Filed by Bowne Pure Compliance

EX-99.1 2 c73003exv99w1.htm EXHIBIT 99.1 Filed by Bowne Pure Compliance

Exhibit 99.1

1 Brigham Exploration Company Analyst Day Stephen F. Austin Hotel Austin, Texas April 18, 2008

Forward Looking Statements / Note Regarding Reserves Except for the historical information contained herein, the matters discussed in this presentation are forward looking statements that are based upon current expectations. This presentation / communication may include estimates, projections and other forward looking statements within the meaning of the federal securities laws. Any such estimates, projections, or statements reflect our current views based on current information about future events and financial performance. Important factors that could cause actual results to differ materially from those in the forward looking statements include risks inherent in exploratory drilling activities, the timing and extent of changes in commodity prices, unforeseen engineering and mechanical or technological difficulties in drilling wells, availability of drilling rigs, land issues, federal and state regulatory developments and other risks more fully described in the Company's filings with the U.S. Securities and Exchange Commission. Cautionary Note to U.S. Investors - The U.S. Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this presentation such as probable reserves, probable drilling locations, possible reserves and possible drilling locations that the SEC's guidelines prohibit us from including in filings with the SEC. These terms include reserves with substantially less certainty and no discount or other adjustment is included in the presentation of such numbers. U.S. investors are urged to consider closely the disclosures in our form 10-K available on our internet site or by contacting us at 6300 Bridge Point Parkway, Building 2 Suite 500, Austin, TX 78730.

Agenda Introduction Bud Brigham - Chairman & CEO Williston Basin Overview Bud Brigham Williston Basin Geologic Overview Jeff Larson - EVP Exploration Williston Basin Operational Review Lance Langford - EVP Operations Bakken Economics Review Bud Brigham Vicksburg Erik Hoover - Operations Manager Southern Louisiana Erik Hoover Financial Strategy Gene Shepherd - EVP & CFO

Key Takeaways As Was the Case Historically, Our Recent Long-Term Land and Seismic Investments Position Us for a Multi-Year Period of Higher Rate Reserve Growth & Lower Finding Costs Potentially Highly Impactful 240,000 Net Acre Position in Williston Basin Targeting Multiple Objectives in ND and MT Bakken is Expansive Growth Opportunity - Similar to Barnett Shale in 2004 In 2008, Migrating a Portion of Our Bakken Acreage to Development Risk Profile Based on Production History to Date, Apparently Attractive Drilling Results Number of Independent Catalysts that Could Trigger Acceleration in Bakken Drilling 2008 Bakken Drilling Provides for Potentially Large Impact on Year-End 2008 Reserves Currently, Laying the Foundation for Future Acceleration in Bakken Drilling Activity

Brigham Core Operating Areas TEXAS GULF COAST Acreage: 30,121 Reserves: 83 Bcfe Production: 19.6 MMcfe/d Brigham Major Field Discoveries ROCKIES Acreage: 306,000 Reserves: 11 Bcfe Production: 0.8 MMcfe/d ANADARKO BASIN Acreage: 33,647 Reserves: 35 Bcfe Production: 8.2 MMcfe/d S. LOUISIANA Acreage: 1,513 Reserves 3 Bcfe Production: 10.7 MMcfe/d Net acreage at current levels; reserves at YE 2007; production average for 2007 WEST TEXAS Acreage: 14,855 Reserves: 8 Bcfe Production: 2.3 MMcfe/d

Corporate Strategy Concept Emerging Play Exploration Development

Land & G&G Capex vs. Finding Costs Historically, our longer term investments in acreage and seismic preceded a multi-year period of low finding costs and reserve growth (upper chart) Increased levels of land and G&G spending in 2005 though 2008 to capture resource play opportunities (lower chart) 2005 - 2007 spent $69 million In 2008, expect to spend $18 million Resource play inventory provides potential opportunity to grow reserves and production on a more consistent and predictable basis Over 300,000 net acres in the Rockies, of which over 240,000 net acres of which is located in Williston Basin

2008 Opportunity Set Significant activity in Mountrail County and extensional areas 88,000 net acres in Mountrail County and extensional areas Currently, one rig drilling with opportunity to add additional rig in 2H 2008 Testing advance completion technologies on 51,000 net acres west of Nesson Anticline Re-entering and redrilled lateral of Mracheck well in McKenzie Co, ND to stage frac with swell packers 100,000 net acres in Montana targeting multiple objectives including the Bakken Utilizing proprietary 3-D interpretation techniques to identify Red River targets 16 initial Red River prospects identified Conduct 3-D shoot in Roosevelt County, MT to identify additional Red River and Bakken opportunities Vicksburg drilling has commenced with 2 rigs currently running Completing apparently successful Floyd Fault Block C-38 Currently drilling C-39 and F-35 Southern Louisiana wells completing / additional activity commencing in 2Q and 3Q 2008 Completing Carey Estate #1 New Southern Louisiana joint venture program commences May 2008 Cotten Land #5 commences 3Q 2008 Key Wyoming Powder River Basin Mowry Shale well completing with swell packers

