Bud Brigham - Chairman & CEO Jeff Larson - EVP, Exploration Lance Langford - EVP, Operations Gene Shepherd - EVP & CFO

Subash Chandra - Jefferies Michael Jacob - Tudor, Pickering & Holt Scott Hanold - RBC John Freeman - Raymond James Steve Berman - Pritchard & Capital Partners Joel Musante - C.K. Cooper & Company Ron Mills - Johnson Rice Mike Scialla - Thomas Weisel Partners Derrick Whitfield - Canaccord Adams Joe Allman - JPMorgan Dan McSpirit - BMO Capital Markets

Good day, ladies and gentlemen and welcome to the Fourth Quarter 2009 Brigham Exploration Company Earnings Conference Call. My name is Francis and I will be your coordinator for today. At this time, all participants are in listen only mode. We will be facilitating a question and answer session towards the end of this conference. (Operator Instructions). 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, Bud Brigham, Chairman, Chief Executive Officer and President. You may proceed.

Thank you, Francis. Thanks to each of you for participating in Brigham Exploration Company's year end and fourth quarter 2009 conference call. With me today we have Gene Shepherd, our CFO and Executive VP, Lance Langford, Executive VP of Operations, Jeff Larson, our Executive VP of Exploration, and Rob Roosa, our Finance Manager. Importantly, before we get started, I'd like to encourage you to be prepared such that during the course of this call you can view our conference call presentation, which can be accessed via our website at www.bexp3d.com. It includes very helpful information regarding our year end and fourth quarter 2009 results, as well as our plans for 2010. We'll be referring to the slides in the presentation during our discussion. During the call, we're going to make some forward-looking statements to help you understand our company's results. In our company's SEC filings and the press releases that were issued yesterday there are some risk factors that should be noted that might cause our actual results to differ from what we talk about today or from our projections. I encourage you to review our filings with the SEC. In addition, in this call we may use the terms probable and possible reserves that we do not include in our SEC filings. We may also discuss locations, which include proved reserves as disclosed in our SEC filings. Please refer to page two of our corporate presentation for a cautionary note to U.S. investors regarding the use of the terms probable and possible reserves and locations. Finally, a copy of our company's press releases, as well as other financial and statistical information about the periods to be presented in the call will be available on the company's website, under the section entitled Investor Relations at www.bexp3d.com. So let's get started. First if you'll go to slide 3, you can see our outline for the call today. I am going to provide you with an overview and a few hard points following which Jeff Larsen will update you on our operational activity in the Williston. After that Lance will discus reserves and finding costs and Gene will finish up with a financial update. After our updates we would be happy to answer any questions. On slide 4 you can see a list of our achievements during 2009. I won't go through all of them but will simply say that we're proud of the operational leadership we provided in the Bakken and Three Forks play. We've now drilled 13 consecutive high rate, high frac stage long laterals with an average initial rate of 2,379 barrels of oil equivalent per day. We're also pleased with our very solid reserve growth despite relatively modest drilling capital investments and we're excited about the transformation of our company from a predominantly shorter lived natural gas exploration company to an oil driven resource player with a 17 plus year inventory of de-risk core projects assuming our current four rigs running. Importantly, our operated proved developed drilling costs in the Bakken and Three Forks was only $13.75 per Boe and that's our engine for growth. Moving forward to slide 5, you can see the oil commodity advantage has persisted for the last several years. We expect oil to be the favorite commodity domestically for at least the next three to five years, given the ample supply of natural gas provided by the numerous quality unconventional gas plays. As you can see on slide 6, we're ideally positioned to capitalize on this advantage, given our huge position centered in the core of the only large high quality domestic oil resource play. We believe we'll continue to benefit from a very well supplied natural gas environment, which we expect to keep our cost to drill and complete our wells low, thereby providing attractive margins and returns on our huge inventory of Bakken and Three Forks oil drilling projects. In slide 7, is last quarter's corporate presentation slide showing our well by well growth in Bakken and Three Forks oil production. Now that was through the third quarter and if you move forward to slide 8 you can see how we progressed during the fourth quarter of 2009. Our fourth quarter Williston Basin production was up 18% relative to the third quarter. Clearly, this is what you want to see for a resource play, predictable additions to production and reserves, in this case with results improving significantly over time. Not shown on the graph in a box on the upper right of the slide you can see that our Liffrig Three Fork's discovery which came on at over 2,400 barrels of oil equivalent per day is now producing. As we move forward this slide will begin to reflect our acceleration, given that we've gone from one to four rigs and as a result we have four wells tracking or waiting to be fraced. The production growth on this slide should accelerate as we move forward in time. In the yellow box, you can see how early we are in developing the de-risked portion of our inventory, having moved only 19 net wells proved developed in the reserve report, and that would be roughly 4% of the roughly 452 de-risked locations in inventory. Slide 9 simply illustrates the impact our Williston drilling is having in our company's oil volumes and that's despite the fact that we're just getting started. We’ve quickly grown meaningful oil volumes and transformed to a resource driven oil company. Our fourth quarter oil production was up roughly 10% sequentially, again despite no drilling done in the first half of the year and only one rig completing wells during the second half of 2009. Slide 10 illustrates our first quarter and full year 2010 guidance. Given that we now have four rigs running, we expect to more than double our oil production to an average of almost 5,000 barrels of oil per day in 2010. Slide 11 illustrates our company's total oil production volumes with the green line and of course the growth is driven by our Bakken and Three Forks drilling. The orange bars illustrates our Bakken and Three Forks net wells completed and currently expected to be completed by quarter. Looking at these slides you can see the meaningful oil production growth that our very modest 2009 drilling generated. With eight wells either completing or drilling today, the second quarter will see very substantial production additions. Further, I think you can see from this graph while we're confident that we'll more than double our oil production to almost 5,000 barrels per day in 2010. Moving to slide 12, you can see our six to one equivalent production volume and they were becoming oilier pretty quickly. In the fourth quarter, we were 57% oil. In the full year 2010 we expect to be 70% oil. We're essentially replacing our shorter reserve life gas reserves with 30 year economic life higher value oil reserves. As shown on slide 13, oil continues to trade at a substantial premium to natural gas. In the fourth quarter, our oil volumes were sold at a 13.7 equivalency as opposed to the six to one convention. Given that our oil mix is growing and that it doesn't trade at that six to one conventional conversion to natural gas. The prior illustration is misleading regarding our engine for growth. On slide 14 you can see our realized equivalency by quarter based on the actual prices we received. Although our activity has been relatively modest in 2009, you can see we've substantial grown our realized equivalent production volumes by becoming oilier. Again, we expect our oil volumes to more than double in 2010. Now I'm just going to make a couple of quick comments on reserves given that Lance is going to cover our reserve report in some detail in a minute. On slide 15, you can see the remarkable transformation of our reserves that occurred during last year. Our predominantly long life Williston oil reserves grew from 18% of our reserves in 2008 to 56% of our reserves in 2009. In addition, our total reserves grew by about 21%. Slide, 16 also illustrates our newly quantified probable reserves; these were quantified independently by our third party engineers. Our 2P hydrocarbon volumes are estimated at approximately 83 million barrels of oil. Roughly 90% of these probable reserves are Bakken and Three Forks which we expect to convert to approved over the next several years. On slide 17, a couple of quick points on finding costs. Our total proved all sources F&D cost for 2009 was $11.08 per BOE. If you focus in on our Rockies province our proved developed drilling cost was $16.16 per barrel. Maybe, most importantly you see it look at our agent for growth. Our Bakken and Three Forks proved developed drilling cost was a very attractive $15.73 per barrel. It's also important to look at the next slide, slide 18. Although we participate on a non-operated basis and attractive field such as Parshall, Austin and the Sanish field, our operated proved developed drilling cost were substantially lower then our non operated, another very positive statement about the great works that our operations in G&G team are doing. Our operated proved developed drilling cost was $13.75 per BOE and operated drilling will be the primary driver of our reserve additions. And last on finding costs. If you'll view slide 19, you will see that given the commodity pricing advantage that oil offers, low finding costs and predominantly oil place such as the Bakken generate substantially superior economics to the same finding costs in predominantly natural gas place today. Now one last comment before I hand the call over to Jeff. Slide 20, shows the improvements our team has delivered in well performance as we have increased the number of frac stages. Lance will have more to say on this in a minute but it's our belief that we are still early in optimizing how the drilling completes these wells. As evidence by recent wells, the results continue to improve and we believe therefore that we are in the very, very early stages of figuring out how to optimally get this tremendous resource out of the ground. Clearly there is much more to come. So with that I am going to turn the call over Jeff to give you an update on our operations in the field.

