshall and Austin fields. One of the recently completed Southern Louisiana wells has hooked up to sales in late October at an initial rate of 17.2 MMcfe per day or $5.7 million net to Brigham. We expect our second Southern Louisiana to be hooked up to sales in late November based on production tests this well could produce at a gross rate of 15 MMcfe per day to 20 MMcfe per day or approximately $6 million to $8 million per day net to Brigham. Our remaining two Southern Louisiana wells are currently expected to be hooked up to sales in early 2009. At present we are developing a preliminary 2009 CapEx budget that we will be reviewing with our board of directors in December. Given the recent downturn in commodity prices and the ongoing turmoil in the financial market, our plans are to consistent with much of the rest of the industry reduce the level of our 2009 CapEx to live much closer to our cash flow in 2009. Minimize our land in G&G CapEx in favor of maximizing our 2007drilling CapEx and the associated 2009 production and cash flow. Focusing the majority of our drilling capital in the Bakken and Three Forks where even with reduced commodity prices we can still generate attractive rates of return and strong net asset value growth for our shareholders. Focusing the majority of our Bakken and Three Forks drilling capital in our proven development areas in the Ross and North Stanley areas where our significant acreage position and exposure to both Bakken and Three Forks potential leaves us with plentiful drilling opportunities in areas where we achieved our best drilling results today. Concentrating the majority of our efforts in CapEx dollars in these areas will enable us to meaningfully and predictably impact production and cash flow while financial markets recover and commodity markets stabilize. Finally we will continue to review our conventional plays to opportunistically divest of non-strategic assets, in addition we will explore opportunities to bring in joint venture partners in certain of our unconventional projects however with the current industry fundamentals we recognize this may be difficult and we are currently operating under the assumption that these opportunities will not have a meaningful impact on our budgets and are therefore planning our capital program accordingly. Based on these guidelines we are currently forecasting that we would spend between $90 million and $120 million of 2009 E&P CapEx however this amount will not be finalized until we meet with our board of directors. We expect that we will be finalizing the 2009 CapEx budget early next year but are currently implementing the measures I have just listed to ensure that capital spending during 2009 meets these guidelines. We are forecasting that we will be some modest degree of spending beyond our forecasted cash flow and expect that availability under our senior credit facility will fund the shortfall. As we announced in yesterday’s earning release we have recently closed on our borrowing base redetermination, it has taken our borrowing base from $135 million to $145 million. Based on the $79 million outstanding under the senior credit facility on October 5, this leaves us with current availability under the senior facility of $66 million. Banc of America is the lead bank on our senior credit facility and we do not believe based on our experience in increasing the borrowing base that our access to this availability will be limited. To summarize we feel that with the downturn in commodity prices and the current unsettled financial markets, we are taking a conservative approach towards 2009 CapEx. As I stated we will not be finalizing 2009 CapEx until January and there are a number of factors that could positively impact our final budget. Importantly we like the fact that the majority of our 2009 drilling CapEx will target the Williston Basin Bakken oil resource play which we believe offers us attractive economics even at lower prices. We believe that the silver lining for BEXP [ph] provided by soft natural prices will result in the migration of oil field services to the Williston Basin and these markets fundamentals will generate a meaningful reduction in our drilling completion cost during 2009 further enhancing a return even in low commodity prices. I am sorry I mentioned earlier October 5; it is November 5 where our outstanding balance was $79 million. As far as the income statement is concerned, the higher commodity prices partially offset the impact from lower production volume and increased hedge settlement losses during the third quarter resulting in a 6% decrease in revenues including hedge settlements to $29.6 million. Third quarter 2008 revenues were positively impacted by $10.8 million due to a 59% increase in pre-hedge commodity prices. These increases were partially offset by a $8.5 million decline in revenues due to the aforementioned decline in production volumes and a $4.1 million increase in cash hedged settlement losses. Including our hedge settlement losses but excluding our unrealized gains, average realized prices for the quarter increased about 48% to $11.89 per Mcfe compared to $8.5 million [ph] in the prior year’s quarter. On a per unit basis, these operating expenses increased 88% to $1.24 per Mcfe in the third quarter from $0.66 per Mcfe in third quarter of 2007. Oil production volumes (inaudible) increase in the dollar amount of our operating and maintenance expense accounted for the increase more partially offset by 68% decline in the dollar amount of work over expense and a 26% decline in the dollar amount of our (inaudible) Texas. The increase in O&M expense was driven by higher salt water disposable expenses, compressor rental and maintenance expense, and electricity and fuel costs. On a per unit basis, production taxes increased to $0.56 per Mcfe in the third quarter 2008 from $0.24 in the third quarter of 2007. The increase in the dollar amount of production taxes for the third quarter of 2008 from that in the prior year’s quarter relate primarily to $0.3 million decline in higher cost, gas production tax abatement in connection with our recent Vicksburg and Mills Ranch wells. General and administrative expense at $2.5 million for the third quarter of 2008 was essentially flat with the $2.5 million incurred in the third quarter of 2007. Completion expense was lower by $3.1 million as a result of our reduced production volumes the impact from the reduced volumes was partially offset by an increase in our DD&A rates. Our commodity prices partially offset the impact of lower production volumes and the increase in lease operating expense resulting in a 13% decrease in EBITDA during the third quarter of 2008 to $23.1 million. Net income for the third quarter including the impact of our non-cash hedging gains was $4.3 million or $0.09 per share. Moving to the balance sheet at the end of the quarter we had $72.9 million outstanding under the senior credit facility and $116 million of senior notes. In terms of our levered statistics, we ended the quarter with total debt to book capitalization ratio of 45%, and a total debt to EBITDA ratio of 2.4 to 1. Recapping capital spending activity for the third quarter, exploration and development capital expenditures totaled $46 million, of which $36.7 million went to drilling expenditures and $9.2 million went to land and G&G expenditures. In our operations release last week we updated our production guidance for the fourth quarter of 2008. In terms of our expectations for the fourth quarter, we are forecasting production volumes to average between 33 and 37 million cubic feet of equivalents per day. Of this we expect our oil volumes to make up roughly 34% of our fourth quarter volume. This would equate to fourth quarter oil production of approximately 2000 barrels per day or roughly double that of the fourth quarter last year which should be a real positive for our current quarter revenues given the superior economics associated with oil versus natural gas. That concludes my remarks and I will turn the call back over to Bud.

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.