Williston Basin Overview

The Bakken Formation is the Largest Oil Accumulation Accessed by USGS in the Lower 48

Williston Basin USGS Assessment BEXP's 240,000 Net Acres Attractively Located

Mountrail County and Extensional Areas High Potential Acreage Position 88,000 net acres In Mountrail and Extensional Areas potentially provides 137 net drilling locations Other operator currently testing 320 acre spacing Market Capitalization as of April 16, 2008 Peer group comprised of Continental, EOG, Kodiak, Northern Oil & Gas, St. Mary and Whiting Additional 51,000 net acres in Williams and McKenzie Counties, North Dakota Additional 100,000 net acres in Roosevelt and Sheridan Counties, Montana

Williston Basin Overview A Quick Look at the Bakken Relative to the Barnett

Bakken vs. Barnett Barnett Play Unproven & in R&D in 1990, Similar to the Bakken in 1998 1990 2004 2006 Present 1998 Barnett Shale Early Wise County drilling generated inconsistent & generally marginal results Bakken Shale Pioneering early horizontal drilling in late 80's to mid 90's by Burlington generated inconsistent & generally marginal results

Bakken vs. Barnett Barnett Play Unproven & in R&D in 1990, Similar to the Bakken in 1998 1990 2004 2006 Present 1998 Barnett Shale Technical improvements resulted in accelerated development of Wise County area in early 2000's Bakken Shale Technical advancements and Middle Bakken horizontal drilling preceeded rapid development of the Elm Coulee Field area 2000 2006 Early outposts provide encouragement. Early Dunn County and first Parshall Field wells encourage operators.

2004 Bakken vs. Barnett Barnett Play Unproven & in R&D in 1990, Similar to the Bakken in 1998 1990 2004 2006 Present 1998 Barnett Shale Operators continue to refine operations. Bakken Shale Techniques continually evolving. 2000 2006 Present Drilling begins to accelerate in Johnson County & adjacent areas. Drilling in Mountrail & Dunn County accelerates.

Bakken vs. Barnett Barnett Play Unproven & in R&D in 1990, Similar to the Bakken in 1998 2004 2006 Present Barnett Shale Operators continue to refine operations. Drilling accelerates in Johnson County & adjacent areas. Bakken Shale Techniques continually evolving. Drilling in Mountrail & Dunn County accelerates. Drilling activity expected to spread over time. 2003 Present 2006 Present

Bakken vs. Barnett Approximate aerial extent of Bakken oil play is roughly double that of Barnett gas play Assuming 100% of Barnett drilled on 160 acre spacing indicates 31,831 total wells drilled, or 23,893 additional wells. Assuming 100% of Bakken drilled on 640 acre spacing indicates 17,906 total wells drilled, or 16,508 additional wells. * Both estimates based on USGS assessments, excludes NGL's.

Williston Basin Overview BEXP's Bakken Opportunity

Williston Basin Historical Overview Multiple Objective Potential - 240,000 Net Acres Bakken Elm Coulee Field (Richland County, MT) discovered 2001 3 years later declared economic BEXP drilled 3 Bakken wells in Williams / McKenzie Counties, ND in 2006 51,500 Net Acres in counties Field / Erickson wells IP @ 200 Bopd, subsequently stabilized at 50 - 90 Bopd, est. avg. EUR 165,000 Boe each Mracheck (3rd well) currently being reentered, utilizing swell packers Currently over 88,000 net acres in Mountrail County, ND and extensional areas Numerous high rate completions in area Extensive leasing efforts ongoing Targeting extensional areas with similar attributes BEXP Red River discovery in Sheridan Co, MT utilizing 3-D seismic 16 Prospects & leads identified Prospecting for Red River, Bakken, Mission Canyon & other potential objectives on 100,000 net acres Acreage Summary: MT ~100,000 net acres; ND west of Nesson Anticline ~ 51,500 net acres; ND east of Nesson Anticline over 88,000 net acres * Reported EOG Acreage in Yellow

Williston Basin Overview - Expansive Bakken Reservoir Bakken Cross Section West to East Across Williston Elm Coulee Field Richland Co., MT Pale Rider Roosevelt Co., MT Rough Rider McKenzie Co. ND South Nesson Dunn Co., ND East Nesson Mountrail Co., ND BEXP Acreage Area 100,000 Net Acres in Eastern Montana BEXP Acreage Area 51,000 Net Acres West of Nesson in ND BEXP Acreage Area 88,000 Net Acres East of Nesson in ND

2007 PUDs 2007 BEXP Wells 2008 BEXP Wells 2008 PUDs Williston Basin - Mountrail County Area Current 2007 - 2008 Drilling Plan '08 Total 51 32 83 '08 Non Op. 44 19 63 13 20 '08 Oper. 7 '07 3 6 9 PDP PUD TOTAL After Proved Credit for 9 Gross or ~5 Net Booked Locations in 2007 Current 2008 Plan Provides Potential for Adding ~83 Gross or ~19 Net Booked Locations Added in 2008 Parshall/Austin Area Stanley Area Ross Area Hallingstad #1H 56% WI 76%WI 69%WI 67%WI Johnson 38% WI Manitou #1H 100% WI Olson 70% WI Bergstrom #1H 57% WI Bakke #1H 93% WI Hynek #1 H 97% WI