Thanks Bud, slide 22 highlights our inventory of acreage and potential drilling locations in the Williston Basin. Looking at the green box and excluding the Three Forks in Rough Rider we believe that we derisked about 452 net locations in our 146,500 core acres in Easy Rider and Rough Rider. Also shown in the yellow box, we've only drill about 4% of these locations and by drilling 25.7 net wells this year; we'll develop only an additional 6%. The derisked represents more then the 17 year inventory with four rigs running and that doesn't include other objective and the potential impact of our Williston Basin acreage that we hope to de-risk in the near future. So you can understand why we would like to further accelerate our development over four rigs we are currently running to bring forward the very substantial net asset value in front of us. I should point that we've also done an excellent job managing any material lease exploration in Williston Basin. We originally designed our three rig program to stay ahead of lease explorations and now with four rigs running, we're well ahead of any material issues. Now I would like to update you by area with the summary of the key areas on slide 23. As you can see on this slide, we've actually grown our acreage position in Rough Rider to almost a 105,000 net acres at year end. Given other opportunities that are in a fairly advanced stage, we expect this position to grow further. Moving forward to slide 24, to look at our drilling results in the Rough Rider area, subsequent to our Mrachek with regards excess full of seventh stage short lateral well, we've now drilled 10 consecutive high rate, high frac stage long laterals with average early rates of roughly 2,400 barrels of oil equivalents per day. As you can see on the map of our Rough Rider area, these wells highlighted in yellow are well dispersed across our acreage plot. Given that we believe we've essentially derisked the Bakken in this area and that we're now in development mode. We currently have three Rough Rider wells completing, shown in green and three wells drilling, shown in orange. So we will have a steady stream of results and wells coming on line. We have also seen a significant ramp up in non-operated activity on the edges of our block, highlighted in gray on the map. In addition, we're very excited about the three course potential in Rough Rider, in part because several operators to the south east of us have drilled relatively good producers using inferior completion technology. And today Continental Resources announced that they are flowing back a Three Forks completion in their overt well directly to the west of our block. Lastly our Olson wells seen on slide 25 will record the Bakken in upper Three Forks provides another important data point and encouragement about our Rough Rider Three Forks potential. The curve on the far left side is a core Gamma Ray. Importantly, we see the same clean Gamma Rays (inaudible) member starting at 10,682 feet as we see in Montreal County. The Three Forks also has good oil saturations in the core. We expect to commence our first Three Forks test with US energy in the second quarter. Speaking of catalysts, looking forward to drilling our first high frac stage long lateral Bakken well in our Eastern Montana acreage block in mid March, as shown on slide 26. Our plans are to core this well in both the Bakken and upper Three Forks and hence be very thoughtful in our analysis. As a result, we may not complete the well immediately. We've included a key offset well on slide 27 which demonstrates why we are excited about Eastern Montana. Notice that both the upper and lower Bakken Shales are highly resistive, indicating thermal maturity and also that the middle Bakken is approximately 35 feet thick with a well developed Porosity member similar to Rough Rider. Moving East to Montreal County North Dakota and the Ross area as shown on slide 28 Tuesday, we announced our Liffrig well on the North West side of our Ross block. This is our third Ross Three Forks well. It has also had the highest early rate of a There Forks well at over 2,400 barrels of oil equivalent per day. Our fourth Williston basin rig is currently drilling our 95% working interest Sorenson well which is the west offset to possibly the best well that we drilled to date in the basin the Anderson. Given the Bakken and the Three Forks wells, we and other operators have drilled in and around our Ross Block. We think it's obvious we're in development mode for both the Bakken and the Three Forks. Finishing up, we also have our extension areas to the north and south of Montreal. Other operators continue to drill wells proximate to our acreage which is helping us to lineate the economics of these areas. We are continuing to explore potentially bringing in JV partners on some of this acreage. That concludes my remarks. Now I'll hand the call over to Lance to discuss reserve.

Thank you, Jeff. Before I review our year-end 2009 proved reserves, the key takeaway for everyone should be the tremendous impact of our Williston Basin, Bakken and Three Forks drilling program on our 2009 reserves. This point is significant given that we just spent $50 million on drilling in the Williston Basin during 2009 and we plan to increase our drilling capital to buy 250% to $176 million in 2010. 2009 was the first year we've been able to demonstrate the immense reserve potential of the Williston Basin and we are pleased with our reserve results we announced yesterday evening. In 2008, our efforts were hampered by low commodity prices, high differentials and high service cost. In the second quarter of 2009, the situation began to reverse itself. Benefiting from the improving macro environment and the proceeds from our May 2009 equity offering, we resumed our Williston Basin drilling and completion operations. Since we restarted our drilling program in the Williston Basin, we added 9.4 million barrels of oil equivalent to our reserves and ended 2009 with our reserves at record levels. Importantly, our proved reserves were comprised of the record level of crude oil. One of the key elements of our success in the Basin was our vision on how to drill and complete our long lateral wells which has been validated by our steady improving drilling results. The credit goes to our staff. We're not a large company but we have a highly motivated and talented group of employees that are committed to delivering results for our shareholders and dedicated to being at the forefront of technological development. As a company we have transitioned from a conventional Gulf Coast exploration company to an oil resource play company with a deep inventory of Bakken and Three Forks drilling locations. In 2009, as we mentioned earlier we spent $50 million of our total $58 million of drilling capital in the Rockies while we only spend $7 million in our historically active onshore Gulf Coast. If you view slide 30, you can see that our Gulf Coast proved reserves as a percent of our total proved reserves declined from 55% to 30% from last year to 2009 while our Rockies proved reserves as a percent of total proved results increased from 18% to 56% from last year to 2009. Our proved reserves are now 60% oil versus 31% in 2008 which represents a record level of oil as a percent of total proved reserves. Now on to a more detailed discussion of our reserves. Our third party engineering firm Cawley, Gillespie & Associates prepared our year end 2009 proved reserves as they have in the past. As shown on slide 31, Cawley, Gillespie's year end 2009 proved reserves for Brigham are 27.7 million barrels of oil equivalent which represents a 21% increase from our year end 2008. The 27.7 million barrels of oil equivalent represents a record level of reserves for the company. Looking first at our reserve additions, the company added 9.4 million barrels of oil equivalent of reserves during 2009. We replaced 372% of our 2009 production when revisions are netted out of additions. If revisions are excluded, we replaced 524% of our 2009 production. Our additions were dominated by the Williston Basin, Bakken and Three Forks reserves. Our proved reserves in the Rocky Mountain increased 278% to 15.4 million barrels of oil equivalent at year end 2009. The key drivers behind this level of reserve growth in the Williston Basin are our technological drilling and completion improvements, some of which are shown on slide 32. The four major drivers of our strong Williston Basin horizontal well performance are one, our geosteering, which allows us to stay within a 10-foot target zone over the entire 10,000 foot length of lateral and thereby contacting more of our highest quality rock. Two our use of more swell packers which allows us to perform more stages resulting in the effective stimulation of the entire horizontal well bore. Three, our use of perf and plug technique which helps us selectively pin point and create more fractures between the swell packers and finally four, our use of high concentrations of ceramic propants which creates and retains high conductivity fractures to the well bore. In determining our additions, Cawley, Gillespie independently reviewed all of the producing wells and first assessed the overall proved develop producing reserves for each well. As we have discussed in the past and now confirmed by Cawley, Gillespie, our EURs for our long laterals with multistage fracs are estimated to average between 500,000 and 700,000 barrels of oil equivalent. Next they looked at all the other pertinent offsetting wells and evaluated whether our potential horizontal Bakken and Three Forks locations would be booked at PUD locations. As shown slide 33, under 2008 SEC rules we booked no more then two PUD locations offsetting the producing well. As a result of the SEC monetization of its reserve rules Cawley, Gillespie took the position that up to four PUDs could be booked offsetting a producing well. This does not imply that each producing well has 4 PUD locations booked. It only implies that 4 locations were booked where we had acreage offsetting the producing well and the productivity of the off setting producing wells justified a booked PUD. 57% of our proved reserve editions met the 2008 SEC requirements which allowed the booking of up to 2 PUD locations offsetting the producing well. The other 43% of our proved reserve editions of approximately 4 million barrels of oil equivalent were added as a result of the new SEC rules. These were the third and fourth PUD locations offsetting a producing well. Again, not in all instances did we book all four locations surrounding the producing well. Furthermore our operated PUD locations averaged 80% of the reserve level of our average operated long lateral multi stage producing wells on a gross basis. One final point regarding the assessment of reserve additions, Cawley, Gillespie used a 8% final decline rate when calculating our reserves. We believe there is additional upside to the final decline rate to potentially be as low as 5% or 6% if lower final decline rates hold through, we should have positive reserve revisions in front of us as we move forward. In terms of revisions, the company had negative revisions of 2.7 million barrels of oil equivalent in 2009. Our revisions were dominated by the drop in of 13 PUDs along the onshore Gulf Coast and the Anadarko Basin that no longer fall within the new SEC five year development window. These wells no longer fall under the development window because of the transformation I spoke of early from a conventional exploration company to an oil resource play company with a 17 plus year inventory of Bakken and Three Forks development locations. Our extensive Bakken and Three Forks inventory and associated strong Williston Basin returns that were generated, caused us to push up our estimated time for drilling the 13 conventional PUD locations beyond the five year mandatory window. Importantly these PUDs continue to meet all other SEC requirements and with an unlimited capital budget would still be classified as proved reserves. Our 2009 production was 1.8 million barrels of oil equivalent. Full volumes were a record 46% of total production. This is up from 30% in 2008. Looking at F&D costs for 2009 on slide 34, our all sources F&D cost which include drilling, land and seismic and capitalized cost were $11.08 per BOE including revisions and $7.86 per BOE if you excluded the revisions. Our exploration and development capital F&D cost which includes our drilling and land and seismic capital only were $8.98 per BOE including revisions and $6.37 per BOE if you excluded revisions. Looking at slide 35, if you look at our proved developed finding cost for our Bakken and Three Forks wells they were $15.73 per BOE using drilling capital only. Looking at slide 36, if you break our Bakken and Three Forks proved developed finding costs between our operated and non operated portfolio, our operated proved developed finding costs were $13.75 per BOE based on our drilling capital and our non operated proved developed finding costs were $27.67 per BOE. You can see the obvious advantage of our drilling and completion techniques when you break out proved developed finding cost between our operated and non operated portfolio. I want to briefly point out some of our year end PV10 statistics. The SEC PV10 of our proved reserves was $254 million based on the 2009 average first of the month pricing. This pricing was $61.18 per barrel for crude oil and $3.87 per MMBtu for gas. If we use strip prices at 12-31-09 to calculate the PV10 value for reserves, the PV10 value would be $578 million. Brigham's Bakken and Three Forks 2009 proved reserves included only 10 net producing wells developed on 1280 acres spacing and nine net producing wells on 640 spacing. We also had 28 net PUD locations planned for 1280 spacing and four net PUD locations planned for 640 spacing. This is the first year that Cawley, Gillespie has fully prepared a probable reserves for year end 2009 and thus given us an independent look at our 2P reserves as shown on 37. (inaudible) estimates that our probable reserves are 55.5 million barrels of oil equivalent at year-end 2009, our probable reserves therefore, roughly two times the current proved reserves at the company which truly gives you an initial glance at the potential we have in the Williston Basin. As you can see on slide 38, 90% of our probable reserves are Bakken and Three Forks. Our 2009 reserve growth was substantial given that we had very little drilling during the first half at 2009 and only one operated rigs running for the majority of the last half 2009. In 2010, the company will have at least four operated rigs running in Bakken and Three Forks and we'll be looking for ways to further accelerate activities. As you can see on slide 39, our estimated February differentials were down to about $6 a barrel, that's another positive which combined with are having entered into longer-term contracts and alliances to minimize cost increases going forward, puts us in an excellent position in 2010 from a cost perspective. Given that all the factors we've discussed anticipate another record year in both production and reserves and beyond 2010, there is still significant upside in our core 150,000 acres which should grow further with drilling success in our extensional areas. With that I'll now turn the call over to Gene.