Williston Basin - Mountrail County Area Fully Developed Assuming 640 Acre Dev. (Potentially >Gross 300 Wells) Assuming 640 Acre Spacing Potential to Drill Over 300 Gross or 137 Net Wells East of the Nesson Anticline Parshall/Austin Area Stanley Area Ross Area

Williston Basin Overview Brief Comparison of Elm Coulee & Mountrail Bakken Drilling Areas

Williston Basin Bakken Oil Production Elm Coulee vs Dunn & Mountrail Counties Elm Coulee Mountrail Dunn 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 With Continued Drilling Success Mountrail & Dunn County Production Will Both Eclipse Elm Coulee

Williston Basin Elm Coulee/Mountrail County Overlay To Approximate Scale Parshall/Austin Area Stanley Area Ross Area Estimated BEXP Leasehold Over 88,000 Net Acres & Growing Approximately 2 laterals in each section thus far in Elm Coulee (some long laterals from other sections, some tri-laterals) 9 rigs currently running in Elm Coulee, 26 rigs drilling in Mountrail County Current Mountrail Co. drilling area roughly double aerial extent Elm Coulee (~1,300 vs 560 sq. miles)

Williston Basin Overview Brief Look at Our Current View on Mountrail Bakken Drilling Economics

Williston Basin Bakken Reserves & Economics Break Even Today ~ 158 Mbo Break Even ~158 Mbo * Based on NYMEX strip at 4/07/08. Price differentials: $1.256/Mcf & -$5.337/Bbl. CWC of $4.95 million in Ross, $5.5 million in Parshall/Austin. OPEX at $8397/month. Monthly average rate which given natural declines is less than IP rates.

Williston Basin Bakken Reserves & Economics Ross Area Avg. Res/Well Currently Est. @ 200 - 400 Mbo Ross Area 200 - 400 Mbo Drill Net PV10%/$ $/Mcfe PV10% (mill.) Coverage ROR * Based on NYMEX strip at 4/07/08. Price differentials: $1.256/Mcf & -$5.337/Bbl. CWC of $4.95 million in Ross, $5.5 million in Parshall/Austin. OPEX at $8397/month. Monthly average rate which given natural declines is less than IP rates. 200 Mbo $4.37 $1.58 1.3 18% 300 Mbo $2.93 $5.14 2.1 41% 400 Mbo $2.20 $8.98 2.9 87% Break Even ~158 Mbo

Drill Net PV10%/$ $/Mcfe PV10% (mill.) Coverage ROR Williston Basin Bakken Reserves & Economics Parshall/Austin Avg. Reserves Currently Est. @ 400 - 1,000 Mbo Ross Area 200 - 400 Mbo Parshall/Austin Area 400 - 1,000 Mbo 200 Mbo $4.37 $1.58 1.3 18% 300 Mbo $2.93 $5.14 2.1 41% 400 Mbo $2.20 $8.98 2.9 87% * Based on NYMEX strip at 4/07/08. Price differentials: $1.256/Mcf & -$5.337/Bbl. CWC of $4.95 million in Ross, $5.5 million in Parshall/Austin. OPEX at $8397/month. Monthly average rate which given natural declines is less than IP rates. 400 Mbo $2.66 $7.51 2.4 64% 700 Mbo $1.52 $20.32 4.8 >100% 1,000 Mbo $1.07 $35.21 7.5 >100%

Williston Basin Bakken Reserves & Economics Elm Coulee & Dunn County EUR's vs Mountrail Area Parshall/Austin Area Midpoint ~ 700 Mbo Ross Area Midpoint ~ 300 Mbo Elm Coulee Avg. ~ 437 Mbo Dunn County Avg. ~ 258 Mbo * Based on NYMEX strip at 4/07/08. Price differentials: $1.256/Mcf & -$5.337/Bbl. CWC of $4.95 million in Ross, $5.5 million in Parshall/Austin. OPEX at $8397/month. Monthly average rate which given natural declines is less than IP rates.

Williston Basin Geologic Overview Jeff Larson

Williston Basin Structure Map Base of Mississippian Large Intra-Cratonic 'Sag' Basin 'Inside' Stable Continent Illinois & Michigan Basins Circular Geometry Over 125,000 sq miles Parts of Three States and Two Provinces Old Basin Began Subsiding in the Late Cambrian (490 m.y.a) Bakken Occupies Only Northern Portion of Basin After Webster 1987

After Peterson 1987 Williston Basin Regional Cross-Section After Peterson 1987 Resembles a Giant Cereal Bowl Over 15,000 ft of Strata in Center Feather Edges Formations 'Pinch-out' Elm Coulee Field Variable Amounts of Subsidence Through Time Some Formations Very Thick, 'Rapid Subsidence' Variable Degrees of Marine Incursion Through Time Wide Areal Extent Indicative of Widespread Marine Flooding Basin Was Restricted Periodically Salt Deposition Structurally Not Complex Anticlines, Faults and Folds Bakken

Generalized Williston Basin Stratigraphic Section Majority of the Geologic Section Represented in Basin Paleozoic Through Tertiary Paleozoic Section is Dominated by Marine Limestones and Dolomites 99% Hydrocarbons 90% From Paleozoic Carbonates Numerous Producing Intervals Mesozoic and Cenozoic Section Dominated by Sandstones and Shales Periods of Salt Deposition Periodic Restriction = Sandstone = Limestone = Dolomite = Shale = Salt Madison Group Charles/Ratcliffe Productive Intervals

Mountrail County Bakken Type Log Lear Petroleum East Parshall S #1 Sanish

Mountrail County Bakken Type Log Lear Petroleum East Parshall S #1 Upper Devonian / Lower Mississippian Aged Age of Fishes Equivalent to Chattanooga, New Albany, Woodford Shales Depths Range from 8,500' to 11,000' Maximum Total Thickness: 170 ft Divided into 3 Members: Upper and Lower Shale Members are Lithologically Very Similar Upper Max. 28 ft, Lower Max 55 ft Shales: Black, Siliceous (Brittle), Pyritic, Often Thinly Laminated, Organic Rich (TOC) Average 10 % (As High as 20%) Well Log Response: GR Often Reads "Hot" (Off Scale), High TOC & Associated Uranium Resistivities Greater Than 100 Ohms in Thermally Mature Area (Non-Mature 10 Ohms or Less) Middle Member: Highly Variable 'Heterogeneous' Lithologies Max. 87 ft Dolomitic Grading to Limestone, Siltstone and Sandstone Components Common Often Burrowed Textures Clean Interval: Porosities Avg 5%, Permeabilities Avg .01 Md Well Log Response: Clean Gamma Ray Section w/Density Porosity Developed Horizontal 'Target' Zone

Upper and Lower Bakken Core Photograph Upper and Lower Shales are Lithologically Similar: Black Color, Anoxic 'Oxygen Starved' Deposition Few Burrows, Pyrite (Reducing Environment) High Organic Content ('World Class Source Rock') Average 10% TOC Thin Laminations Quiet Water Deposition Scattered Storm Lamina Upper Bakken Lower Bakken

Middle Bakken Core Photograph Mountrail Area Example Higher Energy Deposition Coarser Grains, Marine Near Shore Environment Laminations Bioturbation (Burrowing) Oxygenated Sediments Illustrates Variable 'Heterogeneous' Lithologies Upper Part is Dolomite Lower Part Quartz-Rich Sandstone Several Different Types of Fractures First Set Filled with Calcite Cement 'Healed' Second Set Open Small Fault with 'Off-Set' Core Studies Critical to Understanding Bakken Colorado State University Core Consortium Coring Several Wells Southern Extension

Bakken Depositional Model Seaward Landward

Bakken Depositional Model Fossil Record Indicates Marine Conditions Throughout Upper & Lower Shale Deposition Basin Partially Restricted (Little Water Flow) Stratified Water Column (No 'Turn -Over') Quiet Water, Anoxic (Oxygen Starved) Bottom Conditions Reducing Environment Ideal of Organic Preservation Prolific Marine Plankton Production Near Surface 'Blooms' 'Heavy Rain' of Organic Debris to Bottom Result: World Class Source Rock Middle Bakken Time Higher Energy Conditions Introduction of Source for Silts and Sands Regional Uplift Shallow Water Carbonate Deposition Modern-Day Persian Gulf Anolog Mixed Silicaclastic/ Carbonate System

Bakken Hydrocarbon Generation Model Bakken Upper Middle Lower

Bakken Hydrocarbon Generation Model Shales Experienced Several Important Hydrocarbon Generating Conditions with Burial Increasing Temperatures & Significant Timeline Onset of Hydrocarbon Generation 9,000 ft with Intense Window at 10,000 ft Thermal Maturation Temperatures Estimated 100 C / 212 F Late Cretaceous (70 m.y.a.) Onset of Generation (Approx. 300 Million Years to 'Cook') Kerogens Cracked to Oils / Expulsion Giant Kerogen Molecules Split into Oils Significant Increase in Volume Microfractures Created in Rock Fabric Overpressuring Begins Hydrocarbons Begin to Migrate Along Conduits (Pathways) Faults and Permeable Rock Layers In Situ Water Displaced-Resulting in High Resistivities of 'Kitchen' Rocks Localized Overpressured Areas Hydrocarbons Unable to Migrate Impermeable Rocks, Sealed Faults 'Packages' of Rock Uplifted