Thanks Lance. Before we get into a discussion of our fourth quarter and full-year 2009 results, I have several comments about the company's current CapEx plans for 2010 and current liquidity position. First, from a financial perspective the first several months of 2009 were challenging for Brigham given that many of our traditional funding sources were not available to the company. However, we never doubted the value of our inventory of Williston Basin, Bakken and Three Forks horizontal drilling locations nor our ability to continue to innovate in the drilling completion phases of our business in order to enhance well performance. During 2008 and 2009, this innovation generated an almost sequential improvement in well performance in drilling economics. And our drilling results have continued to improvement in the first several months of 2010 as demonstrated by our Liffrig completion that we announced yesterday, that experienced the highest initial production rate today for the Three Forks and with our 13th consecutive high rate long lateral completion. With the benefit of the two equity offerings and our new senior credit facility that were completed last year, combined with the further derisking of our 104,700 net acres in a Rough Rider project area West of the Nesson Anticline, the growth in our production and reserve volumes are at an inflection point with a huge inventory of low risk Williston Basin horizontal drilling opportunities in front of us. In 2010, Brigham is poised to benefit dramatically from this inventory with an acceleration in drilling activity that we have been building to ever since we began to experience the upper trend in horizontal well performance in mid 2008. In terms of our updated 2010 CapEx budget outlined on slides 41 and 42, we currently plan to spend a $183.7 million on drilling CapEx and $15.7 million on land CapEx in 2010. Our 2010 drilling CapEx will fund 25.7 net horizontal Bakken and Three Forks wells, and one Vicksburg well in our South Texas project area where we are partnering with ExxonMobil. The increase in our 2010 drilling CapEx of roughly $14 million relative to the preliminary 2010 budget that we announced in October 2009 is being driven by slightly higher Williston Basin drilling activity where we currently have four rigs running and an increase in completion cost that we are expecting to encounter in 2010. Our updated drilling CapEx is based on AFE's for our 2010 long lateral hot frac stage horizontal wells of $6,825,000. The expansion of our land budget by $9 million will allow us to continue to capture additional acreage in and around our core areas where we plan to focus the majority of our drilling CapEx over the next several years. Beyond internally generated cash flow, our current liquidity position outlined on slide 43 consists of the following. As of February 25, $180 million of cash and marketable securities, this is down marginally from $120,900,000 at the end of 2009. Our undrawn senior credit facility was a $110 million borrowing base that will be up for redetermination in May and our conventional reserves which at year end 2009 consisted of 12.3 million barrels of oil equivalent representing another potential source of liquidity. Based on our updated 2010 CapEx budget, we would not expect to draw down under our senior credit facility until very late in 2010. Further, we are continuing to actively evaluate opportunities that will allow us to further accelerate our Williston Basin drilling activity. Given the 25.7 net Williston Basin oils budgeted for 2010 relative to our current inventory of roughly 433 horizontal development locations on our core Williston Basin acreage, together with the potential to add to theses inventory in the first half of 2010 by drilling on our Eastern Montana acreage and an initial three Forks well on a Rough Rider acreage is important that we look for ways to bring forward more of this development potential. From a staffing standpoint we certainly could handle higher level of activity. As we've stated in the past to continue to out performance of our Bakken and Three Forks wells, related to our budget forecast should serve as a catalyst to fund incremental Williston Basin drilling activity above and beyond the updated 210 CapEx budget that I have just described. Based on our updated 2010 CapEx budget our earnings release yesterday, we issued production guidance for the first quarter and full year 2010. In terms of our expectations for the first quarter, we are forecasting that oil volume should grow sequentially by roughly 19% relative to those in the fourth quarter of 2009 and that our total equivalent production volumes will average between 5400 and 5100 BOEs per day. The mid point of this first quarter production guidance represents a 4% sequential growth and our total equivalent production volumes. Further, this growth is expected to accelerate in subsequent quarters as we have four wells fracing or waiting to be fraced and four rigs currently drilling. For the full year 2010, we would expect that our oil volumes will more then double in 2010 relative to those in 2009 and average roughly 4,930 barrels of oil per day while our total equivalent production volumes should increase by between 35% and 45%. Moving on to a brief discussion of our financial results, our fourth quarter total production volumes averaged 5069 BOEs per day which was above the midpoint of our Q4 production guidance of 4950 BOEs per day. Our oil volumes of 2867 barrels per day represented 57% of our total volumes. However, because of the substantial pricing disparity of oil versus natural gas, which we are full able to capitalize on by focusing our drilling in the Williston Basin, our oil revenues represented 74% of our total fourth quarter pre-hedge revenues. Our fourth quarter production volumes included approximately 16475 barrels of oil produced in the Williston Basin during the quarter, but held in our on-site tank batteries and recorded as inventory at year-end. Adjusting our Q4 production volumes for amounts included in inventory results in average daily sales volumes for the quarter of 4886 BOEs per day. In terms of our cost, our per BOE leased operating expense increased 37% do $9.10 in the fourth quarter 2009 from $6.66 in the fourth quarter of 2008. This increase was largely driven by $2.13 per BOE increase in work-over expense during the fourth quarter due primarily to significant workovers of two of our conventional natural gas wells. For the full year 2009 leased operating expense increased 26% to $8.16 per BOE from $6.47 in 2008. For the full year higher salt water disposal compressor rental and work over expense accounted for the increase. Our fourth quarter 2009 production taxes increased $2.06 per BOE due to the growth in our North Dakota oil volumes and the higher oil prices experienced in the fourth quarter 2009 relative to those in the prior year's quarter. Production taxes for the full year 2009 were relatively flat at $2.84 per BOE with those in 2008. G&A expense for the fourth quarter 2009 increased $900,000, compared to that in the fourth quarter 2008 because of higher employee compensation costs which were partially offset by lower contract and professional services, franchise taxes and office expenses. G&A expense for the full year declined $300,000 due to cost reduction initiatives that were implemented in the first four months of 2009 and were partially offset by higher contract and professional services. To conclude our income statement discussion, fourth quarter EBITDA decreased 17% to $16.3 million and full year EBITDA decreased by 45% to $53 million. Moving on to the balance sheet at year end 2009, we had a $120,900,000 of cash and marketable securities on deposit, nothing outstanding under our senior credit facility with a $110 million borrowing base and $160 million of senior notes outstanding. Of our $120.9 million in cash and marketable securities at year end, approximately $19.4 million was invested in short term cash equivalents and $80.1 million was invested in marketable securities. Approximately $61 million of our cash used in investing activities on our statement of cash flows for the fourth quarter 2009 is related to investing the proceeds of our October 2009 equity offering in marketable securities. In terms of capital expenditures during 2009, we spent $60 million on E&D CapEx with roughly $58.2 million or 97% of this capital consisting of drilling expenditures. The vast majority of this capital was spent in the Williston Basin. To summarize with the benefit of our 17 plus year inventory of horizontal Williston Basin development locations and sufficient liquidity to fund our updated 2010 level of drilling activity for both 2010 and 2011, we have a high degree of confidence in our ability to drive our production volumes, our reserve volumes and net asset value per share to record levels over the next two years. And as we have openly discussed, we continue to evaluate ways to bring forward more of this captive net asset value in order to further accelerate the growth in our company's net asset value per share. In addition to further acceleration on our core acreage, other near term opportunities to enhance our company's net asset value are outlined on slide 44 and includes the following. Number one, drilling in initial Bakken and test well on our Eastern Montana acreage in the first half of 2010. I remember two drilling and initial Three Forks on our Rough Rider acreage also in the first half of 2010. Item number three, drilling an increased density Bakken well on our Rough Rider acreage this summer and finally our continuing efforts to add to our core acreage particularly in Rough Rider where we currently have an operational advantage relative to other companies that should enhance our acreage acquisition efforts. That concludes my remarks. I'll now turn the call back over to Bud.

Thanks, Gene. That concludes our prepared comments. We would be happy to answer any questions. Subash Chandra - Jefferies: A great release, a welcome relief from some of the others. I'm curious on the Bakken reserves, the 600. Did you see much variance between West of the Anticline or East of the Anticline in the booking in the reserves?

Yeah, Subash this is Lance. We got that 150,000 core acres pretty much well in every corner and every niche of that area and we are seeing some variance in EURs. It could even be on side, either east or the west. We see variance into those areas. And so we're looking at that. We just don't have enough well data to tell what the variance is by area by area. So by the end of 2010 we will have a better feel for that. Subash Chandra - Jefferies: Okay. A couple of references to the Continental call. I was on it, probably had to hop too early. Did they give a rate on that Thorvald well?

I don't believe that they did. Subash Chandra - Jefferies: Okay. And in their conference call, the part that I got, the sort of 430,000 per barrel, it looks like their first month average is 430. From your slide, the 11 or so wells averaged 1000 barrels with reserve midpoint of 600,000. And so I'm curious, any commentary? How we should think about that? If there are revisions, what's your tolerance on what those revisions could be? I would assume it's not going to be one to one like the Continental release. But could it be?

I'm not sure what you're talking about on one to one but…. Subash Chandra - Jefferies: I'm sorry; I meant the 430 barrels average in the first month equals 430,000 barrels in reserves. So not one to one sorry but 1000 to one or whatever the number is?

I don't have that view point in that first 30 day versus the EURs. I think there is a co-relation from IPD [ph] EUR in a better correlation from 30 day to EUR and a better correlation from 90 day to EUR. So, you can plot that and I think Tudor Pickering, they actually did some of that but we do it routinely. But I think the one thing that I got out of what they said about their reserves is they're seeing increased rates using more stages and Continental is a great company and I think they're one of the companies we emulated when we got in and we're glad to see them pushing the number stages along because I think that rate that they're seeing, they have the wells on long enough to see the EURs increase, prove for but we have and we believe they will see higher EURs and as they increase the number of stages even further they will see higher EURs than what they're getting right now.

This (inaudible), I think overtime we're going to have more data and probably better be able to quantify as you're saying, for 30 days kind of have a better feel for that relationship in the EURs relative to the 30 days.

The difficulty in it is you've got varying completion techniques. And so, when we look…

And profits.

Yeah and profits, and when we look at ours we're building a database now of just our wells where we got it in a more controlled environment as a variable. Subash Chandra - Jefferies: In the non Bakken, what was the non Bakken CapEx in 2010?

It was really like five. It was not a big number. When you drill a (inaudible) When you drill well $4 million and then we got may be another $1 million of other West Texas. Subash Chandra - Jefferies: So in that context, how much of risk is there, do you see sort of continued, part of eliminations from the non Bakken portfolio and so how much of that can be rescued through discretionary means like drilling versus price?

Well I think that we are not going to see that on an on going basis, pretty much our reserves are left in the PUD side with Bakken and Three Forks and then of course our Vicksburg play. We still have our PUDs in there and then I think we have one hunting PUD and so we're pretty much limited in what we could have and we have nothing to drop and those things, we left then in there because we feel strongly that we're going to drill. Subash Chandra - Jefferies: Okay.

We're just waiting for our gas prices to move it closer to this year.