Williston Basin Basement Block Faulting Lineament Lineament

Structural Block Diagram Illustrate Structural Implications in Basin Critical to Understanding of Predicting New Areas to Explore Williston Basin Underlain by Very Old (Pre-Cambrian) Granitic Basement Rocks Broken Up into Large Blocks Township to 1/2 County Scale Blocks Separated by Zones Structural Weakness 'Lineaments' / Fault Zones Multiple Stages Movement, Blocks 'Jostled' Localized Uplifts, Structural Noses and Faulting Regional Shearing, NE-SW Orientation Localized Areas Intense Fracturing Techniques Basin-wide Aeromagnetic Survey Changes in Basement Rocks 2-D and 3-D Seismic Surveys 10,000 Line Miles 587 Sq Miles Existing 3-D Participating in 2 New Shoots Two Operated 3-D Shoots Planned (223 Sq's) Satellite Imagery Landsat / Orthophotography Identify Surface Expressions of Lineaments Subsurface Mapping Several Thousand Control Points Williston Basin Basement Block Faulting

Williston Basin Historical Bakken Activity Map Antelope Field 1953 Nesson Anticline 1950's-1960's Elkhorn Ranch 1961 Bicentennial 1987-1999 Elm Coulee 2001 Nesson Anticline 2004 Saskatchewan 2004 West Side of Nesson 2005 Parshall Field 2006 Elm Coulee Extension 2007 Production 'Bakken Kitchen' (Resistivities > 100 Ohms)

Bakken Historical Activity Antelope Field (1953) Sanish Production, Several Bakken Tests 90 Vertical Wells 41 MMBO & 60 BCF Cumulative Nesson Anticline (1950's - 1960's) Scattered Early Vertical Development Elkhorn Ranch Field (1961) Shell, Vertical Wells Bicentennial / Elkhorn Ranch (1987 - 1999) Meridian Oil First to Complete Bakken Horizontal Targeted Upper Bakken Shale Drilling Problems 192 Horizontal Wells, 22 MMBO & 52 BCF Cumulative Elm Coulee (2001 to Present) Lyco Energy 634 Horizontal & Vertical Drilled to Date 33,400 BOPD (12/2007) 65 MMBO & 42 BCF Cumulative Nesson Anticline (2004 to Present) Horizontal Technology Applied With Success Canadian Play Starts (2004 to Present) Saskatchewan and Manitoba Vertical and Horizontal West Side of Nesson Anticline (2005 to Present) Several Operators Long Lateral Horizontals Brigham First to Use Swell Packer Technology (Mracheck) Parshall Field Discovery (2007 to Present) EOG Extends Play to East Elm Coulee Extension (2007) Sinclair Well IP 300 BOPD Proximal to Large Brigham Leasehold Ghost Rider 3-D

Williston Basin Geologic Overview Summary "Our Technical Team has Developed a Comprehensive Understanding of Geologic & Geophysical Aspects of the Williston Basin Which Will Greatly Aid Our Successful Exploration for Hydrocarbons in the Bakken and Other Formations in the Basin"

Bakken Operations Overview Lance Langford

Williston Basin Historical Bakken Drilling Activity Antelope Field 1953 Nesson Anticline 1950's-1960's Elkhorn Ranch 1961 Bicentennial 1987-1999 Elm Coulee 2000 Nesson Anticline 2004 Saskatchewan 2004 West Side of Nesson 2005 Parshall Field 2006 Elm Coulee Extension 2007 1950 to late-1980s - vertical drilling 1987 to 2000 - upper Bakken horizontal drilling 2000 - Middle Bakken horizontals 2001 - Two section horizontals 2006 - Introduction of swell packers 2008 - Introduction of cemented liners

Bakken Drilling and Completions

Williston Basin Map

Well Bore Design West of Nesson Anticline Initiated Bakken drilling program in Williams & McKenzie Cos., ND (Rough Rider) in 2006 Drilled 3 wells utilizing the following design: 1280 acre spacing with 8,100' lateral Preperforated uncemented liner Large single uncontrolled fracture stimulation Typical well costing $5.1 million and having 165 MBOE of recoverable reserves Wells were marginally economic

Well Bore Design East of Nesson Anticline Initiated Bakken drilling in Mountrail Co., ND (Easy Rider) in 2007 Drilled 5 wells to date utilizing the following design: 640 Acre Spacing with 4,900' lateral Uncemented liner with swell packers Multiple isolated fracture stimulations between swell packers Utilize frac sleeves or perf and plug to communicate with isolated intervals Typical well costing $5 million and having recoverable reserves averaging 200 to 400 MBOE Resulting in an economic drilling program Swell Packer Animation

Bakken Swell Packer Tools Swell Packer Frac Sleeve

Bakken Technology Consortium

Seven E&P Companies & Schlumberger E&P Companies share costs / revenues Schlumberger provides discounted and free services 3 wells drilled east flank of Nesson Anticline Within 3D Seismic shoot 4/17/2008 57 DDM Bakken Consortium Overview Bakken Consortium

Compare 3 major completion designs Preperforated uncemented liners Uncemented liners with Swell Packers Cemented liners Study refracture stimulations Optimize fracture stimulation designs Correlate with 3-D Study long-term production results 4/17/2008 58 DDM Technology Consortium Major Objectives

3 Optimally Placed Sub-Bakken Vertical Penetrations with wellbores suitable for geophone deployment. 6,000 ft Horizontal Producer 2,000' between vertical wells 2,000' between vertical wells 2,000' between vertical wells Typical Fracture Stimulation Monitoring 640 Acre Section Typical fracture stimulation monitoring utilizes vertical well bore (red well) Unable to effectively monitor outer reaches of horizontal well bore Improvements when place multiple vertical wells along length of lateral (blue wells) Costly as multiple wells must be drilled After Headington 2008

4/17/2008 Monitoring Well (Cemented liner) Producer #1 (Pre-perforated liner) Producer #2 (liner with swell packers) ~1500 ft ~1500 ft Technology Consortium Plan 1500 ft 1500 ft of geophones 1500 ft First industry attempt with horizontal monitoring well 3 horizontal wells drilled: 2 producing wells plus monitoring well Wells spaced such that middle well serves as monitoring station Producers completed using pre-perforated liner and swell packer Refracture stimulate producers in ~ 18 months Stimulate monitoring well post-refracture stimulation of producers 640 Acre Section After Headington 2008

All 3 wells TD'd Drilling and Logging data quality has been good Geophones expected to deploy the week before fracture stimulation Expected to fracture stimulate both producers in May Seismic interpretation will be begin in May 4/17/2008 61 DDM Consortium Current Status/Conclusions

Bakken Full Scale Field Development

Full Scale Field Development Growing Bakken staff Preparing additional locations in Ross and Stanley areas Rig availability Evaluating field yard opportunities Evaluating further field optimizations such as equipment acquisitions Evaluating water supply and water disposal alternatives

Bakken Oil and Natural Gas Marketing

Oil Pipelines and Refineries Keystone Pipeline Enbridge Pipeline Oil Refineries Oil Pipelines Platte Pipeline Butte Pipeline Suncor 88,000 Frontier 52,000 Tesoro 58,000 Sinclair 22,500 Conoco Phillips 58,000 ExxonMobil 60,000 Cenex 56,000 Big West 25,000 Chevron Texaco 45,000 Holly Corp 25,000 Silver Eagle Refining 12,500 Tesoro 60,000 Sinclair 72,000 Wyoming Refining 12,500 ExxonMobil 238,000 BP PLC 399,000 CITGO 159,000 Conoco Phillips 306,000 Flint Hills Resources 298,000 Marathon Ashland 70,000 NCRA 79,000 Frontier 110,000 Red Text Montana Refining 8,200 Rocky Mountain Region ,IL

North Dakota Oil Marketing Overview Markets for Williston Basin crude oil production are: Refineries within the Rocky Mountain Region Refineries in the Midwest via two "export" pipelines Regional Refining Capacity 15 refineries in the Rocky Mountain Region Capacity exceeds local production so substantial volumes of Canadian oil are also processed Refining capacity static for the last 20 years Most expansion projects have focused on heavier sour crude

North Dakota Oil Marketing Export Capacity Enbridge Pipeline moves 110,000 BOPD to Clearbrook, MN. Platte Pipeline moves 150,000 BOPD to Wood River, IL. Expansion Projects Enbridge will expand capacity from 110,000 to 161,000 BOPD by early 2010 Keystone planning 435,000 BOPD to Patoka, IL. by late 2009 Other Transportation Major regional purchaser is finalizing transportation by railcar from Stanley, ND by late 2008

North Dakota Oil Marketing

Natural Gas Pipelines Headington Hess EOG Whiting Bear Paw McKenzie County 148N-105W Brigham Carkuff 22-1-H Proposed Brigham Manitou State 36-1H Drilling Brigham Hynek 2-1H IP: 585 BOEPD Brigham Bakke 23-1-H IP: 380 BOEPD Brigham Bergstrom 26-1H IP: 202 BOEPD Brigham Hallingstad 27-1H Est 400 BOEPD Brigham Johnson 33-1-H Permit 2/19/08

North Dakota Natural Gas Marketing West of Nesson Anticline Bear Paw Energy purchases all of Brigham's gas under long term percentage of proceeds contract Plant capacity is expanding from 60 MMcfd to 100 MMcfd in 2008 East of Nesson Anticline Area is in early stages of gas gathering infrastructure development Existing Producer-Owned Systems Hess's Tioga sour gas plant with capacity of 110 MMcfd Headington's gas plant has capacity but is on other side of Nesson Anticline EOG's gas plant with capacity of 3 to 20 MMcfpd is currently under construction Whiting's gas plant with capacity of 3-10 MMcfpd is currently under construction

North Dakota Natural Gas Marketing Interstate Take away Williston Basin Interstate Pipeline is the major Transporter of gas from North Dakota Expansion of these facilities could be in service by late 2008. Brigham's Plan Continue negotiations with producer owned gathering systems for connection of the Bergstrom Family Trust and Hallingstad wells Build a Brigham-owned gathering system to handle the Ross and North Stanley areas