And Subash on the non Bakken CapEx, drilling CapEx is $7.9 million. $5.3 million of that is the Vicksburg well that's currently drilling... Subash Chandra - Jefferies: And one last one from me. Any signs of life in the Mowry shale program? Any commentary there?

No, we know some other operators that are active in the area and apparently getting more active. Jeff, I don't know if you want to add anything?

Yeah, Subash, Jeff here. We continue to monitor the activity in the Southern powder. We still think that the technology needs to be unlocked there. I think there is oil in place and obviously the Mowry is a source rock and vertical wells are produced out of the Mowry. We think there is some other technological formula that needs to be applied there but we're watching other operators try.

Your next question is from the line of Michael Jacob with Tudor, Pickering & Holt. Michael Jacob - Tudor, Pickering & Holt: You talked a little bit about the numbers that Cawley is giving you on the wells, and I want to just focus on the most recent higher order completions. On average what is Cawley giving you for 1P reserves and what could a proved plus probable plus possible case look like?

Well, Mike, this is Lance. So right now Cawley has given us just on the producing wells just a 1P number. We discussed and there is a 2P number to that for those producing wells. Just like I discussed, one of the major factors is the final decline rates. If they're actually lower we're going to have significant revisions as we go forward. So that's part of the 2P and there is also the B factors that are assumed there. So you assume a little more aggressive B factor you get additional reserves and so we did not quantify those or have Cawley quantify that on the producing wells. We strictly did our 2P on undrilled locations. Michael Jacob - Tudor, Pickering & Holt: And on the propant cocktail, I was wondering if you can give us a little bit of color and specifically as you're tinkering with these various options, how do you think about the costs and the EUR trade off between increasing fracling density versus lengthening those fraclings with more propant?

Well I think that we've showed that as you increase the number of stages, our economics have improved dramatically. The stage we're in now is watching production, trying to determine what is the optimal number of stages and what's the optimum amount of ceramics to pump and then once we find that out and we will continue to look at economics as costs go up or the price of oil goes up or down, the cost of the services go up or down but right now I think that what we're doing is working well. I don't see us making any dramatic changes that I can see unless we find something that's working better. Michael Jacob - Tudor, Pickering & Holt: And any thoughts the Khorat [ph] well is drilling now, any idea what EOG is doing there in terms of lateral length and completion design just so when we can get that data, we just want to correlate it to the Rogney Well.

Yeah this is Jeff. It looks like to us its going to be a 640. They've listed it to the NDIC as a Bakken well but you know how the NDIC is. You can either drill a Three Forks or Bakken well when you call it Bakken but it’s our belief that it will be a Bakken well but we're definitely watching it. Obviously we've got off that acreage.

And we don't know like the stages or anything on that.

The only thing we know is what they've said publicly. They haven't shared anything with us. Michael Jacob - Tudor, Pickering & Holt: And last question, I jumped on the call a little late so I apologize if you already said this but could you provide us with the net proved developed and proved undeveloped locations on both 640s and 1280s

Yeah, we did it in the call. Michael Jacob - Tudor, Pickering & Holt: If you did in the call, I can just grab it later.

O the proved developed it’s 10 on 1280s and nine on 640s and then on the PUDs it was 28 on 1280 and four on 640.

Your next question is from the line of Scott Hanold with RBC. Scott Hanold - RBC: A question on your sort of pace of development. Obviously you all indicated several times that you want to bring forward the value and when you step back and look at what you have in your hands, four or maybe six rigs could handle and then due to the potential, you need to accelerate more if Ghost Rider starts to work. What are your additional capital options, and how do you rank that?

I'll start but Gene's really going to answer the question primarily. We start with well out performance and we're continuing to see improving well performance as we go forward here. So that's the first time that could provide incremental capital. Go ahead Gene. You want to take it from there.

Our cash flow is going to be ramping up pretty dramatically as you move through the year. Even as we exit the year, we may or may not have any need for the credit facility, the borrowing base. It currently has a zero balance and obviously as we drill more and more wells, this is really becoming just almost exclusively a developmental type program and certainly you can argue relative to maybe where we were last year, you can argue that we look forward to take on more debt when you're in just that development drilling. So, certainly using incremental debt and I'm really, obviously the budget this year will be funded out of cash flow and the cash that's on the balance sheet. The big components of liquidity for next year will be the higher level of cash flow in 2011, the unused credit facility or something comparable to that and really use of some leverage. And then the proceeds from the sale of some, all or some subset of our conventional assets and I think if you modeled 20 -- the current level of activity that we have announced for 2010, if you hold that level constant, then we're going cash flow positive in 2012. So, I think you could argue that we're in great shape if we want to hold our activity level constant so that we're not really having to look to other external sources for capital other than drawing down the credit facility or doing some debt like transaction. But obviously there is an interest in accelerating above and beyond what we have announced today. So, that will be function of a whole series of issues, obviously well out performance will give us some incremental – we expect to have some incremental liquidity this year from the outperformance relative to what we're budgeting for our wells. Scott Hanold - RBC: Okay, okay, very good. And so on that subject, Gene, did you indicate 2010 budget is based on a $6.8 million well cost in the Bakken?

Yeah, that CapEx number that I give you was 6.825 and then we have 5% overage factor to that number to further gross it up, just to protect ourselves in the event we have some unforeseen issues. And then that all feeds into the budget, it gets us to the drilling CapEx that we announced. Scott Hanold - RBC: Okay. Because, correct me if I'm wrong, you guys have been drilling the wells so far for about $6 million to $6.5 million. Are you starting to see some pressures in the field on service costs and what can you do or have you done to further mitigate some of that?

Yes Scott, this is Lance. I think probably the largest problem in the field is just manpower and it's really about the cost of manpower. That continues to go up when it’s booming like this and so that impacts everybody across the board. So you should see some cost just from the intangible part like manpower but we've had, of course rigs are picking up, we’re at record levels again now, put some more pressure on stimulations but the thing that we have done is we have got some long term contracts that limit how much they can adjust. Manpower is typically one that we give people direct increases in manpower. So, we're having increases in cost but not that significant so far. And we think that as we come out of the winter, we'll offset some of these increases in cost just by the reduction in winter operations, the extra cost associated there. Scott Hanold - RBC: And on the Ghost Rider testing, did you say that was mid-March when you were going to spud that, and can you just clarify when we could expect to hear results on that?

Yes, Scott, Jeff. We said sometime in March, looks like it will be a spud and just as a reminder it will be a 100% test. And typically with core operations, you can be 30 plus days before you get the core analysis back after you basically TDed the post-hole. And that well also Scott we're going to core basically -- we will core that content. There has been a lot of discussion recently about the Scallion. I mean you heard Continental Resource speak of the Scallion in their Traxel well. We’ll probably core that Scallion, which is at base Lodgepole member right against the upper Bakken shale, then we will core the full Bakken section, upper Three Forks and then our plan is to also the Niski [ph] we're very interested in. Our plan is to then drill that post hole down the Niski [ph] and DST it. So I mean we are going to be pretty thoughtful about and it will take a bit of time. It could be as long as the end of second quarter before you see production. Scott Hanold - RBC: And then also on Continental’s release, they talked about a well that sort of stepped out on to the Northern part of Elm Coulee. Does that have any analogies to your Ghost Rider?

I think, when you look at that well, we've watched those wells. At Elm Coulee, there is a tight area between Elm Coulee and Ghost Rider where were picked back up our porosity number and they're just kind of on the edges of their porosity in the Elm Coulee trend but we are watching it and we're well aware of the Sinclair well in Northwest Elm Coulee also which were step out wells and some of those are actually pretty encouraging wells. A couple of those that are over 200,000 barrel EURs and as you then move to the north from the Sinclair well that porosity improves significantly in Ghost Rider. Scott Hanold - RBC: One last question. Could you provide the PV10 value of PDP versus PUD?

Well, I don't have that in front of me. We'll have to get back with you on that one.

And I know that our PV10 values are typical 600,000 barrels at current strip prices, the net was like $9.5 million. So, that’s sort of a generic type.