Bakken Economics

Williston Basin Bakken Reserves & Economics Ross & Parshall/Austin Price Sensitivities Parshall/ Austin Midpoint ~ 700 Mbo * Based on NYMEX strip at 4/07/08. Price differentials: $1.256/Mcf & -$5.337/Bbl. CWC of $4.95 million in Ross, $5.5 million in Parshall/Austin. OPEX at $8397/month. Ross Area Midpoint ~ 300 Mbo Ross Area Low ~ 200 Mbo Ross Area High ~ 400 Mbo Parshall/Austin Low 400 Mbo

Williston Basin Bakken Reserves & Economics Ross & Parshall/Austin Price Sensitivities Parshall/ Austin Midpoint ~ 700 Mbo * Based on NYMEX strip at 4/07/08. Price differentials: $1.256/Mcf & -$5.337/Bbl. CWC of $4.95 million in Ross, $5.5 million in Parshall/Austin. OPEX at $8397/month.. Ross Area Midpoint ~ 300 Mbo Ross Area Low ~ 200 Mbo Ross Area High ~ 400 Mbo Parshall/Austin Low 400 Mbo

Current 2008 Drilling Plan

Extensive Bakken Drilling Inventory Net Wells Proved in 2007, Expected to be Proved in 2008 & Potential Locations Approximately 2.5 net wells were proved developed @ YE 2007, estimate roughly 8.6 net proved developed wells @ YE 2008 Estimate to have ~19 net wells added to proved @ YE 2008, assuming current permits & proposals Assuming avg. $5 million/well CWC, approximately $685 million in potential drilling opportunities east of Nesson, and roughly $1.2 billion in total potential Williston Basin Bakken drilling investments 374 137 * Current potential acreage inventory. Assumptions in potential locations include 640 acre spacing. 5 19 Estimated 237

2007 PUDs 2007 BEXP Wells 2008 BEXP Wells 2008 PUDs Mountrail County & Extensional Areas Current 2007 - 2008 Drilling Plan '08 Total 51 32 83 '08 Non Op. 44 19 63 13 20 '08 Oper. 7 '07 3 6 9 PDP PUD TOTAL After Proved Credit for 9 Gross or ~5 Net Booked Locations in 2007 Current 2008 Plan Provides Potential for Adding ~83 Gross or ~19 Net Booked Locations Added in 2008 Parshall/Austin Area Stanley Area Ross Area Hallingstad #1H 56% WI 76%WI 69%WI 67%WI Johnson 38% WI Manitou #1H 100% WI Olson 70% WI Bergstrom #1H 57% WI Bakke #1H 93% WI Hynek #1 H 97% WI

BEXP Net Bakken Production Estimated Exit Q1 2008 ~ 450 Boepd Net ~400 Net Boepd from 2.5 net wells completed late 2007 & early 2008. Estimated 8.6 net wells online by YE 2008 Manitou State (100% WI, Ross Area) currently completing Johnson (38% WI, N. Stanley Area) currently drilling Non Operated Parshall Area drilling expected to pick up mid- year with 25% WI offset to EOG 3,060 Bopd discovery BEXP Net Bakken Production Boe/Day Bakke Hynek Bergstrom Erickson Field Mrachek Hallingstad

Vicksburg Overview

Formed the first JV with ExxonMobil in 1997 4 additional JVs implemented Since 1999, 39 completions in 41 attempts In 2007, completed all 5 100% initial WI wells Anticipate 2008 wells at initial 100% WI 3 Year Total Proved F&D of $2.77/Mcfe 54 drilling locations at year-end 2007 34 proved, 12 probable and 8 possible Acquired additional acreage in southwest Home Run / shallow rights in eastern Triple Crowne C-39 #12 Vicksburg ExxonMobil Joint Venture Overview Net Vicksburg Production (MMcfe/d) PUD Probable Home Run Field Triple Crowne Field Floyd Field C-38 2003 2002 2001 2004 2005 2006 2007 F-35 Floyd South Field Possible PDP

Exploiting the Vicksburg Two Rigs Currently Running Operating Overview Difficult drilling environment: High mud weights: 18.0+ ppg >300° bottom hole temperature Laminated lithology Casing collapse has been an issue Large fracture stimulations required Condensate ranges from 10-100 BO/MMcf 2008 Wells: Currently completing C-38 Vick 10 tested 2.7 MMcfe/d Currently completing Vick 9 with Vick 8 still to complete, expected rate of 3-5 Mmcfed C-39 at intermediate casing point Targeting 9800', Vick 6, 7 & 8 sands F-35 drilling below 9,300' Targeting Brigham, 9800', Loma Blanca and Dawson Sands. C-39 #12 PUD Probable Home Run Field Triple Crowne Field Floyd Field C-38 F-35 Floyd South Field Possible PDP

Driving Operational Excellence Implementing Optimal Drill & Complete Technologies Early wells drilled with oil based drilling fluids Experienced severe losses and casing problems / collapses Switched to water based mud and alleviated most lost circulation issues Continual evolution of drilling and completion practices to limit casing failures Latest enhancement, Terra-Max drilling fluid, is greatest operational improvement Reduced drilling days Reduced mud losses / mud costs Elimination of costly drilling liners Reduced hole enlargement Limited / no differential sticking Terra-Max paper recently presented at the AADE Drilling Fluids Conference in Houston

Brooks County Vicksburg Drilling Curves

Brooks County Vicksburg Drilling Curves BEXP drilled the fastest well (Sullivan C-36) in Brooks County to 13,500': 20 days

Brooks County Vicksburg Drilling Costs 2006-2007 Wells

Southern Louisiana Overview

Southern Louisiana JV Relatively Low Risk Shallow 3-D Delineated Prospects Diane Breton SD 52 Romere Pass SE Tiger Pass Main Pass 66 Chandeleur Sound Executed JV to drill 6 wells in next 18 months Retain option to terminate if 3 of first 5 wells not completed Currently plan to drill approximately 5 wells in 2008 Five prospects target 3-D amplitude related prospects at 9,000 to 10,500 feet Estimated risked dry hole capital of $17.1 to $20.5 million Chandeleur Sound will target amplitude offsetting well shut in by Hurricane Katrina

Finance Overview

Financial Discussion and Strategy Balance Sheet - Maintain strong balance sheet 2008 E&D Capex - Fund majority through internally generated cash flow and proceeds from Granite Wash asset sale Hedge Portfolio - Hedged during 2008 with a $8.11 per Mcfe floor price NAV per Share - Currently trading at a discount to 2007 year end proved NAV, with the Bakken, the Mowry and the exploration prospect inventory representing non-proved share price appreciation potential

Balance Sheet Maintain Strong Balance Sheet Current balance sheet ratios in-line with that of peer companies Conservative 2008 capex budget funded largely with cash flow and proceeds from Granite Wash asset sale Target total debt / EBITDA and total debt / book capitalization ratios below 2.0x and 45%, respectively 2004 2005 2006 '2007 East 0.9 0.9 1.9 1.7 0.9X 0.9X 1.9X TOTAL DEBT/ EBITDA 1.7X 2004 2005 2006 '2007 East 22 23 38 39 22% 23% 38% TOTAL DEBT/CAP 39%

2008 Capital Expenditure Plan Funding Review 2004 2005 2006 2007 2008E East 81.2 110.5 174 102.4 120.8 $81 $110 $174 E&D CAPEX ($ MILLIONS) $102 $121 GC AB Rockies WT & Other S LA East 28 11 43 3 15 Gulf Coast 28% Anadarko Basin 11% W. TX/Other 3% Rockies 43% S. LA 15% Anadarko Basin 11% Allocation By Focus Area In January, announced $121 million E&D capex budget: Mid-point of Q1 guidance generates $19 million of forecasted Q1 cash flow, based on a combination of actual and strip prices Annualizing Q1 cash flow, combined with $36 million of proceeds from Granite Wash asset sale, covers 90-95% of announced capex budget Other "equity-like" funding sources: Production outperformance versus Q1 guidance Additional asset sales Greater usage of availability under credit facility: $10 million outstanding at year end 2007 with current borrowing base of $101 million Due to reset borrowing base in May Drilling results that de-risk Bakken acreage Will re-evaluate capex budget to determine potential for increase in the second half of 2008

Hedge Portfolio 2008 Hedged at $8.11/Mcfe Floor Price 2008 Hedged at $8.11/Mcfe Floor Price 2008 Hedged at $8.11/Mcfe Floor Price

Currently Valued at a Discount to Proved NAV Bakken, Mowry and Exploration Portfolio Represent Upside NAV Calculation: Proved reserves at Year-End 2007 April 14, 2008 Strip Prices PV10 Value $ 629.2 Million Less: Debt 180.1 Million Net Asset Value $ 449.1 Million Shares Outstanding ÷ 46.1 Million Shares NAV Per Share = $ 9.74 per share Other Sources of Value: Williston Basin Bakken and Red River Powder River Basin Mowry Vicksburg Non-Proved Development Locations Southern Louisiana Exploration Locations Other Conventional Exploration Locations NAV per Share Analysis

Key Takeaways

Key Takeaways As Was the Case Historically, Our Recent Long-Term Land and Seismic Investments Position Us for a Multi-Year Period of Higher Rate Reserve Growth & Lower Finding Costs Potentially Highly Impactful 240,000 Net Acre Position in Williston Basin Targeting Multiple Objectives in ND and MT Bakken is Expansive Growth Opportunity - Similar to Barnett Shale in 2004 In 2008 Migrating a Portion of Our Bakken Acreage to Development Risk Profile Based on Production History to Date, Apparently Attractive Drilling Results Number of Independent Catalysts that Could Trigger Acceleration in Bakken Drilling 2008 Bakken Drilling Provides for Potentially Large Impact on Year-End 2008 Reserves Currently, Laying the Foundation for Future Acceleration in Bakken Drilling Activity