Your next question comes from the line of John Freeman with Raymond James. You may proceed. John Freeman - Raymond James: Most of my questions have been answered at this point just a few. What percentage of your Bakken acreage at this point is held by production?

It’s pretty small. I would say 28%; we'll do some math on that real quick. John Freeman - Raymond James: And while you are looking at that, the reason that I asked is obviously there has been, you all have made several references to maybe looking at additional possible JVs like you did with U.S Energy that obviously worked out really well. And then specifically you mentioned the Ross area. Does that particular area have any near-term lease expiration issues relative to the rest of your acreage?

This is Bud. We are well ahead, go ahead, Jeff.

Jeff here. We're in great shape on our lease expirations. First of all talking about Rough Rider then I will hop to Easy Rider. In Rough Rider, our wells are actually, this year we'll actually drill expirations that aren't even out until 2011. So we basically have mitigated all the 2010 expirations and we're actually gearing 2011 expirations already with our two rigs in Rough Rider. In Easy Rider our lease expiration schedule is even a lot better than it is in Rough Rider. So with our current four rig program we feel very comfortable that we're going to be able to control our acreage. John Freeman - Raymond James: And on the Montana slide that you'll have in your presentation, I'm just a little bit confused. On there is a well, the Sweetman that says it's going to be completed in March. It's like obviously you have all been referencing the Rogney well. What is going on with the Sweetman?

The Sweetman is actually a well that we're in. It's a long lateral Bakken well and they're waiting for it to come out of winter time operation before they frac that well and so we have got a small interest, I think we’ve got 3% or 4% and basically we're just waiting on that completion John Freeman - Raymond James: Okay. So it would sound like we would actually most likely get results on that well before the one you're actually operating.

I think you’d probably see results on that well and also the the EOG Khorat [ph], the fourth one we're operating. John Freeman - Raymond James: But I mean at least the Sweetman; you could control actually the release unlike, EOG?

Yeah, we have an interest in the well. So we'll have real time data on the Sweetman. John Freeman - Raymond James: And then at least on the slide, do you know if that Sweetman well, was it drilled with the utilization of 3-D like your Rogney will be?

We believe it was not. Remember our Ghost Rider 3-D is basically a 70 square mile proprietary data volume and there is a fairly extensive 2-D data grid across the basin. We are not sure if U.S Energy [ph] is that active on the geophysical front.

Hey, John, your HBP acreage in the Bakken is 19,000 acres. That's the core.

Yeah, that's just in the core 150,000 acres. So you can do a percentage of it, but its 19,000 acres HBP in the Bakken.

Your next question is from the line of Steve Berman with Pritchard & Capital Partners. You may proceed. Steve Berman - Pritchard & Capital Partners: Just a couple left. One clarification, the 105,000 net acres in Rough Rider, was that before backing out the 5,000 that U.S Energy can earn?

They've only earned based on the wells that have been drilled today. So the 5,000 would, and you would ultimately back out, would assume that on the back end of drilling all 15 wells. Steve Berman - Pritchard & Capital Partners: But ultimately the 105 could be 100.

It’s really not that simple because as you recall I am sure, the initial wells they're given equity in but their subsequent wells in those spacing units, the equity flips and we have like 64% and they have like 36%. So it’s kind of complicated calculation, but it would be something less than that 5,000.

We arrived at the 5,000 based on three wells per drilling unit. And they and we're participating to maximum of our interest. So we drilled a third of the wells and maybe a third of the number is captured in 105 and there still additional acreage to earn up to that 5000 acres as we finish drilling up those JV well this year.

And Steve one thing to add is Jeff touched on, that acreage position is grown from roughly 100,000 acres at year-end, 105 today and we've got transactions in the works. We're very confident we're going to grow that position. Steve Berman - Pritchard & Capital Partners: And my other question is, I know you say you are still early in the process here, but in terms of the number of frac stages with last several wells have kind of been in the 29 to 30. Do you think you've kind of hit that maximum sweet spot if you will or can we see even longer laterals in this kind of 29 to 32 stages that you're at now.

Steve, Lance will have probably have more to stay on this. This is Bud. Initially what we're trying to do (inaudible) in the different areas we're seeing a little bit different well performance in EURs and so we want to have one variable. An additional variable would be geography. So in a given area we're going in line with the 30-32 frac stages. So we're getting that control and then look at the performance on those wells and then we'll evaluate whether to go to higher frac stages or maybe start varying something else in some of those areas. Lance you do want to add to that?

Yeah, I think the one thing that we might start varying soon, we are still trying to figure out what the ultimate number of stage is and we think that's going to vary from area to area and then the next step we want to go to pumping more profit and getting larger frac weights with the same number of stages to see what the impact is there.

Your next question comes from the line of Joel Musante - C.K. Cooper & Company. Joel Musante - C.K. Cooper & Company: I've just got a couple of questions. First, what percentage of the 150,000 acres they have in Ross in the vicinity and Rough Rider has proved reserves on it at this point?

We just calculated, it was about 4%.

Its 19,000 acres of proved developed. Its 4.2. That's in proved. Joel Musante - C.K. Cooper & Company: And how many would be PUDs?

Yeah, that's pretty developed.

That's correct, that was 19,000 acres of the 150,000 as developed. So 4.2% proved developed. You didn't calculate for the total proved, did you? 36 proceeds; 35,000 acres possibly would be the total PUD. With the proved PUD,

It would be about 19,000 proved developed and about an incremental 35,000 or 36,000 proved and undeveloped. Joel Musante - C.K. Cooper & Company: All right. And it looked like the well program that you have going forward is more weighted towards the middle of the year, and that seemed to change from what you had before.

Yeah, what they on, that's a net wells completed by quarter on that slide and the way the drilling schedule works out, there is some high equity wells including that are going to be drilled on the plan in that period and so on a net basis, its inflated there in those (inaudible).

We've modeled the activity and assumed four wells, keeping four rigs constant for the full year. So, in terms of gross wells I would think that it's going to be pretty even over the course of 2010. Joel Musante - C.K. Cooper & Company: Okay. Is that net well account, is that based on the before payout or after payout number for the DPA?

I think it's the before payout. Joel Musante - C.K. Cooper & Company: Before payout?

That working interest will increase as those probably won't increase this year at least for the sake of the wells we're going this year certainly, though it'll be next year. We would back in for incremental working interest when those wells do payout. Joel Musante - C.K. Cooper & Company: All right, your agreement I remember and there was a slide that showed kind of an assumption that you had with 75% of ownership in the leases that, from the DPA leases, you would own about 75% of those? Is that still the case going forward for the remaining blocks sections in that agreement?

You're talking about US Energy? Joel Musante - C.K. Cooper & Company: Yeah, you would have -- you know they would participate in a pertain certain percentage of what you owned, and you said that you would own about 75% of interest in those blocks?

I mean just kind as a reminder right now, I am surely the three rigs we have running in Rough Rider currently they are not in any of those wells. So and basically the agreement is that by the end of 2010 they'll have the opportunity to get in up to 15 wells gross wells and that's a very important because the interest we've got industry partners in all these drilling locations so the interest can drop significantly and potentially some of the wells that they are in and which it mitigate the company has. Joel Musante - C.K. Cooper & Company: Okay.

That's a lot bit complicated but in general what came on the last set of wells we elected to the 50% interest. So, the 50-50 plus we have the back in on their interest on the initial wells and then on the subsequent wells in those units it would be a 64% Brigham and 36% US Energy. Joel Musante - C.K. Cooper & Company: Okay. But your interest in those blocks, you get to select which blocks.

That's right. Joel Musante - C.K. Cooper & Company: Okay.

We've got a better answer on your question on the percent of our acreage is falling in the proved category both developed and PUD is about 39% of that 150,000 core. Now I will point out that proved for the first well because we are only obviously booking one well, we think we are going to be developing three wells in these areas. So drill three wells for both the Bakken and three wells for the Three Forks ultimately. Joel Musante - C.K. Cooper & Company: Okay so that's only one well per block?

That's right. That's what (inaudible).

And then you also note the comment that Lance made that the PUDs were only typically booked at about 80% of the prudent developed well is there. So they discounted some at 20% Joel Musante - C.K. Cooper & Company: There were some questions earlier that asked about the decline curve. I don't know if you have give out that information, but what does the decline curve look like for the declining per year?

You can look at our ad on our website and get some indication of how the wells are performing and I don't think we've put out a tag curve today so… Joel Musante - C.K. Cooper & Company: What are you assuming after the first year, I guess? Because most of those wells are within one year…

I think the way we do, we don't assume so much one year, so much the next year. We've got the decline curve in it. It varies, what the top curve we're using and so we do it on the in an areas database.

And obviously if its hyperbolic and it goes to 8% terminal, then we think there is typical to kind of see 5% to 6% terminal so there is opportunity for positive revisions down the road.

We said we typically, we've only announced that we're producing the year 80,000 to 140,000 barrels in that range.

Your next question is from the line of Ron Mills from Johnson Rice Ron Mills - Johnson Rice: Just a question on the stimulation, as you'll continued and I know Lance, you and I spoken about it, spoken to a lot of other operators about what you're doing. Has there been, like we've seen in Angel and other plays, any sort of consortium, and now that I know people are still leasing, but how interactive have the industry partners been in terms of discussing the various completion techniques.

Well I'll start but Lance is probably have more to say on this, but we were in that consortium in Montreal County early on and I think that was beneficial where operators were working together. One thing that we've done is we've had a couple of meetings now with the University of Texas Petroleum Engineering professors and they are touted as being the top academic institution involved in R&D regarding stimulations and they've done a lot of work in the gas shale plays and with our exchanges that we've had, it just further convinces us that we are very, very early in figuring out how to optimally stimulate these reservoirs and get the tremendous amount of oil that's in place out of them and so we're in discussions with them about developing a plan for working together where they can help us and we can help them further their research and we may develop a plan for another consortium which is a real possibility. Lance, do you want anything to that?

Yes as far as communicating with better operators, we communicate different desks with different operators but recently it seems like that most of the communication is trying to understand what we're doing and how we're doing it and you can see it through the basin. You see everybody pushing to more stages and at last people move in the ceramic and I think you will see that to continue and then as that happens, we'll be able to gather more data to try and figure out the best way or better way to complete the optimum way to complete these wells and over the entire basin. Does that answer your question? Ron Mills - Johnson Rice: Yeah it does and then I think Gean you talked about the present value of the Bakken well that based on your current well cost and 600,000 barrels and so on your presentation, it look like it was just $75 oil or plus or minus $18.5 million of PV. I think you said something higher currently.

We just ran this morning based on strip prices, the 6.825. It was like $9.5 million is the net number, the net PV creation after subtracting out the drilling CapEx. That's current price. Ron Mills - Johnson Rice: And then probably for you, Lance, just on the 600,000 barrel EUR, I know that that's I know that that's Cawley, Gillespie, what they have been booking and you've talked about that number for quite some time. Importantly, you have talked about that number going back well before you had really instituted or had the kind of actual production results to date. You know, at what point or what's it going to take to be able to start talking about that 500,000 to 700,000 barrel range maybe being a little bit higher just due to the higher initial productivity or is it more of a reserved acceleration issue rather than reserve additions by completing the wells the way you are?

We know that by completing the wells, the way we are that we are increasing EUR, so we know it's not an acceleration. What the level of those increased EURs, we're going to find out more over time. I think that the numbers that we're giving you in the range, our wells are averaging in there. I think they are going to be varying from area to area, but what we do know is that our wells in our areas are the best wells and it's definitely EURs and not acceleration. As we get more history, you got to remember we just have a year and a couple of months as our oldest 20 states long laterals and that's the oldest one by far end in the industry other than the other ones that we drill. So, we just don't have enough production data to get to the final decline rates and what are the impacts, the positive impacts through the ceramics versus the sand and I think its going to separate us from the operators that even going to more stages that are pumping sand. Later in the life, we'll have a better production rates in the sands is what we predict from looking at this technology and then we'll also determine if we're going to have a 5% or 6% final decline rate or an 8% decline rate in. We just have to have more time and I think that's at least another year out to see that. But I think as we along we'll become more and more confident. Ron Mills - Johnson Rice: And then, Bud you mentioned something and it raised one last question from me. On the US Energy group deal, have you all just drilled the first six wells in that first set of wells? I think, as you said you agreed to 50% level in the next slate of four wells, and I think the third group is five wells. But do all 15 of those wells have to be drilled by the end of this year for them to earn that acreage? Is that what I understood you said?

Yes. We have to drill all of those by year end that's correct.

Ron Jeff here, we six drilled but we seven, eight, nine are currently completing or getting ready to complete. Ron Mills - Johnson Rice: Okay. And then I assume based on what you do with the second group and with the kind of results that what you would likely elect to do on the fourth or on the third group is to take as high as to that 64% level that…

Yes, we are going to maximize our interest, that's right.

Your next question comes from the line of Mike Scialla with Thomas Weisel Partners. Please proceed Mike Scialla - Thomas Weisel Partners: Hi guys, I had to get on your call late, so I apologize if you have already addressed any of these questions. But I was wondering in terms of the Rough Rider area, how do you expect the geologic properties that in the Three Forks to compare to what you're seeing over in Ross?

All right Jeff here, the things that I got us excited about Rough Riders is not only the early time production to the South East of us by a couple of operators and notably Encore and Panther, both drilled Three Forks well using single end controlled fracs to make some decent wells as the Panther well IPed over 500 barrels a day, so that very encouraging and we know what the rock looks like in that area and then also we just kind of resources announced their (inaudible) well today just west of our Rough Rider block completed in the Three Forks and pulling back very encouraging and we've got a core in our Olson well and what we like about our core in the Olson well in the upper Three Forks is we see that same clean Gamma Ray that dolomite member that we see working for us on the east side of Nesson and Mountrail. Looks very similar to us in Rough Rider and also we have got good oil saturations in our core in the Olson well which is in middle of our Rough Rider block. So we like a lot of things that we are seeing, surely we just need to get a rolling it and get it top and be stimulated and we're very excited about the opportunity there. Mike Scialla - Thomas Weisel Partners: Do you see that same dolomite section over in the Ghost Rider area or no?

We do, it's a little bit thinner but we do see it and its thinned up I would say, its probably 20%, 30% thinner than we see in Rough Rider. Mike Scialla - Thomas Weisel Partners: So, that will be the target zone, though, for the Rogney well?

No, that's not correct. The target zone for the Rogney will Bakken. And the middle Bakken in the Rogney well, a number of things we like. There is a real close control point to the south as we put on in the website, the middle Bakken is about 35 feet thick, very comparable to what we see in Rough Rider and its also got very well developed middle Bakken porosity which we like a lot and then also the upper Bakken and lower Bakken shales are thermally maturing, very resistive. So we think there's a lot of things going forward in Rough Rider or in Ghost Rider. So we're excited about but (inaudible) us drill in middle Bakken test in Ghost Rider. Mike Scialla - Thomas Weisel Partners: Can you guys stick with the long lateral approach in similar kind of high number of frac stages?

We are scheduled for 1280 and more plants are to be completed very similar to our Rough Rider well. Mike Scialla - Thomas Weisel Partners: : And last one from me, it sounds like you're not ready to revisit the (inaudible) at this point but any of the other emerging horizontal oil plays in the Rockies pick your interest in (inaudible) or Frontier anything else?

Jeff here again, I think we are very interested in a bunch of different areas as there has been a lot of press recently about areas in and around of Williston Basin. We are very interested in the oily place and I have got guys in the group looking at a number of different resource plays to look for an excellent for us. Mike Scialla - Thomas Weisel Partners: Anything on the budget this year for acreage in those?

Not at this point.

It just minimal amount at this point.

Your next question is from the line of Derrick Whitfield from Canaccord. You may proceed. Derrick Whitfield - Canaccord: Thinking on the Ghost Rider here, how does the thickness and porosity in the Ghost Rider middle Bakken compare to the Rough Rider middle Bakken?

When you look at the and we got the Olson port out there and we've also got the logs for the offset well to the Rogney which will help on your thickness analysis but when you look at the middle Bakken very comparable in regard to thickness, within a couple of feet of each other 30 to 35 feet in both areas in the middle Bakken and then I think importantly when you look at that log on the website, in Ghost Rider, that real nice low bate porosity you see on that log just south of what our horizontal well is going to be actually touches 10% porosity which has us very encouraged and that's the type of porosity that we've mapped all throughout our Rough Rider area and that's what drove us to our acreage selection in Rough Rider and also our acreage selection in Ghost rider. Its identifying that nice low base and middle Bakken porosity and leasing where we see it. Derrick Whitfield - Canaccord: Got it. Thanks for that. And then maybe for Lance, what are your thoughts on using restrained initial flow rates to increase recovery as we've heard about in the Haynesville and Eagle Ford as of recent?

Well we are not doing that right now and I have done that in the past and its really never made any significant difference in the EUR. Another good reason for holding back is sub $5 gas I would think also but you can afford to that more but that theory has been pushed around a lot over the years and I am not saying there is not validity to it, I am sure there is in certain areas but we haven't considered doing it so far. Derrick Whitfield - Canaccord: Okay. And then a final question, what 30 day average rates are you guys using for your production forecast in the Bakken?

We are taking in the average of our wells and build the top curve in the areas, I don't know what exactly what the first 30 days is but it starts on a daily rate in areas and declines and of course it declines rapidly in that first 30 days, but its modeled off our production so it ought to be similar to what we are seeing here. Derrick Whitfield - Canaccord: Okay. So it would be in 900 type range if I'm looking at your latest slides?

Yeah that slide will be helpful on that.

We are modeling an average in that model.

That slide showing our wells should be helpful to you to definitely remodel there.

Yeah we are doing an average.

And your next question will be from the line of Jessica Lee from JPMorgan. You may proceed. Joe Allman - JPMorgan: This is Joe Allman, hi everybody. I know you mentioned this or referred to this several times during the call, but what did Cawley and Gillespie give you in terms of reserves for your PUDs in the Bakken, and also what's the implied number for the PDPs?

We didn't give the actual numbers Joe. You give them back into and we gave that our operated our operated PUDs were 80% of our operated PDP. Joe Allman - JPMorgan: I guess what I mean is I am sorry on a per well basis.

We didn't disclose that. We just said that the average of the wells fall within our 500 to 700 MBoe. Joe Allman - JPMorgan: Okay and is it fair to say that Cawley and Gillespie for the larger number of frac wells, did they give you more rather than less or was that on the high end versus the low end?

Cawley and Gillespie look at each individual well and location independently and took into account the offset results, so they did give us some credit for our results. If we're the operator, if we're not the operator we've got less results because we have less impact on that completion technology. so I don't know if that answers your question but this. Joe Allman - JPMorgan: So for the wells that you operated, were you did more frac stages, did you generally get a high EUR.

Joe this is Bud, you can see that we have a slide in there based on the reserves that they quantified for our wells and so its 36, our fleet developed drilling task were $13.75 a barrel relative to the non-operated was $27.67 a barrel.

Yes, but he's asking about the PUDs aren't you? Joe Allman - JPMorgan: Actually I mean both and so PUDs and PDP?

Yes the PDPs are based on the actual results. But for poor then they've got a poor EUR and if the results were good, each individual well, if it was good you got, but you could see that in our EUR they are significantly better. The PUDs are more complicated than that because you have to take into consideration whose operating for one, and then one of the results not just your well, but the offering wells.

Joe this is Bud, you can see from what we have been talking about as far as type well performance in EURs, we're talking of $10 to $18 a barrel drill dollar on finding costs. And as we just mentioned, probably quantifies our proved developed operated drill finding cost at 1375 a barrel equivalent. So it's in that range.

The other thing you would expect to see Joe is those PUDs going up overtime. A lot of the offset in the non-operated wells, those EURs are poor because they are old completion technology and a lot of the industry is moving towards our completion techniques that we are using are similar. So I expect to see EURs go up across the board and then plus on our operated as I said, our operated PUDs were 80% of our operated PDPs. I expect that there is some upside in reserve revisions going forward. Joe Allman - JPMorgan: So when you get to 500,000 to 700,000 barrel number, that's the average for the PDP that you got from Cawley and Gillespie?

Yes, for our long lateral multistage. All of them. Joe Allman - JPMorgan: And the PUDs would be just on average 80% of that?

Yes for our operated PUD, well that's the majority of what's driving our value. Joe Allman - JPMorgan: Got you, and what about the B factor that Cawley and Gillespie used? Do you have that?

Well, I don't have that in front of me for PUDs, I am sure he's using the average one and I am not sure exactly what it is and then on the PDP wells, I am sure he is looking at those individually and they have different ones. Joe Allman - JPMorgan: Got you. And Bud you, you brought up the $13.75 per barrel in the growth engine through developed F&D. So what's the numerator using there and what's the denominator there for that calculation?

Well, that's just the drilling cost is and it's the reserves. Joe Allman - JPMorgan: Yes, so what's the value? What is the number actually? Do you have that in front of you?

No, I don't have that Joe. Once you circle back with us. Joe Allman - JPMorgan: Okay that will do. And then lastly, just for Gene. You might have said this and it might be in your press release and I missed it, I apologize. So what was cash on hand at year-end, what's cash on hand now, and then I just want to check on that because I'm not…

Yes, one was where it was at year end and 1.18 as of today. Joe Allman - JPMorgan: Okay, got you.

Cash marketable securities and cash equivalence. Joe Allman - JPMorgan: Okay. So 1.18 as of today?

As of this morning. Joe Allman - JPMorgan: Okay. And so when you are talking about needing to finance, is raising equity a possibility for you guys for this year as one way to accelerate the drilling?

Based on the budget that we have outlined No. I There would absolutely there will be no reason to do it, because we have got $100 million and almost to $120 million of cash and given that in our cash flow, we are able to fully finance this year's budget, so based on the current level of CapEx, the answer would be no.

The next question comes from the line of Dan McSpirit from BMO Capital Markets. You may proceed. Dan McSpirit - BMO Capital Markets: When you report your wells, you do so over "early 24 hour throwback period". Is that the first 24 hours or how is that decided?

Its kind of the peak early 24 hour throwback. Its obviously very early, but its 24 consecutive hours.

Its probably within the first few days because some of the wells flow back a lot of water and they all flow back a lot of water but some of the wells have a low all cut early on for the first day or two, so it depends on when it actually turns the corner and starts making the higher or low volumes. Dan McSpirit - BMO Capital Markets: Okay great. And then turning to your presentation on slide 23 where you give some production history here on wells drilled in the Bakken and in the Williston Basin, is it possible to give current rates on any of these wells? Do you have that data handy?

I don't have that handy.

But overtime we are going to be filling this chart out and continue to fill in the 30 day rate and then possibly overtime…

Yes, obviously overtime as we have more and more history as well it will be able to provide more and more data.

Because you see we did write that charts where you can see, those are pretty up to date, in the corporate present.

And you can look at it and see…

We are going to find then and there, yeah, you could see it Dan on that. Dan McSpirit - BMO Capital Markets: Okay. And then I'm sorry, I missed the answer to the question that was raised earlier on what the assumed first-year decline rate was?

Well, what we have said in the past is that we in the first year we usually make 80,000 to 140,000 MBO in a first year and our top curve is in the middle there somewhere.

At this time I'll turn the call over to Mr. Bud Brigham for our closing remarks.

This is Bud Brigham again, I want to thank everybody for the participation in the call and we look forward to reporting on our first quarter results.

And ladies and gentlemen thank you all for your participation in today's conference call. This concludes the presentation and you may now disconnect.